Drilling and Well Completions

4 Drilling and Well Completions Frederick E. Beck,

Abdul Mujeeb

Ph.D. ARCO Alaska Anchorage, Alaska

Henkels & McCoy, Inc. Blue Bell, Pennsylvania

Daniel E. Boone

Charles Nathan, Ph.D., P.E.

Consultant, Petroleum Engineering Houston, Texas

Consultant, Corrosion Engineering Houston, Texas

Robert DesBrandes, Ph.D.

C h r i s S. R u s s e l l , P.E. Consultant, Environmental Engineering Las Cruces, New Mexico

Louisiana State University Baton Rouge, Louisiana

Ardeshir K .

P h i l l i p W . J o h n s o n , P h . D . , P.E. University of Alabama Tuscaloosa, Alabama

Shahraki, Ph.D. Dwight's Energy Data, Inc. Richardson, Texas

Andrzej K .

W i l l i a m C. L y o n s , P h . D . , P.E. New Mexico Institute of Mining and Technology Socorro, New Mexico

Wojtanowicz, Ph.D., P.E. Louisiana State University Baton Rouge, Louisiana

Stefan Miska, Ph.D. University of Tulsa Tulsa, Oklahoma

Derricks and Portable Masts ................................................................. 499 Standard Derricks 50t. Load Capacities 506. Design Loadings 508. Design Specifications 511. Maintenance and Use of Drilling and Well Servicing Structures 515. Derrick Efficiency Factor 52t.

Hoisting Systems ................................................................................... 523 Drawworks 525. Drilling and Production Hoisting Equipment 530. Inspection 540. Hoist Tool Inspection and Maintenance Procedures 542. Wire Rope 544.

Rotary

616

Mud

Pumps ........................................................................................... Pump Installation 627. Pump Operation 630. Pump Performance Charts 63t. Mud Pump Hydraulics 631. Useful Formulas 645.

627

D r i l l i n g Muds and Completion S y s t e m s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Testing of Drilling Fluids 652. Composition and Applications 664. Oil-Based Mud Systems 675. Environmental Aspects 682. Typical Calculations in Mud Engineering 687. Solids Control 691. Mud-Related Hole Problems 695. Completion and Workover Fluids 70t.

650

D r i l l String: Composition and Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drill Collar 716. Drill Pipe 735. ToolJoints 748. Heavy-Weight Drill Pipe 749. Fatigue Damage of Drill Pipe 763. Drill String Design 765.

715

Equipment ................................................................................. Swivel and Rotary Hose 616. Drill-Stem Subs 619. Kelly 620. Rotary Table and Bushings 622.

Drilling Bits and Downhole Tools ........................................................ 769 Classification of Drilling Bits 769. Roller Rock Bit 771. Bearing Design 774. Tooth Design 776. Steel Tooth Bit Selection 783. Diamond Bits 789. IADC Fixed Cutter Bit Classification System 801. Downhole Tools 8t2. Shock Absorbers 813.Jars. Underreamers 819. Stabilizers 823.

497

498

Drilling and Well Completions

Drilling M u d Hydraulics .......................................................................

829

Rheological Classification of Drilling Fluids 829. Flow Regimes 830. Principle of Additive Pressures 834. Friction Pressure Loss Calculations 836. Pressure Loss Through Bit Nozzles 839.

Air a n d Gas Drilling .............................................................................

840

Types of Operations 840. Equipment 844. Well Completion 847. Well Control 852. Air, Gas, and Unstable Foam Calculations 853.

D o w n h o l e M o t o r s ..................................................................................

862

Turbine Motors 863. Positive Displacement Motor 882. Special Applications 899.

M W D a n d LWD .....................................................................................

901

MWD Technology 901. Directional Drilling Parameters 954. Safety Parameters 961. LWD Technology 971. Gamma and Ray Logs 971. Resistivity Logs 974. Neutron-Density Logs 985. Measuring While Tripping: Wiper Logs 999. Measurements at the Bit 1002. Basic Log Interpretation 1005. Drilling Mechanics 1015. Abnormal Pressure Detection 1036. Drilling Safety, Kick Alert 1067. Horizontal Drilling, Geosteering 1070. Comparison of LWD Logs with Wireline Logs 1077. Comparison of MWD Data with Other Drilling Data 1078.

Directional Drilling ..............................................................................

1079

Glossary 1079. Dogleg Severity (Hole Curvature) Calculations 1083. Deflection Tool Orientation 1085. Three-Dimensional Deflecting Model 1088.

S e l e c t i o n o f Drilling Practices .............................................................

1090

Factors Affecting Drilling Rates 1090. Selection of Weight on Bit, Rotary Speed, and Drilling Time 1091. Selection of Optimal Nozzle Size and Mud Flowrate 1097.

Well P r e s s u r e C o n t r o l ..........................................................................

1100

Surface Equipment 1101. When and How to Close the Well 1101. Gas-Cut Mud 1103. The Closed Well 1105. Kick Control Procedures 1106. Maximum Casing/Borehole Pressure 1111.

F i s h i n g O p e r a t i o n s a n d E q u i p m e n t ....................................................

1113

Causes and Prevention 1114. Fishing Tools 1115. Free Point 1124.

C a s i n g and C a s i n g String D e s i g n ........................................................

1127

Types of Casing 1127. Casing Program Design 1128. Casing Data 1132. Elements of Threads 1141. Collapse Pressure 1147. Internal Yield Pressure 1155. Joint Strength 1156. Combination Casing Strings 1157. Running and Pulling Casing 1164.

W e l l C e m e n t i n g ................................................................................... 1177 Cementing Principles 1179. Properties of Cement Slurry 1183. Cement Additives 1193. Primary Cementing 1200. Large-Diameter Casing Cementing 1211. Multistage Casing Cementing 1216. Secondary Cementing 1223. Squeeze Cementing 1224. Plug Cementing 1228.

T u b i n g a n d T u b i n g String D e s i g n .......................................................

1233

API Physical Property Specification 1233. Dimension, Weights, and Lengths 1233. Running and Pulling Tubing 1239. Selection of Wall thickness and Steel Grade of Tubing 1251. Tubing Elongation/Contraction 1252. Packer-to-Tubing Force 1254. Permanent Corkscrewing 1257.

C o r r o s i o n a n d Scaling .........................................................................

1257

Corrosion Theory 1259. Forms of Corrosion Attack 1268. Factors Influencing Corrosion Rate 1292. Corrodents in Drilling Fluids 1300. Corrosion Monitoring and Equipment Inspections 1312. Corrosion Control 1323. Recommended Practices 1340.

E n v i r o n m e n t a l C o n s i d e r a t i o n s ............................................................

1343

Site Assessment and Construction 1344. Environmental Concerns While in Operation 1352.

O f f s h o r e O p e r a t i o n s ............................................................................

1363

Drilling Vessels 1357. Marine Riser Systems. 1359. Casing Programs 1361. Well Control 1363.

R e f e r e n c e s ............................................................................................

1373

Chapter 4 Drilling and Well Completions DERRICKS AND PORTABLE MASTS Derricks and p o r t a b l e masts p r o v i d e the clearance and structural s u p p o r t necessary for raising and lowering drill pipe, casing, r o d strings, etc., d u r i n g drilling and servicing o p e r a t i o n s . S t a n d a r d derricks are b o l t e d t o g e t h e r at the well site, a n d are c o n s i d e r e d n o n p o r t a b l e . P o r t a b l e derricks, which do not require full disassembly for transport, are t e r m e d masts. T h e derrick or mast must be d e s i g n e d to safely c a r r y all loads that are likely to be used d u r i n g the structure's life [1]. T h e largest vertical d e a d l o a d that will likely be i m p o s e d on the structure is the heaviest casing string r u n into the borehole. However, the largest vertical l o a d i m p o s e d on the structure will result from pulling e q u i p m e n t (i.e., drill string or casing string) stuck in the borehole. T h e most accepted m e t h o d is to design a d e r r i c k or mast that can carry a d e a d l o a d well b e y o n d the m a x i m u m casing l o a d expected. This can be accomplished by utilizing the safety factor. T h e d e r r i c k or mast must also be d e s i g n e d to withstand wind loads. W i n d loads are i m p o s e d by the wind acting on the outer and i n n e r surfaces o f the o p e n structure. W h e n designing for wind loads, the designer must consider that the drill p i p e or o t h e r tubulars may be out o f the hole and stacked i n - t h e structure. This means that t h e r e will be loads i m p o s e d on the structure by the p i p e weight (i.e., setback load) in a d d i t i o n to the a d d i t i o n a l loads i m p o s e d by the wind. T h e h o r i z o n t a l forces due to wind are c o u n t e r a c t e d by the lattice structure that is firmly secured to the structure's foundation. Additional s u p p o r t to the structure can be a c c o m p l i s h e d by the guy lines a t t a c h e d to the structure and to a d e a d man anchor some distance away from it. T h e d e a d man anchor is b u r i e d in the g r o u n d to firmly s u p p o r t the tension loads in the guy line. T h e guy lines are p r e t e n s i o n e d when a t t a c h e d to the d e a d man anchor. T h e APT S t a n d a r d 4F, First Edition, May 1, 1985, "APT Specifications for Drilling and Well Servicing Structures," was written to p r o v i d e suitable steel structures for drilling and well servicing o p e r a t i o n s and to p r o v i d e a u n i f o r m m e t h o d o f rating the structures for the p e t r o l e u m industry. APT S t a n d a r d 4F supersedes APT Standards 4A, 4D, and 4E; thus, many structures in service today may not satisfy all o f the requirements o f APT S t a n d a r d 4F [2-5]. For modern derrick and mast designs, APT Standard 4F is the authoritative source o f information, and much o f this section is extracted directly from this standard. Drilling and well servicing structures that meet the requirements o f APT Standard 4F are identified by a nameplate securely affixed to the structure in a conspicuous place. T h e nameplate markings convey at least the following information:

Mast and Derrick Nameplate Information a. b. c. d.

Manufacturer's name Manufacturer's address Specification 4F Serial n u m b e r 499

500

Drilling and Well C o m p l e t i o n s

e. Height in feet f. Maximum r a t e d static h o o k load in pounds, with guy lines if applicable, for stated n u m b e r o f lines to traveling block g. Maximum r a t e d wind velocity in knots, with guy lines if applicable, with rated capacity o f pipe racked h. T h e API specification and edition o f the API specification u n d e r which the structure was designed and m a n u f a c t u r e d i. Manufacturer's guying d i a g r a m - f o r structures as applicable j. Caution: Acceleration or impact, also setback and wind loads will reduce the m a x i m u m r a t e d static h o o k load capacity k. Manufacturer's load distribution d i a g r a m (which may be placed in mast instructions) 1. G r a p h o f m a x i m u m allowable static h o o k load versus wind velocity m. Mast setup distance for mast with guy lines.

Substructure Nameplate Information a. b. c. d. e. f. g. h.

Manufacturer's name Manufacture's address Specification 4F Serial n u m b e r Maximum r a t e d static rotary capacity Maximum r a t e d pipe setback capacity Maximum c o m b i n e d r a t e d static rotary and rated setback capacity API specification and edition u n d e r which the structure was designed and manufactured.

T h e manufacturer o f structures that satisfy API Standard 4F must also furnish the purchaser with one set o f instructions that covers o p e r a t i o n a l features, block reeving d i a g r a m , a n d l u b r i c a t i o n p o i n t s for each d r i l l i n g or well s e r v i c i n g structure. Instructions should include the raising and lowering o f the mast and a facsimile o f the API nameplate.

Definitions and Abbreviations Definitions T h e following terms are c o m m o n l y used in discussing derricks and masts:

Crown block assembly: T h e stationary sheave or block assembly installed at the top o f a d e r r i c k or mast.

Derrick: A s e m i p e r m a n e n t structure o f square or rectangular cross-section having m e m b e r s that are latticed or trussed on all four sides. This unit must be assembled in the vertical or o p e r a t i o n position, as it includes no erection mechanism. It may or may not be guyed. Design load: T h e force or c o m b i n a t i o n o f forces that a structure is designed to withstand without exceeding the allowable stress in any member. Dynamic loading: T h e loading i m p o s e d u p o n a structure as a result o f m o t i o n as o p p o s e d to static loading. Dynamic stress: The varying or fluctuating stress occurring in a structural m e m b e r as a result o f dynamic loading. Erection load: T h e load p r o d u c e d in the mast and its supporting structure during the raising and lowering o p e r a t i o n .

Derricks and Portable Masts

501

Guy line: A wire rope with one e n d attached to the derrick or mast assembly a n d the other e n d attached to a suitable anchor.

Guying pattern: A plane view showing the manufacturer's r e c o m m e n d e d loca-tions and distance to the anchors with respect to the wellhead.

Height of derrick and mast without guy lines: T h e m i n i m u m clear vertical distance f r o m the top of the w o r k i n g f l o o r to the b o t t o m o f the c r o w n block s u p p o r t beams. Height of mast with guy lines: The m i n i m u m vertical distance from the g r o u n d to the bottom of the crown block support beams. Impact loading: The loading resulting from sudden changes in the motion state of rig components. Mast: A s t r u c t u r a l tower c o m p r i s i n g o n e or more sections assembled in a horizontal position near the g r o u n d and then raised to the operating position. If the u n i t contains two or more sections, it may be telescoped or unfolded d u r i n g the erection. Mast setup distance: The distance from the centerline of the well to a designated point on the mast structure defined by a manufacturer to assist in the setup of the rig. Maximum rated static hook load: T h e sum of the weight applied at the hook a n d the traveling e q u i p m e n t for the designated location of the dead line anchor a n d the specified n u m b e r of drilling lines without any pipe setback, sucker rod, or wind loadings. Pipe lean: The angle between the vertical and a typical stand of pipe with the setback. Racking platform: A platform located at a distance above the working floor for laterally s u p p o r t i n g the u p p e r end of racked pipe. Rated static rotary load: The maximum weight being supported by the rotary table support beams. Rated setback load: T h e m a x i m u m weight of tubular goods that the substructure can withstand in the setback area. Rod board: A platform located at a distance above the working floor for supporting rods. Static hook load: see Maximum Rated Static Hook Load.

Abbreviations The following standard abbreviations are used throughout this section. ABS--American Bureau of Shipping A I S C - A m e r i c a n Institute of Steel C o n s t r u c t i o n AISI--American Iron a n d Steel Institute A N S I - A m e r i c a n National Standard Institute API--American Petroleum Institute ASA--American Standards Association ASTM--American Society for Testing and Materials AWS--American Welding Society IADC--International Association of Drilling Contractors SAE--Society of Automotive Engineers USAS--United States of America Standard (ANSI) R P - R e c o m m e n d e d Practice

Standard Derricks A standard derrick is a structure of square cross-section that dimensionally agrees with a derrick size shown in Table 4-1 with dimensions as designated in Figure 4-1.

¢jx O

Table 4-1 Derrick Sizes and General Dimensions [2]

i

2

Derrick Size No.

Height A ft in.

I0 11 12 16 18 18A 19 20 25

80 87 94 122 136 136 140 147 189

0 0 0 0 0 0 0 0 0

3 .. Nominal Base Square B ft in. 20 20 24 24 26 30 30 30 37

0 0 0 0 0 0 0 0 6

4 Drawworks Window Opening C ft in. 7 7 7 7 7 7 7 7 7

6 6 6 6 6 6 6 6 6

Tolerances: A, ± 6 in.; B. ± 5 in.; C, + 3 ft.. 6 in., D, _+ 2 in.; E. :l: 6 in.

5 V Window Opening C ft in. 23 23 23 23 23 23 26 26 26

8 8 8 8 8 8 6 6 6

o~

6 Opening D ft in. 5 5 5 5 5 5 7 6 7

6 6 6 6 6 6 6 6 6

7 Gin Pole Clearance E ft in. 8 8 8 8 12 12 17 17 17

0 0 0 0 0 0 0 0 0

Derricks and Portable Masts

A

503

+

L F--

A ~ The vertical distance from the top o f the base plate to the bottom of the crown block support beam. B ~ The distance between heel to heel of adjacent legs at the top of the base plate. C m The window opening measured ]n the clear and parallel to the center line of the derrick s~de from top of base plate. D ~ The smallest clear dimension at the top of the derrick that would restrict passage of crown block. E ~ The clearance between the horizontal header of the gin pole and the top of the crown support beam.

Figure 4-1. Derrick dimensions [2]. Derrick Window T h e d e r r i c k window a r r a n g e m e n t types A, C, D, a n d E, shown in Figure 4-2, shall be interchangeable. T h e sizes and general d i m e n s i o n s o f the V window o p e n i n g a n d drawworks window o p e n i n g are given in Tables 4-1 a n d 4-2.

Foundation Bolt Settings F o u n d a t i o n bolt sizes and p a t t e r n s are shown in Figure 4-3. M i n i m u m bolt sizes are used a n d should be i n c r e a s e d if stresses dictate larger diameter. T h e (text continued on page 506)

504

Drilling and Well Completions

V-Window TYPE A

Drowworks Window TYPE C !

|

! Drowworks Window TYPE D

Lodder Window TYPE E

Figure 4-2. Derrick windows [2].

Table 4-2 Conversion Values (For 0-50 Ft. Height) [2]

Wind VelociW Pressure P Lb./Sq. Ft. 10 15 20 25 30 35 40 45 50 55

Vk Knots 49 60 69 77 84 91 97 103 109 114

Wind Velocity Miles P e r Hour 56 69 79 89 97 105 112 119 125 131

Derricks a n d Portable Masts

"--~d' -+ 118" Y Nominal Base Square

m

4"

0" -+ 118"

_L

Two I" or I-I/4" bolts at each corner

"~ 4"-,

I - 3 / 8 " holes in base plate 8 0 - , 8 7 - , 9 4 - , 122-, and 136-ft. Derricks

,~,,

Nominal Bose Square Four 1-12" bolts at each corner

~

0"-* 118"

15,,t i/se~ --(

~ 0 "+ i/8"

±

~

I-3/4"holes in base plate

*-I1

1 4 0 - f t and 147-ft. Derricks

---~0" -* I/ 8~1 Nominal Base Square

,

Four 2" bolts at each corner II

2 - 3 / 8 Holes in base plate

15"± 118"

T,;,,:

" ~ 15l-+1/8~4.

189-ft Derrick

Figure 4-3. Foundationbolt patternfor derrick leg [2]

1/8"

505

506

Drilling and Well Completions

(text continued from page 503)

m a x i m u m reaction (uplift, compression, and shear) produced by the standard derrick loading foundation bolt size and setting plan should be furnished to the original user.

Load Capacities All derricks and masts will fail u n d e r an excessively large load. Thus API makes it a practice to provide standard ratings for derricks and masts that meet its specifications. The m e t h o d for specifying standard ratings has changed over the years; therefore, old structures may fail u n d e r one rating scheme and new structures may fail u n d e r another. API Standard 4A (superseded by Standard 4F) provides rating of derrick capacities in terms of m a x i m u m safe load. This is simply the load capacity of a single leg multiplied by four. It does not account for pipe setback, wind loads, the n u m b e r of lines between the crown block and the traveling block, the location of the dead line, or vibratory and impact loads. Thus, it is recomm e n d e d that the m a x i m u m safe static load of derricks designed u n d e r Standard 4A exceed the derrick load as follows: Derrick load* = 1.5(W h + W c + W t + 4FL)

(4-1)

where W h = weight of the traveling block plus the weight of the drillstring suspended in the hole, corrected for buoyancy effects W = weight of the crown block W~ = weight of tools suspended in the derrick F L = extra leg load produced by the placement of the dead and fast lines In general, F L = W i n if the d e a d l i n e is attached to o n e of the derrick legs, and F L = W J 2 n if the deadline is attached between two derrick legs. n is the n u m b e r of lines between the crown block and traveling block. The formula for F L assumes that no single leg shares the deadline and fastline loads. The value of 1.5 is a safety factor to accommodate impact and vibration loads. Equation 4-1 does not account for wind and setback loads, thus, it may provide too low an estimate of the derrick load in extreme cases. API Standard 4D (also superseded by Standard 4F) provides rating of portable masts as follows: For each mast, the manufacturer shall designate a maximum rated static hook load for each of the designated line reevings to the traveling block. Each load shall be the maximum static load applied at the hook, for the designated location of deadline anchor and in the absence of any pipe-setback, sucker-rod, or wind loadings. The rated static hook load includes the weight of the traveling block and hook. The angle of mast lean and the specified m i n i m u m load guy line pattern shall be considered for guyed masts. U n d e r the rigging conditions given on the nameplate, and in the absence of setback or wind loads, the static hook load u n d e r which failure may occur in masts c o n f o r m i n g to this specification can be given as only approximately twice the m a x i m u m rated static hook load capacity. *This is an API Standard 4A rating capacity and should not be confused with the actual derrick load that will be discussed in the section titled "Derricks and Portable Masts."

Derricks and Portable Masts

507

The manufacturer shall establish the reduced rated static hook loads for the same conditions under which the maximum rated static hook loads apply, but with the addition o f the pipe-setback and sucker-rod loadings. The reduced rated static hook loads shall be expressed as percentages o f the maximum rated static hook loads. Thus, the portable mast ratings in Standard 4D include a safety factor o f 2 to allow for wind and impact loads, and require the manufacturer to specify further capacity reductions due to setback. The policy o f Standard 4D, that the manufacturer specify the structure load capacity for various loading c o n f i g u r a t i o n s , has been applied in detail in Standards 4E (superseded by Standard 4F) and 4F. Standard 4F calls for detailed capacity ratings that allow the user to look up the rating for a specific loading configuration. These required ratings are as follows.

Standard Ratings Each structure shall be rated for the following applicable loading conditions. The structures shall be d e s i g n e d to meet or e x c e e d these c o n d i t i o n s in accordance with the applicable specifications set forth herein. The following ratings do not include any allowance for impact. Acceleration, impact, setback, and wind loads will reduce the rated static hook load capacity.

Derrick--Stationary Base 1. Maximum rated static hook load for a specified n u m b e r o f lines to the traveling block. 2. Maximum rated wind velocity (knots) without pipe setback. 3. Maximum rated wind velocity (knots) with full pipe setback. 4. Maximum n u m b e r o f stands and size o f pipe in full setback. 5. Maximum rated gin pole capacity. 6. Rated static hook load for wind velocities varying from zero to maximum rated wind velocity with full rated setback and with maximum n u m b e r o f lines to the traveling block.

Mast with Guy Lines 1. Maximum strung to 2. Maximum 3. Maximum 4. Maximum

rated static hook load capacity for a specified number o f lines the traveling block and the manufacturer's specified guying. rated wind velocity (knots) without pipe setback. rated wind velocity (knots) with full pipe setback. n u m b e r o f stands and size o f pipe in full setback.

Mast without Guy Lines 1. Maximum rated static hook load for a specified number o f lines to the traveling block. 2. Maximum rated wind velocity (knots) without pipe setback. 3. Maximum rated wind velocity (knots) with full pipe setback. 4. Maximum n u m b e r o f stands and size o f pipe in full setback. 5. Rated static hook load for wind velocities varying from zero to maximum rated wind velocity with full rated setback and with maximum number o f lines to the traveling block.

508

Drilling and Well C o m p l e t i o n s

Mast and Derricks under Dynamic Conditions 1. M a x i m u m r a t e d static h o o k l o a d for a specified n u m b e r o f lines to the

traveling block. 2. H o o k load, wind load, vessel motions, and pipe setback in combination with each o t h e r for the following: a. O p e r a t i n g with partial setback. b. Running casing. c. Waiting on weather. d. Survival. e. Transit.

Substructures 1. 2. 3. 4.

Maximum Maximum Maximum Maximum

rated rated rated rated

static h o o k load, if applicable. p i p e setback load. static l o a d on rotary table beams. c o m b i n e d l o a d o f setback and rotary table beams.

Substructure under Dynamic Conditions 1. 2. 3. 4. 5.

Maximum Maximum Maximum Maximum All ratings

rated rated rated rated in the

static h o o k load. p i p e setback load. l o a d on rotary table beams. c o m b i n e d l o a d o f setback and rotary table beams. section tided "Mast and Derricks u n d e r Dynamic Conditions."

Design Loadings Derricks and masts are d e s i g n e d to withstand some m i n i m u m loads or set o f l o a d s w i t h o u t f a i l u r e . Each s t r u c t u r e shall be d e s i g n e d for t h e f o l l o w i n g applicable loading conditions. T h e structure shall be designed to meet or exceed these conditions in accordance with the applicable specifications set forth herein.

Derrick--Stationary Base 1. O p e r a t i n g l o a d s (no wind loads) c o m p o s e d o f t h e following l o a d s in combination: a. Maximum r a t e d static hook l o a d for each applicable string up condition. b. Dead l o a d o f d e r r i c k assembly. 2. W i n d l o a d w i t h o u t p i p e s e t b a c k c o m p o s e d o f t h e following l o a d s in combination: a. W i n d l o a d on d e r r i c k , d e r i v e d f r o m m a x i m u m r a t e d wind velocity without setback ( m i n i m u m wind velocity for API standard d e r r i c k sizes 10 t h r o u g h 18A is 93 knots, and for sizes 19 t h r o u g h 25 is 107 knots). b. Dead l o a d o f d e r r i c k assembly. 3. W i n d l o a d with r a t e d p i p e setback c o m p o s e d o f the following loads in combination: a. W i n d l o a d on d e r r i c k derived from m a x i m u m r a t e d wind velocity with setback o f not less than 93 knots. b. Dead l o a d o f d e r r i c k assembly.

Derricks and Portable Masts

509

c. Horizontal load at racking platform, derived from m a x i m u m r a t e d wind velocity with setback o f not less than 93 k n o t s acting on full p i p e setback. d. Horizontal l o a d at racking platform from pipe lean.

Mast with Guy Lines 1. O p e r a t i n g l o a d s (no wind l o a d ) c o m p o s e d o f the following l o a d s in combination: a. Maximum r a t e d static hook l o a d for each applicable string up condition. b. Dead l o a d o f mast assembly. c. Horizontal and vertical c o m p o n e n t s o f guy line loading. 2. W i n d loads c o m p o s e d o f the following loads in combination: a. W i n d l o a d on mast, derived from a m a x i m u m r a t e d wind velocity with setback o f not less than 60 knots. b. Dead l o a d o f mast assembly. c. Horizontal l o a d i n g at racking board, derived from a m a x i m u m r a t e d wind velocity with setback o f not less than 60 knots, acting on full pipe setback. d. Horizontal and vertical c o m p o n e n t s o f guy line loading. e. Horizontal and vertical l o a d i n g at r o d board, derived from a m a x i m u m r a t e d wind velocity with setback o f not less than 60 knots, acting on rods in conjunction with d e a d weight o f rods. 3. W i n d loads c o m p o s e d o f the following loads in combination: a. W i n d l o a d on mast, derived from a m a x i m u m r a t e d wind velocity with setback o f not less than 60 knots. b. Dead l o a d o f mast assembly. c. Horizontal l o a d i n g at racking platform, derived from a m a x i m u m r a t e d wind velocity with setback o f not less than 60 knots, acting on full p i p e setback. d. Horizontal and vertical c o m p o n e n t s o f guy line loading. 4. W i n d loads c o m p o s e d o f the following loads in combination: a. W i n d l o a d on mast derived from a maximum rated wind velocity without setback o f not less than 60 knots. b. Dead l o a d o f mast assembly. c. Horizontal and vertical c o m p o n e n t s o f guy line loading. 5. E r e c t i o n l o a d s (zero wind l o a d ) c o m p o s e d o f the following l o a d s in combination: a. Forces a p p l i e d to mast and s u p p o r t i n g structure created by raising or lowering mast. b. Dead l o a d o f mast assembly. 6. Guy line l o a d i n g (assume g r o u n d a n c h o r p a t t e r n consistent with manufacturer's guying d i a g r a m shown on the nameplate). a. Maximum horizontal and vertical reactions from conditions o f l o a d i n g a p p l i e d to guy line. b. Dead l o a d o f guy line. c. Initial tension in guy line specified by mast manufacturer.

Mast without Guy Lines 1. O p e r a t i n g loads c o m p o s e d o f the following loads in combination: a. Maximum rated static hook l o a d for each applicable string up condition. b. Dead l o a d o f mast assembly.

510

Drilling and Well C o m p l e t i o n s

2. W i n d l o a d w i t h o u t p i p e s e t b a c k c o m p o s e d o f t h e following l o a d s in combination: a. W i n d loading on mast, derived from a m a x i m u m r a t e d wind velocity without setback o f not less than 93 knots. b. Dead load o f mast assembly. 3. Wind load with pipe setback composed o f the following loads in combination: a. W i n d loading on mast, derived from a m a x i m u m r a t e d wind velocity with setback o f not less than 70 knots. b. Dead load o f mast assembly. c. Horizontal load at racking platform derived from a maximum r a t e d wind velocity with setback o f not less than 70 knots acting on pipe setback. d. Horizontal load at racking platform from pipe lean. 4. Mast e r e c t i o n loads (zero wind load) c o m p o s e d o f the following loads in combination: a. Forces a p p l i e d to mast and s u p p o r t i n g structure created by raising or lowering mast. b. Dead load o f mast assembly. 5. Mast handling loads (mast assembly s u p p o r t e d at its e x t r e m e ends).

Derricks and Mast under Dynamic Conditions All conditions listed in the section titled " L o a d Capacities," subsection titled "Mast and Derricks u n d e r Dynamic Conditions," are to be specified by the user. Forces resulting from wind and vessel m o t i o n are to be calculated in accordance with t h e f o r m u l a s p r e s e n t e d in t h e s e c t i o n t i t l e d " D e s i g n S p e c i f i c a t i o n s , " paragraphs titled "Wind," "Dynamic Loading (Induced by Floating Hull Motion)."

Substructures X. Erection o f mast, if applicable. 2. Moving or skidding, if applicable. 3. Substructure shall be d e s i g n e d for the following conditions: a. Maximum r a t e d static rotary load. b. Maximum r a t e d setback load. c. Maximum r a t e d static h o o k load (where applicable). d. Maximum c o m b i n e d r a t e d static h o o k and r a t e d setback loads (where applicable). e. Maximum c o m b i n e d r a t e d static rotary and r a t e d setback loads. f. Wind loads resulting from maximum r a t e d wind velocity acting from any direction on all e x p o s e d elements. W i n d pressures and resultant forces are to be calculated in accordance with the equations and tables in the section titled "Design Specifications," p a r a g r a p h titled "Wind." W h e n a substructure is utilized to react guy lines to the mast, these reactions from the guy lines must be d e s i g n e d into the substructure. g. Dead load o f all c o m p o n e n t s in c o m b i n a t i o n with all o f the above.

Substructure under Dynamic Conditions All conditions listed in the section titled "Load Capacities," p a r a g r a p h titled "Structure u n d e r Dynamic Conditions," are to be specified by the user. Forces resulting from wind and vessel m o t i o n are to be calculated in accordance with f o r m u l a s from t h e s e c t i o n titled "Design S p e c i f i c a t i o n s , " p a r a g r a p h s titled "Wind" and "Dynamic L o a d i n g ( I n d u c e d by Floating Hull Motion)."

Derricks and Portable Masts

511

Design Specifications In addition to withstanding some minimum load or loads (sections titled "Load Capacities" and "Design Specifications"), derricks and masts that satisfy API standards must also satisfy certain requirements regarding materials, allowable stresses, wind, dynamic loading, earthquakes and extremes of temperature.

Materials The unrestricted material acceptance is not intended since physical properties are not the sole measure o f acceptability. Metallurgical properties, which affect fabrication and serviceability, must also be considered.

Steel. Steel shall conform to one o f the applicable ASTM specifications referred to by applicable AISC specifications. Other steels not covered by these specifications may be used provided that the chemical and physical properties conform to the limits guaranteed by the steel manufacturer. Structural steel shapes having specified minimum yield less than 33,000 psi shall not be used. Certified mill test report or certified reports o f tests made in accordance with ASTM A6 and the governing specification shall constitute evidence o f conformity with one o f the specifications listed.

Bolts. Bolts shall c o n f o r m to one o f the applicable SAE, ASTM, or AISC specifications. O t h e r bolts not covered by these specifications may be used provided the chemical, mechanical, and physical properties conform to the limits guaranteed by the bolt manufacturer. Certified reports shall constitute sufficient evidence o f conformity with the specification. Bolts o f different mechanical properties and o f the same diameter shall not be mixed on the same drilling or servicing structure to avoid the possibility o f bolts o f relatively low strength being used where bolts o f relatively high strength are required. Welding Electrodes. Welding electrodes shall conform to applicable AWS and ASTM specifications or o t h e r governing codes. Newly developed welding processes shall use welding electrodes conforming to applicable AWS or other governing publications. Certified reports shall constitute sufficient evidence o f conformity with the specifications. Wire Rope. Wire rope for guy lines or erection purposes shall conform to API Specification 9A: "Specification for Wire Rope."

Nonferrous Materials. N o n f e r r o u s materials must c o n f o r m to a p p r o p r i a t e governing codes. Certified r e p o r t s shall constitute sufficient evidence o f conformity with such codes.

Allowable Stresses AISC specifications for the design fabrication and erection o f structural steel for buildings shall govern the design o f these steel structures (for AISC specifications, see the current edition o f Steel Construction Manual o f the American Institute o f Steel Construction). Only Part I o f the AISC manual, the portion commonly referred to as elastic design, shall be used in determining allowable unit Stresses; use o f Part II, which is commonly referred to as plastic

512

Drilling and Well C o m p l e t i o n s

design, is not allowed. T h e AISC shall be the final a u t h o r i t y for d e t e r m i n a t i o n o f allowable unit stresses, except that current practice and experience do not dictate the n e e d to follow the AISC for m e m b e r s and connections subject to r e p e a t e d variations o f stress, and for the c o n s i d e r a t i o n o f s e c o n d a r y stresses. For p u r p o s e s o f this specification, stresses in the individual m e m b e r s o f a latticed or trussed structure resulting from elastic d e f o r m a t i o n and rigidity o f j o i n t s are d e f i n e d as secondary stresses. These secondary stresses may be taken to be the difference between stresses from an analysis assuming fully rigid joints, with loads a p p l i e d only at the joints, and stresses from a similar analysis with p i n n e d j o i n t s . Stresses a r i s i n g f r o m e c c e n t r i c j o i n t c o n n e c t i o n s , or f r o m transverse l o a d i n g o f m e m b e r s between joints, or from a p p l i e d moments, must be considered p r i m a r y stresses. Allowable unit stresses may be increased 20% from the basic allowable stress when secondary stresses are computed and a d d e d to the primary stresses in individual members. However, primary stresses shall not exceed the basic allowable stresses.

Wind and Dynamic Stresses (Induced by Floating Hull Motion). Allowable unit stresses may be i n c r e a s e d o n e - t h i r d over basic allowable stresses when p r o d u c e d by wind or dynamic loading, acting alone, or in c o m b i n a t i o n with the design dead load and live loads, p r o v i d e d the required section c o m p u t e d on this basis is not less than required for the design dead and live loads and impact (if any), c o m p u t e d without the one-third increase. Wire Rope. T h e size and t y p e o f wire r o p e shall be as s p e c i f i e d in A P I Specification 9A and by API RP 9B (see section titled "Hoisting System"). 1. A mast raised and lowered by wire r o p e shall have the wire r o p e sized to have a n o m i n a l strength o f at least 2~ times the m a x i m u m load on the line d u r i n g erection. 2. A mast or d e r r i c k guyed by means o f a wire r o p e shall have the wire r o p e sized so as to have a n o m i n a l strength o f at least 2 ½ times the m a x i m u m guy load resulting from a l o a d i n g condition.

Crown Shafting. Crown shafts, including fastline and deadline sheave s u p p o r t shafts, shall be d e s i g n e d to AISC specifications except that the safety factor in b e n d i n g shall be a m i n i m u m o f 1.67 to yield. Wire r o p e sheaves and bearings shall be d e s i g n e d in a c c o r d a n c e with "API S p e c i f i c a t i o n 8A: D r i l l i n g and P r o d u c t i o n Hoisting Equipment."

Wind W i n d forces shall be a p p l i e d to the entire structure. T h e wind directions that result in the highest stresses for each c o m p o n e n t o f t h e structure must be d e t e r m i n e d and considered. W i n d forces for the various wind speeds shall be calculated according to F = (P) (A)

(4-2)

where F = Force in lb P = Pressure in l b / f t 2 A = Total area, in ft2, projected on a plane, p e r p e n d i c u l a r to the direction o f the wind, except that the e x p o s e d areas o f two opposite sides o f the mast or d e r r i c k shall be used.

D e r r i c k s a n d P o r t a b l e Masts

513

W h e n p i p e o r t u b i n g is r a c k e d in m o r e t h a n o n e area, t h e m i n i m u m a r e a o f setback shall b e n o less t h a n 120% o f t h e a r e a o n o n e side; w h e n r o d s are r a c k e d o n m o r e t h a n o n e area, t h e m i n i m u m a r e a o f r o d s shall b e n o less t h a n 150% o f t h e a r e a o f o n e s i d e to a c c o u n t f o r t h e e f f e c t o f w i n d o n t h e l e e w a r d a r e a ( F i g u r e 4-4). T h e p r e s s u r e d u e to w i n d is P = 0.00338 (Vk2)(Ch)(C)

(4-3)

where P = pressure in lb/ft 2 V k = w i n d v e l o c i t y in k n o t s Ch = height coefficient

Height (ft)

C.

O- 50 50-100

1.0 1.1

100-150

1.2

150-200 200-250

1.3 1.4

)

(2

\ .-2-- i \ O L

;1\

\ C Oxv,,. C

NOTE: In calculating the value of A, If R is greater than 1.5a, use R. If not, use 1.5a. IfT is greater than 1.2b, use T. If not, use 1.2b.

Figure 4-4. Diagram of projected area [9].

514

Drilling and Well C o m p l e t i o n s

Height is the vertical distance from g r o u n d o r water surface to the center o f area. The shape coefficient C s for a d e r r i c k is assumed as 1.25. C s a n d C h were obtained from ABS, "Rules for Building and Classing Offshore Drilling Units, 1968."

Dynamic Loading (Induced by Floating Hull Motion) Forces shall be calculated according to the following [6]:

¢

]¢.,

FP = t ~--~-_7. 2 jt.-~-~- )t ]-g6 j

FP

=

Wsin"

-

¢ w )¢ w sin 0 t ---~7.2 ~t.-7-~-r~)t--76- J

W2~2H FH = W + - Th2g

(4-4)

(4-5)

(4-6)

where W = d e a d weight o f the point u n d e r c o n s i d e r a t i o n L~ = distance from pitch axis to the gravity center o f the point u n d e r c o n s i d e r a t i o n in feet L = distance f r o m roll axis to the gravity center o f the p o i n t u n d e r c o n s i d e r a t i o n in feet H = heave (total displacement) Tp = p e r i o d o f pitch in seconds T r = p e r i o d o f roll in seconds T h = p e r i o d o f heave in seconds = angle o f pitch in degrees 0 = angle o f roll in degrees g = gravity in 32.2 f t / s / s Unless specified, the force d u e to c o m b i n e d roll, pitch, a n d heave shall be c o n s i d e r e d to be the largest o f the following: 1. Force d u e to roll plus force d u e to heave. 2. Force due to pitch plus force due to heave. 3. Force due to roll and pitch d e t e r m i n e d as the square root o f the sum o f squares plus force due to heave. A n g l e o f roll o r pitch is the angle to one side from vertical. The p e r i o d is for a complete cycle.

Earthquake Earthquake is a special l o a d i n g c o n d i t i o n to be addressed when requested by the user. T h e user is responsible for furnishing the design criteria that includes design loading, design analysis m e t h o d , and allowable response. T h e design criteria for land units may be in accordance with local b u i l d i n g codes using equivalent static design methods. For f i x e d o f f s h o r e p l a t f o r m units, the d e s i g n m e t h o d s h o u l d follow the strength level analysis guidelines in API RP 2A. T h e drilling and well servicing units should be able to resist the deck movement, i.e., the response o f the deck

Derricks and Portable Masts

515

to the g r o u n d motion prescribed for the design o f the offshore platform. The allowable stresses for the c o m b i n a t i o n o f earthquake, gravity and o p e r a t i o n a l loading should be limited to those basic allowables with the one-third increase as specified in AISC Part I. The c o m p u t e d stresses should include the p r i m a r y and the secondary stress c o m p o n e n t s .

Extreme Temperature Because o f the effect o f low t e m p e r a t u r e s on structural steel, it will be no use to change (decrease) the allowable unit stresses m e n t i o n e d in the p r e c e d i n g p a r a g r a p h s t i t l e d "Allowable Stresses." Low t e m p e r a t u r e p h e n o m e n a in steel are well established in principle. Structures to be used u n d e r extreme conditions should use special materials that have been, and are being, developed for this application.

Miscellaneous Structural Steels. Structures shall c o n f o r m to sections o f the AISC "Specifications for the Design, Fabrication and Erection o f Structural Steel Buildings."

Castings. All castings shall be thoroughly cleaned, and all cored holes shall be drifted to ensure free passage o f p r o p e r size bolt. Protection. Forged parts, rolled structural steel shapes and plates, and castings shall be cleaned, p r i m e d , and painted with a g o o d commercial paint or o t h e r specified coating before shipment. Machined surfaces shall be protected with a suitable lubricant or c o m p o u n d .

Socketing. Socketing o f raising, erecting, or telescoping mast wire ropes shall be p e r f o r m e d in accordance with practices outlined by API RP 9B.

Recommended Practice for Maintenance and Use of Drilling and Well Servicing Structures These general r e c o m m e n d a t i o n s , if followed, should result in longer satisfactory service from the equipment. These r e c o m m e n d a t i o n s should in every case be considered as s u p p l e m e n t a l to, and not as a substitute for, the manufacturer's instructions. The safe o p e r a t i o n o f the drilling and well servicing structure and the success o f the drilling o p e r a t i o n d e p e n d on whether the foundation is adequate for the load imposed. The design load for foundation should be the sum o f the weight o f the drilling or well servicing structure, the weight o f the m a c h i n e r y and e q u i p m e n t on it, the m a x i m u m hook load o f the structure, and the m a x i m u m setback load. Consultation with the m a n u f a c t u r e r for approval o f materials and m e t h o d s is required before p r o c e e d i n g with repairs. Any bent or otherwise d a m a g e d m e m b e r should be repaired or replaced. Any d a m a g e d compression m e m b e r should be r e p l a c e d r a t h e r than r e p a i r e d by straightening. Drilling and well servicing structures use high-strength steels that require specific welding electrodes and welding techniques. Fixtures and accessories are preferably a t t a c h e d to a structure by suitable clamps. Do not drill or b u r n holes in any m e m b e r s or p e r f o r m any welding without o b t a i n i n g approval o f the manufacturer.

516

Drilling and Well C o m p l e t i o n s

Wire line slings or tag lines should have suitable fittings to prevent the r o p e from being bent over sharp edges and damaged. Loads due to impact, a c c e l e r a t i o n , and d e c e l e r a t i o n may be i n d i c a t e d by fluctuation of the weight indicator readings and the o p e r a t o r should keep the indicator readings within the required hook load capacity. In the erecting and lowering operation, the slowest practical line speed should be used. Girts, braces, and o t h e r m e m b e r s should not, u n d e r any circumstances, be removed from the d e r r i c k while it is u n d e r load. The drilling and well servicing structure m a n u f a c t u r e r has carefully designed and selected materials for his or her p o r t a b l e mast. The mast should p e r f o r m satisfactorily within the stipulated load capacities and in accordance with the instructions. Every o p e r a t o r should study the instructions and be p r e p a r e d for erecting, lowering, and using the mast. The substructure should be restrained against up-lift, if necessary, by a suitable dead weight or a hold-down anchor. The weight of the hoist and vehicle, where applicable, may be c o n s i d e r e d as part or all of the required anchorage. Each part of a b o l t e d structure is designed to c a r r y its share of the load; therefore, parts o m i t t e d or i m p r o p e r l y placed may contribute to the structure failure. In the erection of b o l t e d structures, the bolts should be tightened only slightly tighter than finger-tight. After the erection of the structure is completed, all bolts should be drawn tight. This p r o c e d u r e permits correct a l i g n m e n t of the structure and results in p r o p e r load distribution.

Sling Line Inspection and Replacement O n e or m o r e of the three principal factors, including wear due to o p e r a t i o n , c o r r o s i o n and incidental damage, may limit the life of a sling. The first may be a function of the times the mast is raised, and the second will be related to time and atmospheric conditions. The third will bear no relation to either, since incidental damage may occur at the first location as well as any other. Charting of sling line r e p l a c e m e n t shows an erratic pattern. Some require r e p l a c e m e n t at a relatively early date and others last several years longer. Early replacements generally show incidental damage, and it is possible that some of the longer lived ones are used b e y o n d the time when they should be replaced. T h e r e is no way of j u d g i n g the r e m a i n i n g strength of a rusty rope; therefore, rusty sling lines should be replaced. Areas adjacent to e n d connections should be e x a m i n e d closely for any evidence of corrosion. It would no doubt be possible to establish a normal sling line life expectancy in terms of the number of locations used, as long as a set n u m b e r of months was not exceeded. However, this would not preclude the necessity for careful inspection to guard against incidental damage. A line with any broken wires should be replaced. A line showing any material reduction of metal area from abrasion should be replaced. A line showing kinking, crushing, or other damage should be replaced. R e p l a c e m e n t of lines b a s e d on n o r m a l life e x p e c t a n c y will p r o v i d e s o m e degree of safety, but it is i m p o r t a n t that such provisions do not cause any degree of laxity in sling line inspection. Sling lines should be well lubricated. The field lubricant should be compatible with the original lubricant, and to this e n d the rope m a n u f a c t u r e r should be consulted. The object of rope lubrication is to reduce internal friction and to prevent corrosion. The following routine checks, as applicable, should be m a d e at a p p r o p r i a t e intervals:

Derricks and Portable Masts

517

1. Inspect welds in erecting m e c h a n i s m for cracks and other signs of deformity. 2. Follow the manufacturer's instructions in checking hydraulic circuits before lowering operation. Make sure of adequate supply of hydraulic fluid. 3. Wire rope, including operating lines, raising lines, and guy lines, should be inspected for kinks, broken wires, or other damage. Make certain that guy lines are not fouled and that other lines are in place in sheave grooves before raising or lowering operation. 4. Check safety latches and guides in telescoping mast for free operation before lowering operation. Keep latches and guides clean and properly lubricated. 5. Check unit for level and check foundation and s u p p o r t s for correct placement before erecting operation. 6. Check lubrication of crown sheaves. 7. Check lubrication and condition of bearings in all sheaves, sprockets, etc. 8. Check folding ladders for free operation before lowering operation. 9. During drilling operations, it is advisable to make scheduled inspections of all bolted connections to ensure that they are tight. 10. The visual field inspection of derrick or mast and substructure procedure is r e c o m m e n d e d for use by operating personnel (or a designated representative) to the extent that its use satisfies conditions for which an inspection is intended. A sample report form for this inspection procedure can be found in API Standard 4F. Forms are also available from International Association of Drilling Contractors (IADC). Splicing locks should be checked frequently for locking position or tightness, preferably on each tour during drilling operations. To develop its rated load capacity, the axis of the structure must be in alignment throughout its length. It is i m p o r t a n t that any splice m e c h a n i s m or locks be maintained in such condition as to ensure structure alignment.

Guying for Portable Masts with Guy Lines This recommendation is applicable for most conditions encountered in the use of this type mast. There will be exceptions where location clearance, ground conditions, or other unusual circumstances require special considerations. Figure 4-5 shows a r e c o m m e n d e d guying pattern that may be used u n d e r general conditions in the absence of an authorized API manufacturer's recommendations. Guy lines should be maintained in g o o d condition, free from rust, corrosion, frays, and kinks. Old sand line is not r e c o m m e n d e d for guy lines. All chains, boomers, clamps, and tensioning devices used in the guy lines shall satisfy the mast m a n u f a c t u r e r ' s r e c o m m e n d a t i o n s . In the absence o f mast manufacturer's recommendations, the following minimum breaking strengths should be maintained: load guy l i n e s - 1 8 tons; external guy l i n e s - 1 2 tons; racking board guy lines-10 tons.

Guy Line Anchors for Portable Masts with Guy Lines Guy line anchors including e x p a n d i n g anchors, concrete deadmen, or any other approved techniques are acceptable. The soil condition may determine the most applicable type. R e c o m m e n d a t i o n s for a n c h o r design and testing are as follows:

518

Drilling and Well Completions

:

T

L

I~

Z

T

_u_

"r

y

T

.d

"1"

A = Four crown to ground guys. Minimum guyline size recommended as 5/8" unless otherwise specified by mast manufacturer. Tensioning may be judged by catenary (sag). 6" catenary (approximately 1,000 Ib tension) recommended on initial tensioning. B = Two racking board to board guys. Minimum guyline size recommended is 9/16" unless otherwise specified by mast manufacturer. 12"-18" catenary (approximately 500 lb tension) recommended on initial tensioning. C = Two additional racking board guys to ground. Recommended when winds are in excess of design magnitude (name plate rating) or when pipe set back exceeds rated racking capacity or when weather protection is used on board. Minimum guyline size recommended is 9/16" unless otherwise specified by mast manufacturer. 6"-12" catenary (approximately 1,000 Ib tension) recommended on initial tensioning. D = Two or four intermediate mast to ground guys. Recommended at option of mast manufacturer only. Minimum guyline size recommended is 5/8" unless otherwise specified by mast manufacturer. 6"-12" catenary (approximately 1,000 lb tension) recommended on initial tensioning. CAUTION: WHEN THE TWO "A" LINES ON THE DRAWWORKS SIDE OF THE MAST ARE USED AS LOAD GUYS, THE MINIMUM LINE SIZE SHALL BE 3/4" IPS 6 x 31 CLASS OR BETTER, AND THE "Z" DIMENSION SHALL NOT BE LESS THAN 60'. F i g u r e 4-5. R e c o m m e n d e d guying p a t t e r n - - g e n e r a l conditions [3].

Derricks and Portable Masts

519

1. All guy line anchors should have a m i n i m u m breaking or pull-out strength at least equal to two times the m a x i m u m total calculated anchor l o a d in the direction o f the resultant load, and in the absence o f manufacturer's r e c o m m e n d a t i o n s , values in Table 4-3 are r e c o m m e n d e d . 2. Representative pull tests for the area, size, and type o f anchor involved and made by recognized testing methods should be made and recorded. Records should be m a i n t a i n e d by the installer for t e m p o r a r y anchors a n d by the lease owner for p e r m a n e n t anchors. P e r m a n e n t anchors should be visually inspected p r i o r to use. If damage or d e t e r i o r a t i o n is apparent, the a n c h o r should be tested. 3. Metal c o m p o n e n t s o f anchors should be galvanized or otherwise protected against corrosion. Sucker rods should not be used in anchor construction. A n c h o r location should be marked with a stake if projections a b o v e g r o u n d are subject to b e n d i n g or o t h e r abuse. 4. A n c h o r location should avoid old pit or o t h e r d i s t u r b e d areas.

Mast Foundation for Portable Masts with Guy Lines F o u n d a t i o n s must c o n s i d e r g r o u n d c o n d i t i o n s , l o c a t i o n p r e p a r a t i o n , a n d supplemental footing as required to provide a stable base for mast erection and to s u p p o r t the mast d u r i n g the most e x t r e m e l o a d i n g encountered. A recomm e n d e d location p r e p a r a t i o n to p r o v i d e g r o u n d conditions for safe o p e r a t i o n s is shown in Figure 4-6.

Supplemental Footing S u p p l e m e n t a l footing must be p r o v i d e d to distribute the c o n c e n t r a t e d loads from the mast and mast mount to the ground. T h e manufacturer's load distribution d i a g r a m indicates the m a g n i t u d e and location o f these c o n c e n t r a t e d loads. If the manufacturer's l o a d distribution d i a g r a m is not available, supplemental footing should be p r o v i d e d to carry the m a x i m u m h o o k l o a d encountered, plus the gross weight o f mast and mast mount weight d u r i n g mast erection. T h e area

Table 4-3 Recommended Guyline Anchor Spacing and Loads See Par. C. 16a and Figure C.1 [3] 2 Minimum

Spacing

X or Y Dimension See Fig. A. I, feet 20 25

30 ,o

50 60 70

3

Doubles Mast ' , Anchor Test Angle Anchor from Horiz. Test Load, to Well tons Center Line N.A. N.A. 15.6 71 °

4

5

Singles Mast ' • Anchor Test Angle Anchor from Horiz. Test Load, to Well tons Center Line 3.7 70 °

137 11.0

670 so"

3~ 5.s

9.3 8.4 7.8

54 ° 49" 45 °

2.7 2.7 2.7

J°

6

7 Pole Mast ' Anchor Test Angle Anchor from Horiz. Test Load, to Well tons Center Line 7.0 67 ° -- -

530

,~

,;.

45 = 45" 45 °

3.~

4 5°

45°

80

7.4

45°

5.7

45"

~

90

7.0

45 °

2.7

45 °

--

NOTE: Preferred, X greater than Y. Limits, Y mind not exceed 1.25X and Z re.st be eq~ml t o o r lees ~a~ L s Y. b~d not less than Y. (Fig. C.I)

--

CAUTION: THE ADDITION OF WINDSCREENS OR THE RACKING OF PIPE ABOVE G R O U N D L E V E L CAN S I G N I F I CANTLY INCREASE THE ABOVE ANCHOR REQUIREMENTS.

Drilling and Well Completions

520

9 0 ' ± I0' ''

90' :.'.'.tI0'

"~,~

o

' 0 I

"o

Pumping Unit Second Preference-,,~.1, ~

Jr c

IZ~

:::i-::.:i:!::.:::

-4"1

"o

O~

o-

•Pumping Unit

L

,o,

i_

T "o

_First Preference

-4-1

"o

O~

-- I%"-Dead ma n

Capacity

7 Tons

I

~

---Grade I, 20 m o x - ~ L e v e l ,-~

Load Bearing Area Rig Location Area Load Bearing Area: Compacted sand or gravel requiring picking for removal or better base. Safe bearing capacity desired--Min., 8000 psf, level and drained. Rig Location Area: May grade away from well along centerline II at max. drop of 1:20. Should be level across grades parallel to centerline I. Safe bearing capacity desired--min., 6000 psf. Allow maneuvering entry for drive in or back in. Drainage of entire area required. See Table 4-3. Figure 4-6. Portable mast location preparation [3].

Derricks and Portable Masts

521

and type o f s u p p l e m e n t a l footing must ensure that the safe b e a r i n g capacity o f soils on location is not exceeded.

Precautions and Procedures for Low-Temperature Operations A survey o f 13 drilling contractors o p e r a t i n g 193 drilling rigs in n o r t h e r n C a n a d a and Alaska i n d i c a t e d that t h e r e is a wide r a n g e o f e x p e r i e n c e and o p e r a t i n g practices u n d e r e x t r e m e l y l o w - t e m p e r a t u r e c o n d i t i o n s . A sizable n u m b e r o f p o r t a b l e masts failed in the lowering or raising process in winter. Thus the exposure to low-temperature failures focuses on mast lowering and r a i s i n g o p e r a t i o n s . B a s e d on r e p o r t s , however, this o p e r a t i o n has b e e n a c c o m p l i s h e d successfully in t e m p e r a t u r e s as low as -50°F. W h i l e the risk may be considerably greater because o f the change in physical characteristics o f steel at low t e m p e r a t u r e s , o p e r a t o r s may c a r r y on " n o r m a l " o p e r a t i o n s even at extremely low t e m p e r a t u r e s . This may be a c c o m p l i s h e d by closely c o n t r o l l e d inspection procedures and careful handling and o p e r a t i o n to reduce damage and impact l o a d i n g d u r i n g raising and lowering operations. At present, there seems to be no widely accepted or soundly s u p p o r t e d basis for establishing a critical t e m p e r a t u r e for limiting the use o f these oilfield structures. Experience in the o p e r a t i o n o f trucks and o t h e r heavy e q u i p m e n t e x p o s e d to i m p a c t forces indicates that -40°F may be the t h r e s h o l d o f the t e m p e r a t u r e range, at which the risk o f structural failure may increase rapidly. Precautionary measures should be m o r e rigidly p r a c t i c e d at this point. T h e following r e c o m m e n d e d practices are included for reference: 1. To the extent possible, raising and lowering the mast at the "warmest" time o f the day; use any sunlight or p r e d i c t a b l e a t m o s p h e r i c conditions. Consider the wind velocity factors. 2. Use any practical, available means, such as high-pressure steam t i m b e r bonfires, to warm sections o f the mast. 3. Take up and l o o s e n mast raising lines several times to assure the free movement o f all parts. 4. W a r m up engines and check the p r o p e r functioning o f all m a c h i n e r y to assure that t h e r e will be no m a l f u n c t i o n s that would result in s u d d e n b r a k i n g or j a r r i n g o f the mast. Mast travel, once begun, must be slow, smooth, and continuous. 5. I n s p e c t i o n a n d r e p a i r p r o v i d e d in t h e s e c t i o n t i t l e d " R e c o m m e n d e d Practice for Maintenance and Use o f Drilling and Well Servicing Structures" are extremely critical u n d e r low-temperature conditions. Masts should be m a i n t a i n e d in excellent condition. 6. In m a k i n g field welds, the t e m p e r a t u r e o f s t r u c t u r a l m e m b e r s s h o u l d preferably be above 0°F. In the weld areas, steel should be p r e h e a t e d before welding or cutting operations.

Derrick Efficiency Factor Derrick efficiency factor (DEF) is often used to rate or classify d e r r i c k or mast structural capacity [1,7,8]. T h e derrick efficiency factor is d e f i n e d as a ratio o f actual load to an equivalent load that is four times the force in the derrick leg c a r r y i n g the greatest load. Thus the ratio is Actual load DEF = . . . . (100%) ~qulvment loaa

(4-7)

522

Drilling and Well C o m p l e t i o n s

The derrick efficiency factor can be found for static (dead load) conditions and dynamic conditions. In this section, only the static conditions will be considered.

Example Find the d e r r i c k efficiency factor ( u n d e r static conditions) for a derrick that is capable of lifting a 600,000 lb drill string with a block and tackle that has eight working lines between the crown block and the traveling block. T h e crown block weighs 9,000 lb and the traveling block weighs 4,500 lb. Assume that there are no o t h e r tools h a n g i n g in the derrick. T h e d e a d line is attached at the b o t t o m o f leg A as shown in Figure 4-7. Table 4-4 gives the calculations o f the force in each leg of the d e r r i c k due to the centered load (i.e., 613,500 lb), the hoist-line load (i.e., the fast-line load;

Table 4-4 Example of Derrick Efficiency Factor Calculation [9] Force in Individual Derrick Legs (Ibs) A

Hoist-lineload Centeredload Dead-lineload

B

153,375.00 75,562.50 228,937.50

C

153,375.00

37,781.25 153,375.00

37,381.25 153,375.00

153,375.00

191,156.25

191,156.25

Derrick - ' ' ~ " Leg [~~""

D

~ ]

Dead Line to Block ffLines

0 0 0 0 0 0 0 0

Fost Line

Figure

4-7. Projection of fast-line and deadline locations on rig floor [9].

Hoisting System

523

75, 562.50 lb, divided by 2 since this load is shared by legs C and D) and the dead-line load at leg A (i.e., 75,562.50 lb). The actual load on the derrick is the sum of the bottom row in Table 4 4 . The equivalent load is four times the force in leg A, which is the largest load of all four legs. Thus, DEF =

764,625.00 (100%) 4(228,937.50)

= 83.50%

HOISTING SYSTEM A hoisting system, as shown in Figure 4-8, is composed of the drawworks, traveling block, crown block, extra line storage spool, various clamps, hooks, and wire rope. Normally, a hoisting system has an even n u m b e r of working lines between the traveling block and the crown block. The fast line is spooled onto the drawworks' hoisting drum. The dead line is anchored to the rig f l o o r across from the drawworks. The weight indicator is a load cell incorporated in the dead line anchor.

Ira orage )ol

,.

Drawworks

Dead line anchor

Figure 4-8. Schematic of simplified hoisting system on rotary drilling rig [9].

524

Drilling a n d Well C o m p l e t i o n s

T h e mechanical advantage o f the hoisting system is d e t e r m i n e d by the block a n d tackle a n d the n u m b e r o f working lines between the crown block a n d the traveling block [7]. Thus, for the static c o n d i t i o n (i.e., no friction losses in the sheaves at the blocks), Ff (lb), the force in the fast line to hold the hook load, is Ff =

Wh

(4-8)

J where W h is the weight o f the traveling block plus the weight o f the drill string s u s p e n d e d in the hole, c o r r e c t e d for buoyancy effects in pounds; and j is the n u m b e r o f working lines between the crown block and traveling block. U n d e r these static conditions, Fd (lb), the force in the d e a d line, is Fd -- Wh j

(4-9)

T h e mechanical advantage (ma) u n d e r these static conditions is ma(static) = wh = j Ff

(4-10)

W h e n the hook load is lifted, friction losses in crown block and traveling block sheaves occur. It is normally a s s u m e d that these losses are approximately 2% d e d u c t i o n p e r w o r k i n g line. U n d e r d y n a m i c c o n d i t i o n s , t h e r e will be an efficiency factor for the block a n d tackle system to reflect these losses. T h e efficiency will be d e n o t e d as the hook-to-drawwork efficiency (eh). T h e force in the fast line u n d e r dynamic conditions (i.e., hook is moving) will be Ff = Wh

eh j

(4-11)

Equation 4-9 remains u n c h a n g e d by the initiation o f hook m o t i o n (i.e., the force in the d e a d line is the same u n d e r static or dynamic conditions). T h e mechanical advantage (ma) u n d e r dynamic conditions is ma (dynamic) = %j

(4-12)

T h e total load on the d e r r i c k u n d e r dynamic conditions, F (lb), will be

F t-- W h+

Wh Wh + +W c+w, ehj j

(4-13)

w h e r e W c is the weight o f the crown block, a n d W t is the weight o f tools s u s p e n d e d in the derrick, both in pounds.

Example For dynamic conditions, f i n d the total l o a d on a derrick that is capable o f lifting a 600,000-1b drill string with an 8-working line block and tackle. The crown

Hoisting System

525

block weighs 9,000 lb and the traveling block weighs 4,500 lb. Assume that there are no o t h e r tools h a n g i n g in the d e r r i c k a n d that the d e a d l i n e is attached to the rig floor across from the drawworks in its normal position (see Figure 4-7). Assume the s t a n d a r d d e d u c t i o n o f 2% p e r working line to calculate e h. e h = 1.00 - 0.02(8) = 0.84 F r o m Equation 4-13 F t = 604,500 ~ 600,000 + 600,000 + 9,000 O.84(8) 8 = 604,500 + 89,286 + 75,000 + 9,000 = 786,786 lb

Drawworks The drawworks is the key o p e r a t i n g c o m p o n e n t o f the hoisting system. O n most m o d e r n rotary drilling rigs, the p r i m e movers e i t h e r o p e r a t e the hoisting d r u m within the drawworks or o p e r a t e the rotary table through the transmission within the drawworks. Thus the drawworks is a c o m p l i c a t e d mechanical system with many functions [1,7].

Functions T h e drawworks does not c a r r y out only h o i s t i n g functions on the r o t a r y drilling rig. In general, the functions o f the drawworks are as follows: 1. Transmit power from the p r i m e movers (through the transmission) to its hoisting d r u m to lift drill string, casing string, or tubing string, or to pull in excess o f these string loads to free stuck pipe. 2. Provide the b r a k i n g systems on the hoist d r u m for lowering drill string, casing string, or tubing string into the borehole. 3. Transmit power from the p r i m e movers (through the transmission) to the rotary drive sprocket to drive the rotary table. 4. Transmit power to the catheads for breaking out a n d making up drill string, casing string, a n d tubing string. Figure 4-9 is a schematic o f drawworks t o g e t h e r with the p r i m e mover power source.

Deslgn The drawworks basically contains the hoist drum, the transmissions, the brake systems, the clutch systems, rotary drive sprocket, a n d cathead. Figure 4-10 shows a schematic o f the drawworks. The power is p r o v i d e d to the drawworks by the p r i m e movers at the master clutch (see Figure 4-9) a n d is transmitted to the master clutch shaft via sprockets a n d roller chain drives. The s p e e d a n d the torque from the p r i m e movers are controlled through the c o m p o u n d . The c o m p o u n d is a series o f sprockets, roller chain drives, a n d clutches that allow the driller to control the power to the

526

Drilling a n d Well C o m p l e t i o n s 3

4

2 5

d_ m

_= []

[] i m

14

O:

13

I

11

1. Drive to pump 2. Master clutch 3. Generator 4. Air compressor 5. Washdown pump 6. Sand reel drive 7. Drum high air clutch 8. Auxiliary brake

9. 10. 11. 12. 13. 14. 15. 16.

Rotary drive air clutch countershaft Driller's console Drum low air clutch High gear Reverse gear Intermediate gear Low gear Power flow selector*

*Note: This item is shown as a manually operated clutch. This, of course, on an actual rig would be air actuated. Figure 4-9. Power train on a drawworks with accessories. drawworks. T h e driller o p e r a t e s the c o m p o u n d a n d the drawworks (and other rig functions) from a d r i l l e r ' s console (see Figure 4-11). W i t h the c o m p o u n d , the d r i l l e r can o b t a i n as m a n y as 12 gears working t h r o u g h the drawworks transmission. In Figure 4-11, the driller's console is at the left o f the drawworks. Also, the hoisting d r u m a n d sand reel can be seen. T h e driller's brake control is between the d r i l l e r ' s console a n d the drawworks to control the b r a k e systems o f the hoisting drum.

Hoisting Drum. T h e hoisting d r u m (usually g r o o v e d ) is p r o b a b l y the m o s t i m p o r t a n t c o m p o n e n t on the drawworks. It is t h r o u g h the d r u m that power is t r a n s m i t t e d to lift the drill string with the drilling line (wire rope) wound on the d r u m . From the standpoint o f power requirements for hoisting, the ideal

Hoisting System

527

/7

~g'N

e

~

.....................

,~ .....................

,

~

.........

I1 ~I~¸¸¸ i i "%, ~/~;~¸B~ $B

Figure 4-10. The drive group of a large DC electric rig. Note that this rig may be equipped with either two or three traction motors.

L Drill~r~s~ o l e ~

Figure 4-11. The hoist on the rig floor.

2. ~

~a~ad~

528

Drilling and Well Completions

d r u m would have a diameter as small as possible and a width as great as possible. From the standpoint of drilling line wear and damage, the hoisting d r u m would have the largest d r u m diameter. Therefore, the design of the hoisting drum must be compromised to obtain an optimum design. Thus, the hoist drum is usually designed to be as small as practical, but the d r u m is designed to be large enough to permit fast line speeds in consideration of operation and economy. Often it is necessary to calculate the line-carrying capacity of the hoist drum. The capacity or length of drilling line in the first layer on the hoist drum L~ (ft) is L~ = -i~(D + d)

(4-14)

where D is the drum diameter, d is the line diameter, and e is the hoisting drum length, all in inches. The length of the second layer, L 2 (ft) is L 2 = -n~ ( D + 3d)-~g

(4-15)

The length of the n th layer L n (fl) is n " + (2n-1)d]~ L. = ]~[D

(4-16)

where n is the total number of layers on the hoisting drum. The total length of drilling line on the hoisting drum, L (ft), will be the sum of all the layers: n gh L, = -i~(D + h) d---~

(4-17)

where h is the hoist drum flange height, in inches.

Example A hoist d r u m has an inside length of 48 in. and an outside diameter of 30 in. The outside diameter of the flange is 40 in. The drilling line diameter is 1 in. Find the total line capacity of the drum. The flange length is 40 - 30 h=~=5in. 2 The total length (capacity) is L, = ~ 2 ( 3 0 + 5)~i.~(48)(5) = 2199fi

Hoisting System

529

Transmlsslon and Clutch. The transmission in the drawworks generally has six to eight speeds. Large rigs can have more gears in the drawworks transmission. More gearing capacity is available when the c o m p o u n d is used. This transmission uses a combination of sprockets and roller chain drives and gears to accomplish the change of speeds and torque from the prime movers (via the compound). The clutches used in the transmitting of prime mover power to the drawworks are jaw-type positive clutches and friction-type clutches. In m o d e r n drawworks, nearly all clutches are pneumatically operated from the driller's console. The driller's console also controls the shifting of gears within the drawworks. Torque converters used in most drawworks are designed to absorb shocks from the prime movers or the driven equipment and to multiply the input torque. Torque converters are used in conjunction with internal combustion prime movers when these engines are used directly to drive the drawworks. More m o d e r n drawworks are driven by electric drives since such prime movers usually simplify the drawworks.

Brakes. The brake systems of the drawworks are used to slow and stop the movement of the large weights that are being lowered into the borehole. The brake system will be in continuous use when a round trip is made. The principal brake of the drawworks is the friction-type mechanical brake system. But when this brake system is in continuous use, it would generate a great deal of heat. Therefore, an auxiliary brake system is used to slow the lowering speeds before the friction-type mechanical brake system is employed to stop the lowering motion. Hydraulic brake system and electromagnetic brake system are the basic types of auxiliary brake systems in use. The hydraulic brake system uses fluid friction (much like a torque converter) to absorb power as equipment is lowered. The electromagnetic brake system uses two o p p o s e d magnetic fields supplied by external electrical current to control the speed of the hoisting drum. The auxiliary brake system can only control the speed of lowering and cannot be used to stop the lowering as does the mechanical friction-type brake system. Catheads. The catheads are small rotating spools located on the sides of the drawworks. The cathead is used as a power source to carry out routine operations on the rig f l o o r and in the vicinity of the rig. These operations include making up and breaking out drill pipe and casing, pulling single joints of pipe and casing from the pipe rack to the rig floor. The sand reel is part of this mechanism. This small hoisting drum carries a light wire rope line (sand line) through the crown to carry out pulling operations on the rig floor or in the vicinity of the rig.

Power Rating In general, the drawworks is rated by its input horsepower. But it used to be rated by depth capability along with a specific size of drill pipe to which the depth rating pertains. The drawworks horsepower input required HP~, for hoisting operations is HPi. =

WVh 33,000ehem

(4-18)

where W is the hook load in lb, vh is the hoisting velocity of the traveling block in f t / m i n , e h is the hook-to-drawworks efficiency, and e is the mechanical efficiency within the drawworks and coupling between the prime movers and the drawworks (usually taken as about 0.85).

530

Drilling and Well Completions

Example It is required that the drawworks i n p u t power be able to lift 600,000 lb at a rate of 50 f t / m i n . There are eight working lines between the traveling block and the crown block. Three i n p u t power systems are available: 1,100, 1,400, and 1,800 hp. Which of the three will be the most appropriate? The value of e h is e h =

1.00

-

0.02(8)

= 0.84

The i n p u t horsepower is

6oo, ooo(5o) HPin

33,000(0.84)(0.85) = 1273.2

The i n p u t power system requires 1400 hp.

Drilling and Production Hoisting Equipment [9,10] Drilling a n d p r o d u c t i o n hoisting e q u i p m e n t includes:

1. Crown block sheaves and bearings: The stationary pulley system at the top of the derrick or mast.

2. Traveling blocks: A heavy duty pulley system that hangs in the derrick and travels up and down with the hoisted tools. It is connected to the crown block with a wire rope that ultimately runs to the hoisting drum. 3. Block-to-hook adapters: A metal piece that attaches to the bottom of the traveling block and serves as the m o u n t for the hook.

4. Connectors and link adapters. 5. Drilling hooks: The hook that attaches to the traveling block to connect the bail of the swivel.

6. Tubing and sucker rod hooks: Hooks connected to the traveling block for t u b i n g a n d sucker-rod hoisting operations.

7. Elevator links: The elevator is a hinged clamp attached to the hook and is used to hoist drill pipe, tubing, and casing. The actual clamp is in a pair of links that in t u r n attaches to a bail supported on the hook.

8. Casing, tubing and drill pipe elevators. 9. Sucker rod elevator. 10. Rotary swivel bail adaptors: A bail adaptor that allows the bail of the swivel to be grasped a n d hoisted with elevators. 11. Rotary swivels. T h e swivel c o n n e c t i n g the n o n r o t a t i n g hook a n d the rotating kelley while providing a n o n r o t a t i n g c o n n e c t i o n through which m u d enters the kelley. 12. Spiders: The c o m p o n e n t of the elevator that latches onto the hoisted item. 13. Deadline tiedowns: The deadline is the n o n m o v i n g e n d of the wire rope from the hoisting down through the crown and traveling blocks. This e n d is anchored at g r o u n d level with a tiedown. 14. Kelley spinners, when used as tension members: A n a d a p t e r between the swivel and the kelley that spins the kelley for rapid attachment and disattachment to joints of drill pipe. 15. Rotary tables, as structural members: The rotary table rotates to t u r n the drill string. It is also used to support the drill string d u r i n g some phases of operation.

Hoisting System

531

16. Tension members of subsea handling equipment. 17. Rotary slips: Wedging devices used to clamp the tool string into the rotary table. The wedging action is provided by friction.

Material Requirements Castings. Steel castings used in the manufacture o f the main load carrying components o f the drilling and production hoisting equipment shall conform to ASTM A781: "Common Requirements for Steel and Alloy Castings for General Industrial Use," and either an individual material specification listed therein or a proprietary material specification that as a minimum conforms to ASTM A781.

Forgings. Steel forgings used in the manufacture o f the main load carrying components o f the equipment shall conform to ASTM A668: "Steel Forgings, Carbon and Alloy, for General Industrial Use" and ASTM A778: "Steel Forgings, General Requirements." A material specification listed in ASTM A788 or a proprietary specification conforming to the minimum requirements o f ASTM A788 may be used. Plates, Shapes, and Bar Stock. Structural material used in the manufacture o f main load carrying components o f the equipment shall conform to applicable ASTM or API specifications covering steel shapes, plates, bars, or pipe, or a proprietary specification conforming to the minimum requirements o f applicable ASTM or appropriate standard. Structural steel shapes having a specified minimum yield strength less than 33,000 psi, or steel pipe having a specified minimum yield strength less than 35,000 psi shall not be used. Design Rating and Testing All hoisting equipment shall be rated in accordance with the requirements specified herein. Such ratings shall consist o f a maximum load rating for all items, and a main-bearing rating for crown blocks, traveling blocks, and swivels.

The traveling block and crown block ratings are independent of wire rope size and strength. Such ratings shall be calculated as specified herein and in accordance with good engineering practices. The ratings determined herein are intended to apply to new equipment only.

Maximum Load Rating. The maximum load ratings shall be given in tons (2,000-1b units). The size class designation shall represent the dimensional interchangeability and the maximum rated load o f equipment specified herein. The r e c o m m e n d e d size classes are as follows (ton): 5 10 15 25

40 65 100 150 250

350 500 650 750 1,000

For purpose o f interchangeability contact radii shall comply with Table 4-5.

Maximum Load Rating Bases. The maximum load rating will be based on the design safety factor and the yield strength o f the material. Crown block beams are an exception and shall be rated and tested in accordance with API Spec 4E: "Specification for Drilling and Well Servicing Structures."

532

Drilling and Well Completions Table 4-5 Recommended Hoisting Tool Contact Surface Radii (All dimensions in inches) [9] 1

2

3

Rating

4

5

6

7

Traveling Block & Hook Bail See Fig. 4-16 A~ Max in. mm

Short tons

Metric tons

25-40 41-65 66-100

22.7-36.3 2V, 69.85 37.2-59 23/, 69.85 59.9-91 23/, 69.85

A_. Min in. mm

B~ Min in. mm

2~ 69.85 2sA 69.85 23/, 69.85

3¼ 82.55 3¼ 82.55 3¼ 82.55

B._. Max in. mm 3 3 3

E~ Min in. mm

E2 Max in. mm

351-500 501-650

318.7-454 454.9-591

4 4

101.60 4 101.60 4

101.60 3~ 88.90 101.60 3~ 88.90

3¼ 82.55 3~ 88.90 3¼ 82.55 3½ 88,90

651-750

591.1-681

6

152.40 6

152.40 3¼ 88.90

3¼ 82.55 4¼ 107.95 4

751-1000

681.9-908

6

152.40 6

152.40 6¼ 158.75 6

12

13

11

14

F~ Max in. mm

7 6 . 2 0 2~6 63.50 2V, 57.15 7 6 . 2 0 2~ 69.85 2½ 63.50 76.20 3 76.20 2~ 69.85 3¼ 82.55 31A 82.55

4tA 114.30 4~ 114.30 4½ 114.30 4~ 114.30

101.60 4~ 114.30 4~ 114.30

152.40 5¼ 133.35 5 15

4~6 114.30 4~ 114.30 4~ 114.30 4Yz 114.30 4~ 114.30 4~ 114.30

127.00 5

16

127.00 5

17

Rating

C~ Max in. mm

C.: Min in. mm

Dj Min in. mm

D.2 Max in. mm

1~6 38.10 2~6 63.50 2~6 63.50

1~ 38.10 2~ 63.50 21.6 63.50

1~ 31.75 1¼ 31.75 1~638.10

~ 22.23 ~ 22.23 1~ 28.58

2~6 63.50 2~6 63.50 4 101.60 4 101.60 4 101.60 4 101.60

1~ 38.10 1~ 44.45 lSA 44.45

1~ 28.58 1~ 34.93 1~ 34.93

l:./~ 23.82 17/.z 30.94 ll.ytz 37.31

1~6 38.10 14 47.63 2 50.80

2 50.80 23/, 69.85 2~ 69.85

4 4

101.60 4~ 120.65 101.60 4~ 120.65

2¼ 57.15 2¼ 57.15

1~ 47.63 1~ 47.63

1~ 47.63 2¼ 57.15

2 50.80 2~ 60.32

3¼ 82.55 3¼ 82.55 351-500 5 127.00 5 127.00 501-650

318.7-454 454.9-591

4

101.60

5

127.00

2½ 63.50

2~

63.50

2¼ 57.15

2% 60.32

5

591.1-681

41.6 114.30

5

127.00

3

2~

69.85

2sA 69.85

2~ 73.03

61/4 158.75

76.20

G~ Min in. mm

127.00

18

Elevator Link & Elevator Link Ear See Fig. 4-18 G~ Max in. mm

F2 Min in. mm

76.20 2 50.80 1½ 38.10 3 76.20 3 76.20 76.20 2 50.80 13/, 44.45 3~6 88.90 3½ 88.90 76.20 2t/, 57.15 2 50.80 4 101.60 4 101.60

91.7-136 23/, 69.85 23/, 69.85 3¼ 82.55 3 137.1-227 4 101.60 4 101.60 3~A 82.55 3 227.9-318 4 101.60 4 101.60 3¼ 82.55 3

Elevator Link & Hook Link Ear See Fig. 4-18

9

Hook & Swivel Bail See Fig. 4-17

101-150 151-250 251-350

10

8

H~ Min in. mm

1 25.40 1 25.40 1 25.40

H. Max in. mm

Short tons

Metric tons

25-40 41-65 66-100

22.7-36.3 37.2-59 59.9-91

2 5 0 . 8 0 101-150 23/, 69.85 151-250 28A 69.85 251-350

91.7-136 137.1-227 227.9-318

2 2 2

127.00 5

50.80 50.80 50.80

127.00 651-750

6¼ 158.75 751-1000

681.9-908

Crown Blocks. For crown block design, see API Specification 4F. Crown block sheaves and bearings shall be designed in accordance with API Specification 8A. Spacer Plates. Spacer plates of traveling blocks, not specifically designed to lend support to the sheave pin, shall not be considered in calculating the rated capacity of the block. Sheave Pins. In calculations transferring the individual sheave loads to the pins of traveling blocks, these loads shall be considered as uniformly distributed over a length of pin equal to the length o f the inner bearing race, or over an equivalent length if an inner race is not provided. Design Factor. The design safety factors shall be calculated as follows (see Figure 4-12) for the relationship between the design safety factor and rating:

Hoisting System

533

2. (/)

|II

•

0

I

I

)

:.

3.00

..........................................

I--

W '~ 2.50

.

.

.

~Z 0

.

.

"'.

N z.zs

U.I

~

ca

0

i

i

I I I I I I00 150 250 350 500 650 I000 M A X I M U M LOAD R A T I N G , TONS

Figure 4-12. Design safety factor and rating relationships [9]. Calculated Rating (ton)

Yield Strength Design Safety Factor, SF o

150 or less

3.00

O v e r 150 to 500

3.00 -

O v e r 500

2.25

* R

=

0.75(R* -150) 350

rating in tons (2,000-1b units).

M e c h a n i c a l P r o p e r t i e s . The mechanical properties used for design shall be the minimum values allowed by the applicable material specification or shall be the minimum values determined by the manufacturer in accordance with the test procedures specified in ASTM A370: "Methods and Definitions for Mechanical Testing o f Steel Products," or by mill certification for mill products. The yield point shall be used in lieu of yield strength for those materials exhibiting a yield point. Yield strength shall be determined at 0.2% offset. S h e a r S t r e n g t h . For the purpose o f calculations involving shear, the ratio o f yield strength in shear-to-yield strength in tension shall be 0.58. E x t r e m e L o w T e m p e r a t u r e . Maximum load ratings shall be established at room temperature and shall be valid down to 0°F (-18°C). The equipment at rated loads when temperature is less than O°F is not recommended unless provided for by the supplemental requirements. When the equipment is operating at lower temperatures, the lower impact absorbing characteristics of many steels must be considered.

Test Unit. To assure the integrity o f design calculations, a test shall be made on one full size unit that in all respects represents the typical product. For a family o f units o f the same design concept but o f varying sizes, or ratings, one test will be sufficient to verify the accuracy o f the calculation method used, if the item tested is approximately midway o f the size and rating range o f the family, and the test results are applicable equally to all units in that family. Significant changes in design concept or the load rating will require supportive load testing.

534

Drilling and Well Completions

P a r t s T e s t i n g . Individual parts of a unit may be tested separately if the holding fixtures simulate the load conditions applicable to the part in the assembled unit.

Test Fixtures. Test fixtures shall support the unit (or part) in essentially the same m a n n e r as in actual service, and with essentially the same areas of contact on the load-bearing surfaces.

Test Procedure. 1. The test unit shall be loaded to the m a x i m u m rated load. After this load has been released, the unit shall be checked for useful functions. The useful function of all e q u i p m e n t parts shall not be impaired by this loading. 2. Strain gages may be applied to the test unit at all points where high stresses are anticipated, provided that the c o n f i g u r a t i o n of the units permits such techniques. The use of finite element analysis, models, brittle lacquer, etc., is r e c o m m e n d e d to c o n f i r m the proper location of strain gages. Threeelement strain gages are r e c o m m e n d e d in critical areas to permit determ i n a t i o n of the shear stresses and to eliminate the need for exact orientation of the gages. 3. The maximum test load to be applied to the test unit shall be 0.80 x R x SFD, but not less than 2R. Where R equals the calculated load rating in tons, SF D is design safety factor. 4. The unit shall be loaded to the maximum test load carefully, reading strain gage values and observing for yielding. The test unit may be loaded as many times as necessary to obtain adequate test data. 5. U p o n completion of the load test, the u n i t shall be disassembled and the dimensions of each part shall be checked carefully for evidence of yielding.

Determination of Load Rating. The m a x i m u m load rating may be d e t e r m i n e d from design and stress distribution calculations or from data acquired d u r i n g a load test. Stress distribution calculations may be used to load rate the equipment only if the analysis has b e e n shown to be w i t h i n a c c e p t a b l e e n g i n e e r i n g allowances as verified by a load test on one m e m b e r of the family of units of the same design. The stresses at that rating shall not exceed the allowed values. Localized yielding shall be permitted at areas of contact. In a unit that has been load tested, the critical p e r m a n e n t deformation d e t e r m i n e d by strain gages or other suitable means shall not exceed 0.002 i n . / i n . If the stresses exceed the allowed values, the affected part or parts must be revised to obtain the desired rating. Stress distribution calculations may be used to load rate the e q u i p m e n t only if the analysis has b e e n shown to be w i t h i n a c c e p t a b l e e n g i n e e r i n g allowances as verified by a load test of one m e m b e r of the family of units of the same design.

Alternate Test Procedure and Rating. Destructive testing may be used provided an accurate yield and tensile strength for the material used in the e q u i p m e n t has been determined. This may be accomplished by using tensile test specimens of the actual material and d e t e r m i n i n g the yield strength to ultimate strength ratio. This ratio is then used to obtain the rating R (ton) of the e q u i p m e n t by the following equation:

R-

( YS ) L ~"~) B SFD

(4-19)

Hoisting System where SF D = YS = TS = LB =

535

yield strength design safety factor yield strength in psi ultimate tensile strength in psi breaking l o a d in tons

Load Testing Apparatus. The load apparatus used to simulate the working load on the test unit shall be calibrated in accordance with ASTM E-4: "Standard Methods o f Verification o f Testing Machines," so as to assure that the prescribed test load is obtained. Block Bearing Rating. T h e b e a r i n g rating o f crown a n d traveling blocks shall be d e t e r m i n e d by W b = NWr 714

(4-20)

where W b = calculated block b e a r i n g rating in tons N = n u m b e r o f sheaves in the block W r = individual sheave b e a r i n g rating at 100 r p m for 3,000-hr m i n i m u m life for 90% o f bearings in p o u n d s S w i v e l Bearing Rating. The b e a r i n g rating o f swivels shall be d e t e r m i n e d by W s = Wr 1600

(4-21)

where W = calculated main thrust-bearing rating at 100 r p m in tons W I = main b e a r i n g thrust rating at 100 r p m for 3000-hr m i n i m u m life for 90% o f bearings in p o u n d s

Traveling Block Hood Eye Opening Rating. T h e traveling block top handling m e m b e r shall, for 500-ton size class and larger, have a static l o a d rating based on safety factors given in the p r e c e d i n g p a r a g r a p h titled "Design Factor."

Design Changes. W h e n any change m a d e in material, dimension, o r construction might decrease the calculated load o r b e a r i n g shall be rerated, and retested if necessary. Parts o f the u n c h a n g e d f r o m t h e o r i g i n a l d e s i g n n e e d n o t be omission does not alter the test results o f the o t h e r

ratings, the unit changed m o d i f i e d unit that remain r e t e s t e d , p r o v i d e d such components.

Records. T h e m a n u f a c t u r e r shall keep records o f all calculations a n d tests. W h e n requested by prospective p u r c h a s e r o r by a user o f the equipment, the manufacturer shall examine the details o f computations, drawings, tests, o r other s u p p o r t i n g data necessary to d e m o n s t r a t e c o m p l i a n c e with the specification. It shall be u n d e r s t o o d that such i n f o r m a t i o n is for the sole use o f the user o r prospective p u r c h a s e r for checking the AP! rating, and the m a n u f a c t u r e r shall not be required to release the information from his custody.

Elevators Drill pipe elevators for t a p e r shoulder a n d square shoulder weld-on tool j o i n t s shall have bore dimensions as specified in Table 4-6.

536

Drilling and Well Completions Table 4-6 Drill Pipe Elevator Bores (All dimensions in Inches) [9] 1

2

3

Drill Pipe Size and Style (All Weights and Grades)

4

5 Weld-On Tool Joints

7

Neck Diam. DrzMaxJ in, mm

Elev. Bore in, mm

Square Shoulder . . Neck Diam. Elev. DszMax.Z Bore in. mm in. mm

NC 26 (2~ IF) 2"~ EU

29/~

65.09

2~t[~ 67.47

*

*

NC 31 (2~ IF) 27~ EU

3:~/~

80.96

3s[,~

3:'/~s 80.96

3s~

8733

2~ EU

NC 38(3~ IF) 3½ EU NC 40 (4 FH) 3~ EU

37~ 37~

98.43 98.43

3:"L~ 100.81 3:"~ 100.81

3~ 37/s

98.43 98.43

4V~ 103.19 4V~s 103.19

3~ EU

NC 40(4 FH) 4 IU

4s/~

106.36

4~L~ 101.86

4~

104.78

4~/~s 109.54

4 IU

NC 46 (4 IF)

4½ 4H/~ 4H/~. 4H/~ 4"/~

114,30 119,06 119,06 I19,06 119,06

4~:~:~ 4~ 4~ 4~ 4~

121,44 121,44 121,44 121,44 121,44

4P~ 4,~ 4~ 4`% 4~

114,30 117,48 117,48 I17,48 117,48

4~:Y~s 122,24 4~:~'~ 122,24 4~:~/~s 122,24 4~:~/~ 122,24 4~:~'~s 122,24

4EU 4~IU 4~IEU

5 5¼

127.00 130,18

5¼ 5¼

133.35 133,35

5 5~

127.00 130,18

5~/~ 134.94 5~'~ 134,94

4~ EU 51EU

133.35

5~

130.18

5:'/~ 134.94

Tool Joint Designation Reference

4~FH**

4 EU 4~IU 4½IEU 4½1U 4~IEU

NC 50 (4½ IF) 4~ EU 5 IEU

Taper Shoulder

6

^

.

.

~

.

.

83.34

5½ FH**

5 IEU

5~

130.18

5¼

5~FH**

5IEU

5H/~

144,46

5~:~/~ 147,64

6~ FH

6"%IEU

6~/~

175,02

7~[,~ 178,66

A

5H/~ 144,46

Elev. Marking 2`%EU

57~

149,23

5~IEU 6~

NOTE: Eleeator~ ~rit~the same bores are t~e ~ame eler~tor.~. •Not manufactured. • *Obsoleecentconnection.

~DimensionDTE fromAP] Spec7. Table 4.2. ~DimensionDSE from API Spec7. AppendixH.

Elevator Bores

Casing i

"D" Casing Dia.

IP "TB" ~ "~i in.

5 5½ 6`% 7 7`% 7~ 8`%

mm 1•7.00 139.70 168.~8 177.80 193.68 196.85 219,08

9~ ~$$,$8 "BB"

Seo uote

Top ~ore

Bottom Bore

,1/64 ±.40 mm

-1/64+1/32

+.79_.40

in.

in.

mm

5.125 5.625 6350 7.125 7.781

mm

5.125 5.625 6.750 7.125 7.781 7.908 7.906 8.781 .~',','28,05 8,781 9.781 ~/~8,$$ 9 . 7 8 1 13fl~18 152.88 171.$5 180.98 197.65 200.81

150.18 15~.88 171.$5 180.98 197.65 ~00.81

2~.~,0~ ,~$8,$$

11~ ~98.$5 11.988 803.~8 11.988 805.~8 13~ 339.73 13.563 8k~.50 18.582 855.50 18 $06.$0 16.219 $11.96 16.219 $11.98 18`% $73.08 18.875 $79.$3 18.875 $79.$3 20 508.00 20.281 515.15 20.281 515.15 NOTE: Bottombore "BB"/s opt/ona/, some e/evator des/gns do not have a bottom bore.

Hoisting System

537

Table 4-6 (continued) -.*4t,.

"D~" "TB" F

"BB"

Tubing Non-Ups~,t Tubin~ "T B" "BB" "" "W" "D" "" "W" Size O . D . Collar Dis. Top Bore Bottom Bore Collar Di~ + 1/32 +.79 +1,64 :t:.40 mm -1/64 -.40 in. mm in. mm in. mm in. mm in. mm 1.050 1.315 1.660 1.900 2~ 2~ 3~ 4 4~

~6,67 38,~0 ~£,16 ~8,28 60,32 73,03 88,90 101.60 ll~,30

See n o t e

External Upset Tubing" "D~" "TB" Upset Di& Top Bore in.

mm

"BB" Bottom Bore +1/32 +.79 :t:1/64 +.40 ram-l/64 -.40 in. mm in. mm

1.313 33,35 1.125 28,58 1.125 28,58 1.680 ~ , 1 6 1.315 83,~0 1.422 36,lt. 1.422 1.660 ~2,16 1.390 35,3l 1.390 35,.$l 1.900 ~8,t.6 1.489 37,31 1.578 /~0,08 1.578 55,88 1.812 ~6,0"2 1.922 ~8,82 1.922 2.054 5£,17 1.734 /~,,0~ 1.734 ~ . 0 ~ 2.200 2.200 65,88 1.984 60,39 1.984 50,89 2.500 63,50 2.093 55,70 2.203 56,03 2.203 2.875 73,05 2.453 6~,8l 2.453 6~,8l 3,063 77,80 2.593 65,89 2.703 68,58 2.703 3.500 88,90 2.953 75,0l 2.953 75,0l 3.666 93,17 3.093 78,56 3.203 81.36 3.203 4.250 107,95 3.678 90,88 3.578 90,88 4.500 ll~,80 3.750 96,~5 3.859 98,02 3.859 4.750 lt.0,85 4.078 105,58 4.078 109,58 5.000 127,00 4.250 107,95 4.359 ll0,7~ 4.359 5.200 lSt.,O# 4.593 ll6,69 4.593 ll6,69 5.583 1~l,80 4.750 l~0,65 4.859 1~8,~ 4.859 CAUTION: DO NOT USE EXTERNAL UPSET TUBING ELEVATORSON NON-UPSET TUBING.

86,l~ ~0,08 ~8,82 56,03 68,58 81,36 98,0~ ll0.7~ l~3.~

NOTE: Bore "BB" is optional some elevator d~g.ns do not hate a bottom bore.

The permissible tolerance on the outside diameter immediately behind the tubing upset may cause problems with slip-type elevators.

Rotary Swivels Rotary Swivel Pressure Testing. The assembled pilot model o f rotary swivels shall be statically pressure tested. All cast members in the rotary swivel hydraulic circuit shall be pressure tested in production. This test pressure shall be shown on the cast member. The test pressure shall be twice the working pressure up to 5,000 psi (incl.). For working pressures above 5,000 psi, the test pressure shall be one and onehalf times the working pressure. Swivel Gooseneck Connection. The angle between the gooseneck centerline and vertical shall be 15 °. The swivel gooseneck connections shall be 2, 2 ~, 3, 3 ~, 4, or 5-in. nominal line pipe size as specified on the purchase order (see Figure 4-13). Threads on the gooseneck connection shall be internal line pipe threads conforming to API Standard 5B: "Threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads." Rotary swivel gooseneck connections shall be marked with the size and type of thread, such as 3 API LP THD.

Rotary Hose Safety Chain Attachment. Swivels with gooseneck connections in 2 in. or larger shall have a suitable lug containing a 1 is-in, hole to accommodate the clevis o f a chain having a breaking strength of 16,000 lb. The location of the lug is the choice of the manufacturer.

538

Drilling a n d Well Completions

'"'- 1,5= / J,,~--'" Goose neck V ~, Internal line-pipe t h r e a d , , , ~ ¢ " " ~ r~ SPEC 8A ~ r~j::=:=::~ P 7 ~ S EC l~ ~ / ~ / ,.,-/.Externolline-pipe threod----,~.~.~ "w] IT--'--"

Rotary

IJ ~ ~

Notesto Users: 1. Nofieldweldingis to bedonebetween thecouplingnipple andthe gooseneck. ~ \ -.L., ~

2. RefertoAPlSpec7 for specificationsfor swivelStemconnections, swivelsubs and rotaryhose:

drilling

h°se " ~~/ ';/)//

~ '~API Swivel

stem~[_J._J 4-

Swive, ,.,.,0--'t i

Standard

Rotary

Connection LH SPEC 8A SPEC 7

r, :otary

Figure 4-13. Rotary swivel connections [9].

Sheaves for Hoisting Blocks The sheave diameter shall be the overall diameter D as shown in Figure 4-14. Sheave diameters shall, wherever practicable, be d e t e r m i n e d in accordance with r e c o m m e n d a t i o n s given in the section titled "Wire Rope." Grooves for drilling a n d casing line sheaves shall be made for the rope size specified by the purchaser. The bottom of the groove shall have a radius R, Table 4-7, s u b t e n d i n g an arc of 150 ° . The sides of the groove shall be tangent to the ends of the bottom arc. Total groove depth shall be a m i n i m u m of 1.33d and a maximum of 1.75d (d is the nominal rope diameter shown in Figure 4-14). In the same manner, grooves for sand-line sheaves shall be made for the rope size specified by the purchaser. The bottom of the groove shall have a radius R, Table 4-6, subtending an arc of 150 °. The sides of the groove shall be tangent to the ends of the bottom arc. Total groove depth shall be a m i n i m u m of 1.75d a n d a m a x i m u m of 3d, and d is n o m i n a l rope diameter (see Figure 4-14, B). Sheaves should be replaced or reworked when the groove radius decreases below the values shown in Table 4-8. Use sheave gages as shown in Figure 4-15. Figure 4-15 A shows a sheave with a m i n i m u m groove radius, a n d Figure 4-15 B shows a sheave with a tight groove.

Hoisting System

"

F~

539

.-

t-,-

?

DRILLINGLINE& CASINGLINE SHEAVES

SAND-LINE SHEAVES

DETAILA

DETAILB

Figure 4-14. Sheave grooves [9].

Table 4-7 Groove Radii for New and Reconditioned Sheaves and Drums All dimensions in inches [9] 1 Wire Rope Nominal Size

¼ :g & ~z '1~ % 1 I~ I ~A 1~ 1~ Standard

2

1

2

1

Radii

Wire Rope Nominal Size

Radii

Wire Rope Nominal Size

Radii

3:~ 3½

1.807 1.869

4 4V4 4~

2.139 2.264 2.396 2.534 2.663 2.804 2.929 3.074 3.198

.137 .167 .20I .234 .271 .303 .334 .401 .468 .543 .605 .669 .736 .803 Machine Tolerance

i% I'~A 1~ 2 2~ 2¼ 2~ 2~ 2~ 2~ 27/. 3 3~ 3¼

.876 .939 1.003 1.070 1.137 1.210 1.273 1.338 1.404 1.481 1.544 1.607 1.664 1.731

3:~

4sA 5 5¼ 5~ 5~ 6

2

1.997

Contact Surface Radii Figures 4-16, 4-17, 4-18, and Table 4-5 show r e c o m m e n d e d radii of hoisting tool contact surfaces. These r e c o m m e n d a t i o n s cover hoisting tools used in drilling, a n d t u b i n g hooks, b u t all other workover tools. Contact radii are i n t e n d e d to cover only points of contact b e t w e e n two e l e m e n t s a n d are not i n t e n d e d to define other physical dimensions of the c o n n e c t i n g parts.

540

Drilling and Well C o m p l e t i o n s

Table 4-8 Minimum Groove Radii for Worn Sheaves and Drums (All dimensions in inches) [9] 1

2

Wire Rope

Nominal Size ¼

½ ?, 7~

1

2

Radii .129 .160 .190 .220 .256 .288 .320 .380 .440

1

• 513

IX 1¼ i~ I~

.577 .639 .699 .759

Nominal Size I~ I~ I~ 2 2~ 2¼ 2% 2½ 2~ 2~ 27A 3 3~ 3¼

DETAIL A

1

2

W i r e Rope

Wire Rope

Radii .833 .897 .959 1.019 1.079 1.153 1.217 1.279 1.339 1.409 1.473 1.538 1.598 1.658

Nominal Size 3~ 3½ 3~ 4 4¼ 4½ 4~ 5 5¼ 51/2 ~A 6

Radii

1.730 1.794 1.918 2.050 2.178 2.298 2.434 2.557 2.691 2.817 2.947 3.075

DETAIL B

Figure 4-15. Use of sheave gages [9].

Inspection, Nondestructive Examination, and Compliance Inspection. While work on the contract of the p u r c h a s e r is being p e r f o r m e d , the purchaser's inspector shall have reasonable access to the a p p r o p r i a t e parts o f the m a n u f a c t u r e r ' s works c o n c e r n i n g the m a n u f a c t u r e o f the e q u i p m e n t o r d e r e d hereunder. Inspection shall be m a d e at the works p r i o r to shipment, unless o t h e r w i s e s p e c i f i e d , a n d shall be c o n d u c t e d so as n o t to i n t e r f e r e unnecessarily with the works' o p e r a t i o n or p r o d u c t i o n schedules.

Nondestructive Examination. T h e manufacturer shall have a reasonable written nondestructive examination p r o g r a m to assure that the equipment manufactured is suitable for its intended use. If the p u r c h a s e r ' s inspector desires to witness these operations, the m a n u f a c t u r e r shall give reasonable notice of the time at which the examinations are to be p e r f o r m e d .

Hoisting System

ii J

LiNG BLOCK "~

HOOK BAIL

Figure 4-16. Traveling block and hook bail contact surface radii [9].

~L'NKEARS~y/Iqll c2

'i lt:J i

L

I

O2

ELEVATOR LINKS

Figure 4-17. Elevator link and link ear contact surface radii [9]. /

l SW,VELBAIL

~2

Figure 4-18. Hook and swivel bail contact surface radii [9].

541

542

Drilling and Well Completions

Compliance. The manufacturer is responsible for complying with all of the provisions of the specification. Supplementary Requirements Magnetic Particle Examination. All accessible surfaces of the main load carrying components of the equipment shall be examined by a magnetic particle examination method or technique conforming to the requirements of ASTM E709: "Recommended Practice for Magnetic Particle Examination." Acceptance limits shall be as agreed upon by the manufacturer and the purchaser. Liquid Penetrant Examination. All accessible surfaces of the main load carrying components of the equipment shall be examined by a liquid penetrant examination or technique conforming to the requirements of ASTM E165: "Recommended Practice for the Liquid Penetrant Examination Method." Acceptance limits shall be as agreed upon by the manufacturer and the purchaser. Ultrasonic Examination. Main load carrying components of the equipment shall be ultrasonically examined in accordance with applicable ASTM standards. The extent of examination, method of examination, and basis for acceptance shall be agreed upon by the manufacturer and purchaser. Radiographic Examination. Main load carrying components of the equipment shall be examined by means of gamma rays or x-rays. The procedure used shall be in accordance with applicable ASTM standards. Types and degrees of discontinuities considered shall be compared to the reference radiographs of ASTM as applicable. The extent of examination and the basis for acceptance shall be agreed upon by the manufacturer and purchaser.

Traceability. The

manufacturer shall have reports of chemical analysis, heat treatment, and mechanical property tests for the main load carrying components of the equipment.

Welding.

Where welding is involved in the critical load path of main load carrying components, recognized standards shall be used to qualify welders and procedures.

Extreme Low Temperature. Equipment intended for operation at temperatures below 0°F may require special design a n d / o r materials. Hoisting Tool Inspection and Maintenance Procedures Inspection Frequency of Inspection. Field inspection of drilling, production, and workover hoisting equipment in an operating condition should be made on a regular basis. A thorough on-the-job shutdown inspection should be made on a periodic basis, typically at 90 to 120-day intervals, or as special circumstances may require. Critical loads may be experienced; for example, severe loads, impact loads such as jarring, pulling on stuck pipe, a n d / o r operating at low temperatures. If in the judgment of the supervisor a critical load has occurred, or may occur, an on-the-job shutdown inspection equivalent to the periodic field inspection should be conducted before and after the occurrence of such loading. If critical

Hoisting System

543

loads are unexpectedly encountered, the inspection should be c o n d u c t e d immediately after such an occurrence. W h e n necessary, disassembly inspection o f hoisting equipment should be m a d e in a suitably e q u i p p e d facility.

Methods of Inspection. Hoisting e q u i p m e n t should be inspected on a regular basis for cracks, loose fits or connections, e l o n g a t i o n o f parts, and o t h e r signs o f wear, corrosion, or overloading. Any e q u i p m e n t showing cracks, excessive wear, etc., should be removed from service. T h e p e r i o d i c or critical l o a d inspection in the field should be c o n d u c t e d by the crew with the inspector. For the p e r i o d i c or critical l o a d inspection, all f o r e i g n m a t t e r should be r e m o v e d from surfaces i n s p e c t e d . Total field disassembly is generally not practical, and is not r e c o m m e n d e d , except as may be indicated in the detailed p r o c e d u r e for each tool. Equipment, if necessary, should be disassembled in a suitably e q u i p p e d facility and i n s p e c t e d for excessive wear, cracks, flaws, or d e f o r m a t i o n . C o r r e c t i o n s should be m a d e in accordance with the r e c o m m e n d a t i o n s o f the manufacturer. Before inspection, all foreign material, such as dirt, paint, grease, oil, scale, etc., s h o u l d b e r e m o v e d f r o m t h e i n s p e c t e d a r e a s by a s u i t a b l e m e t h o d . T h e e q u i p m e n t should be disassembled as much as necessary to p e r m i t inspection o f all l o a d b e a r i n g parts, a n d t h e i n s p e c t i o n s h o u l d b e m a d e by t r a i n e d , c o m p e t e n t personnel. Maintenance and Repairs A r e g u l a r preventive m a i n t e n a n c e p r o g r a m should be e s t a b l i s h e d for all hoisting tools. Written maintenance p r o c e d u r e s should be given to the crew or maintenance personnel. Maintenance p r o c e d u r e s should be specified for each tool, as well as the specific lubricants to be used, and should be b a s e d on the tool m a n u f a c t u r e r ' s r e c o m m e n d a t i o n . This r e c o m m e n d e d p r a c t i c e includes generalized p r o c e d u r e s that are c o n s i d e r e d a m i n i m u m p r o g r a m . Care should be taken that instruction plates, rating plates, and warning labels are not missing, damaged, or illegible. If repairs are not p e r f o r m e d by the manufacturer, such repairs should be m a d e in accordance with methods or procedures approved by the manufacturer. Minor cracks or defects, which may be removed without i n f l u e n c e on safety or operation o f the equipment, can be removed by g r i n d i n g or filing. Following repair, the part should again be inspected by an a p p r o p r i a t e m e t h o d to ensure that the defect has b e e n completely removed. Antifriction bearings play an i m p o r t a n t part in the safe p e r f o r m a n c e o f the tool. T h e most likely requirements for b e a r i n g placement are very loose or bent cages (retainers), corrosion, abrasion, inadequate (or i m p r o p e r ) lubrication, and spalling from fatigue. Excessive clearance may indicate i m p r o p e r adjustment or assembly and should be corrected. Repair o f antifriction bearings should not be a t t e m p t e d by field or shop personnel. Consultation with the equipment manufacturer is r e c o m m e n d e d in case o f unexplained or repeated bearing failure. If the tool or part is defective beyond repair, it should be destroyed immediately. Welding should not be done on hoisting tools without consulting the manufacturer. Without full knowledge o f the design criteria, the materials used and the p r o p e r procedures (stress relieving, normalizing, tempering, etc.), it is possible to reduce the capacity o f a tool sufficiently to make its continued use dangerous. Inspection and maintenance (lubrication) o f wire rope used in hoisting should be c a r r i e d out on a r e g u l a r basis. Wire r o p e i n s p e c t i o n a n d m a i n t e n a n c e

544

Drilling and Well Completions

recommendations are included in API RP 9B, "Application, Care and Use of Wire Rope for Oil Field Service" (see "Wire Rope").

Inspection and Maintenance Illustrations Figures 4-19 through 4-36 are self-explanatory illustrations of generalized inspection and maintenance recommendations for each of the hoisting tools.

Wire Rope Wire rope includes (1) bright (uncoated), galvanized, and drawn-galvanized wire rope of various grades and construction, (2) mooring wire rope, (3) torpedo lines, (4) well-measuring wire, (5) well-measuring strand, (6) galvanized wire guy strand, and (7) galvanized structural rope and strand [11,12].

Material Wire used in the manufacture of wire rope is made from (1) acid or basic open-hearth steel, (2) basic oxygen steel, or (3) electric furnace steel. Wire tested before and after fabrication shall meet different tensile and torsional requirements as specified in Tables 4-9 and 4-10. (text continued on page 563)

Sheave groove wear and cracks (See RP-9B) \

~ ~ - ~

~

Grease fittings

Loose

fasteners

Cracks and deformation Check all welds Loose f a s t e n e r s MAINTENANCE: 1. Keep clean. 2. Lubricate bearings. 3. Remove any rust and weather protect as 4. Check and secure all fasteners.

required.

Figure 4-19. Crown block [10].

Hoisting System Weor ond crocks Sheove groove weor Sheove wobble ond beoringweor ~

~

¢"~.

/

~-~\'~"~

~

ii

.oZT ,oo

"v-~----Weor ond crocks

~---Weor ond crocks

MAINTENANCE: 1. Keep clean. 2. Lubricate bearings: 3. Remove any rust and weather protect as required. 4. Check and secure all fasteners. F i g u r e 4-20. Traveling block [10].

Reduction of body section

Weor ond crocks

se possoge ~'Weor ond crocks ~

MAINTENANCE: 1. Keep clean. 2. Grease coat wear surface of clevis. 3. Remove any rust and weather protect as required, 4. Check and secure all pins. F i g u r e 4-21. Block-to-hook adapter [10].

545

546

Drilling and Well Completions

[~~_~.......--~ I J-

)~

Fluld leaks (units with hydraulic snubber

J

Excessive effort to rotate (if so equipped )

J

~J~

Pin wear and pin r e t a i n e r / ~ / / ~ ' ~

Wear an~ ~racks

in pin holes

/

/

Loose

pin retainers

"Wear and cracks

f'-ll~) ~ ~' ..j~'~

Weor

MAINTENANCE: 1. Keep clean. 2. Grease coat wear surfaces. 3. On units with hydraulic snubber check oil level and change oil at intervals recommended by manufacturer. 4. Oil pins not accessible to grease lubrication. 5. Remove any rust and weather protect as required. 6. Check and secure pins and fasteners.

Figure 4-22.

Link a d a p t e r [10].

Pin Wear and crocks Pin fit and crocks Excessive extension from borret I,condltion of sprlng) Freedom af tongue _ and latch operation

Fluid leak (units with hydraulic snubber ) "-/ Excessive effort to rotate Lubrication

~'

MAINTENANCE: wear and crocks 1. Keep clean. 2. Grease coat latching mechanism, link arms, and saddle. 3. Lube all grease fittings. 4. On units with hydraulic snubber check oil level and change oil at intervals recommended by manufacturer. 5. Oil pins not accessible to grease lubrication. 6. Remove any rust and weather protect as required. 7. Check and secure pins and fasteners.

Figure 4-23.

Drilling h o o k [10].

Hoisting System

S

Lubrication Condition of

ot and crocks

I~L~Crocks

in lost threod

/-~ /

Excessive effort to rotote

spring

I

Crocks Lotch ond lever operotion

Z-Crocks ond weor

MAINTENANCE: 1. 2. 3. 4. 5. 6.

Keep clean. Grease coat latching mechanism, hook, and bail throat. Grease main bearing. Oil pins not accessible to grease lubrication. Remove any rust and weather protect as required. Check and secure pins and fasteners.

Figure 4-24. Tubing and sucker rod hook [10].

°\ "!{

Thickness is measured ot top of upper eye with calipers

Weor point A To determine strength of worn links, measure with colipers. Link copocity is thot of weokest eye. Consult monufocturer for roting.

Check ENTIRE link for crocks

O

Thickness is meosured ot bottom of lower eye with colipers

~J Wear point B MAINTENANCE:

PLAN

SECTION

1. Keep clean. 2. Grease coat upper and lower eye wear surfaces. 3. Remove any rust and weather protect as required.

Figure 4-25. Elevator link [10].

547

548

Drilling and Well Completions

-Body cracks and gage

a~..,..,~_ ~ Cracks and we in latch

//-Wear

ofh pins o l e Sends) and (both

~'~

Cond"ih'on of should er

.Broken springs

'---Caliper for wear and check for cracks (both ends)

MAINTENANCE: 1. Keep clean. 2. Grease coat link arm wear surfaces, latch lug and bore seat on bottleneck elevators. 3. Lubricate hinge pin. 4. Remove any rust and weather protect as required. 5. Check and secure pins and fasteners.

Figure 4-26a. Casing, tubing, and drill pipe elevators, side door elevators [10]. Wear of pins and holes.-~

\~) ~

Br°kc~22; ~rings a nwear, d n, ~ d y

~ l----'Ca~ioPre:raf°;s~e;arthn:ndhs;Ck

c~rocks

gacje for wear MAINTENANCE: 1. Keep clean. 2. Grease coat link arm wear surfaces, latch lug and bore seat on bottleneck elevators. 3. Lubricate hinge pin. 4. Remove any rust and weather protect as required. 5. Check and secure pins and fasteners.

Figure 4-26b. Casing, tubing, and drill pipe elevators, and center latch elevators [10].

HoistingSystem 549 --

Wear of pins and

Grease back surface of slips

~

7----Check for broken springs

~

~

Cihb~Pthk!drre~)eaakand

Broken springs~ ~ C r a c k wea~/~--s and i°ilYiil(t~ktsh-~igdaecJse)fOr MAINTENANCE: Check slips -1. Keep clean. 2. Grease coat link arm wear surfaces and latch lug. 3. Lubricate hinge pin. 4. Remove any rust and weather protect as required. 5. Clean inserts. Replace when worn. 6. Tighten all loose fasteners. Figure 4-26c. Casing, tubing, and drill pipe elevators, slip type elevators [10].

' Wear and cracks

Lotphration

/ Wear and cracks

~

Freedom to rotate

Loose fasteners or pin retainers -~__=

Lever operation

Wear and cracks at base of trunnion and eye of ball MAINTENANCE: 1. Keep clean. 2. Grease coat rod seating area, bail throat and latch mechanism. 3. Oil pins not accessible to grease lubrication. 4. Remove any rust and weather protect as required. 5. Check and secure pins and fasteners. Figure 4-27. Sucker rod elevators [10].

550

Drilling and Well Completions

~Toper

wearandcrocks

Reductionof area Crocks ear and cracks

anddeformation /4 Loose tosteners-~ MAINTENANCE: 1. Keep clean. 2. Lubricate pivot and pin. 3. Remove any rust and weather protect as required. 4. Check and secure pins and fasteners. Figure 4-28. Swivel bail adapter [10].

Wear and c r o c k s - - ~ 8oIts~, Packing Crocksand deformation Pin wear Pin retainer Crocks

•

~Threods Crocks

~ ~-L ~'~~--~

'~

Crocks Bolts

Inspectp" and box

MAINTENANCE: 1. 2. 3. 4. 5. 6. 7. 8.

tool joints Keep clean. Grease coat bail throat wear surface. Lubricate bail pins, oil seals, upper bearing, and packing. Check oil level as recommended by manufacturer. Change oil at intervals recommended by manufacturer. Remove any rust and weather protect as required. Check and secure fasteners. Protect threads at the gooseneck inlet and on the coupling nipple when not assembled during handling. Thread protection should be used. Figure 4-29. Rotary swivel [10].

Hoisting System

551

racks

/ / /

/{

'-Wear

Check top and bottom diameters and taper for wear

to _1 __J joints hitting hitt r Maximumr= suggested I.D. wear in the t h r o a t Consult manufacturer

L- Cracks

MAINTENANCE: 1. Keep clean. 2. Lubricate taper before each trip. 3. Remove any rust and weather protect as required.

Figure 4-30. Spider [10],

Wear-Loose fasteners ~ _

Cracks and ~

~

~

,,~

,~~--~'~

~"X~

//~.

"~J'/J?/fT"~/J/

,

o, o,vo, I J"

Loose fasteners ~

)/

movementand bearing wear

MAINTENANCE: 1. Keep clean. 2. Grease coat surface of wire line spool. 3. On units equipped with load cell for weight indicator, lubricate pivot bearing. 4. Remove any rust and weather protect as required. Figure 4-31, Deadline anchor [10].

55£

Drilling and Well Completions

~

Shoulder domo0e- - - ' - ~ "

- -Crocks in lost thread

accordance with manufacturer's recomendotions Thread domocJe~

Freedom of shaft to rotate

inspect pin and box in accordance wlth'API RP-7G for tool joints MAINTENANCE: 1. Keep clean. 2. Use thread compound on pin and box, and apply proper makeup torque in accordance with API RP-7G recommendations. 3. Maintain power unit in accordance with manufacturer's recommendations. 4. Remove any rust and weather protect as required. 5. Check and secure fasteners.

Figure 4-32.

Kelly spinner [10].

The load corryincJ structure should be checked for crocks and deformation. All fasteners should be checked for proper tightness.

,4,

t-Check top and bottom diameters and taper for wear

Maximum = g e s t e d ~ wear in the t h r o a t consult manufacturer MAINTENANCE: 1. Keep clean. 2. Remove any rust and weather protect as required. F i g u r e 4-33. Rotary table [10].

Check master bushincJ O.D. and turntable bore for wear

Hoisting System

555

INSPECTION: Heave compensator designs vary considerably among manufacturers, therefore, manufacturers' recommendations should be closely followed. In general, load carrying members should be checked for wear, cracks, flaws, and deformation. For compensators with Integral traveling block and hook adaptor, the procedures defined in Figures. 4-16 and 4-17 apply to those parts of the assembly. MAINTENANCE: 1. Keep clean. 2. Follow manufacturer's recommendations for specific unit. 3. For compensators with integral traveling block and hook adaptor, the procedures in Figures. 4-16 and 4-17 apply to those parts of the assembly. 4. Remove any rust and weather protect as required. Figure

4-34. Heave compensator [10].

Ref. 4, p. 23 INSPECTION: Tension members for sub sea handling equipment should be inspected according to the manufacturers' recommendations. In general, tension members should be checked for wear, cracks, reduction of area and elongation. MAINTENANCE: 1. Tension members in sub sea handling equipment should be maintained in accordance with manufacturer's recommendations. Figure

4-35. Tension members of subsea handling equipment [10]. Straight edge

-

©

Hinge pin check for wear ~

Insert slot check for wear /

. .~

ked wet:

_ :

Bent

=

MAINTENANCE: 1. Keep clean. 2. Check the insert slots for wear and replace inserts as required. 3. Lubricate hinge pin. 4. Remove any rust and protect as required. 5. Use straight edge to detect uneven wear or damage. 6. Caution: Do not use wrong size slips--Match pipe and slip size. Figure

4-36. Rotary slips [10].

554

Drilling and Well Completions

Table 4-9 Mechanical Properties of Individual Rope Wires (After Fabrication) [12] (I)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

Levi 2

Wive Size Nominal Diarne~r in ~

(9)

(10)

(II)

(I2)

(17)

(I9)

(20)

(21)

Drawn-G*dvanlzed Breaking Strength Individual A~rag¢ Minimum Minimum Ib N Ib N

Drawn-GaIvanized BRaking Stn:ng~h Individual Av~¢ Minimum Minimum lb N Ib N

Breaking S~ngth IndividoM Average Minimum Minimum Ib N Ib N

Min. "for.

Min, T~.

196 144

45

2~)

47

209

50 57 65 73 $1

222134 254126 2891I$ 325112 360106

52 59 66 74 83

231 262 294 329 369

54 62 70 78 87

240 II7 276 I09 3 I t 103 34797 38793

89 98 108 ]]8 I28

396100 43695 48090 525 86 569 82

92 100 II0 121 132

409 445 489 538 587

96 106 ]I6 ~27 138

427 87 471 83 51679 565 75 6147I

56~5 . . . . . . . . . . . . . . . . . . . . . . . . . 85 143 636 I51 672 75 154 685 162 82 154 685 I62 721 72 t66 738 174 79 i66 738 174 77469 178 792 188 76 ]77 787 I87 832 66 19I 850 201

6~5 721 77463 83660 89458

805

956

93222 i l l 202 133185 156 I71 178 I59

0.015 0.38 0.016041 00170.43

38 43 49

I69 40 19145 2I$ 51

178 16i 200150 227142

44 50 56

I96 22252 249

46 58

205 148 23I 139 258130

0.018 0.46

55

245

57

254

62

276

66

294

0.0190.48

60

267

64

285126

70

31I

74

329117

0.020 0.5I 0,02I 0.53 0.0220.56 0.023 0.58 0,0240.61

67 74 81 89 97

298 329 360 396 431

71 78 85 93 10]

316 120 347 I14 378109 4]4 105 449 IGO

77 85 94 ]02 IH

342 378 418 454 494

81 89 98 108 II7

360 396 436 480 520

0.0250.64 0.0260.66 0.0270,69 0,0280,71 00290,74

104 113 122 I31 140

5463 543 583 623

...... 119 128 t37 148

529 569 609 658

88 86 83

. . . . . . 130 578 ]40 623 151 672 162 721

I36 148 159 I70

658 707 756

134

~9~

0.030 0.76

150

667

158

703

80

173

770

181

0.03I 0.79 0.0320.81 0,0330.84 0,0340.86

160 17I 18I 192

712 761 805 854

168 179 19I 202

74777 796 74 850 72 898 70

184 196 209 22I

818 872 930 983

194863 206 9]6 219 974 233 L036

907

214

1,04I

246

215

956

227

l.OlO

67

248

I.I03

260

227 240 253

204

1.010 L065 1,125

239 252 265

1.G63 LI21 LI79

65 63 61

26I 276 29t

1,161275 1,225 290 1.294 305

0.0401.022695 0.0411.04 0.0421.07 293 0.0431.09 3(16 0.0441.I2 320

......... 1.241 1.303 L36I 1,423

293 308 322 336

.241 ~9 1,303 L370 56 L43255 L495 54

0,04.....

1.486

334

952

. . . . . 566

68

234

124

I10 I05 ]01 96 92

]87

48 55 61 69 77

214 245 271 307 342

85 94 102 H2 ]22

378 418 454 498 543

31 36

73

190

71 68 67 65244

203 215 229

845

200

903 213 956 227 1.019 24I L085256 271

890

205

912

218 232 247 261

970 L032 1,099 1,16I

230 1 . 0 2 3 5 4 244 1 . 0 8 5 5 1 259 L 1 5 5 0 5 0 275 L223 .*9

1,094

63

257

L143

1,205

54

277

1.232

29I

1.156

61

273

1.214

287

1.277

52

293

1.303

309

1,223 1,290 1.357

59 58 56

288 303 319

1,281 1,348 L419

302 319 335

1.343 50 1.419 49 L49047

309 326 343

1,374325 1,450 342 L526 361

44~35 L646 L726 1,81042 1.8904[

.... "378 397 416 436

606 1,65t 1,766 1.850 L939

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 321 1,428 337 1,499 53 352 1.566 370 336 1,495 354 L575 52 370 1.646 388 352 L566 370 1.646 50 387 L72I 407 369 1,64I 387 L72149 405 LS01 425 385

1. . . . . . . . . .

416

4~ ..... 437 455

1.788 422 8644~ L944 2.024 479

1,87748 1.96247 2,042 46 2,13145

433 450

L926 2,002

48 47

474 492

2.}06 2,188

2.215 44 2.30443

.... 2.055 4792.]31

4~ 503

2.0774~5 2.|62 2,237 44

.... 531 551

,2. . . . . . . . . . . . 2,362 559 2,486 2.451 579 2.575

4I 40

4962.206 515 2.291 532 2,366 55I 2,45I 569 2,531

522 541 560 579 599

2.322 2,406 2.491 2,575 2.664

43 42 41 41 dO

571 592 612 634 655

2,540 foOl 2.633 622 2,722644 2,820 666 2.913689

2.673 2.767 2.865 2,962 3,065

39 39 38 37 36

0.060 . . . . ~ 2.620 ~ 0.061 L55 2,704 0,G621.57 628 2.793 6~t 0.G63 L60 6482,882682 0.(~41,63668 2.971 702

2.753339 2,847 2.936 38 3.034 37 3.122 36

..... 700 722 745 768

0.......... 3.114 736 3.211 760 3.314 783 3.416808

33~ 3.274 3,380 35 3.483 34 3.59433

. . . . . . . . . . . . . . . . 769 3.421 809 3.598 27 795 3.536 835 3.714 27 820 3,647 862 3.83426 845 3.759 889 3.95426

0.G651.65 0,(1661.68 0.~671,70 0.068173 0.0691.75

689 3.(165 7103.158 731 3.251 753 3349 7743.443

725 746 769 791 814

3.225 3.318 3.421 3.518 3,621

36 35 35 34 34

793 816 840 865 890

3.527 833 3.630 858 3.736 884 3.848 909 3.959936

3,7(~ 3.816 3.932 4,043 4,163

33 32 32 31 31

872 898 924 952 979

0,0701.78 0.07I 1.80 0.0721.83 0.073 L 8 5 8 6 4 0.0741,88

797 819 841

837 86I 885 908 933

3.723 3.830 3,936 4*039 4,150

33 33 32 32 3I

916 942 967 994 1,021

4.074 962 4.190990 4,30I 1,017 4,421 1.044 4.541 1.073

4,279 30 4,404 30 4,52429 4,644 29 4.77329

4,257 31 4372 30 4.484 30 4.595 29 4.71529

1,047 1,075 1.103 1.131 1.159

4,657 4,782 4.9(36 5.031 5.155

4,897 29 5.03129 5.155 28 5.289 28 5,42227

0.0501,27 0.0511.30

41I 428

....... 0.053 L35 0.0541.37

~

0.055 L40 0.056 L42 0.0571.45 0.058 L47 0.0591.50

887

1.828 1,904

3,545 3,643 3.741 3.843 3.945

91I 4,052 957 935 4,I59 983 958 4.261 IJX~ 9834.3721.033 1.0~ 4,4841.060

498 518

I,]01 1,131 LI59 1,I89 1.219

48

126

64

52

367 ~

215

ll1176 133160 156146 182 I35

94762 1.010 59 1,072 57 1,I39 56

1.6325I 1.70445~9 L779 1.850 48

0.0461.17349 1,552 ........ 33651.624 0.0481.22 1.690 0.0491.24 396 1.761

25 30 35 41

Min. T~.

44

21 25 30 35 40

42

Min. Tot.

102 125 147 I73

89 I02 125 I47 169

23 28 33 38

Drawn .Galvanized

23 28 33 39

20 23 28 33 38

93 116 138 160

(22)

102202 125183 147168 169155

7624I 98219 11620I 133 ]85 I56172

0.0751.91 0.0761.93 0.0771.96 0.078 L98 0.0792.01

(t8)

D~awn-Galvanized Bwatking Stl~ nbqh Individual A~mge Minimum Minimum Ib N Ib N I7 22 26 30 35

0,91

(16)

Lev~ 5 Brigh[ (Uncoated)

76 89 107 125 147

00350,89

(15)

Level 4 Brighl (U~oated)

17 20 24 28 33

0.0370.94 0.0380.97 0,0390.99

(14)

Level 3 Bright (Uncoated)

0.0100.25 0,01I 0,28 0.0120.30 0.0130.33 0.0140.36

0036

(I3)

Brigt~ (Uncoated)

...............

40

455

55

1,29447 L374

45

1,44643 L521 43 1,6(1641

...... 334079 398 1,770 417 1.855 438 1 . 9 4 8 3 6 4582.03736

2. . . . . . . . . . . . .

442 1.966 464 2,06439 475 2.113 4992,22034 46 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 481 2.I39 5C5 2.246 37 517 2,3G0 5432.41532 5(30 2.224 526 2,34036 538 2 . 3 9 3 5 6 6 2.51832 521 541

2.317 2.406

2,433 2.531

35 34

560 582

5563

33~

605

. . . . . . . . . 2.598 614 2,731 2.691 637 2,833

547 569

60. . . . . . 628 2,793 651 2.896

.... 2,936 6853,047

628 650 674 697 72I

2,793 660 2.891 684 2.998708 3A00 733 3,207 757

676 700 724 750 775

3.007 3.114 3.220 3,336 3,447

7103,15827 736 3,274 27 7623.38926 7883.505 8153,625

880~

.............. 3.678 8693.86523 3.799 8983.99423 3.919 9274,123 4.043 9554.248

32

2,936 31 3,042 31 3,149 30 3,26029 3,367 29

854 88I 909

2.49I 2,589

5882,61531 6122,72230 ~6~

22~8

2~

3.879 916 3,994944 4,110 972 4,234 L000 4,355 L029

4.074 4.199 4,323 4,448 4,577

25 25 24 24 23

937 965 994 L023 L053

4.168 4.292 4.42! 4,550 4.684

985438122 22 1.0154,515 L0.M 4 , 6 4 4 2 1 1.0754.78221 1,1074.92420

I.G07 1.035 I,(~4 L093 1.122

4.479 4,604 4.733 4.862 4,991

1.059 1.G~i9 1.118 L149 1,180

4.710 4.844 4,973 5.Ill 5.249

23 22 22 22 21

1.063 I.II3 1.144 L175 L207

4.817 4,951 5,089 5,226 5,369

1,139 5.066 1.171 5.209 L2025.346 1.2355.493 |.2695,645

~9

1,152 1.183 L213 L244 1.275

5.124 5.262 5,395 5,533 5.671

L212 1.243 L275 1,3~ L34I

5,391 5.529 5,67! 5,818 5,965

21 20 20 20 19

L239 L271 1.34)4 1.337 L37I

5,511 5.653 5,800 5.947 6.098

L3035.796 1.3375.947 1.3706,094 1/~56,249 1,441 6.410

I8 18 17 I7 ]7

19 18

Hoisting System

555

Table 4-9 (continued) (I)

(2)

(3)

(4) (5) Level 2 Bright ( U ~ . ~ t )

(6)

(7)

(8)

(9) (I0) Level 3 Bright (Unco~d)

(II)

(12)

(13)

04) (15) Level 4 Bright ( U ~ o a ~ )

(16)

(17)

(18)

(19) (20) Level 5 Bright (Uncoated)

(21) (22)

W'ue Size Nominal ~ r in. mm 0.080 2.03 0.081 2.06 0.082 2.08 0.083 2AI 0.084 2A3

Drawn.3al~ized Bl~,akingStrength Individual Average Minimum Minimum Mill. lb N lb N Tot. 1,033 4,595 ],4~5 4,826 29 1.058 4.706 1,112 4,946 29 1.083 4,817 IA39 5.066 29 1,110 4,937 IA66 5A86 28 1.136 5,053 1,194 5,311 28

Drawn~tlvardzed Breaking Stlength ludividual Average Minimum Minilmlm Min. Ib N Ib N Tot'. 1,]88 5,284 1,248 5.551 27 1217 5,413 1.279 5.689 27 1246 5.542 1.310 5.827 26 1,276 5,676 L342 5,969 26 1,3G6 5,809 L372 6,103 26

Dm.wn~alvanized BreakiBg~ Indi~du~ Averege Minimum Minimum Min. lb N lb N Tot'. 1,307 5,814 1,374 6,112 19 1,339 5.956 1.407 6,258 19 1,371 6,098 L44l 6,410 18 1,404 6245 1.476 6,565 18 1.436 6387 1.510 6,716 18

Drawn-Gslvanized BtP.alcingS t r e ~ Ind~u~ Avera~ Minimum Minimum Min. lb N lb N Tot. ]?/05 6,249 1,477 6,570 16 1,439 6,401 L513 6,730 16 1,473 6.552 1.549 6,890 16 1.509 6,712 1,557 7.059 16 1,544 6,868 L624 7.224 ]5

0.085 0.086 0.087 0.088 0.089

2A6 2.18 2.21 2.24 2.26

1.162 1,189 1,216 1,243 1270

5.169 1222 5,435 5289 1249 5,556 5,409 L278 5,685 5:529 1.307 5.814 5,649 1.336 5,943

28 27 27 27 26

1,337 1,367 1,398 IA29 1,462

5,947 6,080 6,218 6,356 6,503

1.405 1,437 1,470 ],503 ].536

6,249 6,392 6:539 6,685 6.832

25 25 25 24 24

1,470 1,503 1.538 1,573 1,607

6:539 6,685 6.841 6.997 7.148

t,546 1,58t 1,616 1,653 1,689

6,877 7,032 7.188 7,353 7:513

18 18 18 17 17

1.580 1.617 1,654 1,691 L728

7,028 7.192 7,357 7,522 7.686

L662 ].699 1.738 1,'777 1,816

7,393 7,557 7,731 7,904 8.078

0.090 0.091 0.092 0.0f6 0.094

2.29 2.31 234 2.36 2.39

1299 1.326 1.355 1.384 1.413

5,778 5.898 6J~7 6.156 6,285

L365 1,394 1,425 1,454 1,485

26 26 25 25 25

1,493 1,525 1,558 1:591 1,624

6,641 6,783 6*930 7,077 7,224

1,569 1.603 1.638 1.673 1.708

6.979 7.130 7286 7.442 7.597

24 23 23 23 23

1,6,42 1.678 1.714 1.750 1.786

7,304 7.464 7.624 7.784 7,944

L726 1,764 1.802 1,840 L878

7,677 7.846 8,015 8,184 8.353

17 17 16 16 16

L766 1,804 1,843 1,882 1,921

7,855 8,0~4 8,198 8~371 8~545

1,856 1.896 1.937 1.978 Z019

8~255 15 8~433 15 8,616 14 8.798 14 8,981 14

0.095 0.096 0.097 0,098 0.099

2.41 2.44 2.46 2,49 2.51

1,442 h471 1.501 1.531 1.561

6,414 6,543 6,676 6,810 6.943

l:516 6,743 1,547 6,88! 1,577 7,014 1,609 7,157 1,641 7,299

24 24 24 24 23

1,658 1,692 1.726 h761 1.795

7,375 7,526 7,677 7.833 7,984

1.743 1.778 1,814 1.851 1,887

7.753 7,909 8,069 8,233 8,393

22 22 22 22 21

1,823 1.861 1.898 1,936 1,975

8,109 8278 8.442 8,61I 8.785

1,917 1,957 1,996 2.036 2'077

8.527 8,705 8,878 9,056 9238

16 15 15 15 15

1,961 2,001 2,041 2,082 Z123

8,723 8.900 9,078 9,261 9,443

2,061 2,103 2.145 2,188 2,231

9.167 9,354 9,541 9,732 9,923

14 13 13 13 13

0.100 0.10I 0.10~ 0.103 0A04

2.54 2.57 2.59 2.62 2,6,4

1:592 1,622 1,654 1.685 1.717

7,081 7.215 7,357 7,495 7.637

1,674 1,706 1.738 1.771 1.805

7.446 7.588 7,731 7,877 8,029

23 23 23 22 22

1.830 1,866 1,902 1,938 1,974

8,140 8,300 8,460 8.620 8,780

1,924 1.962 2,0(]0 2038 2.076

8,558 8~727 8~896 9.065 9234

21 21 21 20 20

2'013 2'052 2'092 2,131 2.172

8,954 9.127 9,305 9,479 9.661

2.117 2'158 2'200 2,~ll 2284

9.416 9:599 9.786 9,968 10.159

15 15 I5 15 15

2.165 2.206 2,249 2,291 2,335

9,630 9,812 I0.CO4 10,190 10,386

2,276 2,320 2,365 2,409 2,455

10.124 10,319 10,520 10.715 10,920

13 13 12 12 t2

0.105 0.106 0.107 0.10~t 0,109

2.67 2.69 2.72 2.74 2.77

1.749 1,781 1,814 1,847 1.880

7.780 7.922 8,(~9 8215 8.362

1.839 1.873 1,907 1,941 1.976

8,180 8,331 8,482 8,634 8.789

22 22 21 21 21

2,011 2.048 2.086 2.124 2.162

8,945 9,110 9.279 9.448 9,617

2.115 2,154 2'[92 2,232 2,272

9,408 9.581 9,750 9.928 10.]06

20 20 20 19 19

2,212 2,253 2,294 2,336 2,377

9,839 10,021 10204 10"391 10,573

2,326 2,369 2.412 2.456 2.499

10.346 10.537 10,729 10,924 1I,I16

14 14 14 14 14

2,378 2,422 2.466 2,511 2,555

10,577 10,773 10.969 11.169 11.365

2,500 2,546 2.592 2,639 2,687

11,120 11.325 11,529 11.738 11.952

12 12 12 12 12

0.110 0.111 0.112 0.113 0.I14

2.79 2.82 2.84 2,87 2.90

1.913 1.946 1,980 2,014 2,048

8,509 8,656 8.807 8,958 9,110

2,011 2,046 2,~2 2.118 2.1,54

8~945 9,101 9,261 9.421 9.581

21 2] 20 20 20

2,200 9.786 2,312 2,239 9,959 2.353 2,278 10,133 2.394 2,317 10,306 2.435 2*356 10,479 2,476

10284 10A66 10,649 10,831 11,013

19 I9 19 18 18

2,420 2,462 2,505 2.548 2,592

10,764 I0,951 II,142 11.334 1I:529

2.544 2,588 2'633 2,678 2.724

11,316 [1,511 11.712 11,912 12.116

13 13 13 13 13

2,601 2,647 2,693 2,739 2.786

11,569 11,774 11,978 12.183 12,392

2.735 2,783 2,831 2.879 2.928

12,I65 12 12,379 12 12'592 12 12.806 11 13.lP.,4 I1

0.115 0.116 0.I17 0.118 0.119

2.92 2.95 2.97 3.00 3.02

2'084 2,118 2.154 2.189 2224

9270 9,421 9,581 9,737 9,892

2.190 9,741 2,226 9,90I 2264 10,070 2.301 10,235 2*338 10,399

20 20 19 19 19

2,396 2,436 2.477 2:517 2:558

2.518 2'.YoO 2.604 2.647 2.690

11,200 11.387 11:583 11,774 11,965

18 t8 18 17 17

2.635 2'679 2.724 2,769 2,814

11,720 11,916 12,116 12.317 12.517

2.771 2.817 2.864 2,911 2.958

12.325 12`530 12.739 12,948 13.157

13 12 12 12 12

2'833 2.880 2'928 2.977 3,024

12.601 12,810 13.024 13,~12 13,451

2.979 3.028 3,078 3,129 3.180

13,251 13.469 13.691 13.918 14,145

11 I1 11 11 11

0,120 0.121 0.122 0.123 0.124

3.05 3,07 3.10 3.12 3,15

2,260 2296 2,333 2.370 2,4~6

10,052 10213 10,377 10,542 10.702

2.376 2,414 2.453 2,492 2,530

10,568 10,737 10,9ll 11,~84 11,253

19 19 18 18 18

2.599 11,560 2'641 11,747 2,683 ti,934 2.725 12,121 2.768 12,312

2,733 2'777 2.821 2'865 2,910

12,156 12,352 12,548 12.744 12,944

17 17 17 17 17

2'860 2,906 2,951 2*998 3,045

12.721 12.926 13.126 13.335 13,544

3,006 3,055 3.103 3.152 3,201

13,371 13:589 13.802 14.020 14238

12 12 11 II 11

3.074 13,673 3.123 13.891 3,173 14,114 3,222 14.331 3,273 14.558

3232 3,283 3.335 3*388 3,44l

14,376 14,603 14,834 15.070 15,306

10 10 10 190

0.125 0.126 0.127 0A28 0.129

3A8 3.20 3.23 3.25 3.28

2,444 2,481 2,519 2.557 2.595

10,871 11,035 11205 11.374 11.543

2:570 2,609 2,649 2.689 2.729

11.431 11,605 11.783 11,961 12,139

18 18 18 17 17

2.811 12,503 2,854 12.695 2,897 12,886 2'941 13.082 2.984 13.273

2,955 3,0GO 3,045 3,091 3.138

13.144 13,344 13,544 13,749 13.958

16 16 16 16 16

3.092 3.140 3,187 3,235 3,284

13.753 13,967 14.176 14.389 14.607

3.250 3,30[ 3,351 3.401 3,452

14A56 14,683 14,905 I5,128 15354

II 11 11 10 10

3,324 3.374 3.426 3,478 3.530

14,785 15,008 15,239 15.470 15.701

3,494 3,548 3.602 3,656 3,711

I5,541 15,782 16,0~2 16.262 16.507

9 9 9 9 9

0.130 0.131 0.132 0.133 0.134

3.30 3.33 3.35 3.38 3,40

2.634 2.672 2,711 2,751 2.790

11.716 11.885 12.059 12,236 12,410

2.770 2,810 2,851 2.893 2,934

12,321 12,499 12.681 12,868 13,050

17 17 17 17 17

3,029 13,473 3,074 13.673 3,119 13,873 3.164 14,073 3210 14.278

3.185 3,232 3,279 3.326 3,374

14,167 14.376 14:585 14.794 15,008

16 16 15 I5 15

3.333 3,381 3.431 3,481 3,530

14,825 15.039 15261 15.483 15.701

3.503 3.555 3,607 3.659 3.712

15:581 I5,813 16,044 16275 16.511

10 10 10 l0 9

3,582 3.635 3.687 3.741 3.795

15.933 16.168 I~ 16,640 16.880

3,766 3,821 3.877 3,933 3,989

16,751 16,996 17,245 17,494 17,743

9 8 8 8 8

0.135 0.136 0.137 0.138 0.139

3.43 3.45 3.48 3.51 3.53

2.830 2,870 2,911 2,951 2.992

12.588 12,766 12.948 13.126 13,3(]@

2.976 3,018 3,061 3,103 3,146

13237 13,424 13,615 13.802 13,993

16 16 16 i6 16

3256 14,483 3,301 14,683 3347 14,887 3,394 15,097 3,441 15,306

3,422 3,471 3,519 3,568 3,617

15,221 15,439 15.653 15.870 16.088

15 15 15 15 14

3.580 3.631 3.683 3.733 3.785

15,924 16,151 16.382 16,604 16,836

3.764 3,817 3,87I 3,925 3,979

16.742 16,978 I7218 17,458 17,699

9 9 9 9 9

3,849 17,120 3.904 17,365 3,959 17,610 4,014 17,854 4,069 18,099

4,047 4,104 4,162 4,220 4,277

18,001 18,255 18,513 18,771 19,0~.4

8 8 8 8 8

0.140 0.141 0.142 0,143 0.144

3.56 3.58 3.61 3.63 3.66

3,033 3.074 3,116 3,158 3200

13,491 13,673 13.860 14.047 14234

3,189 3,232 3276 3,320 3,364

14,185 14,376 14~572 14,767 14,963

16 16 16 15 15

3,489 3*535 3,583 3.632 3.680

15.519 15,724 15.937 16,155 16,369

3,667 3,717 3.767 3,818 3,868

16.311 16,533 16,756 16,982 17,205

14 t4 14 14 14

3.837 3.889 3.942 3.995 4,048

17.067 17,298 17,534 17,770 18,006

4.033 4,089 4,144 4,199 4,256

17,939 18,188 18,433 18,677 18,931

8 8 8 8 8

4,125 18~348 4.181 I8:597 4,237 18,846 4,294 19,1130 4,351 19.353

4.337 4,395 4.455 4:514 4:575

19.291 19,549 I9,816 20,078 20.350

7 7 7 7 7

0.145 0.146 0.147 0.148 0.149

3,68 3.71 3.73 3.76 3.78

3242 3285 3,328 3.371 3A13

14,420 14.612 14,803 14.994 15,181

3,408 3.453 3,498 3.543 3,589

15,159 15,359 15,559 15,759 15.964

15 15 15 15 15

3,728 3,777 3,827 3.876 3,925

I6,582 16.800 17.022 17,240 17,458

3.920 3.971 4~0~3 4,074 4,127

17,436 17,663 17,894 18,121 18,357

14 14 14 13 13

4.102 4,155 4.209 4.264 4,318

18,246 18,481 18.722 18,966 19,206

4,312 4,369 4,425 4,482 4,540

19,180 19,433 19,682 19,936 20,194

8 8 8 8 7

4,409 4,466 4,525 4,583 4,6,42

4.635 4,696 4.757 4,819 4.880

20,616 20.888 21,159 21,435 21.706

7 7 77

6,072 6,201 6,338 6*467 6*605

10,657 10,835 11,018 11,196 11,378

19,611 19,865 20.127 20.385 20,648

15 J5 15 15 15

6

556

Drilling and Well Completions Table 4-9 (continued)

(1) (2)

Wire Size Nominal Diameter in. mm 0.150 3.81 0.151 3.84 0.152 3.86 0.153 3.89 0.I54 3.91 0.155 3.94 0.156 3.96 0.167 3.99 0. I58 4.01 0.159 4.04 0.160 4.06 0.161 4.09 0.162 4.11 0.163 4.14 0.164 4.I7 0.165 4.19 0.166 4.22 0.167 4.24 0.168 4.27 0.169 4.29 0.170 4.32 0.171 4.34 0.172 4.37 0.173 4.39 0.174 4.42 0.I75 4.45 0.176 4.47 0.177 4.50 0.178 4.52 0.179 4.55 0.180 4.57 0.181 4.60 0.182 4.62 0.183 4.65 0.184 4.67 0.185 4.70 0.186 4.72 0.187 4.75 0.188 4.78 0.189 4.80 0.190 4.83 0.191 4.85 0.192 4.88 0.193 4.90 0.194 4.93 0.195 4.95 0.196 4.98 0.197 5.00 0.198 5.03 0.199 5.05 0.200 5.08 0.201 5.11 0.202 5.13 0.203 5.16 0.204 5.18 0.205 5.21 0.206 5.23 0.207 5.26 0.208 5.28 0.269 5.31 0.210 5.33 0.211 5.36 0.212 5.38 0.213 5.41 0.214 5.44 0.215 5,46 0.216 5.49 0.217 5.51 0.218 5.54 0.219 5.55

(4) 0) in) (7) Level 2 Bright (Uncoated) or Drawn-Galvanized Brealdng Strength Individual Average

0)

(8)

(9)

(10) in)

(12)

0s)

04 )

05 )

0 ~) PD

Level 3 Bright (Uncoated) or Drawn~?,alvanized Brealdng Strength Individual Average

Level 4 Bright (Uncoated) or Drawn-Galvanized Breaking Strength Individual Average

(18)

09)

(20)

(21)

Minlmmn

Minhnu.m

Mm.

Minimum

Minimum

Min.

Minunum

Minimum

Mhx.

Minimum

Minimtma

lb

lb

Tor.

lb

lb

Tor.

lb

lb

Tor.

lb

lb

N

N

3,457 16,377 3,635 16,168 15 3,501 15,572 3,68I 16,373 14 3,545 15,768 3,727 I6,578 I4 3,589 15,964 3,773 16,782 14 3,634 I6,164 3,820 16,991 14 3,679 16,364 3,867 17,200 14 3,724 16,564 3,914 17,409 14 3,768 16,760 3,962 17,623 I4 3,814 16,965 4,010 17,836 I4 3,859 17,165 4,057 18,046 14 3,905 I7,369 4,105 18,259 13 3,952 17,578 4,154 18,477 13 3,998 17,783 4,203 18,695 13 4,044 17,988 4,252 18,913 13 4,091 18,197 4,30I 19,131 I3 4,138 18,406 4,350 I9,349 13 4,186 18,619 4,400 19,571 13 4,232 18,824 4,450 19,794 13 4,280 19,037 4,500 20,016 13 4,329 19,255 4,551 20,243 13 4,377 19,469 4,601 20,465 13 4,426 19,687 4,652 20,692 12 4,474 19,900 4,704 20,923 12 4,523 20,118 4,755 21,I50 I2 4,572 20,336 4,806 21,377 12 4,622 20,559 4,859 21,613 12 4,670 20,772 4,910 21,840 12 4,720 20,995 4,962 22,071 12 4,771 21,221 5,015 22,307 12 4,820 21,439 5,068 22,542 12 4,871 21,666 5,121 22,778 12 4,922 21,893 5,174 23,014 12 4,973 22,120 5,228 23,254 12 5,023 22,342 5,281 23,490 11 5,075 22,574 5,335 23,730 11 5,127 22,805 5,389 23,970 11 5,178 23,032 5,444 24,125 11 5,230 23,263 5,498 24,455 11 5,283 23,499 5,553 24,700 11 5,335 23,730 5,609 24,949 11 5,387 23,961 5,663 25,189 11 5,441 24,202 5,720 25,443 11 5,493 24,433 5,775 25,687 i1 5,547 24,673 5,831 25,936 11 5,600 24,909 5,888 26,190 11 5,654 25,149 5,944 26,439 I1 5,708 25,389 6,000 26,688 11 5,761 25,625 6,057 26,942 10 5,816 25,870 6,114 27,195 l0 5,870 26,110 6,172 27,453 10 5,925 26,354 6,229 27,707 10 5,980 26,599 6,286 27,960 10 6,035 26,844 6,345 28,223 10 6,091 27,093 6,403 28,481 10 6,146 27,337 6,462 28,743 10 6,202 27,586 6,520 29,00I 10 6,258 27,836 6,578 29,259 10 6.314 28,085 6,638 29,526 I0 6,371 28,338 6,697 29,788 t0 6,427 28,587 6,757 30,055 10 6,484 28,841 6,816 30,318 I0 6,540 29,090 6,876 30,584 10 6,598 29,348 6,936 30,851 10 6,655 29,601 6,997 31,123 10 6,713 29,859 7,057 31,390 10 6,770 30,113 7,118 31,661 10 6,829 30,375 7,179 31,932 10 6,886 30,629 7,240 32,204 I0 6,945 30,891 7,301 32,475 10 7,003 31,149 7,363 32,751 10

N

N

3,976 17,685 4,180 18,693 4,026 I7,908 4,232 18,824 4,076 18,130 4,286 19,064 4,127 18,357 4,339 19,300 4,179 18,588 4,393 19,540 4,230 18,815 4,446 I9,776 4,281 19,042 4,501 20,020 4,334 19,278 4,556 20,265 4,386 I9,609 4,610 20,505 4,438 19,740 4,665 20,754 4,491 19,976 4,721 20,999 4,544 20,212 4,778 21,253 4,597 20,447 4,833 21,497 4,651 20,688 4,889 21,746 4,704 20,923 4,946 22,000 4,759 21,168 5,003 22,263 4,814 21,412 5,060 22,507 4,868 21,643 5,118 22,765 4,923 21,898 5,175 23,108 4,977 22,138 5,233 23,276 5,033 22,387 5,291 23,534 5,089 22,686 5,349 23,792 5,145 22,885 5,409 24,059 5,201 23,134 5,467 24,317 5,257 23,383 5,527 25,584 5,314 23,637 5,586 24,847 5,371 23,890 5,647 25,118 5,429 24,148 5,707 25,385 5,486 24,402 5,768 25,656 5,544 24,660 5,828 25,923 5,601 24,913 5,889 26,194 5,660 25,176 5,950 26,466 5,718 25,434 6,012 26,741 5,777 25,696 6,073 27,013 5,836 25,959 6,136 27,293 5,896 26,225 6,198 27,569 5,955 26,488 6,261 27,849 6,015 26,755 6,323 28,125 6,074 27,017 6,386 28A05 6,135 27,288 6,449 28,685 6,195 27,555 6,513 28,970 6,257 27,831 6,577 29,254 6,317 28,098 6,641 29,539 6,378 28,369 6,706 29,828 6,440 28,645 6,770 30,113 6,501 28,916 6,835 30,402 6,564 29,197 6,900 30,691 6,626 29,472 6,966 30,985 6,689 29,753 7,032 31,278 6,751 30,028 7,097 31,567 6,814 30,309 7,164 31,865 6,877 30,589 7,229 32,155 6,940 30,869 7,296 32,453 7,004 31,154 7,364 32,755 7,068 31,438 7,430 33,049 7,132 31,723 7,498 33,351 7,196 32,008 7,566 33,654 7,261 32,297 7,633 33,952 7,326 32,586 7,702 34,258 7,391 32,875 7,77I 34,565 7,457 33,169 7,839 34,868 7,522 33,458 7,908 35,I75 7,587 33,747 7,977 35,482 7,654 34,045 8,046 35,789 7,720 34,339 8,116 36,100 7,786 34,632 8,186 36,4tl 7,853 34,930 8,255 36,718 7,920 35,228 8,326 37,034 7,987 35,526 8,397 37,350 8,054 35,824 8.468 37,666

13 13 13 13 13 13 13 13 12 I2 12 12 12 12 12 12 12 12 12 11 1I 11 11 11 11 I1 1I 11 I1 I1 11 11 10 10 10 I0 1O 10 10 10 10 10 10 10 I0 10 10 10 10 l0 I0 I0 10 10 10 10 10 10 10 10 10 10 10 10 10 9 9 9 9 9

N

N

4,374 19,456 4,598 20,452 7 4,428 19,696 4,656 20,710 7 4,484 19,945 4,714 20,968 7 4,541 20,198 4,773 21,230 7 4,596 20,443 4,832 21,493 7 4,653 20,697 4,891 21,755 7 4,710 20,950 4,952 22,026 7 4,767 21,204 5,011 22,289 7 4,824 21,457 5,072 22,560 7 4,882 2L715 5,132 22,827 7 4,940 21,973 5,194 23,103 6 4,999 22,236 5,255 23,374 6 5,057 22,494 5,317 23,650 6 5,116 22,756 5,378 23,921 6 5,175 23,018 5,441 24,202 6 5,235 23,285 6,503 24,477 6 5,294 23,648 5,566 24,758 6 5,355 23,819 5,629 25,038 6 5,415 24,086 5,693 25,322 6 5,476 24,357 5,756 25,603 6 5,537 24,629 5,821 25,892 6 5,597 24,895 5,885 26,176 6 5,669 25,171 5,949 26,46I 6 5,721 25,447 6,015 26,755 6 5,784 25,727 6,080 27,044 6 5,846 26,003 6,146 27,337 6 5,909 26,283 6,212 27,631 6 5,971 26,559 6,277 27,920 6 6,034 26,839 6,344 28,218 6 6,098 27,124 6,410 28,512 6 6,162 27,409 6,478 28,814 6 6,226 27,693 6,546 29,117 6 6,291 27,982 6,613 29,415 6 6,355 28,267 6,681 29,717 6 6,419 28,552 6,749 30,020 5 6,485 28,845 6,187 30,322 5 6,550 29,134 6,886 30,629 5 6,616 29,428 6,956 30,940 5 6,683 29,726 7,025 81,247 5 6,748 30,015 7,094 31,554 5 6,815 30,313 7,165 31,870 5 6,882 30,611 7,234 32,177 5 6,949 30,909 7,305 32,493 5 7,016 31,207 7,376 32,808 5 7,084 31,510 7,448 33,129 5 7,I52 31,812 7,518 33,440 5 7,220 32,115 7,590 33,760 5 7,288 32,417 7,662 34,081 5 7,357 32,724 7,735 84,405 5 7,427 33,035 7,807 34,726 5 7,496 33,342 7,880 35,050 5 7,565 33,649 7,953 35,375 5 7,634 33,956 8,026 35,700 5 7,704 34,267 8,100 36,029 5 7,775 34,583 8,I73 36,354 5 7,846 34,899 8,248 36,687 5 7,916 35,210 8,322 37,016 5 7,987 35,526 8,397 37,350 5 8,058 35,842 8,472 37,683 5 8,131 36,167 8,647 38,017 5 8,202 36,482 8,622 38,351 5 8,274 36,803 8,698 38,689 5 8,346 37,123 8,774 39,027 5 8,419 37,448 8,851 39,369 5 8,492 37,772 8,928 39,712 5 8,564 38,093 9,004 40,050 5 8,639 38,426 9,082 40,397 5 8,712 38,751 9,158 40,735 5 8,786 39,080 9,236 41,082 5 8,860 39,409 9,314 41,429 5

(22)

Level 5 Bright (Uncoated) or Drawn-Galvanized Breaking Strength Individual Average N

N

Min. Tot.

4,701 20,910 4,943 21,986 6 4,761 2L177 5,005 22,262 6 4,820 21,439 5,068 22,542 6 4,881 21,71I 6,I31 22,823 6 4,941 21,978 5,195 23,107 6 5,002 22,249 5,258 23,388 6 5,063 22,520 5,323 23,677 6 5,I25 22,796 5,387 23,961 6 5,186 23,067 5,452 24,260 6 5,248 23,343 5,518 24,544 6 5,311 23,623 5,583 24,833 5 5,373 23,899 5,649 25,127 5 5,437 24,I84 5,715 25,420 5 5,500 24,464 5,782 25,718 5 5,563 24,744 5,849 26,016 6 5,628 25,033 5,916 26,314 5 5,692 25,318 5,984 26,617 5 5,756 25,603 6,052 26,919 5 5,821 25,892 6,119 27,217 5 5,886 26,18I 6,188 27,524 5 5,951 26,470 6,257 27,831 5 6,018 26,768 6,326 28,138 5 6,084 27,062 6,396 28,449 5 6,150 27,355 6,466 28,761 5 6,217 27,653 6,535 29,068 5 6,284 27,951 6,606 29,383 5 6,35I 28,249 6,677 29,699 6 6,419 28,552 6,749 30,020 5 6,487 28,854 6,819 30,331 5 6,555 29,157 6,891 30,65t 5 6,624 29,464 6,964 30,976 5 6,692 29,766 7,036 31,296 5 6,762 30,077 7,108 31,616 5 6,832 30,389 7,182 31,946 5 6,90t 30,696 7,255 32,270 5 6,971 31,007 7,329 32,599 5 7,04I 31,318 7,403 32,929 5 7,113 31,639 7,477 33,258 5 7,184 31,954 7,552 33,591 5 7,255 32,270 7,627 33,925 5 7,326 32,586 7,702 34,258 5 7,398 32,906 7,778 34,597 5 7,470 33,227 7,854 34,935 4 7,543 33,551 7,929 35,268 4 7,615 33,872 8,005 35,606 4 7,688 34,196 8,082 35,949 4 7,762 34,525 8,160 36,296 4 7,835 34,850 8,237 36,638 4 7,909 35,I79 8,315 36,985 4 7,983 35,508 8,393 37,332 4 8,057 35,838 8,471 37,679 4 8,I32 36,17I 8,550 38.030 4 8,208 36,509 8,628 38,377 4 8,283 36,843 8,707 88,729 4 8,358 37,176 8,786 39,080 4 8,434 37,514 8,866 39,436 4 8,510 37,852 8,946 39,792 4 8,586 38,191 9,026 40,148 4 8,663 38,533 9,107 40,508 4 8,740 38,876 9,188 40,868 4 8,817 39,218 9,269 41,229 4 8,895 39,565 9,351 41,593 4 8,972 39,907 9,432 41,954 4 9,050 40,254 9,514 42,318 4 9,I29 40,606 9,597 42,687 4 9,207 40,953 9,679 43,052 4 9,286 41,304 9,762 43,421 4 9,365 41,656 9,845 43,791 4 9,445 42,011 9,929 44,164 4 9,524 42,363 10,012 44,533 4

Hoisting System

557

Table 4-9 (continued) (s)

Wire Size Nominal Diameter in. m m

(4)

is) in) L~el2 Bright (Uncoated) or Drawn~alvanlzed Breaking Strength Incfividual Average Minimmn Minimum lb N lb N

(71

Mha. Tor.

is)

(91

(10) 0 i ) (I2) Level 3 Bright (Uncoated) or Drawn-Galvanized Breaking Strength lncfivldual Average Minimum Minimum Min. lb N lb N Tor.

ilS)

ti41 (In) (181 (171 its) (191 (~1 (211 Level 4 Level 5 Bright (Uncoated) Bright (Uncoated) or or I)rawn-G~vanized Drawn-Galva~2ed Breaking Strength Breaking Strength Individual Average Incfividual Average Minimmn Minimum Min. Minimum Minimum lb N lb N Tor. lb N lb N

M/n. Tor.

0.220 0.22I 0.222 0.223 0.224

5.59 5.61 5.64 5.66 5.69

7,063 7,12I 7,181 7,240 7,300

31,416 31,674 31,94I 32,204 32,470

7,425 7,487 7,549 7,612 7,674

33,026 10 33,302 I0 33,578 10 33,858 10 34,I34 I0

8,122 8,190 8,257 8,326 8,395

36,I27 36,429 36,727 37,034 37,341

37,977 38,297 38,613 38,929 39,254

9 9 9 9 9

8,934 9,009 9,083 9,158 9,234

39,738 40,072 40,401 40,735 41,073

41,776 42,127 42,474 42,825 43,181

4 4 4 4 4

9,604 9,685 9,765 9,846 9,926

42,719 43,079 43,435 43,795 44,151

10,096 10,I81 10,265 10,350 10,436

44,907 45,285 45,659 46,037 46,419

4 4 4 4 4

0.225 0.226 0.227 0.228 0.229

5.72 5.74 5.77 5.79 5,82

7,359 7,419 7,479 7,540 7,600

32,733 33,000 33,267 33,538 33,805

7,737 7,799 7,863 7,926 7,990

34,414 34,690 34,975 35,255 35,540

10 l0 10 19 l0

8,463 8,532 8,601 8,671 8,740

37,643 8,897 39,574 37,950 8,970 39,899 38,257 9,043 40,223 38,569 9.115 40,544 38,876 9.188 40,868

9 9 9 9 9

9,309 9,385 9,461 9,537 9,614

4 4 4 4 4

10,007 10,089 10,I71 10,253 10,335

44,511 44,876 45,241 45,605 45,970

I0,521 19,607 10,693 I0,779 10,865

46,797 47,180 47,562 47,945 48,328

4 4 4 4 4

0.230 0.231 0.232 0.233 0.234

5.84 5.87 5.89 5.92 5.94

7,66I 7,722 7,782 7,844 7,905

34,076 34,347 34,614 34,890 35,161

8,053 8,I18 8,182 8,246 8,311

35,820 36,109 36,394 36,678 36,967

10 10 I0 9 9

8,810 8,879 8,950 9,021 9,09t

39,187 39,494 39,810 40,125 40,437

9,262 9,335 9,408 9,483 9,557

41,197 41,522 41,847 42,180 42,510

9 9 9 9 9

9,69I 9,768 9,845 9,923 10,0Ol

4 4 4 4 4

10,418 10,501 10,584 I0,667 10,750

46,339 46,708 47,078 47,447 47,816

10,952 II,039 11,126 11,214 11,302

48,714 49,101 49,488 49,880 50,271

4 4 4 4 4

0.235 0.236 0.237 0.238 0.239 0.240 0.241 0.242 0.243 0.244

5.97 5.99 6.02 6.05 6.07 6.10 6.12 6.15 6.17 6.20

7,967 8,029 8,091 8,I53 8,215

35,437 35,713 35,989 36,265 36,540

8,375 8,441 8,505 8,571 8,637

37,252 37,546 37,830 38,124 38,417

9 9 9 9 9

9,162 9,233 9,304 9,376 9,448

40,753 41,068 41,384 41,704 42,025

9,632 9,707 9,782 9,856 9,932

42,843 43,177 43,510 43,839 44,178

9 8 8 8 8

19,078 10,I57 10,235 10,314 10,393

8,278 8,340 8,404 8,466 8,529

36,821 37,096 37,381 37,657 37,937

8,802 8,768 8,834 8,900 8,967

38,706 39,000 39,294 39,587 39,885

9 9 9 9 9

9,519 9,591 9,664 9,736 9,809

42,341 42,661 42,985 43,306 43,630

10,007 10,083 I0,160 10,236 10,313

44,511 44,849 45,192 45,530 45,872

8 8 8 8 8

10,472 10,550 10,630 10,709 10,790

41,406 9,787 43,533 41,744 9,867 43,888 42,083 9,947 44,244 42,421 10,027 44,600 42,763 I0,108 44,960 43,106 10,187 45,312 43,448 10,268 45,672 43,79I I0,349 46,032 44,138 10,431 46,397 44,484 10,513 46,762 44,827 10,594 47,122 45,178 I0,677 47,491 45,525 10,759 47,856 45,877 10,842 48,225 46,228 I0,92548,594 46,579 11,009 48,968 46,926 11,092 49,337 47,282 11,176 49,711 47,634 11,259 60,080 47,994 11,344 50,458

4 4 4 4 4 4 4 4 4 4

10,834 10,918 11,002 11,087 11,172 11,256 11,342 11,427 11,513 11,600

48,190 48,563 48,937 49,315 49,693 50,067 50,449 50,827 51,210 51,597

11,390 11,478 11,566 I1,655 I1,744 11,834 11,924 12,013 12,103 12,194

50,663 51,054 51,446 51,841 52,237 52,638 53,038 53,434 53,834 54,239

4 4 4 4 4 3 3 3 3 3

0.245 0.246 0.247 9.248 9.249 0.250

6.22 6.25 6.27 6.30 6.32 6.35

8,593 8,657 8,720 8,785 8,848

38,222 38,506 38,787 39,076 39,356

9,033 9,101 9,168 9,235 9,302

40,179 40,481 40,779 41,077 41,375

9 9 9 9 9

9,882 9,955 10,029 10,102 I0,176

43,955 44,280 44,609 44,934 45,263

10,388 10,465 10,543 10,620 10,698

46,206 46,548 46,895 47,238 47,585

I1,685 I1,772 11,859 11,946 12,032

51,975 52,362 52,749 53,136 53,518

12,285 12,376 12,467 I2,558 12,650

54,644 55,048 55,453 55,858 56,267

3 3 3 3 3

I0,249 45,588 10,775 47,927

48,350 48,706 49,066 49,426 49,786 50,I51

4 4 4 4 4

9

I0,870 10,950 11,031 11,112 11,I93 11,275

11,42850,832 11,512 51,205 I1,597 51,583 11,682 51,962 11,767 52,340

8,912 39,641 9,370 41,678

8 8 8 8 8 8

11,853 52,722

4

12,120

53,910 12,742 56,676 3

8,538 8,610 8,681 8,752 8,825

9,392 9,47I 9,549 9,628 9,708

(~)

Drilling and Well Completions

558

Table 4-10 Mechanical Properties of Individual Rope Wires (Before Fabrication) [12] (9) Wire Size Nominal Diameter in. mm

Level 2 Bright (Uncaa~d) or Drawn~Galvanizecl Breaking S t ~ n g t h lb N Tar.

Level 3 Bright (Uncoated) or Drawo-Galvanlzed Breaking Strength lb N "For.

~io)

n)

Level 4 Bright (Uncoated) or Drawn-Galvanized Breaking S t ~ n g t h lb N Tar.

il~)

~13)

04?

Level 5 Bright (Uncoated) or Drawn~alvanlzed Breaking Strength lb N Tar.

0.010 0.011 0.012 0.013 0.014

0.25 0.28 0.30 0.33 0.36

17 21 25 29 34

76 93 111 129 151

254 231 212 195 181

20 24 29 34 39

89 107 129 151 173

234 213 195 180 167

22 27 32 37 43

98 120 142 165 191

218 198 182 168 156

24 29 34 40 46

107 129 151 178 205

190 173 158 146 136

0.015 0.016 0.017 0.018 0.019

0.38 0.41 0.43 0.46 0.48

39 44 50 56 62

173 196 222 249 276

169 158 149 141 133

45 51 57 64 72

200 227 254 285 320

156 146 137 130 123

49 56 63 71 79

218 249 280 316 351

145 136 128 121 114

53 60 68 76 85

236 267 302 338 378

126 118 111 105 100

0.020 0.021 0.022 0.023 0.024

0.51 0.53 0.56 0.58 0.61

69 76 83 91 99

307 338 369 405 440

126 120 115 110 105

79 87 96 105 114

351 387 427 467 507

116 111 106 101 97

87 96 105 115 125

387 427 467 512 556

108 103 98 94 90

94 103 113 124 135

418 458 503 552 600

94 90 86 82 78

0.025 0.026 0.027 0.028 0.029

0.64 0.66 0.69 0.71 0.74

107 116 125 134 144

476 516 556 596 641

101 97 93 90 87

123 133 144 155 166

547 592 641 689 738

93 89 86 83 80

136 147 158 170 182

605 654 703 756 810

86 83 80 77 74

146 158 170 183 196

649 703 756 814 872

75 72 70 67 65

0.030 0.031 0.032 0.033 0.034

0.76 0.79 0.81 0.84 0.86

154 164 175 186 197

685 729 778 827 876

84 81 78 76 74

177 189 201 214 227

787 841 894 952 1,010

77 75 72 70 68

195 208 221 235 250

867 925 983 1,045 1,112

72 69 67 65 63

210 224 238 253 268

934 996 1,059 1,125 1,192

62 60 58 57 55

0.035 0.036 0.037 0.038 0.039

0.89 0.91 0.94 0.97 0.99

209 221 233 246 259

930 983 1,036 1,094 1,152

72 70 68 66 64

240 254 268 283 298

1,068 1,130 1,192 1,259 1,326

66 64 62 61 59

264 280 295 311 327

1,174 1,245 1,312 1,383 1,454

61 60 58 56 55

284 301 317 334 352

1,263 1,339 1,410 1,486 1,566

53 52 50 49 48

0.040 0.041 0.042 0.043 0.044

1.02 1.04 1.07 1.09 1.12

272 286 300 314 328

1,210 1,272 1,334 1,397 1,459

62 61 59 58 57

313 329 345 361 378

1,392 1,463 1,535 1,606 1,681

57 56 55 53 52

344 361 379 397 415

1,530 1,606 1,686 1,766 1,846

53 52 51 50 48

370 388 407 427 447

1,646 1,726 1,810 1,899 1,988

46 45 44 43 42

0.045 0.046 0.047 0.048 0.049

1.14 1.17 1.19 1.22 1.24

343 358 374 390 406

1,526 1,592 1,664 1,735 1,806

55 54 53 52 51

395 412 430 448 467

1,757 1,833 1,913 1,993 2,077

51 50 49 48 47

434 453 473 493 513

1,930 2,015 2,104 2,193 2,282

47 46 45 44 43

467 487 508 530 552

2,077 2,166 2,260 2,357 2,455

41 40 39 38 38

0.050 0.051 0.052 0.053 0.054

1.27 1.30 1.32 1.35 1.37

422 439 456 474 491

1,877 1,953 2,028 2,108 2,184

50 49 48 47 46

486 505 525 545 565

2,162 2,246 2,335 2,424 2,513

46 45 44 43 42

534 555 577 599 621

2,375 2,469 2,566 2,664 2,762

42 42 41 40 39

574 597 620 644 668

2,553 2,655 2,758 2,865 2,971

37 36 35 35 34

Hoisting System

559

Table 4-10 (continued) (1)

(2)

~9)

Level2 Bright(Uncoated) W'~e Size

Nominal

Diameter

Level3 Bright(Uncoated)

or Dram-Galvanlzed Breaking Strength lb N Tor.

in.

mm

0.055 0.056 0.057 0.058 0.059

1.40 1.42 1.45 1.47 1.50

509 528 546 565 584

2,264 2,349 2,429 2,513 2,598

0.060 0.061 0.062 0.063 0.064

1.52 1.55 1.57 1.60 1.63

604 624 644 665 685

0.065 0.066 0.067 0.068 0.069

1.65 1.68 1.70 1.73 1.75

0.070 0.071 0.072 0.073 0.074

IlO)

II1

(12}

Level 4

Bright(Uncoated)

or

Drawn-Galvanlzed BreakingStrength

I13)

(14}

Level 5 Bright(Uncoated) or Drawn-Galvanlzed

or Drawn-Galvanized

BreakingStrength

BreakingStrength

lb

N

Tor.

lb

N

Tor.

lb

N

Tor.

45 44 43 43 42

586 607 628 650 672

2,607 2,700 2,793 2,891 2,989

41 41 40 39 38

644 667 691 715 739

2,865 2,967 3,074 3,180 3,287

38 38 37 36 36

693 718 743 769 795

3,082 3,194 3,305 3,421 3,536

33 33 32 32 31

2,687 2,776 2,865 2,958 3,047

41 40 40 39 38

695 718 741 764 788

3,091 3,194 3,296 3,398 3,505

38 37 37 36 35

764 789 815 841 867

3,398 3,509 3,625 3,741 3,856

35 35 34 33 33

821 848 876 904 932

3,652 3,772 3,896 4,021 4,146

30 30 29 29 28

707 728 750 772 794

3,145 3,238 3,336 3,434 3,532

38 37 37 36 36

813 837 862 887 913

3,616 3,723 3,834 3,945 4,061

35 34 34 33 33

894 921 948 976 1,004

3,977 4,097 4,217 4,341 4,466

32 32 31 31 30

961 990 1,019 1,049 1,080

4,275 4,404 4,533 4,666 4,804

28 28 27 27 26

1.78 1.80 1.83 1.85 1.88

817 840 863 886 910

3,634 3,736 3,839 3,941 4,048

35 35 34 34 33

939 966 992 1,019 1,047

4,177 4,297 4,412 4,533 4,657

32 32 31 31 30

1,033 1,062 1,091 1,121 1,151

4,595 4,724 4,853 4,986 5,120

30 29 29 29 28

1,111 1,142 1,173 1,205 1,238

4,942 5,080 5,218 5,360 5,507

26 26 25 25 24

0.075 0.076 0.077 0.078 0.079

1.91 1.93 1.96 1.98 2.01

934 959 983 1,008 1,034

4,154 4,266 4,372 4,484 4,599

33 32 32 31 31

1,074 1,103 1,131 1,160 1,189

4,777 4,906 5,031 5,160 5,289

30 30 29 29 28

1,182 1,213 1,244 1,276 1,308

5,258 5,395 5,533 5,676 5,818

28 27 27 27 26

1,271 1,304 1,337 1,371 1,406

5,653 5,800 5,947 6,098 6,254

24 24 23 23 23

0.080 0.081 0.082 0.083 0.084 0.085 0.086 0.087 0.088 0.089 0.090 0.091 0.092 0.093 0.094

2.03 2.06 2.08 2.11 2.13 2.16 2.18 2.21 2.24 2.26 2.29 2.31 2.34 2.36 2.39

1,059 1,085 1,111 1,138 1,165 1,192 1,219 1,247 1,275 1,303 1,332 1,360 1,390 1,419 1,449

4,710 4,826 4,942 5,062 5,182 5,302 5,422 5,547 5,671 5,796 5,925 6,049 6,183 6,312 6,445

30 30 30 29 29 29 28 28 28 27 27 27 26 26 26

1,218 1,248 1,278 1,309 1,339 1,371 1,402 1,434 1,466 1,499 1,531 1,564 1,598 1,632 1,666

5,418 5,551 5,685 5,822 5,956 6,098 6,236 6,378 6,521 6,668 6,810 6,957 7,108 7,259 7,410

28 28 27 27 27 26 26 26 25 25 25 24 24 24 24

1,340 1,373 1,406 1,440 1,473 1,508 1,542 1,577 1,613 1,648 1,684 1,721 1,758 1,795 1,832

5,960 6,107 6,254 6,405 6,552 6,708 6,859 7,014 7,175 7,330 7,490 7,655 7,820 7,984 8,149

26 26 25 25 25 24 24 24 23 23 23 23 22 22 22

1,441 1,476 1,511 1,548 1,584 1,621 1,658 1,696 1,734 1,772 1,811 1,850 1,890 1,930 1,970

6,410 6,565 6,721 6,886 7,046 7,210 7,375 7,544 7,713 7,882 8,055 8,229 8,407 8,585 8,763

22 22 22 22 21 21 21 21 20 20 20 20 19 19 19

0.095 0.096 0.097 0.098 0.099

2.41 2.44 2.46 2.49 2.51

1,479 1,509 1,539 1,570 1,601

6,579 6,712 6,845 6,983 7,121

25 25 25 25 24

1,700 1,735 1,770 1,806 1,841

7,562 7,717 7,873 8,033 8,189

23 23 23 23 22

1,870 1,909 1,947 1,986 2,026

8,318 8,491 8,660 8,834 9,012

22 21 21 21 21

2,011 2,052 2,093 2,135 2,177

8,945 9,127 9,310 9,496 9,683

19 18 18 18 18

560

Drilling and Well Completions Table 4-10 (continued) i9)

V~we Size

Nom/n-1 Diameter mm in.

(1o?

Level2

Level3

Level4

Bright (Uncoated) or

Bright (Uncoated) or

Bright (Uncoated) or

Dr~n-Gal~-d BreakingStrength lb N Tor.

Dra~-Galvanized BreakingSU-ength lb N Tar.

11?

~12)

(is)

{14)

level 5

~v~-d BreakingSirtmgth lb N Tar.

Bright (Uncoated) or

Drawn-Galv~l BrealdngStrength lb N Tar.

0.100 2.54 0.101 2.57 0.102 2.59 0.103 2.62 0.104 2.64

1,633 1,664 1,696 1,728 1,761

7,264 7,401 7,744 7,686 7,833

24 24 24 23 23

1,877 1,914 1,951 1,988 2,025

8,349 8,513 8,678 8,843 9,007

22 22 22 21 21

2,065 2,105 2,146 2,186 2,228

9,185 9,363 9,545 9,723 9,910

20 20 20 20 20

2,220 2,263 2,307 2,350 2,395

9,875 10,066 10,262 10,453 10,653

18 18 17 17 17

0.105 0.106 0.107 0.108 0.109

2.67 2.69 2.72 2.74 2.77

1,794 1,827 1,860 1,894 1,928

7,980 8,126 8,273 8,425 8,576

23 23 22 22 22

2,063 2,101 2,139 2,178 2,217

9,176 9,345 9,514 9,688 9,861

21 21 21 20 20

2,269 2,311 2,353 2,396 2,438

10,093 10,279 10,466 10,657 10,844

19 19 19 19 19

2,439 2,484 2,529 2,575 2,621

10,849 11,049 11,249 11,454 11,658

17 17 16 16 16

0.110 0.112 0.113 0.114

2.79 2.82 2.84 2.87 2.90

1,962 1,996 2,031 2,066 2,101

8,727 8,878 9,034 9,190 9,345

22 22 21 21 21

2,256 2,296 2,336 2.376 2,416

10,035 10,213 10,391 10,568 10,746

20 20 20 19 19

2,482 2,525 2,569 2,613 2,658

11,040 11,231 11,427 11,623 11,823

18 18 18 18 18

2,668 2,715 2,762 2,809 2,857

11,867 12,076 12,285 12,494 12,708

16 16 16 15 15

0.115 0.116 0.117 0.118 0.119

2.92 2.95 2.97 3.00 3.02

2,137 9,505 2,172 9,661 2,209 9,826 2,245 9,986 2,281 10,146

21 21 20 20 20

2,457 2,498 2,540 2,582 2,624

10,929 11,111 11,298 11,485 11,672

19 19 19 18 18

2,703 2,748 2,794 2,840 2,886

12,023 12,223 12,428 12,632 12,837

18 17 17 17 17

2,906 2,954 3,003 3,053 3,102

12,926 13,139 13,357 13,580 13,798

15 15 15 15 15

0.120 0.121 0.122 0.123 0.124

3.05 3.07 3.10 3.12 3.15

2,318 2.355 2,393 2,431 2,468

10,310 10.475 10,644 10,813 10,978

20 20 19 19 19

2,666 2,709 2,752 2,795 2,839

11,858 12,050 12,241 12,432 12,628

18 18 18 18 18

2,933 2,980 3,027 3,075 3,123

13,046 13,255 13,464 13,678 13,891

17 17 17 16 16

3,153 3,203 3,254 3,305 3,357

14,025 14,247 14,474 14,701 14,932

14 14 14 14 14

0.125 0.126 0.127 0.128 0.129

3.18 3.20 3.23 3.25 3.28

2,507 2,545 2,584 2.623 2,662

11,151 11,320 11,494 11,667 11,841

19 19 19 18 18

2,883 2,927 2,971 3,016 3,061

12,824 13,019 13,215 13,415 13,615

17 17 17 17 17

3,171 3,220 3,269 3,318 3,368

14,105 14,323 14,541 14,758 14,981

16 16 16 16 16

3,409 3,461 3,514 3,567 3,620

15,163 15,395 15,630 15,866 16,102

14 14 14 13 13

0.130 0.131 0.132 0.133 0.134

3.30 3.33 3.35 3.38 3.40

2,702 2,741 2,781 2,822 2,862

12,018 12,192 12,370 12,552 12,730

18 18 18 18 18

3,107 3,153 3,199 3,245 3,292

13,820 14,025 14,229 14,434 14,643

17 17 16 16 16

3,418 3,468 3,519 3,570 3,621

15,203 15,426 15,653 15,879 16,106

15 15 15 15 15

3,674 3,728 3,782 3,837 3,892

16,342 16,582 16,822 17,067 17,312

13 13 13 13 13

0.135 0.136 0.137 0.138 0.139

3.43 3.45 3.48 3.51 3.53

2,903 2,944 2,986 3,027 3,069

12,913 13,095 13,282 13,464 13,651

17 17 17 17 17

3,339 3,386 3,433 3,481 3,529

14,852 15,061 15,270 15,483 15,697

16 16 16 16 15

3,672 3,724 3,777 3,829 3,882

16,333 16,564 16,800 17,031 17,267

15 15 15 14 14

3,948 4,004 4,060 4,117 4,173

17,561 17,810 18,059 18,312 18,562

13 13 13 12 12

0.140 0.141 0.142 0.143 0.144

3.56 3.58 3.61 3.63 3.66

3,111 3,153 3,196 3,239 3,282

13,838 14,025 14,216 14,407 14,598

17 17 17 16 16

3,578 3,626 3,675 3,725 3,774

15,915 16,128 16,346 16,569 16,787

15 15 15 15 15

3,935 3,989 4,043 4,097 4,152

17,503 17,743 17,983 18,223 18,468

14 14 14 14 14

4,231 4,288 4,346 4,404 4,463

18,819 19,073 19,331 19,589 19,851

12 12 12 12 12

0.111

Hoisting System

561

Table 4-10 (continued) Ill

I~

Wire Size Naminal Diameter in. mm

Ist

14~

fsl

Level 2 Bright (Uncoated) or Drawn-Galvanized Breaking Strengt~ lb N Tot.

t61

171

Is)

Level 3 Bright (Uncoated) or Drawn~Galvanized Breaking S t r ~ g t h lb N Tar.

Io)

0o)

Ixl?

02)

Level 4 Bright (Uncoated) or Drawn-Galvanized

I~s)

114t

Level 5 Bright (Uncoated) or Drawn-Galvanized

Br-dd~gStrength

BreakingStreng~

lb

N

Tar.

lb

N

Tar,

0.145 0.146 0.147 0.148 0.149

3.68 3.71 3.73 3.76 3.78

3,325 3,369 3,413 3,457 3,501

14,790 14,985 15,181 15,377 15,572

16 16 16 16 16

3,824 3,874 3,925 3,975 4,026

17,009 17,232 17,458 17,681 17,908

15 15 15 14 14

4,207 4,262 4,317 4,373 4,429

18,713 18,957 19,202 19,451 19,700

14 14 13 13 13

4,522 4,581 4,641 4,701 4,761

20,114 20,376 20,643 20,910 21,177

12 12 12 11 11

0.150 0.151 0.152 0.153 0.154

3.81 3.84 3.86 3.89 3.91

3,546 3,591 3,636 3,681 3.727

15,773 15,973 16,173 16,373 16,578

16 15 15 15 15

4,078 4,129 4,181 4,233 4,286

18,139 18,366 18,597 18,828 19,064

14 14 14 14 14

4,486 4,542 4,599 4,657 4,714

19,954 20,203 20,456 20,714 20,968

13 13 13 13 13

4,822 4,883 4,944 5,006 5,068

21,448 21,720 21,991 22,267 22,542

11 11 11 11 11

0.155 0.156 0.157 0.158 0.159

3.94 3.96 3.99 4.01 4.04

3,773 3,819 3,865 3,912 3,958

16,782 16,987 17,192 17,401 17,605

15 15 15 15 15

4,338 4,391 4,445 4,498 4,552

19,295 19,531 19,771 20,007 20,247

14 14 14 13 13

4,772 4,831 4,899 4,948 5,007

21,226 21,488 21,746 22,099 22,271

13 13 13 12 12

5,130 5,193 5,256 5,319 5,383

22,818 23,098 23,379 23,659 23,944

11 11 11 11 11

0.160 0.161 0.162 0.163 0.164

4.06 4.09 4.11 4.14 4.17

4,005 4,053 4,100 4,148 4,196

17,814 18,028 18,237 18,450 18,664

14 14 14 14 14

4,606 4,661 4,715 4,770 4,825

20,487 20,732 20,972 21,217 21,462

13 13 13 13 13

5,067 5,127 5,187 5,247 5,308

22,538 22,805 23,072 23,339 23,610

12 12 12 12 12

5,447 5,511 5,576 5,641 5,706

24,228 24,513 24,802 25,091 25,380

10 10 10 10 10

0.165 0.166 0.167 0.168 0.169

4.19 4.22 4.24 4.27 4.29

4,244 4,293 4,341 4,390 4,440

18,877 19,095 19,309 19,527 19,749

14 14 14 14 14

4,881 4,937 4,993 5,049 5,105

21,711 21,960 22,209 22,458 22,707

13 13 13 13 12

5,369 5,430 5,492 5,554 5,616

23,881 24,153 24,428 24,704 24,980

12 12 12 12 12

5,772 5,838 5,904 5,970 6,037

25,674 25,967 26,261 26,555 26,853

10 10 10 10 10

0.170 0.171 0.172 0.173 0.174

4.32 4.34 4.37 4.39 4.42

4,489 4,539 4,589 4,639 4,689

19,967 20,189 20,413 20,634 20,857

14 13 13 13 13

5,162 5,219 5,277 5,334 5,392

22,961 23,214 23,472 23,726 23,984

12 12 12 12 12

5,679 5,741 5,804 5,868 5,932

25,260 25,536 25,816 26,101 26,396

11 11 11 11 11

6,104 6,172 6,240 6,308 6,376

27,151 27,453 27,756 28,058 28,360

10 10 10 10 10

0.175 0.176 0.177 0.178 0.179

4.45 4.47 4.50 4.52 4.55

4,740 4,790 4,841 4,893 4,944

21,064 21,306 21,533 21,764 21,991

13 13 13 13 13

5,450 5,509 5,568 5,627 5,686

24,242 24,504 24,766 25,029 25,291

12 12 12 12 12

5,996 6,060 6,124 6,189 6,254

26,670 26,955 27,240 27,529 27,818

11 11 11 11 11

6,514 6,514 6,584 6,653 6,723

28,974 28,974 29,286 29,593 29,904

9 9 9 9 9

0.180 0.181 0.182 0.183 0.184

4.57 4.60 4.62 4.65 4.67

4,996 5,048 5,100 5,152 5,205

22,222 22,454 22,685 22,916 23,152

13 13 13 12 12

5,745 5,805 5,865 5,925 5,986

25,554 25,821 26,088 26,354 26,626

12 12 11 11 11

6,320 6,386 6,452 6,518 6,584

28,111 28,405 28,698 28,992 29,286

11 11 11 11 10

6,794 6,864 6,935 7,007 7,078

30,220 30,531 30,847 31,167 31,483

9 9 9 9 9

0.185 0.186 0.187 0.188 0.189

4.70 4.72 4.75 4.78 4.80

5,258 5,311 5,364 5,418 5,472

23,388 23,623 23,859 24,099 24,339

12 12 12 12 12

6,047 6,108 6,169 6,230 6,292

26,897 27,168 27,440 27,711 27,987

11 11 11 11 11

6,651 6,718 6,786 6,854 6,921

29,584 29,882 30,184 30,487 30,785

10 10 10 10 10

7,150 7,222 7,295 7,368 7,441

31,803 32,123 32,448 32,773 33,098

9 9 9 9 9

562

Drilling and Well Completions Table 4-10 (continued)

(i)

(2)

Wire Size Nominal Diameter in nun

(3)

141 t51 Level 2 Bright (Uncoated) or Drawa-Galvanlzed Breaking Strength lb N Tar.

(6)

(71

(s I

Level 3 Bright (Uncoated) or DraM-Galvanized Breaking Strength lb N Tar.

,~

(9)

(10 t

1i~

Level 4 Bright (Uncoated) or Drawn-Galvanized Breaking Strength lb N Tar.

~i2)

0sl

1147

Level 5 Brigbt (Uncoated) or DraM-Galvanized Breaking Strength lb N Tar.

0.190 0.191 0.192 0.193 0.194

4.83 4.85 4.88 4.90 4.93

5,525 5,580 5,634 5,689 5,744

24,575 24,820 2,5060 25,305 25,549

12 12 12 12 12

6,354 6,417 6,469 6,542 6,605

28,263 28,543 28,819 29,099 29,379

11 11 11 11 11

6,990 7,058 7,127 7,196 7,266

31,092 31,394 31,701 32,008 32,319

10 10 10 10 10

7,514 7,588 7,662 7,736 7,810

33,422 33,751 34,081 34,410 34,739

9 9 8 8 8

0.195 0.196 0.197 0.198 0.199

4.95 4.98 5.00 5.03 5.05

5,799 5,854 5,909 5,965 6,021

25,794 26,039 26,283 26,532 26,781

12 12 11 11 11

6,668 6,732 6,796 6,860 6,924

29,659 29,944 30,229 30,513 30,798

11 11 10 10 10

7,335 7,405 7,475 7,536 7,617

32,626 32,937 33,249 33,365 33,880

10 10 10 10 10

7,885 7,961 8,036 8,112 8,188

35,072 35,411 35,744 36,082 36,420

8 8 8 8 8

0.200 0.201 0.202 0.203 0.204

5.08 5.11 5.13 5.16 5.18

6,077 6,133 6,190 6,247 6,304

27,030 27,280 27,533 27,787 28,040

11 11 11 11 11

6,989 7,053 7,118 7,184 7,249

31,087 31,372 31,661 31,954 32,244

10 10 10 10 10

7,688 7,759 7,830 7,902 7,974

34,196 34,512 34,828 35,148 35,468

9 9 9 9 9

8,264 8,341 8,418 8,495 8,572

36,758 37,101 37,443 37,786 38,128

8 8 8 8 8

0.205 0.206 0.207 0.208 0.209

5.21 5.23 5.26 5.28 5.31

6,361 6,418 6,476 6,534 6,592

28,294 28,547 28,805 29,063 29,321

11 11 11 11 11

7,315 7,381 7,447 7,514 7,581

32,537 32,831 33,124 33,422 33,720

10 10 10 10 10

8,047 8,119 8,192 8,265 8,339

35,793 36,113 36,438 36,763 37,092

9 9 9 9 9

8,650 8,728 8,806 8,885 8,964

38,475 38,822 39,169 39,520 39,872

8 8 8 8 8

0.210 0.211 0.212 0.213 0.214

5.33 5.36 5.38 5.41 5.44

6,650 6,708 6,767 6,826 6,885

29,579 29,837 30,100 30,362 30,624

11 11 11 11 10

7,648 7,715 7,782 7,850 7,918

34,018 34,316 34,614 34,917 35,219

10 10 10 10 10

8,412 8,486 8,560 8,635 8,710

37,417 37,746 38,075 38,408 38,742

9 9 9 9 9

9,043 9,123 9,202 9,282 9,363

40,223 40,579 40,930 41,286 41,647

8 8 8 8 7

0.215 0.216 0.217 0.218 0.219

5.46 5.49 5.51 5.54 5.56

6,944 7,004 7,063 7,123 7,183

30,887 31,154 31,416 31,683 31,950

10 10 10 10 10

7,986 8,054 8,123 8,192 8,261

35,522 35,824 36,131 36,438 36,745

9 9 9 9 9

8,784 8,860 8,935 9,011 9,087

39,071 39,409 39,743 40,081 40,419

9 9 9 9 9

9,443 9,524 9,605 9,687 9,768

42,002 42,363 42,723 43,088 43,448

7 7 7 7 7

0.220 0.221 0.222 0.223 0.224

5.59 5.61 5.64 5.66 5.69

7,244 7,304 7,365 7,426 7,487

32,221 32,488 32,760 33,031 33,302

10 10 10 10 10

8,330 8,400 8,469 8,539 8,610

37,052 37,363 37,670 37,981 38,297

9 9 9 9 9

9,163 9,240 9,316 9,393 9,471

40,757 41,100 41,438 41,780 42,127

8 8 8 8 8

9,850 9,933 10,015 10,098 10,181

43,813 44,182 44,547 44,916 45,285

7 7 7 7 7

0.225 0.226 0.227 0.228 0.229

5.72 5.74 5.77 5.79 5.82

7,548 7,609 7,671 7,733 7,795

33,574 33,845 34,121 34,396 34,672

10 10 10 10 10

8,680 8,751 8,822 8,893 8,964

38,609 38,924 39,240 39,556 39,872

9 9 9 9 9

9,548 9,626 9,704 9,782 9,861

42,470 42,816 43,163 43,510 43,862

8 8 8 8 8

10,264 10,348 10,432 10,516 10,600

45,654 46,028 46,402 46,775 47,149

7 7 7 7 7

Hoisting System

563

Table 4-10 (continued) tI)

(2)

Wire Size Nominal Diameter in. mm

~3)

(4) (5) Level 2 Bright (Uncoated) or Drawn-Galvanized Breaking Strength lb N Tar.

(6)

t7) t8) Level 3 Bright (Uncoated) or Drawn-Galvanized Breaking Strength lb N Tar.

{9)

~lO) (111 Level 4 Bright (Uncoated) or Drawn-Galvanized Breaking Strength lb N Tor.

(12~

{13) (14~ Level 5 Bright (Uncoated) or Drawn-Galvanized Breaking Strength lb N Tar.

0.230 0.231 0.232 0.233 0.234

5.84 5.87 5.89 5.92 5.94

7,857 7,920 7,982 8,045 8,108

34,948 35,228 35,504 35,784 36,064

10 10 10 9 9

9,036 9,107 9,179 9,252 9,324

40,192 40,508 40,828 41,153 41,473

9 9 9 9 9

9,939 10,018 10,097 10,177 10,257

44,209 44,560 44,911 45,267 45,623

8 8 8 8 8

10,685 10,770 10,855 10,940 11,026

47,527 47,905 48,283 48,661 49,044

7 7 7 7 7

0.235 0.236 0.237 0.238 0.239

5.97 5.99 6.02 6.05 6.07

8,171 8,235 8,298 8,362 8,426

36,345 36,629 36,910 37,194 37,479

9 9 9 9 9

9,397 9,470 9,543 9,616 9,690

41,798 42,123 42,447 42,772 43,101

9 8 8 8 8

10,336 10,417 10,497 10,578 10,659

45,975 46,335 46,691 47,051 47,411

8 8 8 8 8

11,112 11,198 11,284 11,371 11,458

49,426 49,809 50,191 50,578 50,965

7 7 7 7 7

0.240 0.241 0.242 0.243 0.244

6.10 6.12 6.15 6.17 6.20

8,490 8,554 8,619 8,683 8,748

37,764 38,048 38,337 38,622 38,911

9 9 9 9 9

9,763 9,837 9,912 9,986 10,061

43,426 43,755 44,089 44,418 44,751

8 8 8 8 8

10,740 10,821 10,903 10,984 11,067

47,772 48,132 48,497 48,857 49,226

8 8 8 8 8

11,545 11,633 11,720 11,807 11,897

51,352 51,744 52,131 52,522 52,918

6 6 6 6 6

0.245 0.246 0.247 0.248 0.249

6.22 6.25 6.27 6.30 6.32

8,813 8,879 8,944 9,010 9,075

39,200 39,494 39,783 40,076 40,366

9 9 9 9 9

10,135 10,210 10,286 10,361 10,437

45,060 45,414 45,752 46,086 46,424

8 8 8 8 8

11,149 11,231 11,314 11,397 11,480

49,591 49,955 50,325 50,694 51,063

7 7 7 7 7

11,985 12,074 12,163 12,252 12,341

53,309 53,705 54,101 54,497 54,893

6 6 6 6 6

9,141 40,659

9

10,512 46,757

8

11,564 51,437

7

12,431 55,293

6

0.250 6 . 3 5

(text continued from page 544)

Galvanized Wire Rope. Galvanized wire rope shall be made of wire having a tightly adherent, uniform and continuous coating of zinc applied after final cold drawing, by the electrodeposition process or by the hot-galvanizing process. The minimum weight of zinc coating shall be as specified in Table 4-11. Drawn-Galvanized Wire Rope. Drawn-galvanized wire rope shall be made of wire having a tightly adherent, uniform, and continuous coating of zinc applied at an intermediate stage of the wire drawing operation, by the electrodeposition process or by the hot-galvanizing process. The minimum weight of zinc coating shall be as specified in Table 4-12.

Properties and Tests for Wire and Wire Rope Selection of Test Specimens. For the test of individual wires and of rope, a 10-fl (3.05-m) section shall be cut from a finished piece of unused and undamaged

564

Drilling a n d Well Completions

Table 4-11 Weight of Zinc Coating for Galvanized Rope Wire [12] (1)

(2)

(3)

(4)

Minimum Weight Diameter of Wire

of Zinc Coating ozJft2 kg/m2

in.

mm

0.028 to 0.047 0.048 to 0.054 0.055 to 0.063 0.064 to 0.079 0.080 to 0.092 0.093 and larger

0.71 to 1.19 1.22 to 1.37 1.40 to 1.60 1.63 to 2.01 2.03 to 2.34 2.36 and larger

0.20 0.40 0.50 0.60 0.70 0.80

0.06 0.12 0.15 0.18 0.21 0.24

Table 4-12 Weight of Zinc Coating for Drawn-Galvanized Rope Wire [12] (1)

(2) Diameter of Wire

(3) (4) MinimumWeight of Zinc Coating ozJft2 kgtm2

in.

mm

0.018 to 0.028 0.029 to 0.060

0.46 to 0.71 0.74 to 1.52

0.10 0.20

0.03 0.06

0.061 to 0.090 0.091 to0.140

1.55 to 2.29 2.31 to 3.56

0.30 0.40

0.09 0.12

wire rope; such sample must be new or in an u n u s e d condition. The total wire n u m b e r to be tested shall be equal to the n u m b e r of wires in any one strand, and the wires shall be selected from all strands of the rope. The specimens shall be selected from all locations or positions so that they would constitute a complete composite strand exactly similar to a regular strand in the rope. The specimen for all "like-positioned" (wires symmetrically placed in a strand) wires to be selected so as to use as nearly as possible an equal n u m b e r from each strand. Any unsymmetrically placed wires, or marker wires, are to be disregarded entirely. Center wires are subject to the same stipulations that apply to symmetrical wires. Selection and testing of wire prior to rope fabrication will be adequate to ensure the after-fabrication wire rope breaking strength and wire requirements can be met. Prior to fabrication, wire tests should meet the requirements of Table 4-10.

Conduct of Tests. The test results of each test on any one specimen should be associated and may be studied separately from other specimens. If, when making any individual wire test on any wire, the first specimen fails, not more than two additional specimens from the same wire shall be tested. T h e average of any two tests showing failure or acceptance shall be used as the value to represent the wire. The test for the rope may be terminated at any time sufficient failures have occurred to be the cause for rejection.

Hoisting System

565

The purchaser may at his or her expense test all of the wires if the results of the selected tests indicate that further checking is warranted.

Tensile Requirements of Individual Wire. Specimens shall not be less than 18 in. (457 mm) long, a n d the distance between the grips of the testing machine shall not be less than 12 in. (305 mm). The speed of the movable head of the testing machine, u n d e r no load, shall not exceed 1 i n . / m i n (0.4 m m / s ) . Any specimen breaking within ¼ in. (6.35 mm) from the jaws shall be disregarded and a retest made. Note: The diameter of wire can more easily a n d accurately be determined by placing the wire specimen in the test machine a n d applying a load not over 25% of the breaking strength of the wire. The breaking strength of either bright (uncoated) or drawn-galvanized wires of the various grades shall meet the values shown in Table 4-9 or Table 4-10 for the size wire being tested. Wire tested after rope fabrication allows one wire in 6×7 classification, or three wires in 6×19 a n d 8×19 classifications a n d 18×7 a n d 19×7 constructions, or six wires in 6×37 classification or n i n e wires in 6×61 classification, or twelve wires in 6×91 classification wire rope to fall below, but not more than 10% below, the tabular value for individual m i n i m u m . If, when making the specified test, any wires fall below, but not more than 10% below, the individual m i n i m u m , additional wires from the same rope shall be tested until there is cause for rejection or until all of the wires in the rope have b e e n tested. Tests of individual wires in galvanized wire rope a n d of individual wires in strand cores a n d in i n d e p e n d e n t wire rope cores are not required.

Torsional Requirements of Individual Wire. The distance between the jaws of the testing machine shall be 8 in. _+ ~ in. (203 m m ± 1 mm). For small diameter wires, where the n u m b e r of turns to cause failure is large, a n d in order to save testing time, the distance between the jaws of the testing machine may be less than 8 in. (203 mm). O n e e n d of the wire is to be rotated with respect to the other end at a u n i f o r m speed not to exceed sixty 360 ° (6.28 rad) twists per minute, until breakage occurs. The m a c h i n e must be e q u i p p e d with an automatic counter to record the n u m b e r of twists causing breakage. O n e jaw shall be fixed axially a n d the other jaw movable axially and arranged for applying tension weights to wire u n d e r test. Tests in which breakage occurs within !8 in. (3.18 mm) of the jaw shall be discarded. In the torsion test, the wires tested must meet the values for the respective grades a n d sizes as covered by Table 4-12 or Table 4-13. In wire tested after rope fabrication, it will be permissible for two wires in 6×7 classification or five wires in 6×19 and 8×19 classifications and 18×7 and 19×7 constructions or ten wires in 6×37 classification or fifteen wires in 6×61 classification, or twenty wires in 6×91 classification rope to fall below, but not more than 30% below, the specified m i n i m u m n u m b e r of twists for the individual wire being tested. D u r i n g the torsion test, t e n s i o n weights as shown in Table 4-13 shall be applied to the wire tested. The m i n i m u m torsions for individual bright (uncoated) or drawn-galvanized wire of the grades a n d sizes shown in C o l u m n s 7, 12, a n d 17 of Tables 4-9 a n d 4-10 shall be the n u m b e r of 360 ° (6.28 rad) twists in an 8-in. (203 mm) length that the wire must withstand before breakage occurs. Torsion tests of individual wires in galvanized wire rope a n d o f i n d i v i d u a l wires in s t r a n d cores a n d i n d e p e n d e n t wire rope cores are not required. W h e n the distance between the jaws of the testing machine is less than 8 in. (203 mm), the m i n i m u m torsions shall be reduced in direct p r o p o r t i o n to the change in jaw spacing, or d e t e r m i n e d by

566

Drilling a n d Well C o m p l e t i o n s

Table 4-13 Applied Tension for Torsional Tests [12] (1)

(2) Wire Size Nominal Diameter

(in) 0.011 tO 0.016 0.017 tO 0.020 0.021 tO 0.030 0.031 tO 0.040 0.041 to 0.050 0.051 tO 0.060 0.061 tO 0.070 0.071 tO 0.080 0.081 tO 0.090 0.091 tO0.100 0.101 tO0.110 0.111 tO0.120 0.121 tO 0.130 *Weights shall not exceed

T~ = (TL)(L~) (LL)

(mm)

(3)

(4)

Minimum Applied Tension* (Ib) (N)

0.28 tO 0.42 1 0.43 tO 0.52 2 0.53 tO 0.77 4 0.78 tO 1.02 6 1.03 to 1.28 8 1.29 tO 1.53 9 1.54 tO 1.79 11 1.80 tO 2.04 13 2.05 tO 2.30 16 2.31 tO 2.55 19 2.56 tO 2.80 21 2.81 tO 3.06 23 3.07 tO 3.31 25 twice the minimums listed.

4 9 18 27 36 40 49 58 71 85 93 102 111

(4-22)

where T s = m i n i m u m torsions for short wire T L = m i n i m u m torsions for 8-in. (203-mm) length as given in Table 4-9 for size and g r a d e of wire L = distance between testing-machine jaws for short wire in in. (mm) L L = 8 in. (203 ram)

Breaking Strength Requirements for Wire Rope. The nominal strength of the various grades of finished wire rope with fiber core shall be as specified in Tables 4-14, 4-15, and 4-16. The nominal strength of the various grades of wire rope having a strand core or an independent wire-rope core shall be as specified in Tables 4-17 through 4-22. The nominal strength of the various types of flattened strand wire rope shall be specified in Table 4-23. The nominal strength of the various grades of drawn-galvanized wire rope shall be specified in Tables 4-14 through 4-23. W h e n testing f i n i s h e d wire-rope tensile test s p e c i m e n s to t h e i r b r e a k i n g strength, suitable sockets shall be attached by the correct method. T h e length of test specimen shall not be less than 3 ft (0.91 m) between sockets for wire ropes up to 1-in. (25.4 ram) d i a m e t e r and not less than 5 ft (1.52 m) between sockets for wire ropes 1 ~-in. (28.6 ram) to 3-in. (77 ram) diameter. O n wire ropes larger than 3 in. (77 ram), the clear length of the test specimen shall be at least 20 times the rope diameter. The test shall be valid if failure occurs 2 in. (50.8 ram) from the sockets or holding mechanism. Due to t h e variables in s a m p l e p r e p a r a t i o n a n d testing p r o c e d u r e s , it is difficult to d e t e r m i n e the t r u e strength. Thus, the actual b r e a k i n g s t r e n g t h d u r i n g test shall be at least 97.5% of the n o m i n a l strength as shown in the applicable table. If the first specimen fails at a value below the 97.5% n o m i n a l strength value, a s e c o n d test shall be made, a n d if the second test meets the strength requirements, the wire rope shall be accepted.

Hoisting System

567

Table 4-14 Classification Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Fiber Core [12] (I)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(I 0)

Nominal Strength Nominal

Approx.

Diameter

Mass

in. 3/s 7/16 t/2 9/t6

5/S 3/4 7/8 I

nnn 9.5 11.5 13 14.5 16 19 22 26

Plow Steel

I m p r o v e d P l o w Steel Metric

Ib/ft

kg/m

Ib

0.21 0.29 0.38 0.48 0.59 0.84 1.15 1.50

0.31 0.43 0.57 0.71 0.88 1.25 1.71 2.23

10,200 13,800 17,920 22,600 27,800 39,600 53.400 69,000

kN 45.4 61.4 79.7 101 124 176 238 307

Metric

Tonnes

Ib

4.63 6.26 8.13 10.3 12.6 18.0 24.2 31.3

11,720 15,860 20,600 26,000 31,800 45,400 61,400 79,400

kN

Tonnes

52.1 70.5 91.6 116 141 202 273 353

5.32 7.20 9.35 11.8 14.4 20.6 27.9 36.0

Table 4-15 6~19 and 6~37 Classification Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Fiber Core [12] (I)

(2)

Nominal Diameter in. mm t]2 13 9116 14.5 5]$ 16 3]4 19 7]s 22 1 26 Ills 29 11/4 32 13/8 35 It]2 38 IS/S 42 1314 45 ]'I]g 48 2 52

(3)

(4)

Approx. Mass Ib/fl kg/m 0.42 0.63 0.53 0.79 0.66 0.98 0.95 1.41 1.29 1.92 1.68 2.50 2.13 3.17 2.63 3.9[ 3.18 4.73 3.78 5.63 4.44 6.61 5.15 7.66 5.91 8.80 6.72 10.0

(5)

(6)

(7)

Plow Steel Ib 18,700 23,600 29,000 41,400 56,000 72,800 91,400 112,400

kN 83.2 106 129 184 249 324 407 500

Metric Tonnes 8.48 10.7 13.2 18.8 25.4 33.0 41.5 51.0

(8)

(9) (I0) Nomi~S~ngth ImprovedPlowSteel Metric Ib kN Totnmes 21,400 95.2 9.71 27,000 120 12.2 33,400 149 15.1 47,600 212 21.6 64,400 286 29.2 83,600 372 37.9 105,200 468 47.7 129,200 575 58.5 155,400 691 70.5 184,000 818 83.5 214,000 952 97.1 248D00 II00 112 282,000 1250 128 320,000 1420 146

(ll)

(12)

(13)

Extra ImprovedPlowSteel Metric lb kN Tonnes 23,600 105 10.7 29,800 132 13.5 36,600 163 16.6 52,400 233 23.8 70,800 315 32.1 92,000 409 41.7 115,600 514 52.4 142,200 632 64.5 171,000 760 77.6 202,000 898 91.6 236,000 1050 107 274000 1220 124 312,000 1390 142 352,000 1560 160

Manufacture and Tolerances Strand Construction. The 6x7 classification ropes shall contain six strands that are made up o f 3 through 14 wires, of which no more than 9 are outside wires fabricated in one operation.* See Table 4-14 and Figure 4-37. (text continued on page 571)

*One operation strand--When t h e k i n g w i r e o f t h e s t r a n d b e c o m e s so l a r g e ( m a n u f a c t u r e r ' s d i s c r e t i o n ) t h a t it is c o n s i d e r e d u n d e s i r a b l e , it is a l l o w e d to b e r e p l a c e d w i t h a s e v e n - w i r e s t r a n d m a n u f a c t u r e d in a s e p a r a t e s t r a n d i n g o p e r a t i o n . T h i s d o e s n o t c o n s t i t u t e a t w o - o p e r a t i o n s t r a n d .

568

Drilling and Well Completions

(1)

(2)

Table 4-16 18×7 Construction Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Fiber Core [12] (3) (4) (5) (6) (7) (8) (9)

( l 0)

Nominal Strength* Nominal Diameter in. mm

Approx. Mass Ib/ft kg/m

t/2 9/t6 5/, 3/4 7/. 1 I i/. 1I/4 13/s 1I/2

0.43 0.55 0.68 0.97 1.32 1.73 2.19 2.70 3.27 3.89

13 14.5 16 19 22 26 29 32 35 38

0.64 0.82 1.01 1.44 1.96 2.57 3.26 4.02 4.87 5.79

Improved Plow Steel Metric Ib kN Tonnes 19,700 24,800 30,600 43,600 59,000 76,600 96,400 118,400 142,600 168,800

87.6 110 136 194 262 341 429 527 634 751

8.94 11.2 13.9 19.8 26.8 34.7 43.7 53.7 64.7 76.6

Extra Improved Plow Steel Metric lb kN Tonnes 21,600 27,200 33,600 48,000 65,000 84,400 106,200 130,200 156,800 185,600

96.1 121 149 214 289 375 472 579 697 826

9.80 12.3 15.2 21.8 29.5 38.3 48.2 59.1 71.1 84.2

*These strengths apply only when a test is conducted with both ends fixed. When in use, the strength of these

ropesmay be significantly reduced if one end is free to rotate.

Table 4-17 6×19 Classification Wire Rope, Bright (Uncoated)

or Drawn-Galvanized Wire, Independent Wire-Rope Core [12] (1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(1 I)

(12)

(13)

Nominal Strength Nominal Diameter in. mm

Approx. ML~ Ib/It kg/m

t/2 9/16 5/s 3/4 "7/~

0.46 0.59 0.72 1.04 1.42 1.85 2.34 2.89 3.50 4.16 4.88 5.67 6.50 7.39

I II/S IX/4 I3/S It/2 I5/S 13/4 17/S 2

13 14.5 16 19 22 26 29 32 35 38 42 45 48 52

0.68 0.88 1.07 1.55 2. l I 2.75 3.48 4.30 5.21 6.19 7.26 8.44 9.67 11.0

Improved ~ Ib 23,000 29,000 35,800 51,200 69,200 89,800 113,000 138,800 167,000 197,800 230,000 266,000 304,000 344,000

kN 102 129 159 228 3GB 399 503 617 743 880 1020 1180 1350 1630

Steel Mewic Tonn~ 10.4 13.2 16.2 23.2 31.4 40.7 5t,3 63.0 75.7 89.7 104 121 138 156

Extra Improved Plow Steel Melrk: Ib kN Tcca'~s 26,600 33,600 41,200 58,800 79,600 103,400 130,000 159,800 192,000 228,000 264,000 3~000 348,000 396,000

118 149 183 262 354 460 678 711 854 1010 1170 1360 1550 1760

i2.l 15.2 18.7 26.7 36.1 469 59.0 72.5 87.1 103 120 139 158 180

Extra Extra Improved Plow Steel Mea'¢ Ib kN To,rues 29,200 37,000 45,400 64,800 87,600 113,800 |43,000 175,800 212,000 250,000 292,000 338,000 384,000 434~000

130 165 202 288 389 506 636 782 943 1112 1300 15~0 1710 1930

13.2 16.8 20.6 29,4 39.7 51.6 64.9 79.8 96.2 113 132 153 I74 197

Hoisting

System

569

Table 4-18 6x37 Classification Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Independent Wire-Rope Core [12] (1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(11)

(12)

(13)

Nominal Strength

in.

mm

Approx. Mass Ib/fl kf,/m

1/2 9h6 5/S 3/4 ?/s I II/a 1t/4 l:t/A 1112 15/s 1~t/4 I?/s 2 2J/s 21/4 23/S 2112 25/s 23/4 27/s 3 31Is 31/4 3:t/Is 3112 3:t/4 4

13 14.5 16 19 22 26 29 32 35 38 42 45 48 52 54 58 60 64 67 71 74 77 80 83 87 90 96 103

0.46 0.59 0,72 1.04 1.42 1.85 2.34 2.89 3.50 4.16 4.88 5.67 6.50 7,39 8.35 9.36 10.4 11.6 IZ8 14.0 15.3 16.6 18.0 19,5 21.0 22.7 26.0 29.6

Nominal Diameter

0.68 0.88 1.07 1..55 2.11 2.75 3.48 4.30 5.21 6A9 7.26 8.44 9.67 IL0 12.4 13.9 15.5 17.3 19.0 20.8 22.8 24.7 26.8 29.0 31.3 33.8 38.7 44.0

Imlxoved Plow Steel Meu'ic Ib kN Tot,.ncs 23,000 29,000 35,800 51,200 69,200 89,800 113,000 138,800 167,000 197,800 230,000 266,000 304,000 344,000 384,0(]0 430,(X]0 478,000 524,(X]0 576,000 628,000 682,0~0 740,000 798,000 858,000 918,000 982,000 l,114,(X]0 1,254,0(X)

102 129 159 228 308 399 503 617 743 880 1020 1180 1350 1530 1710 1910 2130 2330 2560 2790 3030 3290 3550 3820 4080 4370 4960 5580

10.4 13.2 16.2 23.2 31.4 40.7 51.3 63.0 75.7 89.7 104 121 138 156 174 195 217 238 261 285 309 336 362 389 416 445 505 569

Extra Extra Implored Plow Steel

Plow Steel Meuic kN Tonnes

Exlra l ~ v e d Ib 26,600 33,600 41,200 58,800 79,600 103,400 130,000 159,800 192,000 228,000 264,000 306,000 348,000 396,000 442,0(]0 494,000 548,0~0 604,000 658,0~0 736,000 796,0~0 856,0~0 920,000 984,(X]0 1,074,(X]0 1,144,(X]0 1,290,000 1,466,0(X)

118 149 183 262 354 460 578 711 854 1010 1170 1360 1550 1760 1970 2200 2440 2690 2930 3270 3540 3810 4090 4380 4780 5090 5740 6520

12.1 15.2 18.7 26.7 36.1 46.9 59.0 72,5 87.1 103 120 139 158 180 200 224 249 274 299 333 361 389 417 447 487 519 585 665

Ib

kN

Meuic Tonnes

29,200 37,000 45,400 64800 87,600 I 13,800 143,000 175,800 212,(X]0 250,000 292,(X]0 338,(X]0 384,000 434,000 488,0(]0 544,000 604,000 664,000 728,0~0 794,000 864,000 936,000 1,010,(X]O 1,0~6,(X]0 1,164,(X]0 1,242,000 1,410,000 1,586,0(X)

130 165 202 288 389 506 636 782 943 1112 1300 I.S00 1710 1930 2170 2420 2690 2950 3240 3530 3840 4160 4490 4830 5180 5520 6270 7050

13.2 16.8 20.6 29.4 39.7 51.6 64.9 79.8 96.2 113 132 153 174 197 221 247 274 301 330 360 392 425 458 493 528 563 640 720

Table 4-19 6x61 Classification Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Independent Wire-Rope Core [12] (I)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

Nominal Strength

in.

mm

Approx. Mass Ib/ft kg/m

31/2 33/4 4 41/4

90 96 103 109 I 15 ] 22 128

22.7 26.0 29.6 33.3 37.4 41.7 46.2

Nominal Diameter

41/2 43/4 5

33.8 38.7 44.0 49.6 55.7 62. l 68.8

Improved Plow Steel Ib

kN

Metric Tonnes

966,000 1,098,000 1,240,000 1,388,000 1,544,000 1,706,000 1,874,000

4300 4880 5520 6170 6870 7590 8340

438 498 562 630 700 774 850

Extra Improved Plow Steel Metric Ib kN Tonnes I,I 10,000 1,264,000 1,426,000 1,598,000 1,776,000 1,962,000 2,156,000

4940 5620 6340 7110 7900 8730 9590

503 573 647 725 806 890 978

Drilling and Well Completions

570

Table 4-20 6×91 Classification Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Independent Wire-Rope Core [12] (1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

Nominal Strength Approx.

Nominal Diameter

Improved plow Steel

in.

nun

Mass lb/ft kg/m

4 41/4 4t/2 43/4 5

103 109 115 122 128 135 141 148 154

29.6 33.3 37.4 41.7 46.2 49.8 54.5 59.6 65.0

51/4 51/2

53/4 6

44.1 49.6 55.7 62.1 68.7 74.1 81.1 88.7 96.7

Ib 1,178,000 1,320,000 1,468,000 1,620,000 1,782,000 1,948,000 2,120,000 2,296,000 2,480,000

Extra Improved Plow Steel

kN

Metric Tonnes

5240 5870 6530 7210 7930 8670 9430 10200 I 1000

534 599 666 735 808 884 962 1049 I 125

kN

Metric Tonnes

6020 6750 7510 8290 91 I0 9960 10800 11700 12700

614 689 766 846 929 1016 1106 1198 1294

Ib 1,354,000 1,518,000 1,688,000 1,864,000 2,048,000 2,240,000 2,438,000 2,640,000 2,852,000

Table 4-21 8×19 Classification Wire Rope, Bright (Uncoated) or Drawn-Galvanized Wire, Independent Wire-Rope Core [12] (1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

Nominal Strength Nominal Diameter

Improved Plow Steel

Approx. Mass

Extra Improved Plow Steel

in.

mm

Ib/ft

kg/m

Ib

kN

Metric Tonnes

I/2 9/t6 5/s 3/4 7/s I I ;/a

13 14.5 16 19 22 26 29

0.47 0.60 0.73 1.06 1.44 1.88 2.39

0.70 0.89 1.09 1.58 2.14 2.80 3.56

20,200 25,600 31,400 45,000 61,000 79,200 99,600

89.9 114 140 200 271 352 443

9.16 11.6 14.2 20.4 27.7 35.9 45.2

[b

kN

Metric Tonnes

23,400 29,400 36,200 51,800 70,000 91,000 114,600

104 131 161 230 311 405 507

10.5 13.3 16.4 23.5 31.8 41.3 51.7

T a b l e 4-22 19×7 C o n s t r u c t i o n W i r e R o p e , B r i g h t ( U n c o a t e d ) or D r a w n - G a l v a n i z e d Wire, W i r e S t r a n d C o r e [12] (1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

Nominal Strength* Nominal Diameter in. mm

Approx. Mass Ib/ft kg/m

t/2 9/16 5/s 3/4 7/s I I t/s It/4 13/s 11/2

0.45 0.58 0.71 1.02 1.39 1.82 2.30 2.84 3.43 40.8

13 14.5 16 19 22 26 29 32 35 38

0.67 0.86 1.06 1.52 2.07 2.71 3.42 4.23 5.10 6.07

ImprovedPlow Steel Metric lb kN Tonnes 19,700 24,800 30,600 43,600 59,000 76,600 96,400 118,400 142,600 168,800

87.6 II0 136 194 262 341 429 527 634 751

8.94 11.2 13.9 19.8 26.8 34.7 43.7 53.7 64.7 76.6

Extra Improved Plow Steel Metric Ib kN Tonnes 21,600 27,200 33,600 48,000 65,000 84,400 106,200 130,200 156,800 185,600

96. I 121 149 214 289 375 472 579 697 826

9.80 12.3 15.2 21.8 29.5 38.3 48.2 59.1 71.1 84.2

*Thesestrengthsapplyonly whena test is conductedwith bothendsfixed. When in use,the strengthof these ropes may be significantly reduced ifoig end is free to rotate.

Hoisting System

571

Table 4-23 6x25 "B," 6x27 "H," 6x30 "G," 6x31 "V" Flattened Strand Construction Wire Rope Bright (Uncoated) or Drawn-Galvanized Wire [12] (I)

(2)

(3)

(4)

Nominal

Approx.

Diameter

Mass

in. t/2 9/16

5/s 3/4 7/8 1 I I/8 1 I/4 13/8 I I/2 15/s

13//4 17/8 2

(5)

(6)

(7) (8) (9) 'l~jpicalNominalStten~h*

Improved Plow Steel

mm

Ib/ft

kg/m

Ib

13 14.5 16 19 22 26 29 32 35 38 42 45 48 52

0.47 0.60 0.74 1.06 1.46 1.89 2.39 2.95 3.57 4.25 4.99 5.74 6.65 7.56

0.70 0.89 I. I0 1.58 2.17 2.81 3.56 4.39 5.31 6.32 7.43 8.62 9.90 I 1.2

25,400 32,000 39,400 56,400 76,000 98,800 124,400 152,600 183,600 216,000 254,000 292,000 334,000 378,000

kN I 13 142 175 25 1 330 439 553 679 817 961 1,130 1,300 1,490 1,680

Metric Tonnes I 1.5 14.5 17.9 25.6 34.5 44.8 56.4 69.2 83.3 98.0 115 132 151 171

(10)

Extra Imp. Plow Steel

Ib

kN

Metric Tonnes

28,000 35,200 43,400 62,000 83,800 108,800 137,000 168,000 202,000 238,000 280,000 322,000 368,000 414,000

125 157 193 276 373 484 609 747 898 1,060 1,250 1,430 1,640 1,840

12.7 16.0 19.7 28. I 38.0 49.3 62.1 76.2 91.6 108 127 146 167 188

(text continued from page 567)

T h e 6×19 classification ropes shall contain 6 strands that are made up of 15 through 26 wires, of which no more than 12 are outside wires fabricated in one operation. See Tables 4-15 and 4-17 and Figures 4-38 to 4-43. The 6×37 classification ropes shall contain six strands that are made up of 27 through 49 wires, of which no more than 18 are outside wires fabricated in one operation. See Tables 4-15 and 4-18 and Figures 4-44 to 4-51. The 6×61 classification ropes shall contain six strands that are made up of 50 through 74 wires, of which no more than 24 are outside wires fabricated in one operation. See Table 4-19 and Figures 4-52 and 4-53. The 6×91 classification wire rope shall have six strands that are made up of 75 through 109 wires, of which no more than 30 are outside wires fabricated in one operation. See Table 4-20 and Figures 4-54 and 4-55. T h e 8×19 classification wire rope shall have eight strands that are made up of 15 through 26 wires, of which no more than 12 are outside wires fabricated in one operation. See Table 4-21 and Figures 4-56 and 4-57. The 18×7 and 19×7 wire rope shall contain 18 or 19 strands, respectively. Each strand is made up of seven wires. It is m a n u f a c t u r e d counterhelically laying an outer 12-strand layer over an inner 6×7 or 7×7 wire rope. This produces a rotationresistant characteristic. See Tables 4-16 and 4-22 and Figures 4-58 and 4-59. The 6×25 "B," 6×27 "H," 6×30 "G," and 6×31 "V" flattened strand wire rope shall have six s t r a n d s with 24 wires fabricated in two o p e r a t i o n s a r o u n d a semitriangular shaped core. See Table 4-23 and Figures 4-60 to 4-63. In the manufacture of uniform-diameter wire rope, wires shall be continuous. If joints are necessary in individual wires, they shall be made, prior to fabrication (text continued on page 575)

572

Drilling and Well Completions

FIGURE 4-37 6 x 7 WITH FIBER CORE

6 x 7 CLASSIFICATION

FIGURE 4 - 3 8 6 x 19 SEALE WITH FIRER CORE

FIGURE 4-39 6 x 19 SEALE WITH INDEPENDENTWIRI~ROPE CORE

FIGURE 4-40 6 x 21 FILLER WIRE WITH FIBER CORE

FIGURE 4-41 6 x 2 5 FILLER WIRE WITH FIBER CORE

FIGURE 4-42 6 x 25 FILLER WIRE WITH INDEPENDENT WIRE-ROPE CORE

FIGURE 4-43 6 x 2 6 WARRINGTON SEALE WITH INDEPENDENT WIRE-ROPE CORE

6 x 19 C L A S S I F I C A T I O N TYPICAL WIRE-ROPE CONSTRUCTIONS WITH CORRECT ORDERING DESCRIPTIONS (See the paragraph"StrandConstruction," or construction which may be ordered with either fiber cores or independent wire rope cores.)

Figure Figure Figure Figure Figure Figure Figure

4-37. 4-38. 4-39. 4-40. 4-41. 4-42. 4-43.

6x7 with fiber core [12]. 6x19 seale with fiber core [12]. 6x19 seale with independent wire-rope core [12]. 6x21 filler wire with fiber core [12]. 6x25 filler wire with fiber core [12]. 6x25 filler wire with independent wire-rope core [12]. 6x26 Warrington seale with independent wire-rope core [12].

Hoisting System

FIGURE 4-44 6 x 31 FILLERWIRE SEALE INDEPENDENT WIRE-ROPECORE

FIGURE4-45 6 x 31WARRINGTONSEARLE WITH INDEPENDENT WIRE-ROPECORE

FIGURE 4-46 6 x 36 FILLER WIRE WITH INDEPENDENT WIRE-ROPECORE

FIGURE 4-47 6 x 36 WARRINGTONSEALE WITH INDEPENDENT WIRE-ROPECORE

FIGURE 4-48 6 x 41 WARRINGTONSEALE WITH INDEPENDENT WIRE-ROPECORE

FIGURE 4-49 6 x 41 FILLERWIRE WITH INDEPENDENT WIRE-ROPECORE

FIGURE 4-$O 6 x 4 6 FILLERWIRE WITH INDEPENDENT WIRE-ROPECORE

FIGURE 4-$1 6 x 49 FILLER WIRE SEARLE WITH INDEPENDENT WIRE-ROPECORE

573

6 × 37 CLASSIFICATION

FIGURE4-55 x 61 WARRINGTONSEALE INDEPENDENT wmE-ROeECORE

FIGURE 4-5, 6 x 91 WITH INDE ,ENDENT WIRE-ROPECORE (TWO-OPERATIONALSTRAND) TYPICAL WIRE-ROPE

6 x 61

CLASSIFICATION

FIGURE 4-$3 6 x 73 FILLER WIRE SEARLE WITH INDEPENDENT WmE-ROeECORE

91

CLASSIFICATION

HGURE4-55 6xlO3WITHINDEPENDENT WIRE-ROPECORE (TWO.OPERATION~ND)

6

x

CONSTRUCTION

(See the p a r a g r a p h titled "Strand Construction" fiber

Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure

WITH CORRECT

ORDERING

DESCRIPTIONS

for construction which m a y b e o r d e r e d with e i t h e r

cores or independent wire rope cores.)

4-44. 6x31 filler wire scale with independent wire-rope core [12]. 4-45. 6x31 Warrington scale with independent wire-rope core [12]. 4-46. 6x36 filler wire with independent wire-rope core [12]. 4-47. 6x36 Warrington scale with independent wire-rope core [12]. 4-48. 6x41 Warrington scale with independent wire-rope core [12]. 4-49. 6x41 filler wire with independent wire-rope core [12]. 4-50. 6x46 filler wire with independent wire-rope core [12]. 4-51. 6x49 filler wire scale with independent wire-rope core [12]. 4-52. 6x61 Warrington scale with independent wire-rope core [12]. 4-53. 6x73 filler wire scale with independent wire-rope core [12]. 4-54. 6x91 with independent wire-rope core (two-operation strand) [12]. 4-55. 6x103 with independent wire-rope core (two-operation strand) [12].

574

Drilling and Well Completions

FIGURE 4-56 8 x 21 FILLERWIRE WITH INDEPENDENT WIRE-ROPE CORE

FIGURE 4-57 8 x 25 FILLER W1RE WITH INDEPENDENT WIRE-ROPE CORE

8 x 19 C L A S S E F I C A T I O N

FIGURE 4-58 18 x 7 NON-ROTATING WIRE ROPE FIBER CORE

19

x

FIGURE 4-59 7 NON-ROTATING WIRE ROPE

FIGURE 4-60 6 x 25TYPEB FLA'II'ENED STRAND WITH INDEPENDENTW1RE-ROPE CORE

18 x 7 A N D 19 x 7 C O N S T R U C T I O N

FIGURE 4-61 6x 27TYPEH FLA'II'ENED STRAND WITH INDEPENDENT WIRE-ROPE CORE

FIGURE 4-62 6x30S G WITH INDEPENDENT WIRE-ROPE CORE

FIGURE 4-63 6x 31TYPEV. FLATI'ENED STRAND WITH INDEPENDENTWIRE-ROPE CORE

TYPICAL WIRE-ROPE CONSTRUCTIONS WITH CORRECT ORDERING DESCRIPTIONS (See the paragraph rifled "Strand Construction '' for construction which may be ordered with either fiber cores or independent wire rope cores.)

Figure Figure Figure Figure Figure Figure Figure Figure

4-56. 8x21 filler wire with independent wire-rope core [12]. 4-57. 8x25 filler wire with independent wire-rope core [12]. 4-58. 18x7 nonrotating wire rope with fiber core [12]. 4-59. 19x7 nonrotating wire rope [12]. 4-60. 6x25 type B flattened strand with independent wire-rope 4-61.6x27 type H flattened strand with independent wire-rope 4-62. 6x30 style G flattened strand with independent wire-rope 4-63. 6x31 type V flattened strand with independent wire-rope

core core core core

[12]. [12]. [12]. [12].

Hoisting System

575

(text continued from page 571)

of the strand, by brazing or electric welding. Joints shall be spaced in accordance with the equation J = 24D

(4-23)

where J = m i n i m u m distance between joints in main wires in any one strand in in. m m D = n o m i n a l diameter of wire rope in in. m m Wire rope is most often furnished preformed, but can be furnished nonpreformed, u p o n special request by the purchaser. A preformed rope has the strands shaped to the helical form they assume in the finished rope before the strands have been fabricated into the rope. The strands of such preformed rope shall not spring from their normal position when the seizing bands are removed. Cable tool is one of the few applications for which n o n p r e f o r m e d is still used.

The Lay of Finished Rope. Wire rope shall be furnished right lay or left lay and regular lay or Lang lay as specified by the purchaser (see Figure 4°64). If not otherwise specified on the purchase order, rightqay, regular-lay rope shall be furnished. For 6x7 wire ropes, t h e lay of the finished rope shall not exceed eight times the n o m i n a l diameter. For 6x19, 6x37, 6x61, 6x91, and 8x19 wire rope, the lay of the f i n i s h e d rope shall not exceed 7¼ times the n o m i n a l diameter. For flattened strand rope designations 6x25 "B," 6x27 "H," 6x30 "G," and 6x31 "V," the lay of the finished rope shall not exceed eight times the n o m i n a l diameter.

Diameter of Ropes and Tolerance Limits. The diameter of a wire rope shall be the diameter of a circumscribing circle and shall be measured at least 5 ft (1.52 m) from properly seized end with a suitable caliper (see Figure 4-65). The diameter tolerance* of wire rope shall be Nominal inch diameter: -0% to +5% Nominal m m diameter: -1% to +4%

Diameter of Wire and Tolerance Limits. In separating the wire rope for gaging of wire, care must be taken to separate the various sizes of wire composing the different layers of bright (uncoated), drawn-galvanized, or galvanized wires in the strand. In like-positioned wires total variations of wire diameters shall not exceed the values of Table 4-24. Fiber Cores. For all wire ropes, all fiber cores shall be hard-twisted, best-quality, manila, sisal, polypropylene, or equivalent. For wire ropes of u n i f o r m diameter, the cores shall be of u n i f o r m diameter and hardness, effectively s u p p o r t i n g the strands. Manila and sisal cores shall be thoroughly i m p r e g n a t e d with a suitable lubricating c o m p o u n d free from acid. Jute cores shall not be used.

*A question may develop as to whether or not the wire rope complies with the oversize tolerance. In such cases, a tension of not less than 10% nor more than 20% of nominal required breaking strength is applied to the rope, and the rope is measured while under this tension.

576

Drilling and Well Completions a)

b)

c)

e)

Figure 4-64. Right and left lay, and regular and Lang lay [12].

Itpt_ i ~

I¥~- I ~

"U

"U

Correct way to measure the diameter of wire rope.

Incorrect way to measure the diameter of wire rope.

Figure 4-65. Measurement of diameter [12].

Hoisting System

577

Table 4-24 Wire Diameter Tolerance [12] (I)

(2)

(3)

(4) (5) Total Variation and D r a w n

inches 0.018 0.028 0.060 0.093 0.142

Wke Diameters mm

- 0.027 - 0.059 - 0.092 - 0.141 ~ larger

0.46 0.70 1.51 2.35 3.59

- 0.69 - 1.50 - 2.34 - 3.58 and larger

(6)

Galvanized

GalvanizedWires mc~s mm

mc~s

mm

0.0015 0.0020 0.0025 0.0030 0.0035

-0.0035 0.0045 0.0055 0.0075

-0.089 0.114 0.140 0.190

0.038 0.051 0.064 0.076 0.075

Wires

Lengths. L e n g t h of wire r o p e shall b e specified by the purchaser. If m i n i m u m length is critical to the application, it shall b e specified and c o n f o r m to the following tolerances. 1300 ft (400 m): - 0 to +5% > 1300 ft (400 m): Original tolerance + 66 ft (20 m) p e r each a d d i t i o n a l 3280 ft (1000 m) or part thereof. If m i n i m u m is not critical to the application, it shall c o n f o r m to the following tolerances. 1300 ft (400 m): _+2.5% > 1300 ft (400 m): Original tolerance + 33 ft (10 m) p e r each a d d i t i o n a l 3280 ft (1000 m) or p a r t thereof.

Lubrication. All wire rope, unless otherwise specified, shall be lubricated and i m p r e g n a t e d in the m a n u f a c t u r i n g process with a suitable c o m p o u n d for the a p p l i c a t i o n in a m o u n t s best a d a p t e d to i n d i v i d u a l territories. This lubricant should thoroughly protect the ropes internally a n d externally to minimize rust or c o r r o s i o n until the r o p e is p u t in service. Mooring Wire Rope M o o r i n g wire r o p e is used as a n c h o r lines in spread m o o r i n g systems, a n d shall comply with the all the provisions of Wire Rope. W i r e r o p e for this use s h o u l d b e o n e o p e r a t i o n , r i g h t lay, r e g u l a r lay, i n d e p e n d e n t wire r o p e core, p r e f o r m e d , galvanized or bright. T h e n o m i n a l strength of galvanized and b r i g h t m o o r i n g wire r o p e shall be as specified in Table 4-25. For b r i g h t m o o r i n g wire ropes, the wire g r a d e shall comply with the requirements for Extra I m p r o v e d Plow Steel, Table 4.2.8 o r ISO Std 2232* value o f 1770 N / m m 2.

*International Organization for Standardization, Standard'2232-1973, "Drawn Wire for General Purpose Non-Alloy Steel Wire Ropes-Specifications," available from American National Standards Institute, 1430 Broadway, New York, New York 10018.

578

Drilling and Well Completions

Table 4-25 6×19, 6×37, and 6×61 Construction Mooring Wire Rope, Independent Wire-Rope Core [12] 1

2

3

4

5

6

7

8

9

10

11

Nominal Strength Nominal

Construction

Diameter

Approximate Mass

Galvanized

Bright

Classification

0"# reX

in.

mm

lb/ft

kg/m

1 1~ I~A 1~ 1½ 1% I~ 1~

26 29 32 35 38 42 45 48 52 54 58 60 64 67 71 74 77 80 83 87 9o 96 103 109 115 122

1.85 2.34 2.89 3.50 4.16 4.88 5.67 6.50 7.39 8.35 9.36 10.4 11.6 12.8 14.0 15.3 16.6 18.0 19.5 21.0 22.7 26.0 29.6 33.3 37.4 41.7

2.75 3.48 4.30 5.21 6.19 7.26 8.44 9.67 11.0 12.4 13.9 15.5 17.0 18.6 20.9 22.7 24.6 26.6 28.6 31.4 33.6 38.2 44.0 49.3 54.9 61.8

2 21,~ 2'/, 2~ 2~

O~ X

2%

x

q~

2sA 27~ 3 3~ 3¼ 3~ 3~ 3s/, 4 4¼ 4~ 4~

lb 93.060 117,00~ 143.800 172.800 205,200 237.600 275.400 313,200 356.400 397.800 444.600 493,200 543,600 595,800 649.800 705,600 765,000 ~4,400 885.600 952,200 1,015.000 1,138,000 1.283,000 1.438,000 1.598.000 1.766,000

kN 414 520 640 769 913 1.06o 1.23o 1,390 1,59o 1,770 1,980 2,190 2.420 2,650 2.890 3,140 3,400 3.670 3,940 4,240 4,520 5,060 5,710 6.400 7.110 7.860

Metrit Tonnes 42.2 53.1 65.2 78.4 93.1 108 125 142 162 180 202 224 247 270 295 320 347 374 402 432 460 516 582 652 725 801

Metric lb 95,80o 119.000 145,000 174,000 2o5,000 25o,000 287,000 327.000 369,000 413,000 461,00~ 528,000 604,000 658,00~ 736,00~ 796,00~ 856,004] 920,000 984,000 L074,000 1,144,000 1,290,00~ 1,466,000 1.606.000 1.774.000 1,976,000

kN 426 530 646 773 911 1,110 1,280 1,450 1,640 1,840 2,050 2,350 2,690 2,930 3,270 3,540 3.810 4,090 4,380 4,780 5,090 5,740 6.520 7.140 7,890 8.790

Tonnes 43.5 54.1 65.9 78.8 92.9 113 130 148 167 188 209 239 274 299 333 361 389 417 447 487 519 585 665 728 805 896

NOTE: For tests see Paragraph titled "Acceptance."

Torpedo Lines Torpedo lines shall be bright (uncoated) or drawn-galvanized, a n d shall be right, regular lay. The lay of the finished rope shall not exceed eight times the n o m i n a l diameter. Torpedo lines shall be made of five strands of five wires each, or five strands of seven wires each. The strands of the 5×5 construction shall have one center wire and four outer wires of one diameter, fabricated in one operation. The five strands shall be laid a r o u n d one fiber or cotton core (see Figure 4-66). The strands of the 5×7 construction shall have one center wire and six outer wires of one diameter, fabricated in one operation. The strands shall be laid a r o u n d one fiber or cotton core (see Figure 4-67). The four outer wires in each strand of the 5×5 c o n s t r u c t i o n [both bright (uncoated) and drawn-galvanized] and all the wires in each strand of the 5×7 c o n s t r u c t i o n [both b r i g h t ( u n c o a t e d ) a n d drawn-galvanized] shall have the b r e a k i n g strengths as in Tables 4-15 a n d 4-16 for the specified g r a d e a n d applicable wire size. The center wire of the 5×5 construction shall be hard drawn or a n n e a l e d and shall not be required to meet the m i n i m u m breaking strength specified for the outer wires (the center wire represents about 5% of the total metallic area of the rope a n d is substantially a filler wire). The n o m i n a l strength of torpedo lines shall be as specified in Tables 4-26 and 4-27. W h e n testing finished ropes to their breaking strength, suitable sockets

Hoisting System

579

Figure 4-66. 5×5 construction torpedo line [12].

Figure 4-67. 5×7 construction torpedo line [12]. Table 4-26 5x5 Construction Torpedo Lines [12] (I)

(2)

Nominal Diameter of Rope in. mm I/s 9/64 5/32 3/t6 I/4 5/16

3.18 3.57 3.97 4.76 6.35 7.94

(3)

(4)

Approx. Mass Ib/100 ft kg/100 m 2.21 2.80 3.46 4.98 8.86 13.80

3.29 4.16 5.15 7.41 13.91 20.54

(5)

Ib 1,120 1,410 1,740 2,490 4,380 6,780

(6)

(7)

(8)

(9)

(I0)

Nominal Strength Plow Steel Improved Plow Steel Metric Metric kN Tonnes Ib kN Tonnes 4.98 6.27 7.74 11.08 19.48 30.16

0.51 0.64 0.79 1.13 1.99 3.08

1,290 1,620 2,000 2,860 5,030 7,790

5.74 7.21 8.90 12.72 22.37 34.65

(8)

(9)

0.59 0.74 0.9 I 1.30 2.28 3.53

Table 4-27 5x7 Construction Torpedo Lines [12] (I)

(2)

Nominal Diameter of Rope in. mm I/s 9/64 5/32 3/16 I/4 5/16

3.18 3.57 3.97 4.76 6.35 7.94

(3)

(4)

Approx. Mass Ib/100 ft kg/100 m 2.39 3.02 3.73 5.38 9.55 14.90

3.56 4.49 5.55 8.01 14.21 22.17

(5)

Ib 1,210 1,530 1,890 2,700 4,760 7,380

(6)

(7)

(10)

Nominal Strength Improved Plow Steel Plow Steel Metric Metric kN Tonnes Ib kN Tonncs 5.38 6.81 8.41 12.01 21.17 32.83

0.55 0.69 0.86 1.23 2.16 3.35

1,400 1,700 2,170 3,110 5,470 8,490

6.23 7.83 9.65 13.83 24.33 37.77

0.64 0.80 0.98 1.41 2.48 3.85

580

Drilling a n d Well C o m p l e t i o n s

or o t h e r acceptable means of holding small cords shall be used. The length of tension test specimens shall be not less than 1 ft (0.305 m) between attachments. If the first specimen fails at a value below the specified n o m i n a l strength, two additional specimens from the same r o p e shall be tested, one of which must comply with the n o m i n a l strength requirement. T h e d i a m e t e r of the ropes shall be not less than the specified diameter. Torpedo-line lengths shall vary in 500-ft (152.4 m) multiples.

Well-Measuring Wire Well-measuring wire shall be in accordance with Table 4-28, a n d shall consist of one continuous piece of wire without brazing or welding of the finished wire. T h e wire shall be m a d e from the best quality of specified g r a d e of material with g o o d w o r k m a n s h i p a n d shall be free from defects that might affect its a p p e a r a n c e or serviceability. Coating on well-measuring wire shall be o p t i o n a l with the purchaser. A specimen of 3-ft (0.91 m) wire shall be cut from each coil of well-measuring wire. O n e section of this specimen shall be tested for e l o n g a t i o n simultaneously with the test for tensile strength. The ultimate elongation shall be measured on a 10-in. (254 mm) specimen at instant of rupture, which must occur within the 10-in. (254 mm) gage length. To determine elongation, a 100,000-psi (690-mPa) stress shall be i m p o s e d u p o n the wire at which the e x t e n s o m e t e r is applied. Directly to the e x t e n s o m e t e r reading shall be a d d e d 0.4% to allow for the initial e l o n g a t i o n occurring before application of extensometer. T h e r e m a i n i n g section of the 3-ft (0.91-m) test specimen shall be gaged for size a n d tested for torsional requirements. If, in any individual test, the first specimen fails, not m o r e than two additional specimens from the same wire shall be tested. The average of any two tests showing failure or acceptance shall be used as the value to represent the wire.

Well-Measuring Strand Well-measuring s t r a n d shall be bright (uncoated) or drawn-galvanized. Well-measuring strand shall be left lay. The lay of the finished strand shall not exceed 10 times the nominal diameter. Well-measuring s t r a n d s may be of various c o m b i n a t i o n s of wires b u t are c o m m o n l y furnished in l x 1 6 (1-6-9) a n d lx19 (1-6-12) constructions. Well-measuring strands shall c o n f o r m to the p r o p e r t i e s listed in Table 4-29. To test finished strands to their breaking strength, suitable sockets or o t h e r acceptable means of holding small cords shall be used.

Wire Guy Strand and Structural Rope and Strand Galvanized wire guy s t r a n d shall conform to ASTM A-475: "Zinc-Coated Steel Wire Strand."* A l u m i n i z e d wire guy s t r a n d shall c o n f o r m to ASTM A-474: " A l u m i n u m C o a t e d Steel Wire Strand."* G a l v a n i z e d s t r u c t u r a l s t r a n d shall c o n f o r m to ASTM A-586: "Zinc-Coated Steel S t r u c t u r a l Strand."* Galvanized structural r o p e shall c o n f o r m to ASTM A-603: "Zinc-Coated Steel S t r u c t u r a l Wire Rope."*

*American Society for Testing and Materials, 1916 Race Street, Philadelphia, Pennsylvania 19103.

Hoisting System

581

Table 4-28 Requirements for Well-Measuring Wire, Bright or Drawn-Galvanized Carbon Steel* [12] 1 N o m i n a l Diameter "[ i n .

.

.

.

.

.

.

.

.

.

I m~ . .

Tolerance on diameter in . . . . . . . . . . . . . . ±0.001 mm . . . . . . . . . . . . . Breaking strength M i n i m u m lb . . . . . . . . . . . . . . . . . . . . . . . kN . . . . . . . . . . . . . . . . . . . . . . . Maximum lb . . . . . . . . . . . . . . . . . . . . . . . kN . . . . . . . . . . . . . . . . . . . . . . .

2

3

4

5

6

7

0.066 1.68

0.072 1.83

0.082 2.08

0.092 2.34

0.105 2.67

0.108 2.74

-+0.03

-+0.001

±0.001

-+0.001

-+0.001

±0.001

±0.03

±0.03

±0.03

±0.03

±0.03

811 3.61 984 4.38

961 4.27 1166 5.19

1239 5.51 1504 6.69

1547 6.88 1877 8.35

1966 8.74 2421 10.77

2109 9.38 2560 11.38

32

29

26

23

20

19

Elongation to 10 in. (254 ram), per cent Minimum . . . . . . . . . . . . . . . . . . . . . . . . . Torsions, m i n i m u m number of twists in 8 in. (203 ram) . . . . . . . . . . . . . . . . . . . . .

*For welI-measuring wire of other materiaIs or coatings, refer to suppIier for physical properties,

Table 4-29 Requirements for Well-Servicing Strand Bright or Drawn-Galvanized Carbon Steel [12] 1 N o m i n a l Diameter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Inches MM

Tolerances on Diameter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Inches MM

N o m i n a l Breaking Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lbs. KN

Approximate Mass . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lbs./100' kg/100'

2

3

3'16"

I4"

4.8

6.4

-0" +.013" -.048 +.288

-47' +.015" -.064 +.320

4700 20.9

8200 36.5

7.3 3.3

12.7 5.8

Packing and Marking Finished wire rope, unless otherwise specified, shall be shipped on substantial round-head reels. Reels on which sand lines, drilling lines, or casing lines are shipped shall have round arbor holes of 5 in. (127 mm) to 5 Z-in. (146-mm) diameter. W h e n reel is full of rope, there shall be a clearance of not less than 2 in. (51 .mm) between the full reel and the outside diameter of the flange. The manufacturer shall protect the wire rope on reels from damage by moisture, dust, or dirt with a water-resistant covering o f builtup material, such as tar paper and burlap, or similar material. The following data shall be plainly marked on the face of the wire-rope reel: 1. N a m e of manufacturer. 2. Reel number. 3. API m o n o g r a m only by authorized manufacturers.

582 4. 5. 6. 7. 8.

Drilling a n d Well C o m p l e t i o n s G r a d e (plow steel, i m p r o v e d plow steel, or extra i m p r o v e d plow steel). Diameter o f rope, in. (mm). Length o f rope, ft (m). Type o f construction (Warrington, Seale, or Filler Wire). Type o f core (fiber, wire, plastic, or fiber a n d plastic).

Inspection and Rejection T h e m a n u f a c t u r e r will, on request o f the purchaser, c o n d u c t tests as called for in specifications on reasonable notice from the purchaser. During the tests, the manufacturer will afford o p p o r t u n i t y to the p u r c h a s e r ' s representative to present. T h e manufacturer, when delivering wire r o p e with the API m o n o g r a m a n d g r a d e designation, should warrant that such material complies with the specification. The wire r o p e rejected u n d e r specifications should not be wound on reels bearing the API m o n o g r a m , or sold as API wire rope. W h e n the wire r o p e wound on reels b e a r i n g the API m o n o g r a m is rejected, the m o n o g r a m shall be removed. It is r e c o m m e n d e d that whenever possible, the purchaser, u p o n receipt, shall test all new wire r o p e p u r c h a s e d in accordance with specifications. If a r o p e fails to r e n d e r satisfactory service, it is impractical to retest such used rope. It is therefore required that the purchaser shall preserve at least one test specimen o f all new r o p e purchased, length o f specimen to be at least 10 ft (3.05 m), properly identified by reel number, etc. Care must be taken that no damage will result by storage o f specimen. If the purchaser is not satisfied with the wire r o p e service, he or she shall send the properly preserved sample o r a sample o f the r o p e from an u n u s e d section to any testing l a b o r a t o r y mutually a g r e e d u p o n by the purchaser a n d the manufacturer, with instructions to make a complete API test, a n d notify the manufacturer to have a representative present. If the r e p o r t indicates compliance with specifications, the purchaser shall assume cost o f testing; otherwise, the m a n u f a c t u r e r shall assume the expense a n d make satisfactory adjustments not exceeding full purchase price o f the rope. If the r e p o r t indicates noncompliance with specifications, the testing l a b o r a t o r y shall forward a copy o f the test r e p o r t to the manufacturer.

Wlre-Rope Sizes and Constructions Typical sizes a n d constructions o f wire r o p e for oilfield service are shown in Table 4-30. Because o f the variety o f e q u i p m e n t designs, the selection o f o t h e r constructions than those shown is justifiable. In oilfield service, wire r o p e is often r e f e r r e d to as wire line or cable. For clarity, these various expressions are i n c o r p o r a t e d in this r e c o m m e n d e d practice.

Field Care and Use of Wire Rope Handling on Reel. W h e n handling wire r o p e on a reel with a b i n d i n g or lifting chain, w o o d e n blocks should always be used between the r o p e a n d the chain to prevent damage to the wire or distortion o f the strands in the rope. Bars for moving the reel should be used against the reel flange, a n d not against the rope. T h e reel should not be rolled over or d r o p p e d on any hard, s h a r p object to protect the rope, a n d should not be d r o p p e d from a truck or platform to avoid d a m a g e to the r o p e a n d the reel.

Hoisting System

583

Table 4-30 Typical Sizes and Constructions Of Wire Rope for Oilfield Service [12] I

2 ~ Wire R o p e

Service and Well Depth

in.

3

4

Diameter

Wire R o p e Description (Regular Lay)

(mm)

Rod a n d T u b i n g Pull Lines Shallow Intermediate Deep

~ to 3.4 incl. ~4, 7/8 7/8 to 1]~ incl.

(13 to 19) (19, 22) (22 to 29)

6x25FWor6x26WS or6x31WS or18x7'or19x7'. PF, L L ' , I P S or EIPS, IWRC

Rod H a n g e r Lines

1,4

(65)

6xl9, PF, RL, IPS, FC

Sand Lines Shallow Intermediate Deep

1,4 to ~2 incl. V2, 9/16 9/i6 , 5/8

(6.5 to 13) ] (13, 14.5) I (14.5, 16)

6x7 Bright or Galv. 2, PF, RL, PS or IPS, FC

(16, 19) } (19, 22) (22, 26)

6x21 FW, PF or NPF, RL or LL, PS or IPS, FC

(19, 22) } (22, 26) (26, 29)

6x25 FW or 6x26 WS, PF, RL, IPS or EIPS, FC or IWRC

(22, 26) (26, 29)

6x26 WS, PF, RL, IPS or EIPS, IWRC 6x19 S or 6x26 WS, PF, RL, IPS or EIPS, IWRC

Drilling L i n e s ~ a b l e Shallow Intermediate Deep

Tool (Drilling a n d Cleanout) 5/8, 3/4 3.4, 7/8 7/8, 1

Casing Lines--Cable T o o l Shallow Intermediate Deep Drilling L i n e s ~ o r i n g Shallow Intermediate

3/4, 7/8 7/8, 1 1,1, a

a n d Slim-Hole Rotary Rigs 7/8, 1 1, 11/8

Drillings Lines--Rotary Rigs Shallow Intermediate Deep

1, 11,8 11/8, 11/4 11,4 to 15/4 incl.

(26,29) } (29, 32) (32, 45)

6x19 S or 6x21 S or 6x25 FW or FS, PF, RL, IPS or EIPS, IWRC

5/8 to 7/8 incl. ~ to 1V8 incl.

(16 to 22) (22 to 29)

6x26 WS or 6x31 WS, PF, RL, IPS or EIPS, IWRC 6x36 WS, PF, RL, IPS or EIPS, IWRC

b~ to 1I/8 incI. s 5/8 to 11,8 incl. 4

(13 to 29) (16 to 29)

6x19 Class or 6x37 Class or 19x7, PF, IPS, FC or IWRC 6x19 Class or 6x37 Class, PF, IPS, FC or IWRC

Offshore Anchorage Lines

7/8 to 2 ~ incl. 1 ~ to 45,4 incl. 35,4 to 4 ~ incl.

(22 to 70) (35 to 122) (96 to 122)

6x19 Class, Bright or Galv, PF, RL, IPS or EIPS, IWRC 6x37 Class, Bright or Galv., PF, RL, IPS or EIPS, IWRC 6x61 Class, Bright or Galv., PF, RL, IPS o1" EIPS, IWRC

Mast Raising Lines s

13/8 a n d smaller 11/2 a n d larger

(thru 35) (38 and up)

6x19 Class, PF, RL, IPS or EIPS, IWRC 6x37 Class, PF, RL, IPS or EIPS, IWRC

Guideline T e n s i o n e r Line

~

(19)

Winch Lines--Heavy Duty H o r s e h e a d P u m p i n g - U n i t Lines Shallow Intermediate

6x25 FW, PF, RL, IPS or EIPS, IWRC Wire Rope Description (Lang Lay)

Riser T e n s i o n e r Line

1I/2, 2

Abbreviations: WS - - Warrington-Seale S - - Seale FS - - Flattened strand FW - - Filler-Wire PS - - Plow steel

IPS EIPS PF NPF

(38,51)

-----

Improved plow steel Extra improved plow steel Prefon~aed Non-preformed

6x37 Class or PF, RL, IPS or EIPS, IWRC

RL LL FC IWRC

-----

Right lay Left lay Fiber core I n d e p e n d e n t wire rope core

1Single Iine pulIing of rods and tubing requires left lay construction or I8 x 7 or 19 x 7 construction. Either left lay or right lay may be used for multiple line pulling. 32Brigh.A er,." . sand. lines. are regularly . furnished', galvanized fin'shlll"ssometimes required. . . Apphes to pumping umr~ having one piece of wlre rope looped over an ear on the horsehead and both ends fastened to a pobshed-rod equabzer yoke. 4Applies to pumping units having two vertical lines (parallel) ".,Ath sockets at both ends of each line. 5See API Spec 4]~: Specificationfor Drillingand WellSerwringStructures,

Rolling the reel in or allowing it to stand in any harmful m e d i u m such as mud, dirt, or cinders should be avoided. Planking or cribbing will be o f assistance in handling the reel as well as in protecting the rope against damage.

Handling during Installation. Blocks should be strung to give a m i n i m u m of wear against the sides o f sheave grooves. It is also good practice in changing

584

Drilling and Well Completions

lines to suspend the traveling block from the crown on a single line. This tends to limit the amount of r u b b i n g on guards or spacers, as well as chances for kinks. This is also very effective in pull-through and cutoff procedure. The reel should be set up on a substantial horizontal axis, so that it is free to rotate as the rope is pulled off, and the rope will not rub against derrick m e m b e r s or other obstructions while b e i n g pulled over the crown. A snatch block with a suitable size sheave should be used to hold the rope away from such obstructions. A suitable apparatus for jacking the reel off the floor and holding it so that it can t u r n on its axis is desirable. Tension should be m a i n t a i n e d on the wire rope as it leaves the reel by restricting the reel movement. A timber or plank provides satisfactory brake action. W h e n winding the wire rope onto the drum, sufficient tension should be kept on the rope to assure tight winding. To replace a worn rope with a new one, a swivel-type s t r i n g i n g grip for attaching the new rope to the old rope is r e c o m m e n d e d . This will prevent transferring the twist from one piece of rope to the other. Ensure that the grip is properly applied. The new rope should not be welded to the old rope to pull it through the system. Care should be taken to avoid kinking a wire rope since a kink can be cause for removal of the wire rope or damaged section. Wire ropes should not be struck with any object, such as a steel hammer, derrick hatchet, or crowbar, that may cause unnecessary nicks or bruises. Even a soft metal h a m m e r can damage a rope. Therefore, when it is necessary to crowd wraps together, any such o p e r a t i o n should be p e r f o r m e d with the greatest care; and a block of wood should be interposed between the h a m m e r and rope. Solvent may be detrimental to a wire rope. If a rope becomes covered with dirt or grit, it should be cleaned with a brush. After properly securing the wire rope in the d r u m socket, the n u m b e r of excess or dead wraps or turns specified by the e q u i p m e n t manufacturer should be m a i n t a i n e d . W h e n e v e r possible, a new wire rope s h o u l d be r u n u n d e r controlled loads and speeds for a short period after installation. This will help to adjust the rope to working conditions. If a new coring or swabbing line is excessively wavy when first installed, two to four sinker bars may be added on the first few trips to straighten the line.

Care of Wire Rope in Service. The recommendations for handling a reel should be observed at all times d u r i n g the life of the rope. The design factor should be d e t e r m i n e d by the following: Design factor

B

W

(4-24)

where B = n o m i n a l strength of the wire rope in pounds W = fast line tension W h e n a wire rope is operated close to the m i n i m u m design factor, the rope and related e q u i p m e n t should be in good operating condition. At all times, the operating personnel should minimize shock, impact, and acceleration or deceleration of loads. Successful field operations indicate that the following design factors should be regarded as m i n i m u m :

Hoisting System

585

Minimum Design Factor Cable-tool line Sand line Rotary drilling line Hoisting service other than rotary drilling Mast raising and lowering line Rotary drilling line when setting casing Pulling on stuck pipe and similar infrequent operations

3 3 3 3 2.5 2 2

Wire-rope life varies with the design factor; therefore, longer r o p e life can generally be expected when relatively high design factors are maintained. To calculate the design factor for multipart string-ups, Figures 4-68 a n d 4-69 can be used to d e t e r m i n e the value o f W. W is the fast line tension a n d equals t h e fast line factor* times the h o o k l o a d weight i n d i c a t o r r e a d i n g . As an example, see below: drilling line n u m b e r of lines h o o k load

1 ~ in. (35 mm) EIPS 10 400,000 lb (181.4 tons)

Sheaves are roller b e a r i n g type. F r o m Figure 4-68, Case A, the fast line factor is 0.123. T h e fast line tension is then 400,00 lb (181.4 t) × 0.123 = 49,200 lb (22.3 t) = W. Following the formula above, the design factor is then the n o m i n a l strength of 1 ~ in. (35 mm) EIPS drilling line divided by the fast line tension, o r 192,000 lb (87.1 tons) ÷ 49,200 lb (22.3 t) = 3.9. W h e n working n e a r the m i n i m u m design factor, c o n s i d e r a t i o n should be given to the efficiencies of wire r o p e bent a r o u n d sheaves, fittings, o r drums. Figure 4-70 shows how r o p e can be affected by bending. Rope should be kept tightly a n d evenly wound on the drums. Sudden, severe stresses are injurious to a wire rope, and should be r e d u c e d to a m i n i m u m . Experience has i n d i c a t e d that wear increases with speed; e c o n o m y results from moderately increasing the load and diminishing the speed. Excessive speeds may injure wire rope. Care should be taken to see that the clamps used to fasten the r o p e for d e a d e n d i n g do not kink, flatten, o r crush the rope. Wire ropes are well lubricated when manufactured; however, this lubrication will not last throughout the entire service life of the rope. Periodically, therefore, the r o p e will n e e d to be field lubricated. W h e n necessary, lubricate the r o p e with a g o o d g r a d e o f lubricant that will p e n e t r a t e and a d h e r e to the rope, and that is free from acid o r alkali. T h e clamps used to fasten lines for d e a d e n d i n g shall not kink, flatten, o r crush the rope. T h e rotary line dead-end tie down is equal in i m p o r t a n c e to any o t h e r part of the system. T h e dead-line a n c h o r a g e system shall be e q u i p p e d with a d r u m and c l a m p i n g device strong enough to withstand the loading, and d e s i g n e d to prevent wire line damage that would affect service over the sheaves in the system.

*The fast line factor is calculated considering the tensions needed to overcome sheave bearing friction.

586

Drilling and Well Completions

CASE

One(I)

r-~

"A"

CASE

~

Iddeeor ~ - ~

Two

~

(3)

ISdler ~

[

S=No. of Sheoves;

C A S E "C"

('~

~

~'~1 1

Drum L=LOod;

"B"

I'

L

Three(3) ~"~ /'~ I l/,er k~--,'] [ " I ] ]

'}

Drum

I"

L

' I

N : No. of Rope Ports Supporting Lood

F A S T L I N E T E N S I O N = FAST L I N E F A C T O R X LOAD 1

2

3

4

5

6

7

8

9

Plain B e a r i n g Sheaves 1~

=

10

11

12

13

Roller B e a r i n g Sheaves

K = Lq4*

1.09" ^

Efficiency

Fast Line Faetor

Efficiency"

Fast Line Factor

Case A

Case B

Case C

Case A

Case B

Case C

Case A

Case B

Case C

Case A

Case B

Case C

2 3

.880 .844

,807 .774

.740 .710

.368 .395

.620 .431

.675 .469

.943 .925

.907 .889

.872 .855

.530 .360

.551 .375

,574 .390

4 5 6

.810 .778 .748

.743 .714 .686

.682 .655 .629

.309 .257 .223

.336 .280 .243

.367 .305 .265

.908 .890 .874

.873 .856 .840

.839 .823 .808

.275 .225 .191

.286 .234 .198

.298 .243 .206

7 8

.719 .692

.660 .635

.605 .582

.199 .181

.216 .197

.236 .215

.857 .842

.824 .809

.793 .778

.167 .1~18

.173 .154

.180 .161

9

.666

.611

.561

.167

.182

.198

.826

.794

.764

.135

.140

.145

l0 11

.642 .619

.589 .568

.540 .521

.156 .147

.170 .160

.185 .175

.Sll .796

.780 .766

.750 .736

.123 .114

.128 .119

.133 .124

12 13

.597 .576

.547 .528

.502 .485

.140 .133

.152 .145

.166 .159

.782 .768

.752 .739

.723 .710

.106 .100

.Ili .104

.I15 .I08

14 15

.556 .537

.510 .493

.468 .452

.128 .124

.140 .135

.153 .147

.755 .741

.725 .713

.698 .685

.095 .090

.099 .094

.I02 .097

EFFICIENCY =

{K N -I) K S N (K-I)

Fast Line Factor -

I N x EFFICIENCY

NOTE: The above cases apply also where the rope is dead ended at the lower or traveling block or derrick floor after passinlz over a dead shea~,e in the crown. *In these tables the K factor for sheave friction is 1.09 for plain bearings and 1.04 for roller bearings. Other K factors can be used if recommended by the equipment manufacturer.

Figure 4-68. Efficiency of wire-rope reeving for multiple sheave blocks, Cases A, B, and C [11].

The following precautions should be observed to prevent premature wire breakage in drilling lines. 1. Cable-tool drilling lines. Movement of wire rope against metallic parts can accelerate wear. This can also create sufficient heat to form martensite, causing embrittlement of wire and early wire rope removal. Such also can be formed by friction against the casing or hard rock formation.

Hoisting System

CASE "D"

CA S E "E"

or fil I

587

u

fi fi fi

I

I

Single Drum

u

I

Double Drum with Equalizer

L = Load~ S = No. of Sheaves ~ N : No. of Rope Parts Supporting Load (Not counting equalizer)

FAST 1

2

LINE

TENSION

3

= FAST

4

LINE

FACTOR

5

X LOAD

6

7

Plain Bearing Sheaves

8

K = 1.09"" Efficiency Case D

Case D

Case E

.500

981

1.000

.510

962

. . . . .

346

1.000

.522

3

.920

. . . . .

362

4

.883

5

.848

6

.815

7

.784

8

.754

9

.726

10

.700

11

.674

12

.650

13

.628

14

.606

15

.586

.

.

.

.920

182

.883

.166

. . . . .

153

.848

.143

. . . . .

135

.815

.128

. . . . .

122

.784

.118

. . . . .

F A S T LINE FACTOR =

236

.204

. . . . .

CASE "D" E F F I C I E N C Y =

. . . . .

.283 .

Fast Line Factor

Case E

.959

.959

Efficiency

Case D

2

.

K = t.04"

Fast Line Factor

Case E

114

(K N -I) KSN (K-It I N x EFFICIENCY

9

Roller Bearing Sheaves

.261 .

.

.944 .

.

.181

.

926

.981 .

.909

. . . . . .141

892

.118

859

.102

828

.091

799 .785

. . . . .

771

CASE "E"

.

.

.

.

216

.183 .

.

.944

160 .143

.926 .

.813

. . . . .

.265 .

. . . . .

.844

. . . . .

.

.962 .

.875

. . . . .

Case D

.

.

.119 .

.

.

.

.909 .

.

.

130 110 .101

.892

096 .091

. . . . .

EFFICIENCY =

F A S T LiNE FACTOR

086

Case E .500 .... .255 ....

.173 .... .132 .... .108 .... .091 .... .080 ....

2 ( K TN K s N (K-l) I N x EFFICIENCY

NOTE: The above eases apply also where the rope is dead ended or the equalizer is located at the lower or traveling" block or derrick floor after passin~ over a dead sheave in the crown. "In these tabIes, the K factor for sheave friction is 1.09 for plain bearings and 1.04 for roller bearings. Other K factors can be used if recommended b.v the equipment manufacturer.

Figure 4-69. Efficiency of wire-rope reeving for multiple sheave blocks, Cases D and E [11].

2. Rotary drilling lines. Care should be taken to maintain proper winding of rotary drilling lines on the drawworks drum to avoid excessive friction that may result in the formation of martensite. Martensite may also be formed by excessive friction in worn grooves of sheaves, Slippage in sheaves, or excessive friction resulting from rubbing against a derrick member. A line guide

588

Drilling and Well C o m p l e t i o n s

50 5 5 I-! .............. : .......... : .......... :.......... ~......... ; ........ : 60 65 70 75

.....

i ..........

': .........

~ .........

! .........

! ........

: ........

: ........

x i............................. i ......... i ........ i ........ i ........ j

80 85

95

'° I

i

i

35

40

I00

0

5

I0

15

SHEAVE-ROPE

20

25

30

DIAMETER

RATIO

45

50 D/d

Figure 4-70. Efficiencies of wire ropes bent around stationary sheaves (static [11]. stresses only)

should be employed b e t w e e n the d r u m and the fast line sheave to reduce vibration and to keep the drilling line from r u b b i n g against the derrick. Martensite is a hard, nonductile microconstituent f o r m e d when steel is heated above its critical t e m p e r a t u r e and cooled rapidly. In the case o f steel o f the c o m p o s i t i o n conventionally used for rope wire, martensite can be f o r m e d if the wire surface is heated to a t e m p e r a t u r e near or somewhat in excess o f 1400°F (760°C), and t h e n c o o l e d at a c o m p a r a t i v e l y r a p i d rate. T h e p r e s e n c e o f a martensite film at the surface o f the outer wires o f a rope that has b e e n in service is e v i d e n c e that sufficient frictional heat has b e e n g e n e r a t e d on the crown o f the rope wires to m o m e n t a r i l y raise the wire surface t e m p e r a t u r e to a point above the critical t e m p e r a t u r e range o f the steel. T h e heated surface is then rapidly c o o l e d by the adjacent cold metal within the wire and the rope structure, and an effective q u e n c h i n g results.

Hoisting System

589

Figure 4-71A shows a r o p e that has d e v e l o p e d fatigue fractures at the crown in the outer wires, and Figure 4-71B shows a p h o t o m i c r o g r a p h (100x magnification) of a specimen cut f r o m the crown of one of these outer wires. This p h o t o m i c r o g r a p h clearly shows the d e p t h of the martensite layer and the cracks p r o d u c e d by the inability of the martensite to withstand the n o r m a l flexing of the rope. T h e result is a d i s a p p o i n t i n g service life for the rope. Most outer wire failures may be a t t r i b u t e d to the presence of martensite. W o r n sheave and d r u m grooves cause excessive wear on the rope. All sheaves should be in p r o p e r alignment. T h e fast sheave should line up with the center of the hoisting d r u m . F r o m the s t a n d p o i n t of wire-rope life, the c o n d i t i o n and contour of sheave grooves are i m p o r t a n t and should be checked periodically. T h e sheave groove s h o u l d have a r a d i u s n o t less t h a n that in T a b l e 4-31; o t h e r w i s e , r o p e life can be r e d u c e d . R e c o n d i t i o n e d sheave grooves s h o u l d c o n f o r m to the r e c o m m e n d e d radii for new and r e c o n d i t i o n e d sheaves as given in Table 4-32. Each o p e r a t o r should establish the most economical point at which sheaves should be regrooved by considering the loss in r o p e life that will result

BETA~ L A

Figure 4-71. Fatigue fractures in outer wires caused by the formation of martensite [11].

590

Drilling a n d Well Completions

Table 4-31 Minimum Groove Radii for Worn Sheaves [11] 1 Wire Rope Nominal Size (mm) in.

¼ A % a~ sh

(6.5) (8) (9.5) (ll) (13) (14.5) (16) (19)

1

(22) (26)

1~ 1¼ 1"~ 11/2

(29) (~2) (35) (38)

2

1

Radii

Wire Rope Nominal Size in. (mm)

in.

(mm)

.129 .160

(3.g8) (4.06)

1~ 1~ 1~ 2 2~ 2¼

.190 .220

(4.83) (5.59) .256 (6.50) .288 (7.32) .320 (8.lS) .380 (9.65) .440 (ll.18) .513 (lS.O3) .577 (14.66) .639 (16.28) .699 (17.75) .759 (19.28)

1

Radii

Wire Rope Nominal Size in. (mm)

(mm)

in.

(4e) (45) (48) (52) (54) (58) (60) (64) (67) (7l) (74) (77) (80) (83)

2~ 2~ 2a/4 27~ 3 3~ 3¼

2

33& 3½ 3~ 4 4¼ 41/2 4~ 5 5¼ 5~ 53/4 6

.833

(21.16) .897 (22.78) .959 (24.36) 1.025 (26.04) 1.079 (27.4l) 1.153 (29.29) 1.199 (s0.45) 1.279 (32.49) 1.339 (34.0l) 1.409 (35.79) 1.473 (.77.4l) 1.538 (39.07) 1.598 (40.59) 1.658 (42.ll)

2 Radii

mm)

in.

(86) (90) (96) (103) (109) (ll5) (122) (128) (135) (14l) (148) (154)

1.730 1.794 1.918 2.050 2.178 2.298 2.434 2.557 2.691 2.817 2.947 3.075

(43.94) (45.57) (48.72) (52.07) (55.3~2) (58.37) (61.82) (64.95) (68.35) (71.55) (74.85) (78.ll)

Sheaves worn to these sizes can be detrimental to wire rope servlee and should be regrooved or removed from service.

Table 4-32 Minimum Groove Radii for New and Reconditioned Sheaves [11] 1

Wire Rope Nominal Size in. (ram)

¼ aN % .i~ % :~ 1 1~ 1¼ 1% 1½

2

1

Radii

Wire Rope Nominal Size in. (ram)

in.

(ram)

.135 .167 .201

($.45) (4.~4)

1% VA

(42) (45)

(5.ll) (5.94) (6.88) (7.70) (8.48) (10.19) (l 1.89) (13.79) (15.37) (16.99) (18.69) (20.40)

1~ 2

(48) (55)

(6.5) (8) (9.5) (ll) (13) (14.5) (16)

.334

(19) (22)

.401 .468

(~26) (e9) (82) (35) ($$)

.543 .605 .669

.234 .271 .303

.736

.803

2Ys

('%)

2~ 2~ 2~ 2~ 2~ 2"t,~ 3 3~ 3¼

(58) (60) (64) (67) (71) (74) (77) (80) (83)

2

1

Radii in. .876 .939 1.003

1.085 1.137 1.210 1.271

1.338 1.404 1.481 1.544 1.607

1.664 1.731

(ram) (22.25) (23.85) (25.48) (27.56) (28.88) (80.78) (8~.28) (33.99) (35.66) (37.62) (39.22) (40.82) (42.27) (43.97)

Wire Rope Nominal Size in. (ram)

3~ 3~ 3~ 4 4¼ 4½ 4~ 5 5¼ 5½ 5~ 6

(86) (90) (96) (103) (109) (l 15) (122) (128) (135) (14l) (148) (154)

2

Radii in. 1.807 1.869 1.997 2.139 2.264 2.396 2.534 2.663 2.804 2.929 3.074 3.198

(ram) (45.90) (47.47) (50.72) (54.33) (57.5l) (60.86) (64.36) (67.64) (71.22) (74.40) (78.08) (81.23)

Standard Machine Tolerance

from worn sheaves as compared to the cost involved in regrooving. W h e n a new rope is to be installed on used sheaves, it is particularly important that the sheave grooves be checked as r e c o m m e n d e d . To ensure a m i n i m u m t u r n i n g effort, all sheaves should be kept properly lubricated.

Seizing. Before cutting, a wire rope should be securely seized on each side of the cut by serving with soft wire ties. For socketing, at least two additional seizings should be placed at a distance from the e n d equal to the basket length of the socket. The total l e n g t h of the seizing should be at least two rope diameters, and securely wrapped with a seizing iron. This is very important, as it prevents the rope untwisting a n d ensures equal tension in the strands when the load is applied. The r e c o m m e n d e d procedure for seizing a wire rope is as follows:

Hoisting System

591

a. T h e seizing wire should be wound on the rope by hand as shown in Figure 4-73 (1). The coils should be kept together and considerable tension maintained on the wire. b. After the seizing wire has been wound on the rope, the ends of the wire should be twisted together by hand in a counterclockwise direction so that the twisted portion o f the wires is near the middle of the seizing (see Figure 4-73 (2)). c. Using "Carew" cutters, the twist should be tightened just enough to take up the slack (Figure 4-73 (3)). Tightening the seizing by twisting should not be attempted. d. The seizing should be tightened by prying the twist away from the axis of the rope with the cutters as shown in Figure 4-73 (4). e. The tightening of the seizing should be repeated as often as necessary to make the seizing tight.

Figure 4-72, Correct method of attaching clips to wire rope [11].

Figure 4-73. Putting a seizing on a wire rope [11].

592

Drilling and Well C o m p l e t i o n s

f. To c o m p l e t e the seizing o p e r a t i o n , the ends of the wire should be cut off as shown in Figure 4-73 (5), and the twisted p o r t i o n of the wire t a p p e d flat against the rope. T h e a p p e a r a n c e of the finished seizing is illustrated in Figure 4-73 (6).

Socketing (Zinc Poured or Speiter).

Wire Rope Preparation. T h e wire r o p e should be securely seized or c l a m p e d at the e n d before cutting. Measure from the e n d of the r o p e a length equal to approximately 90% of the length of the socket basket. Seize or clamp at this point. Use as many seizings as necessary to prevent the r o p e from unlaying. After the r o p e is cut, the end seizing should be removed. Partial straightening of the strands a n d / o r wire may be necessary. T h e wires should then be separated and b r o o m e d out and the cores treated as follows: 1. Fiber core-Cut back length of socket basket. 2. Steel core-Separate and b r o o m out. 3. Other-Follow m a n u f a c t u r e r ' s r e c o m m e n d a t i o n s .

Cleaning. T h e wires should be carefully cleaned for the distance inserted in the socket by one of the following methods: Acid cleaning 1. Improved plow steel and extra improved plow steel, bright and galvanized. Use a suitable solvent to remove lubricant. T h e wires then should be d i p p e d in commercial muriatic acid until thoroughly cleaned. T h e depth of immersion in acid must not be m o r e than the b r o o m e d length. T h e acid should be n e u t r a l i z e d by rinsing in a b i c a r b o n a t e of soda solution. Fresh acid should be p r e p a r e d when satisfactory cleaning of the wires requires m o r e than one minute. (Prepare new s o l u t i o n - d o not merely add new acid to old.) Be sure acid surface is free of oil or scum. The wires should be dried and then dipped in a hot solution of zinc-ammonium chloride flux. Use a c o n c e n t r a t i o n of 1 lb (454 g) of z i n c - a m m o n i u m c h l o r i d e in 1 gal (3.8 L) of water and maintain the solution at a t e m p e r a t u r e of 180°F (82°C) to 200°F (93°C). 2. Stainless steel. Use a suitable solvent to remove lubricant. T h e wires then should be d i p p e d in a hot caustic solution, such as oakite, then in a hot water rinse, and finally d i p p e d in one of the following solutions until thoroughly cleaned: a. commercial muriatic acid b. 1 p a r t by weight of cupric chloride, 20 parts by weight of c o n c e n t r a t e d hydrochloric acid c. 1 part by weight of ferric chloride, 10 parts by weight of c o n c e n t r a t e d nitric or hydrochloric acid, 20 parts by weight of water. Use the above solutions at r o o m t e m p e r a t u r e . T h e wires should t h e n be d i p p e d in clean hot water. A suitable f l u x may be used. Fresh solution should be p r e p a r e d when satisfactory cleaning of the wires requires m o r e than a r e a s o n a b l e time. ( P r e p a r e new s o l u t i o n s - d o not merely add new solution to old solution.) Be sure solution surface is free of oil and scum. 3. Phosphor bronze. Use a suitable solvent to remove lubricant. T h e wires should t h e n be d i p p e d in commercial muriatic acid until thoroughly cleaned. 4. Monel metal. Use a suitable solvent to remove lubricant. T h e wires then should be d i p p e d in the following solution until thoroughly cleaned: 1 part glacial acetic acid + 1 part c o n c e n t r a t e d nitric acid.

Hoisting System

593

This solution is used at room temperature. The broom should be immersed from 30 to 90 s. The d e p t h o f immersion in the solution must not be m o r e than b r o o m e d length. The wires should then be d i p p e d in clean hot water.

Ultrasonic cleaning (all grades). A n ultrasonic cleaner suitable for cleaning wire r o p e is p e r m i t t e d in lieu o f the acid cleaning m e t h o d s d e s c r i b e d previously. Other cleaning methods. O t h e r c l e a n i n g m e t h o d s o f p r o v e n reliability are permitted.

Attaching SockeL Preheat the socket to approximately 200°F (93°C). Slip socket over ends o f wire. Distribute all wires evenly in the basket and flush with top o f basket. Be sure socket is in line with axis o f rope. Use only zinc not lower in quality than high grade per ASTM Specification B-6. Heat zinc to a range allowing pouring at 950°F (510°C) to 975°F (524°C). Skim off any dross accumulated on the surface o f the zinc bath. Pour molten zinc into the socket basket in one continuous pour if possible. Tap socket basket while pouring.

Final Preparation. Remove all seizings. A p p l y lubricant to r o p e adjacent to socket to replace lubricant removed by socketing procedure. Socket is then ready for service. Splicing. Splicing wire r o p e requires considerable skill, and the instructions for splicing wire r o p e will be found in the catalogues o f most o f the wire-rope manufacturers, where the o p e r a t i o n sequence is carefully described, and many clear illustrations are presented. These illustrations give, in fact, most o f the information needed.

Socketing (Thermo-Set Resin). Before p r o c e e d i n g with t h e r m o - s e t resin socketing, the m a n u f a c t u r e r ' s i n s t r u c t i o n s for using this p r o d u c t should be carefully read. Particular attention should be given to sockets designed specifically for resin socketing. O t h e r thermo-set resins used may have specifications that differ from those shown in this section. Seizing and Cutting the Rope. The r o p e m a n u f a c t u r e r ' s d i r e c t i o n s for a particular size or construction o f r o p e are to be followed with r e g a r d to the number, position, and length o f seizings, and the seizing wire size to be used. The seizing, which will be located at the base o f the installed fitting, must be p o s i t i o n e d so that the ends o f the wires to be e m b e d d e d will be slightly below t h e level o f t h e t o p o f t h e f i t t i n g ' s basket. C u t t i n g t h e r o p e can best be accomplished by using an abrasive wheel. Opening and Brooming the Rope End. Prior to o p e n i n g the r o p e end, place a short t e m p o r a r y seizing directly above the seizing that represents the base o f the broom. The t e m p o r a r y seizing is used to prevent b r o o m i n g the wires to full length o f the basket, and also to prevent the loss o f lay in the strands a n d r o p e outside the socket. Remove all seizings between the e n d o f the r o p e and the t e m p o r a r y seizing. Unlay the strands c o m p r i s i n g the rope. Starting with the IWRC, or strand core, o p e n each strand and each strand o f the rope, and b r o o m or unlay the individual wires. (A fiber core may be cut in the r o p e at the base o f the seizing. Some prefer to leave the core in. Consult the m a n u f a c t u r e r ' s instructions.) W h e n the b r o o m i n g is completed, the wires should be distributed evenly within a cone so that they form an included angle o f approximately 60 ~.

594

Drilling a n d Well Completions

Some types of sockets require a different b r o o m i n g procedure a n d the manufacturer's instructions should be followed.

Cleaning the Wires and Fittings. Different types of resin with d i f f e r e n t characteristics require varying degrees of cleanliness. The following cleaning procedure was used for one type of polyester resin with which over 800 tensile tests were made on ropes in sizes ¼ in. (6.5 mm) to 3-~-in. (90 mm) diameter without experiencing any failure in the resin socket attachment. T h o r o u g h cleaning of the wires is required to obtain resin adhesion. Ultrasonic cleaning in r e c o m m e n d e d solvents (such as trichloroethylene or 1,1,1trichloroethane or other n o n f l a m m a b l e grease-cutting solvents) is the preferred m e t h o d in a c c o r d a n c e with O S H A standards. If u l t r a s o n i c c l e a n i n g is not available, trichloroethane may be used in brush or dip-cleaning; but fresh solvent should be used for each rope e n d fitting a n d should be discarded after use. After cleaning, the b r o o m should be dried with clean compressed air or in a n o t h e r suitable fashion before proceeding to the next step. Using acid to etch the wires before resin socketing is unnecessary and not recommended. Also, the use of a flux on the wires before p o u r i n g the resin should be avoided since this adversely affects bonding of the resin to the steel wires. Since there is a variation in the properties of different resins, the manufacturer's instructions should be carefully followed. Placement of the Fitting. The rope should be placed vertically with the broom up, a n d the b r o o m should be closed a n d compacted to insert the b r o o m e d rope e n d into the fitting base. Slip on the fitting, removing any temporary b a n d i n g or seizing as required. Make sure the b r o o m e d wires are uniformly spaced in the basket with the wire ends slightly below the top edge of the basket, a n d make sure the axis of the rope a n d the fitting are aligned. Seal the a n n u l a r space between the base of the fitting a n d the exiting rope to prevent leakage of the resin from the basket. A n o n h a r d e n i n g butyl r u b b e r base sealant gives satisfactory performance. Make sure the sealant does not enter the socket base, so that the resin may fill the complete depth of the socket basket. Pouring the Resin. Controlled heat-curing (no o p e n flame) at a temperature r a n g e of 250 to 300°F (121 to 149°C) is r e c o m m e n d e d ; a n d is required if ambient temperatures are less t h a n 60°F (16°C) (which may vary with different resins). W h e n controlled heat curing is not available a n d a m b i e n t temperatures are not less t h a n 60°F (16°C), the a t t a c h m e n t should not be disturbed a n d tension should not be applied to the socketed assembly for at least 24 hr. Lubrication of Wire Rope after Socket Attachment. After the resin has cured, relubricate the wire rope at the base of the socket to replace the lubricant that was removed d u r i n g the cleaning operation. Resin Socketing Compositions. Manufacturer's directions should be followed in handling, mixing, a n d p o u r i n g the resin composition. Performance of Cured Resin Sockets. Poured resin sockets may be moved when the resin has h a r d e n e d . After a m b i e n t or elevated t e m p e r a t u r e cure r e c o m m e n d e d by the manufacturer, resin sockets should develop the n o m i n a l strength of the rope; a n d should also withstand, without cracking or breakage, shock loading sufficient to break the rope. Manufacturers of resin socketing material should be required to test to these criteria before resin materials are approved for this e n d use.

Hoisting System

595

Attachment of Clips The clip method of making wire-rope attachments is widely used. Drop-forged clips of either the U-bolt or the double-saddle type are recommended. When properly applied as described herein, the method develops about 80% of the rope strength in the case of six strand ropes. When attaching clips, the rope length to be turned back when making a loop is dependent upon the rope size and the load to be handled. The recommended lengths, as measured from the thimble base, are given in Table 4-33. The thimble should first be wired to the rope at the desired point and the rope then bent around the thimble and temporarily secured by wiring the two rope members together.

Table 4-33 Attachment of Clips [11] 1

2

Diameter of Rope, in. (ram)

Number of Clips

h ¼ :~/~ ½ % ¾ 1 1~ 1¼ 1~ 1~ 1~ 1~ 2 2¼ 2~ 2~ 3

(:3) (5) (6.5) (8) (9.5) (I I) (I;!) (14.5) (16) (19) (22) (26) (29) (;12) (35) (;38) (42) (45) (.51) (57) (64) (70) (77)

2 2 2 2 2 2 3 3 3 4 4 5 6 7 7 8 8 8 8 8 9 10 10

3

Length of Rope T u r n e d Back, in. (mm)

3¼ 33/4 43/4 5¼ 6½ 7 11~ 12 12 18 19 26 34 44 44 54 58 61 71 73 84 100 106

(83) (95) (121) (133) (165) (178) (292)

(305) (305) (457) (483) (660) (864) (1117) (1120) (1372) (1473) (1549) (1800) (1850) (2130) (2540) (2690)

4

Torque, ft-lb (N.m) 4.5 7.5 15 30 45 65 65 95 95 130 225 225 225 360 360 360 430 590 750 750 750 750 1200

( 6.1) (10)

(20) (41) (61) (88) (88) (129) (129) (176) (305) (305) (305) (488) (488) (488) (583) (800) (1020) (1020) (1020) (1020) (1630)

NOTE 1: If a pulley is used in place of a thimblefor turning. baek the rope, add one additim~al clip.

596

Drilling and Well Completions

The first clip should be attached at a point about one base width from the last seizing on the dead e n d of the rope and tightened securely. The saddle of the clip should rest u p o n the long or main rope and the U-bolt u p o n the dead end. All clips should be attached in this m a n n e r (see Figure 4-74). The short e n d of the rope should rest squarely u p o n the main portion. The second clip should be attached as near the loop as possible. The nuts for this clip should not be completely tightened when it is first installed. The r e c o m m e n d e d n u m b e r of clips and the space between clips are given in Table 4-33. Additional clips should be attached with an equal spacing between clips. Before completely tightening the second and any of the additional clips, some stress should be placed u p o n the rope in order to take up the slack and equalize the tension on both sides of the rope. W h e n the clips are attached correctly, the saddle should be in contact with the long e n d of the wire rope and the U-bolt in contact with the short e n d of the loop in the rope as shown in Figure 4-72. The incorrect application of clips is illustrated in Figure 4-74. The nuts on the second and additional clips should be tightened uniformly, by giving alternately a few turns to one side and then the other. It will be found that the application of a little oil to the threads will allow the nuts to be drawn tighter. After the rope has been in use a short time, the nuts on all clips should be retightened, as stress tends to stretch the rope, thereby reducing its diameter. The nuts should be tightened at all subsequent regular inspection periods. A half hitch, either with or without clips, is not desirable as it malforms and weakens wire rope. Figure 4-75 illustrates, in a simplified form, the generally accepted methods of reeving (stringing up) in-line crown and traveling blocks, along with the location of the drawworks drum, monkey board, drill pipe fingers, and deadline anchor in relation to the various sides of the derrick. Ordinarily, the only two variables in reeving systems, as illustrated, are the n u m b e r of sheaves in the crown and traveling blocks or the n u m b e r required for handling the load, and the location of the deadline anchor. Table 4-34 gives the right-hand string-ups. The reeving sequence for the left-hand reeving with 12 lines on a seven-sheave crown-block and six-sheave traveling block illustrated in Figure 4-75 is given in A r r a n g e m e n t No. 1 of Table 4-34. The p r e d o m i n a n t practice is to use left-hand reeving and

/

INCOR

R E C T

/

Figure 4-74. Incorrect methods of attaching clips to wire rope [11].

Hoisting System

597

Vee Side of Derrick Dead Line Anchor (H) Dead Line Anchor (I) (for left hand reevinci) (for right hand reevinc,I)l

Drill Pipe Finaers _

18

~Lf,

!.: t',i ::,i"

,I

i.:l :

,

i

/

I

~ili G( E iil~ I "~ !i~ il i l i

I

!

I I

!p !i :i =!,'t i ! E .:

:I

:: :~. :; ! :=

I l

~lii i

b~ (3.

E(3

:j

::

,'~5 ,-,,t :;3 ]2 /31 , , I l,,il / E/ ~i~D' lille( :B,

/

I

u "r"

,I

'! '1!1!!IHN I II

,

I i

I

E

I=.

o

Monkey Board

0

ill/

°m

03 I=.

re"

_J

Drawworks Drum

Driller Side of Derrick Figure 4-75. Typical reeving diagram for 14-line string-up with eight-sheave crown block and seven-sheave traveling block: left-hand reeving [11].

locate the d e a d l i n e a n c h o r to the left of the d e r r i c k vee. In selecting the best of the various possible methods for reeving casing or drilling lines, the following basic factors should b e considered: 1. M i n i m u m f l e e t angle from the drawworks d r u m to the first sheave of the crown block, a n d from the crown b l o c k sheaves to the traveling block sheaves. 2. P r o p e r balancing o f crown a n d traveling blocks. 3. Convenience in changing from smaller to larger n u m b e r of lines, or from larger to smaller n u m b e r of lines. 4. Location o f d e a d l i n e on monkey b o a r d side for convenience a n d safety of derrickman.

598

Drilling and Well Completions

Table 4-34 Recommended Reeving Arrangements for 12-, 10-, 8-, and 6-Line String-ups Using 7-Sheave Crown Blocks with 6-Sheave Traveling Blocks and 6-Sheave Crown Blocks with 5-Sheave Travelino Blocks 1"111 ~

~=evingSequence

No. of S h e ~ of

1 2

Block

8

7

[~ft Hand

14

7

Right Hanc

14

8

SUing-up

3

7

6

Left Hand

12

4

7

6

Right Hanc

12

5

7

6

Left Hand

10

6

7

6

Pdght Hanc

10

7

6

5

Left Hand

10

8

6

5

Right H a m

(Read From Left to Right Starting with Crown B l ~ k ~ d Going AIternateIy F r m C r o ~ to Traveling to C m ~ )

No. of Lines to

Block

I0

Crown Block Tray. B l ~ k Cro~m Block TI~v. Block Crown Block

1

G

F

A

C r o ~ Block Tray. Block

1

Crown Block

7

2 B

1

Crown Bloc~

6

9

6

5

Left Hand

8

10

6

5

Right Han¢

8

C ~ w n Block Tray, Block

6

C~wn Block Tray. Block

1

Grin

6

I

E

D

3 B D

2

5

Left Hand

8

6

5

Pdght Hanc

8

I3

6

5

Left Ham

6

Crown Block Tray. Block

2

14

6

5

Right Han¢

6

Crown Block Tray Block

5

15

6

5

Left Hand

6

Crown Block Tray. Block

I

I6

6

5

Right Hanc

6

Crown Block:

6

A

3

4 C

4 3

A

H 5

D 3

C 3

C 2

B 4

4

l

D

C

D

G 2

B

H

4 C

4 E

E A 5

3 C

B

6

2 B

D

I A

5 D

B

6 E

2

4

5 E

1

5

B

B

6

F A

D 3

D 2

7

2

4

C

1

6

3

5 E

F A

B

C 4

6 E

3 C

A 7

2

E

C

1

B

B 5

8 G

2

6

3 C

3 5

5

I2

T~v. Block

D

D

2

II

Block

C

3

A

Tray. Block

C

7 F

3

5

E

E

Crown B l ~ k Tray. B I ~ k

D 4 4

6

A

Tray. B I ~ k

6 E

5 E

F

Crown Block Tray, B l ~ k

E

B

A

Tiny. Block

5 D 4

3

6 F

4 5

C 6

2

7

Trav. Block

3 B

7

]

T~v. Block

Crown Block

2 A

8

I A

5. Location of deadline anchor, and its influence upon the m a x i m u m rated static h o o k load of derrick.

Recommended Design Features The proper design of sheaves, drums, and other equipment on which wire rope is used is very important to the service life of wire rope. It is strongly urged that the purchaser specify on his order that such material shall conform with r e c o m m e n d a t i o n s set forth in this section. The inside diameter of socket and swivel-socket baskets should be ~ in. larger than the nominal diameter of the wire rope inserted. Alloy or carbon steel, heat treated, will best serve for sheave grooves. Antifriction bearings are recommended for all rotating sheaves. Drums should be large enough to handle the rope with the smallest possible number of layers. Drums having a diameter of 20 times the nominal wire-rope d i a m e t e r should be c o n s i d e r e d m i n i m u m for e c o n o m i c a l practice. Larger diameters than this are preferable. For well-measuring wire, the drum diameter should be as large as the design of the equipment will permit, but should not be less than 100 times the wire diameter. The r e c o m m e n d e d grooving for wirerope drums is as follows: a. On drums designed for multiple-layer winding, the distance between groove centerlines should be approximately equal to the nominal diameter of the wire rope plus one-half the specified oversize tolerance. For the best

Hoisting System

599

spooling c o n d i t i o n , this d i m e n s i o n can vary according to the' type of operation. b. The curvature radius of the groove profile should be equal to the radii listed in Table 4-32. c. The groove depth should be approximately 30% of the n o m i n a l diameter of the wire rope. The crests between grooves should be r o u n d e d off to provide the r e c o m m e n d e d groove depth.

Diameter of Sheaves. W h e n b e n d i n g conditions over sheaves p r e d o m i n a t e in controlling rope life, sheaves should be as large as possible after consideration has been given to economy of design, portability, etc. W h e n conditions other than b e n d i n g over sheaves p r e d o m i n a t e as in the case of hoisting service for rotary drilling, the size of the sheaves may be reduced without seriously affecting rope life. The following r e c o m m e n d a t i o n s are offered as a guide to designers a n d users in selecting the proper sheave size. DT = d × F

(4-25)

where DT = tread diameter of sheave in in. (mm) (see Figure 4-76), d = n o m i n a l rope diameter in in. (mm), a n d F = sheave-diameter factor, selected from Table 4-35. It should be stressed that if sheave design is based on c o n d i t i o n C, fatigue due to severe b e n d i n g can occur rapidly. If other o p e r a t i o n c o n d i t i o n s are not present to cause the rope to be removed from service, this type of fatigue is apt to result in wires breaking where they are not readily visible to external examination. Any c o n d i t i o n resulting in rope d e t e r i o r a t i o n of a type that is difficult to j u d g e by examination d u r i n g service should certainly be avoided.

g

DRILLING LINE & CASING LINE SHEAVES

DETAILA

D

l SAND-LINE SHEAVE

DETAIL B

Figure 4-76. Sheave grooves [11].

600

Drilling a n d Well Completions Table 4-35 Sheave-Diameter Factors [ 1 1 ] 1

2

3

4

Factor, F •

Rope Classification 6x7 6x17 Seale 6x19 Seale 6x21 Filler Wire 6x25 Filler Wire 6x31 6x37 8x19 Scale 8x 19 Warrington 18x7 and 19x7 Flattened Strand

A

Condition A

Condition B

72 56 51 45 41 38 33 36 31 51 51

42 33 30 26 24 22 18 21 18 36 45

.

Condition C

(See Fig. 3.1 and Table 3.2)

*

*Follow manufacturer's recommendations. Condition A--Where bending over sheaves is of major importance, sheaves at large as those determined by factors under condition A are recommended.

Condition B--Where bending over sheaves is important, but some sacrifice in rope life is acceptable to achieve portability, reduction in weight, economy of design, etc., sheaves at least as large as those determined by factors under condition B are recommended.

Condition C--Some equipment is used under operating conditions which do not reflect the advantage of the selection of sheaves by factors under conditions A or B. In such cases, sheavediameter factors may be selected from Figure 4-76 and Table 4-34. As smaller factors are selected, the bending life of the wire rope is reduced and it becomes an increasingly important condition of rope service. Some conception of relative rope service with different rope constructions and/or different sheave sizes may be obtained by multiplying the ordinate found in Figure 4-76 by the proper construction factor indicated in Table 4-34,

The diameter of sheaves for well-measuring wire should be as large as the design of the e q u i p m e n t will permit but not less than 100 times the diameter of the wire. Sheave G r o o v e s . O n all sheaves, the arc of the groove b o t t o m should be smooth and concentric with the bore or shaft of the sheave. The centerline of the groove should be in a plane p e r p e n d i c u l a r to the axis of the bore or shaft of the sheave. Grooves for drilling a n d casing line sheaves shall be made for the rope size specified by the purchaser. The groove bottom shall have a radius R (Table 4-32) s u b t e n d i n g an arc of 150 ° . The sides of the groove shall be tangent to the ends of the b o t t o m arc. Total groove depth shall be a m i n i m u m of 1.33d a n d a m a x i m u m of 1.75d (d is the n o m i n a l rope diameter shown in Figure 4-76).

Hoisting System

601

Grooves for sand-line sheaves shall be m a d e for the r o p e size specified by the purchaser. T h e groove b o t t o m shall have a radius R (Table 4-32) s u b t e n d i n g an arc o f 150% The sides o f the groove shall be tangent to the ends o f the b o t t o m arc. Total groove d e p t h shall be a m i n i m u m o f 1.75d a n d a m a x i m u m o f 3d (d is n o m i n a l r o p e d i a m e t e r shown in Figure 4-77B). Grooves on rollers o f oil savers should be m a d e to the same tolerances as the grooves on the sheaves. Sheaves c o n f o r m i n g to the specifications (Specification 8A) shall be marked with the m a n u f a c t u r e r ' s name or mark, the sheave groove size a n d the sheave OD. These markings shall be cast or s t a m p e d on the outer rim o f the sheave groove a n d s t a m p e d on t h e n a m e p l a t e o f c r o w n a n d traveling blocks. For example, a 36-in. sheave with 1 x8 in. groove shall be marked AB CO 1 1 / 8 SPEC 8A Sheaves should be replaced or reworked when the groove radius decreases below the values shown in Table 4-31. Use sheave gages as shown in Figure 4-77A shows a sheave with a m i n i m u m groove radius, a n d 4-77B shows a sheave with a tight groove.

Evaluation of Rotary Drilling Line T h e total service p e r f o r m e d by a rotary d r i l l i n g line can be evaluated by c o n s i d e r i n g the a m o u n t o f work d o n e by the line in various d r i l l i n g o p e r a t i o n s (drilling, coring, fishing, setting casing, etc.), a n d by evaluating such factors as the stresses i m p o s e d by acceleration a n d deceleration loadings, vibration stresses, stresses i m p o s e d by friction forces o f the line in contact with d r u m a n d sheave surfaces, a n d o t h e r even m o r e i n d e t e r m i n a t e loads. However, for comparative purposes, an a p p r o x i m a t e evaluation can be o b t a i n e d by c o m p u t i n g only the work d o n e by the line in raising a n d lowering the applied loads in making r o u n d trips, a n d in the o p e r a t i o n s o f drilling, coring, setting casing, a n d short trips.

Round-Trip Operations. Most o f the work d o n e by a d r i l l i n g line is that p e r f o r m e d in making r o u n d trips (or half-trips) involving r u n n i n g the string o f

DETAIL A

DETAIL B

Figure 4-77. Use of sheave gage [11].

602

Drilling and Well C o m p l e t i o n s

drill pipe into the hole and pulling the string out o f the hole. The a m o u n t o f work p e r f o r m e d p e r r o u n d trip should be d e t e r m i n e d by

Tr = D ( L + l~]__/Wm --~ 10,560,000 2,640,000

(4-26)

where T = ton-miles (weight in tons times distance moved in miles) 6= d e p t h o f hole in feet L = length o f drill-pipe stand in feet n u m b e r o f drill-pipe stands W = effective weight p e r foot o f drill-pipe from Figure 4-78 in p o u n d s total weight o f traveling block-elevator assembly in pounds C = effective weight o f drill-collar assembly from Figure 4-78 minus the effective weight o f the same length o f drill-pipe from Figure 4-78 in p o u n d s

Drilling Operations. T h e ton-miles o f work p e r f o r m e d in drilling o p e r a t i o n s is expressed in terms o f work p e r f o r m e d in making r o u n d trips, since there is a direct relationship as illustrated in the following cycle o f drilling operations. 1. 2. 3. 4. 5. 6. 7. 8.

Drill ahead length o f the kelly. Pull up length o f the kelly. Ream ahead length o f the kelly. Pull up length o f the kelly to add single or double. Put kelly in rat hole. Pick up single or double. Lower drill stem in hole. Pick up kelly.

Analysis o f the cycle o f o p e r a t i o n s shows that for any hole, the sum o f operations 1 and 2 is equal to one r o u n d trip; the sum o f o p e r a t i o n s 3 and 4 is equal to a n o t h e r r o u n d trip; the sum o f o p e r a t i o n 7 is equal to one-half a r o u n d trip; and the sum o f o p e r a t i o n s 5, 6, and 8 may, and in this case does, equal a n o t h e r one-half r o u n d trip, thereby making the work o f drilling the hole equivalent to three r o u n d trips to bottom, and the relationship can be expressed as T d = 3(72 - 71)

(4-27)

where T d = ton-mile drilling T~ = ton-miles for one round trip at depth D I (depth where drilling started after going in hole, in ft) T 2 = ton-miles for one round trip at depth D 2 (depth where drilfing stopped before coming out o f hole in ft) If o p e r a t i o n s 3 and 4 are omitted, then formula 4-27 becomes T d = 2(72 - 7i)

Coring Operations, The

(4-28)

ton-miles o f work p e r f o r m e d in coring operations, as for drilling operations, is expressed in terms o f work p e r f o r m e d in making r o u n d trips, since there is a direct relationship illustrated in the following cycle o f coring operations.

Hoisting System 3O

60

45

WEIGHT OF FLUID, I-8 PER CU. FI". 75 90 105 120 --

135

150

603 165

35

30

25

o:

2O ¢,. ¢,.

~J

0 AIR OR GAS

5

i

10 WEIGHT OF FLUID, L B

15

20

PER GAL,

Figure 4-78. Effective weight of pipe-in drilling fluid [11]. 1. 2. 3. 4. 5. 6.

Core ahead length o f core barrel. Pull up length o f kelly. Put kelly in rat hole. Pick up single. Lower drill stem in hole. Pick up kelly.

604

Drilling and Well C o m p l e t i o n s

Analysis of the cycle of o p e r a t i o n shows that for any one hole the sum of o p e r a t i o n s 1 and 2 is equal to one r o u n d trip; the sum of o p e r a t i o n s 5 is equal to one-half a r o u n d trip; and the sum of o p e r a t i o n s 3, 4, and 6 may, and in this case does, equal a n o t h e r one-half r o u n d trip, thereby making the work of drilling the hole equivalent to two r o u n d trips to bottom, and the relationship can be expressed as T = 2(T 4 - Ts)

(4-29)

where T = ton-mile coring T~ = ton-miles for one r o u n d trip at d e p t h D~ (depth where coring started after going in hole, in feet) T 4 = ton-miles for o n e r o u n d t r i p at d e p t h D 4 ( d e p t h w h e r e c o r i n g s t o p p e d before coming out of hole, in feet)

Setting Casing Operations. T h e calculation of the ton-miles for the o p e r a t i o n of setting casing should be d e t e r m i n e d as in round-trip o p e r a t i o n s as for drill pipe, b u t with the effective weight of the casing being used, and with the result being multiplied by one-half, since setting casing is a one-way (one-half roundtrip) o p e r a t i o n . Ton-miles for setting casing can be d e t e r m i n e d from

Ts =

10,560,000

2,640,000

Since no excess weight for drill collars need be considered, Equation 4-30 becomes T = D(L~+D)(Wcm)+ DM /2) 10,560,000 2,640,000

(4-31)

where T s = ton-miles setting casing Los = length of j o i n t of casing in ft W m = effective weight p e r foot of casing in l b / f t T h e effective weight p e r foot of casing Wcm may be estimated from data given on Figure 4-78 for drill p i p e (using the a p p r o x i m a t e lb/ft), or calculated as

Wcm = Wca (1 - 0.015B)

(4-32)

where W¢~ is weight p e r foot of casing in air in l b / f t B is weight of drilling fluid from Figure 4-79 or Figure 4-80 in l b / g a l

Short Trip Operations. The ton-miles of work p e r f o r m e d in short trip operations, as for drilling and coring operations, is also expressed in terms of r o u n d trips. Analysis shows that the ton-miles of work d o n e in making a short trip is equal to the difference in r o u n d trip ton-miles for the two depths in question. This can be expressed as TST = T 6 - T 5 where TST = ton-miles for short trip T 5 = ton-miles for one r o u n d trip at d e p t h D 5 (shallower depth) T 6 = ton-miles for one r o u n d trip at d e p t h D 6 ( d e e p e r depth)

(4-33)

Hoisting System

605

20 18 (/3

> 0 12 w

f

• .°.: . . . . . . . . .

14.

...I I 0 z --

8

Z b.I ao

6

O

iiiiiiiii iiiii

4

Z 2

14

16

18 DT/d

20

22

24

26

Z8

RATIOS

DT = tread diameter of sheave, inches (ram) (see Fig. 4-73) d = nominal rope diameter, inches (ram).

Figure 4-79.

Relative service for various DT/d ratios for sheaves

[11].*

See "Diameter of Sheaves," subparagraph titled "Variation for Different Service Applications." *Based on laboratorY tests involving systems consisting of sheaves only.

For the comparative evaluation of service from rotary drilling lines, the grand total of ton-miles of work performed will be the sum of the ton-miles for all round-trip operations (Equation 4-26), the ton-miles for all drilling operations (Equation 4-27), the ton-miles for all coring operations (Equation 4-29), the tonmiles for all casing setting operations (Equation 4-30), and the ton-miles for all short trip operations (Equation 4-33). By dividing the grand total ton-miles for

606

Drilling and Well Completions WEIGHT OF F L U I D , 140 ~ '

15

".-

I I !

LB. PER CU. FT.

120

30

I"

135

/

, ~3o

I

I

[ I"~.

! I_L~Z!-

~

...........

"

~~ l

.

e

. . . .

~.o l i l i i ! _~

ifllll

:>

= ~ 2

-

[ 40,

.o

; i

i i i

,iiiiii rH+!l I

~o [- I T i - 1 T I

AIR OR GAS

IO W E I G H T OF F L U t D ,

15 LB. P E R

GAL.

F i g u r e 4-80. Effective weight of drill collars in drilling fluid [11].

all wells by the original length of line in feet, the evaluation of rotary drilling lines in ton-miles per foot on initial length may be determined. R o t a r y Drilling L i n e S e r v i c e - R e c o r d

Form

Figure 4-81 is a rotary drilling line service-record form. It can be filled out o n the bases of Figure 4-82 and previous discussion.

ROTARY c+.w*.,r,.

UN[

SI~VICE RECOIU)

l

+

l

m l l O l e

$

'

i

F

+ -

.--.

==er

mo ,-,,

+llZl 111,[(I"I~

lw,44gl O f IAI41"

)

DRUJ.ING

, ~ . . ,.=, =

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11

- .... e ~ ,l,,t

Ii~

P,~ ,i.~.

~,~m

+I

ii

i+

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'.,,ram

11111 1 , 4 o _ _

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+

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lJ

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O=I. ~12

tl

+ ~,.

[m

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I O N . ~ I I LtI, $|11yIC41 - e l t [ V i O ~ WeU L IOI'~LI I¢++I-~ILES

I~N-~IIe| |lmVl¢l ON 111n - TIllS r o l l IINITII~LLIN01K

5elvlCe ~L~e~ IHMLLIId~--mFS W | I I

' l ' ~ . l ,u t e . l M P / i c t 4PO41JWC.,-- THIS WELl •

~

le,,~ i JJ't I P n = +

lOki..U.li[l M I ~ I ( I ~ 1 1 t J ~ CI4JIdG -- m PIm<=~I

41~I~

~lil

~.~i W m 14 Wl, l l ~ b O4~idd A

Figure 4-81. Facsimile of rotary dritling line service-record form [11].

Drilling and Well Completions

608

200 I90-

BASED ON A STAND LENGTH VALUE OF I 0 0 FT. (TAKEN AS A CONVENIENT COMPROMISE BETWEEN 90-FT. AND 120-FT. STANDS.)

180-.

;00-

170~

30~

160"

20~

150.

io~

140

ooo-~

~-0

"~-io

~ VALUESOF

~-,o ooo

130, 120

8~-2

I10

roo-

I00

500"

~ o ooo ~,-zo ooo /

~-~o ooo ~

~

CHART B

70

/

[ :1

E -I ~.

~-~2o

~

50

6.000-FT. TO 20tOOO-FT. ~ DEPTH tu

9o-: 80

.t

gI~°~~ io

,%

VALUESOFFACTOR (M40,50) -40

000

"35 000 -30 000 "Z5 000 ~Z0000 -IS 000 -10 000 -5 000

CHART A O TO

6,000-FT. DEPTH

E: £ - 1o ~ ,o

30

Figure 4-82. Rotary-drilling ton-mile charts [11]. S l i p p i n g a n d C u t o f f P r a c t i c e for R o t a r y D r i l l i n g L i n e s

Using a planned p r o g r a m of slipping and cutoff based upon increments of service can greatly increase the service life of drilling lines. Determining when to slip and cut depending only on visual inspection, will result in uneven wear, trouble with spooling (line "cutting in" on the drum), and long cutoffs, thus decreasing the service life. The general procedure in any p r o g r a m should be

Hoisting System

609

to supply an excess o f drilling line over that required to string up, and to slip this excess t h r o u g h the system at such a rate that it is evenly worn and that the line removed by cutoff at the d r u m end has just reached the end of its useful life.

Initial Length of Line. T h e relationship between initial lengths o f rotary lines a n d t h e i r n o r m a l service life expectancies is shown in Figure 4-83. Possible savings by the use o f a longer line may be offset by an increased cost o f handling for a l o n g e r line.

:

I0

•

.........

: . . . . . .

•

...............

:

, . . . . . . . . . . . . .

:

:

~ .....

; .....

i

.~

:. . . . .

-

: ....

: ....

. . . . .

9

w U

(/,

8

> 7

• REEVING

:

w

.

bJ 0 Iz: ' b.I n,,

LENGTH,

i~,__

6

5

i

i

~

v

v

. . . . . . . . . . . . .

,.•.

1300

..... : . . . . . . . . . . . .

1400

•: ...i : .......... i..

ssool

..... i ..........

s6oo

'

1177 0 0

"

i..

. .......... :...

w > h--

,•.i ..... i ..... i ..... i ..... i ......

3

-

i

w 2

;

I000

:

!

2000

3000

ROTARY

LINE

!

!

4000

:

5000

INITIAL

6000 LENGTH.

7000 FT.

Figure 4-83. Relationship between rotary-line initial length and service life [11].* *Empirical curves developed from general field experience•

610

Drilling and Well Completions

S e r v i c e G o a l . A goal for line service in terms of ton-miles between cutoffs should be selected. This value can initially be determined from Figures 4-84 and 4-85 and later adjusted in accordance with experience. Figure 4-86 shows a graphical method of determining optimum cutoff frequency.

i n L i n e S e r v i c e . Ton-miles of service will vary with the type and condition of equipment used, drilling conditions encountered, and the skill used

Variations

20

22

24

26

D !

I

l

l

I

I-I/2"

LITE

(/) .J --IJ. ~;0

16

18

20

21

I0

II

12

13

I-3/8"

LI N E

t

z~ .....

•~P-I - 114"-"

LINE

Om

~ QE WW

6

7

8

9

5

5

5

6

I (.~ z

2

3

4 ¢9 z

p n n . , , m "( --I - I / 8 " L I N E

ZO •,r- IZ1

.J

;

o o tr <¢ z

glib

m

80 87

=I

~-I" L I N E

94

DERRICK

122

HEIGHT,

136

140 147

189

FT

j

E

o >. (/) <¢ w

Explanation: To determine (approximately) the desirable ton-miles before the first cutoff on a new line, draw a vertical line from the derrick height to the wireline size used. Project this line horizontally to the ton-mile figure given for the type of drilling encountered in the area. Subsequent cutoffs should be made at 100 ton-miles less than those indicated for 11/s-in. and smaller lines, and at 200 ton-miles less than 11/4-in. and 1¾-in. lines. F i g u r e 4 - 8 4 . T o n - m i l e d e r r i c k h e i g h t a n d l i n e - s i z e r e l a t i o n s h i p s [11].* *The values for ton-miles before cutoff, as given in Figure 4-84 were calculated for improved plow steel with an independent wire-rope core and operating at a design factor of 5. When a design factor other than 5 is used, these values should be modified in accordance with Figure 4-85. The values given in Figure 4-84 are intended to serve as a guide for the selection of initial ton-mile values as explained in Par. "Service Goal." These values are conservative, and are applicable to all typical constructions of wire rope as recommended for the rotary ddlling lines shown in Table 4-9.

Hoisting System

1.5

f

I

I

'"

I

t

•

I

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

.. . . . . .

• . . . .

. . . . . . . . . .

. . . .

;

~ - - - ; • •

'

/

•. . . .

~

611

ec

o I-

1.0 i,i. lad

.. . . . .

•

. . . . .

! . . . .

i

. . . .

: . . . . . . . . .

. . . .

-~

- - - :

.

.

.

.

.

> n."

lad ¢/) Ld _1 m

0.5

!

Z

0

I--

....

i ...........

~ .....

.... ....

" ........... i ............

: ........ !..... i

.... i..... ~ .......... . . . . . . . . . . . . . . . . . . . .

0

i

; ....

i

~ .....

~: ....

: i .... "::..... ::.....

i .........

i .......... ::..... !

i ..........

: .....

~ .......... .............

:: .... i .....

i ,.. .... i; ..... ~ .... :;.... i. ..... . . . . :. ..... !! . ..... .... ..... ~. . . . . .... . . . .

i 2

~.....

~ 3

DESIGN

i 4

i

i 5

6

7

FACTOR

F i g u r e 4 - 8 5 . Relationship between design factors a n d t o n - m i l e service factors [11].* NOTE: Light loads can cause rope to wear out from fatigue prior to accumulation of anticipated ton-mites. *Based on laboratory tests of bending over sheaves.

in the operation• A program should be "tailored" to the individual rig. The condition of the line as moved through the reeving system and the condition of the cutoff portions will indicate whether the proper goal was selected. In all cases, visual inspection of the wire rope by the operator should take precedence over any predetermined procedures. (See Figure 4-86 for a graphical comparison of rope services.)

612

Drilling a n d Well C o m p l e t i o n s 4

5

~

40

03 LLI

35

i

z o I-o 30 'l,"'-

c.~ ,~ 25 .-J

~

20

15

RIG: MAKE MODEL OPERATINGAREA

10 ROPE NO 1

LENGTH

S~E

TYPE

TON-MI PERCElT 800

TOTAL TOH-MI 35,000

2

900

39,250

3

1000

43,750

4

1100

40,000

BEST PERFORMANCEWAS OBTAINEDAT 1000 T-M PER CUT FORTHIS PARTICULARTYPEOF RIG & SERVICE

0

500

1000

1500

2000

2500

3000

3500

TOTALCUTOFF,FEET Figure 4-86. Graphic method of determining optimum frequency of cutoff to give maximum total ton-miles for a particular rig operating under certain drilling conditions [11] Cutoff Length. T h e following factors should be c o n s i d e r e d in d e t e r m i n i n g

a

cutoff length: 1. T h e excess length o f line that can conveniently be c a r r i e d on the drum. 2. Load-pickup points from reeving diagram. 3. D r u m d i a m e t e r and crossover points on the drum.

Hoisting System

613

T h e crossover a n d pickup points should not repeat. This is d o n e by avoiding c u t o f f l e n g t h s t h a t are m u l t i p l e s o f e i t h e r d r u m c i r c u m f e r e n c e , o r l e n g t h s between pickup points. Successful p r o g r a m s have been b a s e d on cutoff lengths r a n g i n g from 30 to 150 ft. Table 4-36 shows a r e c o m m e n d e d length o f cutoff ( n u m b e r o f d r u m laps) for each height d e r r i c k a n d d r u m diameter.

Slipping Program. T h e n u m b e r o f slips between cutoffs can vary considerably d e p e n d i n g u p o n drilling conditions a n d the length a n d frequency o f cutoffs. Slips should be i n c r e a s e d if the d i g g i n g is rough, if j a r r i n g j o b s occur, etc. Slipping that causes too much line piles up on the d r u m , particularly an e x t r a layer on the d r u m , before cutoff should be avoided. In slipping the line, the r o p e should be slipped an amount such that no p a r t o f the r o p e will be located for a second time in a p o s i t i o n o f severe wear. T h e positions o f severe wear are the point o f crossover on the d r u m and the sections in contact with the traveling-block a n d crown-block sheaves at the pickup position. T h e cumulative Table 4-36 Recommended Cutoff Lengths in Terms of Drum Laps* See Paragraph Titled "Cutoff Length" [11] 2

3

4

5

11

13

14

16 18 20 22 24 26 Number of Drum Laps per Cutoff

151 Up 141 tolS0 133to140 120to132 91 to 119 73 to 90 Up through 72

6

7

8

9

10

l

Derriek or Mast Height. ft

II

12

13

14

15

28

30

32

34

36

lS~z ll~/~ 11½ 10~,~ 8~

14~ 11% 10:/z 9~

13~ 10~ 9½ 9~z

12~/.',

Drum Diameter, in,

12!§

19!,) 17~ 11

17~ 14~

17~ 14~i 12~

13~ 15!~z 14~,~ 12~ 15~ 14~ 12~ 12~ 12Y~ 11~/.~ 10~ 9~/~ ll~z

12½ 11V2 11~ 9½

11~

eln order to insure • change of the point of crossover on the drum, where wear and crushing are most severe, the laps to be cut off are Liven tn multiples of one-half lap or one quarter lap dependent upon the type of drum grooving.

Example: Assumed conditions: a, b. ¢. d. e.

Derrick height: 138 ft Wire-line size: 11/4in. Type Drilling: #3 Drum diameter: 28 in. Design Factor: 3.

Solution: 1. From Fig. 4-84 determine that (for a line with a design factor of 5) the first cutoff would be made after 1200 ton-miles and additional cut-offs after each successive 1000 ton-miles. 2. Since a design factor of 3 applies, Fig. 4-85 indicates that these values should be multiplied by a factor of 0.58. Hence the first cutoff should be made after 696 ton-miles and additional cutoffs after each successive 580 ton-miles. 3, From Table 4-36 determine that 111/2drum laps (84 ft) should be removed at each cutoff. 4. Slip 21 ft every 174 ton-mites for four times and cut off after the fourth slip. Thereafter, slip 21 ft every 145 ton-miles and cut off on the fourth slip.

614

Drilling and Well C o m p l e t i o n s

n u m b e r of feet slipped between cutoffs should be equal to the r e c o m m e n d e d feet for ton-mile cutoff. For example, if cutting off 80 ft every 800 ton-miles, 20 ft should be slipped every 200 ton-miles, and the line cut off on the fourth slip. Field Troubles and Their Causes All wire rope will eventually d e t e r i o r a t e in o p e r a t i o n or have to be removed simply by virtue of the loads and reversals of load a p p l i e d in n o r m a l service. However, many conditions of service or inadvertent abuse will materially shorten the n o r m a l life of a wire r o p e of p r o p e r construction although it is p r o p e r l y applied. T h e following field troubles and their causes give some of the field conditions and practices that result in the p r e m a t u r e r e p l a c e m e n t of wire rope. It should be b o r n e in m i n d that in all cases the c o n t r i b u t o r y cause of removal may be one or m o r e of these practices or conditions.

Wire-Rope Trouble

Possible Cause

Rope broken (all strands).

Overload resulting from severe impact, kinking, damage, localized wear, weakening of one or more strands, or rust-bound condition and loss of elasticity. Loss of metallic area due to broken wires caused by severe bending.

One or more whole strands parted.

Overloading, kinking, divider interference, localized wear, or rust-bound condition. Fatigue, excessive speed, slipping, or running too loosely. Concentration of vibration at dead sheave or dead-end anchor.

Excessive corrosion.

Lack of lubrication. Exposure to salt spray, corrosive gases, alkaline water, acid water, mud, or dirt. Period of inactivity without adequate protection.

Rope damage by careless handling in hauling to the well or location.

Rolling reel over obstructions or dropping from car, truck, or platform. The use of chains for lashing, or the use of lever against rope instead of flange. Nailing through rope to flange.

Damage by improper socketing.

Improper seizing that allows slack from one or more strands to work back into rope; improper method of socketing or poor workmanship in socketing, frequently shown by rope being untwisted at socket, loose or drawn.

Kinks, dog legs, and other distorted places.

Kinking the rope and pulling out the loops such as in improper coiling or unreeling. Improper winding on the drum. Improper tiedown. Open-drum reels having longitudinal spokes too widely spaced. Divider interference. The addition of improperly spaced cleats increase the drum diameter. Stressing while rope is over small sheave or obstacle.

Hoisting System Wire-Rope Trouble

615

Possible Cause

Damage by hooking back slack too tightly to girt.

Operation of walking beam causing a bending action on wires at clamp and resulting in fatigue and cracking of wires, frequently before rope goes down into hole.

Damage or failure on a fishing job.

Rope improperly used on a fishing job, resulting in damage or failure as a result of the nature of the work.

Lengthening of lay and reduction of diameter.

Frequently produced by some type of overloading, such as an overload resulting in a collapse of the fiber core in swabbing lines. This may also occur in cable-tool lines as a result of concentrated pulsating or surging forces that may contribute to fiber-core collapse.

Premature breakage of wires.

Caused by frictional heat developed by pressure and slippage, regardless of drilling depth.

Excessive wear in spots.

Kinks or bends in rope due to improper handling during installation or service. Divider interference; also, wear against casing or hard shells or abrasive formations in a crooked hole. Too infrequent cutoffs on working end.

Spliced rope.

A splice is never as good as a continuous piece of rope, and slack is liable to work back and cause irregular wear.

Abrasion and broken wires in a straight line. Drawn or loosened strands. Rapid fatigue breaks.

Injury due to slipping rope through clamps.

Reduction in tensile strength or damage to rope.

Excessive heat due to careless exposure to fire or torch.

Distortion of wire rope.

Damage due to improperly attached clamps or wire-rope clips.

High strands.

Slipping through clamps, improper seizing, improper socketing or splicing, kinks, dog legs, and core popping.

Wear by abrasion.

Lack of lubrication. Slipping clamp unduly. Sandy or gritty working conditions. Rubbing against stationary object or abrasive surface. Faulty alignment. Undersized grooves and sheaves.

Fatigue breaks in wires.

Excessive vibration due to poor drilling conditions, i.e., high speed, rope, slipping, concentration of vibration at dead sheave or dead-end anchor, undersized grooves and sheaves, and improper selection of rope construction. Prolonged bending action over spudder sheaves, such as that due to hard drilling.

616

Drilling and Well Completions

Wire-Rope Trouble

Possible Cause

Spiraling or curling.

Allowing rope to drag or rub over pipe, sill, or any object during installation or operation. It is recommended that a block with sheave diameter 16 times the nominal wire-rope diameter, or larger, be used during installation of the line.

Excessive flattening or crushing.

Heavy overload, loose winding on drum, or cross winding. Too infrequent cutoffs on working end of cable-tool lines. Improper cutoff and moving program for cable-tool lines.

Bird-caging or core-popping.

Sudden unloading of line such as hitting fluid with excessive speed. Improper drilling motion or jar action. Use of sheaves of too small diameter or passing line around sharp bend.

Whipping off of rope.

Running too loose.

Cutting in on drum.

Loose winding on drum. Improper cutoff and moving program for rotary drilling lines. Improper or worn drum grooving or line turnback plate.

ROTARY EQUIPMENT Rotary e q u i p m e n t refers to the pieces o f surface e q u i p m e n t in drilling operations that actually rotate or impart rotating motion to the drill pipe. This equipment includes the upper members of the drill string such as the swivel, swivel sub kelly cock, kelly, lower kelly valve, and kelly sub (Figure 4-87), as well as the kelly bushing and rotatary table [13].

Swivel and Rotary Hose Swivel The swivel (Figure 4-88) suspends the kelly, allows for rotation of the kelly and drill string, and provides a connection for the rotary hose to allow mud circulation. T h e rotary swivel is pressure tested periodically, and the test pressure is shown on the swivel nameplate. All cast m e m b e r s in the swivel hydraulic circuit are pressure tested in production, and the test pressure is shown on the cast member.

Rotary Hose Although the rotary hose is not a rotating element, it is mentioned here due to its connection with the swivel. It is used as the flexible connector between the top of the standpipe and the swivel, and allows for vertical travel of the swivel and block (Figure 4-89). It is usually 45 ft or longer. Rotary hose specifications are provided in API Specification 7 [13]. Each hose assembly is

RotaryEquipment 617

~

SWIVEL

ROTARY BOX F"TTI-'I CONNECTION L.H."-,,,Lt"Jr~ i ~ S W l V E L STEM SPEC8A R I ~,!'~

ROTARY PI N ~ ~ CONNECTION L.H. ~

-SP~E7 SUB I !I! ~ /SWIVEL

ROTARY BOX ,u, _ -

F

CONNECTION L.H. " ~

J KELLY COCK

C

.'*'"~(0 PT f ON A L)

ROTARY PIN " r " CONNECTION L.H." ~

ROTARY BOX CONNECTION L.H ~ UPSET

KELLY (SQUARE OR HEXAGON) {SQUARE ILLUSTRATED)

NOTE: ALL CONNECTIONS

BETWEEN "LOWER UPSET" OF KELLY AND "BIT" ARE R H.

ROTARY PIN CONNECTION ROTARY BOX CONNECTION

,,,,

li I,

1

UPSET

KELLY COCK OR KELLY SAVER SUB PROTECTOR "RUBBI-"R (OPTIONAL)

ROTARY PI N CONNECTION

Figure 4-87. Rotary equipment--surface elements of drill string [13].

618

Drilling a n d Well C o m p l e t i o n s

Gooseneck Internal LinePipe Thread

External LinePipe Thread

Rotary Drilling Hose

Swivel Stem , --

MFRS Standard Rotary ConnectionLH.

Swivel Sub API Standard Rotary Connection LH.

Figure 4-88. Swivel nomenclature [15].

individually tested at its applicable pressure a n d is held at this pressure for a m i n i m u m p e r i o d o f 1 min (test pressure). The m a x i m u m working pressure o f the hose assembly includes the surge pressure a n d should be at least 2 ½ times smaller than the m i n i m u m burst pressure o f the hose. Rotary hose external connections (i.e., the connection to the swivel gooseneck) are t h r e a d e d with line-pipe t h r e a d as specified in API Specification 5B [14].

Rotary E q u i p m e n t

619

HighestOperatingPosition

Lengthof HoseTraveled

StandPipe Height 15°

"

Lowes O era ,n, Pos,,,on

;OrPl d" ,O, gF~oor'"---.

~

'111 .--"'"

~-"

Figure 4-89. Rotary hose [15].

Drill-Stem Subs Different types o f drill-stem subs are shown in Figures 4-90 and 4-91. T h e classification o f drill-stem subs is presented in Table 4-37.

Swivel Sub T h e outside d i a m e t e r of the swivel sub is at least equal to the d i a m e t e r o f the u p p e r kelly box. T h e swivel sub should have a m i n i m u m of 8 in. o f tong space length. T h e m i n i m u m b o r e d i a m e t e r is equal to that o f the kelly. T h e

620

Drilling and Well C o m p l e t i o n s

Figure 4-90. Drill-stem subs [13].

Rota#tPir~Or BOXCo m~s~io/1

LHP~ EB

TtPE A

........

24 m!

M~rki~ Recess

...........D~

C~~on

TYPEC ~4m14s~ ~eas

i

45:'

......... ¢~. 4~;

.........

Figure 4-91. Types of drill-stem subs [13].

swivel sub is furnished with a pin-up and a pin-down rotary shouldered connection. Both connections are left h a n d e d .

Kelly Cock and Lower Kelly Valve T h e kelly cock a n d lower kelly valve are manually o p e r a t e d valves in the circulating system.

Rotary Equipment

621

Table 4-37 Drill-Stem Subs [13] 1

2

3

4

Type

Class

Upper Connection to Assemble w!

Lower Connection to Assemble w!

A or B " " " " C

Kelly Sub Tool Joint Sub Crossover Sub Drill Collar Sub Bit Sub Swivel Sub

Kelly Tool Joint Tool Joint Drill Collar Drill Collar Swivel Sub

Tool Joint Tool Joint Drill Collar Drill Collar Bit Kelly

Kelly Cock

The kelly cock (Figure 4-92) is located between the kelly joint and the swivel. The kelly cock will close the drill string if the swivel, drilling hose, or standpipe develops a leak or rupture and threatens to blowout. It also closes in the event that pressure within the hose exceeds the hose pressure rating. The specifications for kelly cocks are provided in API Specification 7 [1]. Lower Kelly Valves

Some kellys (Figure 4-93) are equipped with a mud check-valve that is placed immediately below the kelly. W h e n mud pumps are shut off, this valve closes to save mud that would otherwise be spilled out onto the rig floor. To avoid loss of pressure across the tool, the kelly valve is either fully open or fully closed while in operation. It opens and closes automatically and automatically allows reverse flow. Lower Kelly Cock

The lower kelly cock is often substituted for the lower kelly valve. It is operated manually, as shown in Figure 4-92. The specifications for lower kelly cocks are provided in API Specification 7 [1]. Kelly

The kelly (Figure 4-94) is a square-shaped or hexagonal-shaped pipe (drive section) that transmits power from the rotary table to the drill bit. Also, drilling m u d is p u m p e d d o w n h o l e t h r o u g h the kelly. Kellys must c o n f o r m to the dimensions specified for the respective sizes in API Specification 7 [1]. The drive section of the hexagonal kelly is stronger than the drive section of the square kelly when the appropriate kelly has been selected for a given casing size. For a given bending load, the stress level is less in the hexagonal kelly; thus the hexagonal kelly will operate for more cycles before failure.

622

Drilling and Well Completions

~ --DF ~

V///.j I

~

/~1

VALVE SHAPE

OPT,ONAL

Figure 4-92. Upper kelly cock [13].

Square-Forged Kellys In square-forged kellys, the decarburized zone has b e e n removed from the corners of the fillet between the drive section a n d the upset to prevent fatigue cracks. H e x a g o n a l kellys have m a c h i n e d surfaces a n d are generally free of decarburized zone in the drive section. The life of the drive section as related to the fit with kelly drive bushings is generally greater when the square drive section is used. However, the use of adjustable drive bushings (adjustable bushings with wear) can drastically increase the life of the square drive section. The i m p o r t a n t parts of the kelly that should be examined for wear are: • the corners of the drive section (for surface wear) • the j u n c t i o n s between the upsets and the drive section (for cracks) • the straightness of the kelly.

Rotary Table and Bushings Rotary Table The rotary table (Figure 4-95) provides the rotary movement to the kelly. The master b u s h i n g of the rotary table encases the kelly b u s h i n g or pipe slips, as

Rotary Equipment

623

(B) 4" I.F., 41 or 41/2 ub 21

41j

~-Out Cap lg Bolt older

(A)

Seal Support

STANDA 61/2", 6 : or 61/4" I Protector Seal Housing

41/', 213/1 ;ub

(c) 4" I.F., 411', or 41/2" F.H. Figure 4-93. Lower kelly valve (mud saver) [16].

shown in Figure 4-96. As the rotary table turns, the master bushing, the kelly, the drill pipe, and the bit also turn. The rotary table is driven by the drawworks.

Master Bushings There are two types of master bushings: 1. Square drive master bushings (Figure 4-97) 2, Pin drive master bushings (Figure 4-98) (text continued on page 626)

624

Drilling and Well Completions

Figure 4-94. Square kelly and hexagonal kelly.

Figure 4-95. Rotary table with pin-drive master bushings [16].

Rotary Equipment

625

+0

1164['--

,9;!!!!;:!2;i,a

KELLYSQUARE DRIVEBUSHINGREMOVED FROMTABLE ' - Kelly

CUT-AWAYSHOWING MASTERBUSHING

Figure 4-96. Rotary table with square drive bushings and slips [13].

Figure 4-97. Rotary table opening and square drive master bushing [13].

626

Drilling and Well Completions

B1

\

/- G-Diameter] / DriveHole /

}

;"-4"_____0.018" ~ ~aperperf°°t 27' 45" _+2' 30" Taperperside

g~

~

1

\

k PINDRIVE KELLYBUSHING

--4 --

A~ -

=-

[7I--:T~. 3

PINDRIVE MASTERBUSHING Figure 4-98. Pin-drive master bushing [13].

(text continued from page 623)

The API requirements for rotary table openings for square drive master bushings and the sizes of the square drive and pin-drive master bushings are specified in API Specification 7 [1].

Kelly Bushings The kelly bushing attaches the kelly to the rotary table. It locks into the master bushing and transfers the torque produced by the table to the kelly. There are two types of kelly bushings [16]: 1. Square drive kelly bushings (aligned with square drive master bushings) 2. Pin drive kelly bushings (aligned with pin-drive master bushings)

Mud Pumps

627

MUD PUMPS Mud pumps consume more than 60% of all the horsepower used in rotary drilling. Mud pumps are used to circulate drilling fluid through the mud circulation system while drilling. A pump with two fluid cylinders, as shown in Figure 4-00, is called a duplex pump. A three-fluid-cylinder pump, as shown in Figure 4-100, is called a triplex pump. Duplex pumps are usually double action, and triplex pumps are usually single action. Mud pumps consist of a power input end and a fluid output end. The power input end, shown in Figure 4-101, transfers power from the driving engine (usually diesel or electric) to the pump crankshaft. The fluid end does the actual work of p u m p i n g the fluid. A cross-section of the fluid e n d is shown in Figure 4-102.

Pump Installation Suction Manifold The hydraulic horsepower produced by mud pumps depends mainly on the geometric and mechanical arrangement of the suction piping. If suction-charging centrifugal pumps (e.g., auxiliary pumps that help move the mud to the mud pump) are not used, the pump cylinders have to be filled by the hydrostatic head. Incomplete filling of the cylinders can result in hammering, which produces destructive pressure peaks and shortens the pump life. Filling problems become more important with higher piston velocities. The suction pressure loss through the suction valve and seat is from 5 to 10 psi. Approximately 1.5 psi of pressure is required for each foot of suction lift. Since the maximum available atmospheric pressure is 14.7 psi (sea level), suction pits placed below the p u m p should be

Figure 4-99. Duplex slush (mud) pump. (Courtesy National Oilwell.)

628

Drilling and Well Completions

Figure 4-100. Triplex slush (mud) pump. (Courtesy National Oilwell.)

Figure 4-101. Power end of mud pump. (Courtesy LTV Energy Products Company.)

629

Mud Pumps

eliminated. Instead, suction tanks placed level with or higher than the p u m p should be used to ensure a positive suction head. Figure 4-103 shows an ideal suction a r r a n g e m e n t with the least a m o u n t of friction a n d low inertia. A poorly designed suction entrance to the p u m p can produce friction equivalent to 30 ft of pipe. Factors c o n t r i b u t i n g to excessive suction pipe friction are an intake c o n n e c t i o n with sharp ends, a suction strainer, suction pipe with a small diameter, long runs of suction pipe, a n d n u m e r o u s fittings along the

ValveCapStuds ValveCap "----ValveCapPacking ,~N ~~-- ValvePot

ValveSpring~

l

~

Valve ~

(

~

~

ValveDisc ~%J~~ N , ~

~

GlandNut ~ ~ a t ~

i

~i'!~

~x.x'~'NN.~'~x'x~_~~t ~" ~

--

]I

~'~-~'~.,'=~_z_z~Washerl Liner-. ~ _ _ ~ i n e r

~.

~ ~

it II I ~ H e a d

Ill

Collarlt ~ - - - - ~ ) ~

G,a'n,

~

LLinerSet Screw

. Grease~ X-LanternRingFluidC ~ i ~ r C ~ a e~,,-/, ~ r - ~ ~nnect~°n "~;;TJK--~ } 1LTelI-TaleHole 1 x_ HeadStud .~ . . . . . . ~ t ~--LanternRing L . Packing ' LinerPackingRings Head H~a Figure 4-102. Cross-section of fluid end of mud pump. (Courtesy International Association of Drilling Contractors.)

SHORT AND DIRECT WITH NO TURNS

w :~ O h-

1~~.~~

1

SAMESIZEAS PUMPSUCTION2

'~' oo ID

ROUNDED p/INLET

,!,.

Figure 4-103. Installation of mud pump suction piping. (Courtesy International Association of Drilling Contractors.)

630

Drilling a n d Well C o m p l e t i o n s

suction pipe. Minimizing the effect of inertia requires a reduction of the suction velocity a n d m u d weight. It is generally practical to use a short suction pipe with a large diameter. W h e n a desirable suction c o n d i t i o n c a n n o t be attained, a charging p u m p becomes necessary. This is a c o m m o n solution used on many m o d e r n rigs.

Cooling Mud Mud t e m p e r a t u r e s of 150 ° can present critical suction problems. U n d e r low pressure or vacuum existing in the cylinder on the suction stroke, the m u d can boil, hence decreasing the suction effectiveness. Furthermore, hot m u d accelerates the d e t e r i o r a t i o n of r u b b e r parts, particularly when oil is present. Large m u d tanks with cooling surfaces usually solve the problem.

Gas and Air Separation Entrained gas a n d air e x p a n d s u n d e r the r e d u c e d pressure of the suction stroke, lowering the suction efficiency. Gas in water-base m u d may also deteriorate the natural r u b b e r parts used. Gases are usually s e p a r a t e d with baffles or by changing m u d composition.

Settling Pits T h e n o r m a l l y g o o d l u b r i c a t i n g q u a l i t i e s of m u d can be lost if cuttings, particularly fine sand, are not effectively s e p a r a t e d from the mud. A d e q u a t e settling pits a n d shale shakers usually e l i m i n a t e this trouble. D e s a n d e r s are used occasionally.

Discharge Manifold A poorly d e s i g n e d discharge manifold can cause shock waves a n d excessive pressure peaks. This manifold should be as short a n d direct as possible, avoiding any s h a r p s turns. T h e c o n v e n t i o n a l small a t m o s p h e r i c air c h a m b e r , o f t e n f u r n i s h e d with p u m p s , supplies only a m o d e r a t e c u s h i o n i n g effect. For best results, this air c h a m b e r should be s u p p l e m e n t e d by a large a t m o s p h e r i c air c h a m b e r or by a p r e c h a r g e d pulsation d a m p e n e r .

Pump Operation Priming A few strokes of the piston in a dry liner may r u i n the liner. W h e n the p u m p does not fill by gravity or when the cylinders have been e m p t i e d by standing too long or by replacement of the piston a n d liner, it is essential to p r i m e the p u m p t h r o u g h the suction valve cap openings.

Cleaning the Suction Manifold Suction lines are often partly filled by settled sand a n d by debris from the pits, causing the p u m p to h a m m e r at abnormally low speeds. Frequent inspection a n d cleaning of the suction manifold is required. The suction strainer can also be a liability if it is not cleaned frequently.

Mud Pumps

631

Cleaning the Dlscharge Strainer The discharge strainer often becomes clogged with pieces of piston and valve rubber. This may increase the p u m p pressure that is not shown by the pressure gauge b e y o n d the strainer. T h e strainer should be inspected and cleaned frequently to prevent a pressure buildup.

Lost Circulation Materials Usually special solids, such as nut shells, limestone, expanded perlite, etc., are added to the drilling muds to fill or clog rock fractures in the open hole of a well. Most of these lost circulation materials can shorten the life of p u m p parts. They are especially hard on valves and seats when they accumulate on the seats or between the valve body and the valve disc.

Parts Storage P u m p parts for high-pressure service are made o f precisely manufactured materials and should be treated accordingly. In storage at the rig, metal parts should be protected from rusting and physical damage, and rubber parts should be protected from distortion and from exposure to heat, light, and oil. In general, parts should remain in their original packages where they are usually protected with rust-inhibiting coatings and wrappings and are properly supported to avoid damage. Careless stacking of pistons may distort or cut the sealing lips and result in early failures. Hanging lip-type or O-ring packings on a hook or throwing them carelessly into a bin may ruin them. Metal parts temporarily removed from pumps should be thoroughly cleaned, greased, and stored like new parts.

Pump Performance Charts The charts showing the performance of duplex pumps are shown in Table 4-38 [17]. The charts showing the performance of triplex pumps are shown in Table 4-39 [17]. A chart listing the p u m p output required for a given annular velocity is shown in Table 4-40 [18]. A chart listing the power input horsepower required for a given p u m p working pressure is shown in Table 4-41 [19].

Mud Pump Hydraulics The required p u m p output can be approximated as follows [20-22]: Minimum Q (gal/min): Qmi. = (30 to 50) D h

(4-36)

or 0 2 -- 0 2

Qmi. = 481

h p ~D h

(4-34)

where D h = hole diameter in in. Dp = pipe diameter in in. = mud specific weight in lb/gal

(text continued on page 644)

Table 4-38 Mud Pump Performance--Duplex Pumps [17] Pump Discharge Pressure (PSI) (Shaded Area); Pump Discharge Vo|ume (GaiJStroke) (Based on 100% Volumetric Efficieny)

C-

O

~A~FACT~;

CO~T!~E~TAL il4P+

..........~'~7..................

SR~

L~{~

£~SC0 ~ZE

~klN~

41/4

$LUSH PUM~

(OUPLEX)

4~1i~

. . . . . . . . <

{

•

~

I ........................................................................................................

;°t~:;;~................

"

3I)

~

&4

3<~

:

4,2

:'-T~ 51

gl

7

:

"~--

?I

lt)O

:~~

:

-

..........

c:

43

" ~ g T ; .................; E -

93

7: .............W ~' 7 - - ~

°---

52

i

5~

~I

7,6

~

105

0.~


94

11't

~lI+8

d~

Table 4-38 (continued) MANUFACTURER: CONTIMENTAL EMSCO (OILIPUD~ MOOE,L

M~. iH.~.

!

C

LINERSLZE(IN)

~ SIZE

4-112

a,-S/4

5

5-1/4

5-1J2

5-31=.

6

~-';/4

8-1/2

6"314

T

7-I./4

326 6.5

334 69

7-1/2

0-125

125

85

I0"

1-3/4"

~40 2.5

741 29

~ 3,2

604 3.5

5441 3.9

490 43

456 4.7

419 5.1

386 5.~

337 6,0

D-175

175

78

12"

I-7/8'

1130 3.0

IOQO 34

~ 3.3

607 4.2

}31 46

61~ 51

6~G 56

555 61

514 6.8

475 71

D'225

257

~

12"

1-7/8"

1551 3.0

1379 34

1234 3.8

1111 4.2

1W7 4.0

918 51

~ 56

~ 6I

708 6.8

Ik54 71

60~ 7.7

516 6.3

'~.~00

14k30

9200

11 ll~

~OllO

~

MHEi

815

754

~

~

,~12

3.9

4.4

4.9

54

5.9

6.5

7 ~,

7.7

B3

69

96

103

tin1 3.9

17/7 44

1000 4.9

1455 54

43;3 5.9

1204 6.5

1104 71

1018 77

939 83

871 8.9

ILIG 96

P55 10 3

2-1/2'"

2720 4.2

2350 4.9

21|0 5.3

t902 59

1716 6.5

156(i 7~1

1435 78

1317 8.5

t225 92

1122 160

1035 109

970 11 .5

2915 42

2500 48

23t7 53

2090 59

1894 55

1727 71

1577 76

1449 85

1336 9.2

1235 100

I146 108

~067 11.6

2727 5.3

2463 64

2236 7.3

2044 7T

11175 34

1726 91

lr~3 98

14~ 106

1374 tl 4

t895 10.9

1758 11.9

1629 12.7

7~

O-3OO

i

M~ ST~KE $.P.MLE~H

~4"'

2

"'

8

[ 8-1/4 ~° @

~875

429

,~"

14 ~

DA.5~)

500

65

16""

0-550 08+550

635

75

16"

2-t/2"'

DA-7~) D9-7'0¢

B~

75

15"

2 3/4"

DA-850

850

00

16'"

3'"

2954 70

2680 7,7

2440 8.~)

2240 92

2055 10 I

0~85Q

992

?0

16'"

3"

29~ 7.0

2680 7.7

2440 S.5

~40

2~¢'.5

92

101

10.3

11.8

1&29 12.7

34m 70

3~53 77

2371 9.~,

2~5 92

2416 101

~ 109

2~4 ?l.e

1917 127

3490 7.0

3153 77

2M1 95

~ 9.2

2410 16 1

2229 706

~ 11.8

tg17 12 7

4474 73

405~ 91

37~ 88

3392 97

3123 105

~ 11.4

~9 12~3

73

4960 8.1

4530 9.8

4146 97

~17 105

3520 11.4

3262 12.3

2

7-3/4

1515 136

7411~ 14,6

1329 156

1782 138

1666 14.6

1562 T5 6

I

[

DC-IOCO 08-1000

1757

70

18"

3"

D-1350 GC-~35C ~165~ 0C-1650

1575

70

18""

3-1/~'"

1925

?D

18"

3-1/2 I'

1995

17~

M A N U F A C T U R E R : G A R D N E R - D E N V E R ([XI PI.~X) I~,OOEL

MAX.

MAX.

I.I'I_p

S.PM.

L~NE'RSIZE IIN)

STROKE LENGTH

ROD SIZE

5

rla

591/4

-

5-3//;

5.1/2

U

6-1/4

mt

--

65

6-~/2

?

uau'

m

7-1/4

7o

+4

2

44

--

--

7.7

8+3

9.0

9 6

FXL

625

55

29

2-1/2

~ 60

---

J~ 74

!.Trl 89

---

1514 10.6

141;4 11 5

11111 :2.5

11,il 13.4

F:('O

122

T9

1,3

1-3/4

~ 3.2

---

i 39

r~ 4+7

---

4~ 5.5

60

6.5

6.9

Im 10.2

~ 11 0

--

FXO

320

65

19

2

'~alO 5.0

---

t1:11 6~2

~

150 7.4

---

110 9.8

751 9.5

FXZ

185

70

1Z

2

Mla 36

---

~1 46

-,,--

'~ 56

--

6.6

54~ 2.1

~4 7.7

4~ 0.3 ~ 11.3

GXF¢

1250

60

54]0

79

14

2435 4+3

---

lJ~'4 9.3

GXP

700

70

1G

3t060

GXQ GXR

350 10~)

70 60

'i6

--

,N~

~.9

--

5S

1470 5.O

---

ttU 6.0

166

---

570 12e

Z4m 12 7

136

~O.O

--

1633 64

---

1377 7.6

IZ'/1 3.2

1177 3.9

lure4 9.5

--

~040

--

15Tll 9.2

1,==0

t;JJ~'

m

I0~0

lO.8

--

--

-

-

~ --

13

--

--

1712 3.5

t~ 7.3

---

3.7

94

10.1

1o9

21114 ~1.1

~

llO~

9.4

~i~I~ 102

11 9

12.8

1712 8.5

1571 92

14~I 10.0

~ 108

---

I17t

12.8

13.7

~ 7.1

2~115 8.6

ne

m.

AXF

7¢0

70

~6

KXG

1000

60

19

3113. 7.8

2815 86

9.4

10.2

11.1

I~'.9

K,~

1500

60

18

~ 7.5

---

9.0

1C,.O

1Q.9

11.8

--

!=!71 ~2 3

71

3?13 7.B ~ 5.9

lmO

155

3~I11 9.3

77

--

--

&

to~

--

~

7"314

---

27113 10.9

19

GXN

7"1/2

m

~

--

m

6"3/4

~K

5~4

]

6

17T~ 137 12.3

~Tz

Table 4-38 {continued)

0

0

~i~

oo,~0

~

............ / i ° ~ T ~ ]

~

0,

~

..........

~,,~

7

TN

........

¢8

S

~9

85

1,~

78

t09

;~6

84

98

;fi~

82

10~ ....... 1

q~

Table 4-38 (continued)

O~ O0

Cr~

0

Table 4-39 Mud Pump Performance~Triplex Pumps [17] Pump Discharge Pressure (PSI) (Shaded Area); Pump Discharge Volume (Gal./Stroke) (Based on 100% Volumetric Efficiency) MANUFACTU BEn: EXAMPLE (TRIPLEX) MGDEL

MAX.

MAX

|.H.P.

G.P.M. LENGTH

STROKE

LI~ERSIZE.~IN) ~'

[

3,1

S'112

6

~i-1/2

7

37

~4

52

6G

MANOFA CTU RJ=R: A L F R £ D WIRTH ('TRIPLEX) MODEL

MAX I,H.P.

MAX. S,P.M.

TPKD'1/~"xg-114"/1(~O--1250"

I(~)

";60

STROKE LENGTH

TF~ 7" x 10"113~1--~625"

1300

150

10

TPK7" x ~2"'1160C~ 2D~I*

1EOQ

120

12

9-1/4

LINERSIZE(IN)

'

. ~'"

"'" ~~ .

. ~

I "-'" ~,,'~

4-=,4 ~.~

~ ,~

. "-:

!

~

I

2.6 ;

I ~-'" ' ~

""~

=~

~-~,4 ~o~.

2.8 I ~"

3.1 ' ~

34 501'0

, ~

s

,-,;4 ,D,7

~.,,~ -

~s,, -

_

,

3.7 4u64..

4.0 ~

~ .:397G "

"¢.7 .3MI~t'"

5.a 3428

"INTERMITTENT

~A

i £,8

!,~ t 3~1 34

:

1,7 ~ ~

3~3

3~

33

~,/

~

a~

i

~.~ i

Table 4-39 (continued)

.....

~6T'

......... :~......

}a "T~'$" T t

£ .......... ~-~ ........... 4

i ..... ......... ~ .....

o

...................... i................................... ~ ..........................................................................................................

..............................

...............................................:.........

~

A ~

............................................................ kS~O+~ ~

. . . .

¸ ~i ...............................................................................................................................................

~-~o

~5

/5:%t................. t~8 .... ~

i;~:~

: % ~ L ~ ~" (~,~o,*':~'~", ;

,,%~,:~ . . . . . . .

3!

34

~1

..........

-"

43

7 & ~!~%~

,~

4~

~ '

t

~

50

......1~~

&4

57

6 ~

!

~

Courtesy Hughes Christensen.

0..,

r~

642

Drilling and Well Completions Table 4-40 Pump Output vs. Annular Velocity [18]

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

.q~nulsr y d o ~ t ~ . ~ t / m J n HO]O Drill-piPe 8|Se, 11, ~l~e, | ~ .

I0

90

90

40

50

60

~0

80

90

IOO

I10

188

190

140

150

14 12

21 17

28 U

86 29

41 36

48 41

85 47

69 5|

69 68

75 64

88 70

90 76

9'/ $2

104 87

10 8

19 II

88 24

$8 82

48 40

57 47

$5p S5

71 68

88 71

9| ~g

10J 87

114 9|

184 lU

184 III

148 119 ISl 1~6

II t

$1 18

89 ~

43 86

54 45

64 BS

75 64

U ~|

88 88

10T 81

118 100

In IO

189 114J

150 197

9

S~&

I0

19

29

89

48

58

Q

78

8'/

M

10T

Ill

126

156

145

9~

S~

10

$1

81

41

52

$$

79

89

9|

108

lib

189

184

144

185

II

g2

88

44

55

415

77

88

98

IO0

189

181

149

159

1~84

s~

9~

14

~

41

54

E8

8~t

95

109

189

185

150

ll~J

I~

190

|04

9

19¼

19 15

97 91

56 56

75 $9

94 77

112 98

181 108

liO 184

169 189

187 155

~ 170

IS 189

248 101

tq tie

881 m

|0 17

41 84

61 51

81 ~

102 88

122 102

142 119

169 199

188 158

t08 170

ltt lit

144 884

964 2' ~

884 880

809

94 90

47 41

5'1 61

94 81

118 10t

149 I~

165 152

189 lat

210 188

188 904

260 884

988 244

807 266

881 885

~4 |05

94 91

49 52

79 65

98 85

129 1049

147 187

171 149

196 170

220 191

955 215

90 888

884 845

|18 279

848 897

,867 $18

25 n 20

51 44 40

75 99 50

I01 98 81

I~ I10 101

IS9 IS8 121

I~ 155 141

908 I~ 191

898 190 181

844 981 209

879 84J ~

804 8E6 949

880 28'/ t~t

955 809 288

880 881 802

25 28 21

52 45 49

~9 69 6|

105 98 94

181 115 106

157 I98 126

184 161 147

910 184 I~

888 987 189

262 880 tl0

~ 9U 981

815 975 ~

841 199 2'F8

867 $~t 995

894 845 515

4~ $

25 2S

50 49

74 W)

99 5)1

124 114

149 187

174 160

198 I98

899 206

248 22,8

275 251

~ 874

329 99"7

847 920

$72 548

5~

$2 80 27

88 59 59

95 89 23

199 118 II0

168 149 197

189 179 165

221 207 192

|59 2:87 ~0

184 J6~ 247

$15 ~95 274

847 825 3(~

878 |55 829

410 889 847

441 414 884

478 444 418

5~

89 96 84

75 72 67

118 108 101

151 145 185

189 179 169

~F7 915 J0~

9~ 951 ~99

809 287 ~'F0

840 528 808

978 959 887

419 994 871

484 480 405

491 469 4~8

529 509 472

557 589 506

S~

41 89 87

89 78 74

128 118 III

154 157 148

905 Ig4J 188

947 ~ ~ct

~ ~r4 ~r&

999 $15 898

$70 858 888

411 99$ 970

459 4~1 487

498 470 444

~4 509 481

579 J48 518

617 598 555

58 48

I05 10~ 98 87

159 IF~8 147 130

919 ~04 IH 17|

889 ~5 244 919

918 505 'k98 950

871 895~ 949 904J

94 4~ 891 84•

$~ 459 440 890

580 510 489 488

~ 561 5~8 4g$

889 $19 587 $~0

689 99| 4~95 858

741 714 684 4~4J

794 ~65 795 ~0

(19 97 95 99

Is t 184 180 118

987 901 194 178

879 988 959 897

844 88$ 824 ~96

418 409 889 885

48~ 469 454 415

Ul ~ 518 474

UO ~9 m ~

689 669 948 599

7N 799 •19 999

818 808 V78 ~II

895 870 84~ 770

964 927 ~ 888

1.0#8 1.004 979 888

84 V9 74

155~ 159 148

251 899 822

984 818 296

418 897 8419

501 477 448

585 559 517

~418 689 591

~59 715 885

885 ~95 789

919 874 918

1,00~ 988 88~

1.088 1,088 961

1,170 I*I19 1,0~9

1.958 1,192 1,108

117 II| 101

~ 9PA; 214

860 888 921

497 450 428

~88 559 5~5

700 4F75 642

817 788 749

988 9~I 859

1,050 1,015 95~

1,16"/ I , ~ 4 1,199 I~9 1,0~0 I,I~T

~,400 1,841 I~89

1,917 1,494 1,89~

1,894 1,579 1.499

1,7~0 I,~89 1,6041

9(~1 988 9~8

585 5~r 519

809 790 ~74

9,408 9.871 9.921

9,(575 L849 ~(Lq5 2,898 9.579 ~8~

8 . 9 1 1 9 * 4 7 8 8,745 8,188 9.428 9,889 8*095 8.$58 $.ell

4~

h 88

iN

1,05'0 1 , 8 8 8 1,905 1,054 X~Jl7 1,581 1.99 1,289 1.547

1,878 1,844 1,805

ILl40 M.t08 9.0~

4.013 9,999 9,869

Mud Pumps

643

Table 4-40 (continued) 1

2

18

19

20

21

22

23

24

2~

26

27

28

29

30

81

32

240

260

868

Jq8

J68

290

~, 680 n? 175

A a u u b ~ Vdoctt~. F t / m l n Hole DrUI-pII~ 8hu~ I ~ 8 h ~ I ~

4~

8~

~1~0

170

180

168

680

810

210

no

118 88

117 99

114 105

181 111

188 117

14| 122

IU 128

158 104

166 140

178 146

180 152

188 157

In IQ

JOe 189

158 117

183 184

172 142

181 168

191 168

200 166

210 174

819 182

229 1~

238 198

J80 2041

u'/ 214

247 J8~

1,77 2m

286

1`/1 145

181 154

198 124

t0S 178

814 181~

8~ 191

iU SO0

$46 20g

287 218

183 t27

878 288

~ 845

800 284

811 |88

801 2';8

155

165

174

184

194

203

MIS

228

238

042

259

$62

871

2~I

291

165

175

186

196

205

216

~

837

247

258

268

172

289

299

809 628

8K

8~

175

186

19~

283

219

230

241

252

268

278

n4

295

806

817

25

8~

217

281

248

868

~J

285

~

,16

266

840

855

887

881

694

408

800 247

818 288

1137 1~'8

886 ~4

874 309

898 885

412 140

481 856

449 871

468 886

487 402

508 417

624 468

846 448

862 4f~l

825 278

845 990

U5 80'I

888 824

406 841

428 868

447 874

467 $92

~7 409

508 426

528 448

548 440

569 477

589 454

E02 $11

878 828

402 848

425 1~6

449 *ST

471 40'I

498 4~'/

520 448

f~46 468

587 489

690 4109

614 529

868 550

881 570

685 590

709 611

892 1139

418 881

441 88 ~'

465 40~

490 424

614 444

589 487

51Ut 4~8

E,88 ~09

811 680

638 652

681 678

685 5M4

710 4112

784 488

404 868 8~

411 J'76 648

466 898 8841

488 420 ~

JOT 442 408

~82 464 4J8

668 484 448

683 508 488

~ 680 484

~ ~'52 J04

~9 674 624

885 598 644

710 518 644

786 441 884

761 6~1 I105

420 683

44~ 831 sis

472 418 8~8

499 807 483

526 88o 481

r~l 808 488

4177 688 483

804 183 804

820

858

882

8u

u41

047

708 ~zo 838

786 848 ~

'/81 838 210

787

m

m

m

421

888

471

~

~

482

831 86

u~

8~

~0

,is

~a

n41

~

048

884

817

~

188

`/18

744 808

478 ~

688 838 4~

m

808 884

688

m

688 491 872

834 831 ~4

726 680

7~ `/18

`/68 ~40 ~8

go `/83 `/14

8. `/99 `/~

m

.1+

688 `/~2

848 888 6~

1.83. 1.o4o ~8

1.1~ 1~6 1.o12

7.

II

12~

682 048

04* 8n 788

~

~1

us 211

680 0441

r~8

`/80

'm 788

~s ~5

8~1 m

us

m 8n

1.en

041

`/88 `/17

1.831

en

`/18 681

835

r=

rn

810

*44

4~ 6 5~

us n7 sos

668 688 en

`/48 ~68 en

`/*1 744 `/os

n2 `/80 `/41

868 8n ~8

804 688 818

818 ~@1 st*

837 840 n8

t.ou iv/9

m

1.o~ 1,018 880

1.11. 1.080 t.~

1.151 1,182 1 " 8 9 7 1.1846 1.68`/ t.o~4

1..8 1.175 1.111

4~ S

84`/ 818 `/86 688

He ~r 4121 `/88

818 *so `/eo

1.68* n~ 86~ 8~8

1.083 1.011 ~s

1.118 1.e'~ 1.8rr 810

1.188 t.tn 1.ors 868

tJts 1.1`/8 1.114 688

1~1 t.z~ 1.172 1.0~

1.s84 1~8 1.s~ t.m

l.r~ 1.s~ 1~1 ~.tN

1.800 1.~r8 t'8zo 1.170

1.808 1.4n 1"883 1,2t8

1..* 1.468 1.418 1.s~

1.80~ 1..1 l.ae t'8eo

1.10S 1.071 1,08T 948

1 . 1 ` / 1 1,140 1~105 1.188 1.10~ 1,183 1.687 1.083

1.809 1,~'/z 1.831 1.125

1 " 8 7 7 1,480 1.839 1.408 1.298 1.881 1.186 1.044

1,616 1.478 1.426 1.208

1.684 1.640 1,490 1.862

1.858 1.601 1.866 1.411

1,722 1.678 1.890 1.801

1.791 1.783 1.685 1.640

1"860 I'8G? 1.`/80 1"883

1.928 1.874 1.814 1.888

1.997 1.041 1,878 1.`/12

2,066 2,008 1,944 1.777

1,887 1,871 1.182

1.4~0 1.4104 1.587 1 . 8 1 1 1.4110 1,510 1.2645 1.800 1.404

1,~1 1.689 1,478

1.`/84 1.688 1.5~I

l,n8 1.748 1.836

1,921 1,828 1,700

2.006 L8~ LI`/2 L~56 1 . 9 0 7 1.98111 2,8341 11,146 1 . 7 7 8 I'847 1 , 9 2 1 1.996

2,883 2.126 2.N9

L4~I ~ 2,148

2.58 Z,884 2.21`/

1.287 1.808 1.718

1.984 1.914 1.820

8,18~ L0~/ 1.8~/

8.217 8.140 2.084

2.n4 8.468 2 " 8 6 2 ~.868 2.141 8.880

8.687 S.47`/ 2.855

2,~q4 2.590 ~.480

2.800 2.708 2.569

8,151 8.247 2.040 8.158 2 " 8 2 0 1.897

8.8~4 S.|68 8.104

8,501 8.878 8.211

4J~81 4"215 4,128

4,648 4,4`/9 4,684

4.811 4,`/42 4,648

8"888 4"008 4.900

i.861 6.268 4"180

8"8*8 4"798 4"474

8.154 4 " 4 2 1 4"881J 8,280 ? , n 4 8.04;0 4"4126 4,80T 41,860 7,114 6"8~I 4 " 1 9 0 8.447 4,705 4,688

4~ 5

;1

Used by permission

m

of the American

m

`/u 780

8,118 6.1~J ~418

Petroleum

~ ~n

r~l

587

m

I1 lSK

41~1~ 4121

874

801 883

83~ 274

11

411

681

Institute, Production

8+6

68s

2.917 2.815 ?.478

2,084 8.838 L783

m

Department.

1.oo*

`/~191 `/,`/80 8.0~ 7Ji~7 %840 %684 % 8 3 1 7,~ff9 ~.7:t7

644

Drilling and Well Completions

Approximate

Input

HP

Required

Table 4-41 for Duplex

Mud

Pump

Operation

[15] li

i

~t', ' 6 , "~,. . ............... 15. . . . . .

4

z

4

z 10 ..............

.......

~., ,~ • . . . . . 12., 1~1~ 11).1213.: .......17.,~ 13.(~ |.42 16.4 7.17 1),. 8.~'~ ,~ 1L ~ 12" 115.1 I~I 17. 21 17J 63.4 2O: 21.1)t ~ :

~: 32.

14 ~

1)~ z 10 .............. 1)

z 10 . . . . . . . . . . . . . .

1)

.................. z IO . . . . . . . . . . . . . .

7

s 10...." . . . . . . . . . .

4

1)]

II

7. .................. `o . o1 . 7 ~ 7, 9. 12 . . . . . . . . . . . . . . ,~ s................. ~ ~ ~ I I :~ ~ ,

•

, . 1 , .............. z 12 . . . . . . . . . . . . . . . 1) .12 ...............

~' I

, 1~::...:.:::::::::

-" 41

............... 2 . .z. 1 | .............. • 11). . . . . . . . . . . . . .

1)

14 . . . . . . . . . . . . . . 1)~z..................

rl ~

II

1) i1) ,

..............

2,

:,"

:,

476~

I~ 61

i

1) .,1) ............... 1)~ z 1~ . . . . . . . . . . . . . . .

~ 1)1

151)~z. . .11) . . .......................... . .

4~

7 ~ x 15 . . . . . . . . . . . . . . .

~1@ 74

123 14

|

11l

12 13

~, 1,,,~ 15 1, 1O1 11( 137 11)

14

II~ 14T 17

11

1)7~ 74 ' 1o 11 13 14

13 14~ 17

"

/ '~ ~ h~ 1311°~I~I~ IO;

91 111 14

Ill

;,

141) 17

11o1)1

1511)',

~

~ 8~

7. ~

10

I

. . . . . . .11) 11!

8~ 11

107~ ~

12

II( 13'

13.3 11t 1 4 : 1 7

lg;

172 ]

~ ,, 1)i 2 1),1)~ ~ 11 1,111~ I~1 Ig

15 z 16 . . . . . . . . . . . . . . . 7 z 115. . . . . . . . . . . . . . .

~

I{~

133 I0~ 13~ lf~

13~ 17( 2G

~

~

.1~1 . . . .I ~. . . .1~ . . . .162 . . 144 1~

~

I~168N

N

III

1)~. 11). . . . . . . . . . . . . . .

7 t . ,8...............

~,

~i

71

~ 86

~ 8~ 1~

z 20 . . . . . . . . . . . . . . . zgO ...............

• , ...............

73

131

If!

131 121 1~4 1631 162

12I 13I

[ I~: 142 178 21:

162 1~

101~ 13~ I ~ 14~ I ~ ,1411, ,~ ,,: ,~, ~. ~

~

"~ ............... z 2O. . . . . . . . . . . . . . .

7

II:

1)11 11~ 1011 1~

11

13( 14: 1~1 12~ 11)1

13

164

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3~4 271

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449

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I~1) 474 491 ~ 421 526 631 44~ 4161 °74

Note: For single action triplex pump, multiply table value by 0.75. Note: Values in the table are calculated for a pump efficiency of 0.85. Courtesy Intematona Association of Drilling Contractors.

(text continuedfrom page 631)

The required pump working pressure PWP (psi) can be calculated as PWP = AP s + APd + AP~ + APb where A P = pressure loss through surface equipment in psi APd = pressure loss through the inside of the drill string in psi

(4-35)

Mud Pumps

645

A P = pressure loss in annulus in psi AP b = pressure d r o p through bit nozzles in psi Table 4-42 shows the j e t velocity. Table 4-43 shows the diameters a n d areas o f various nozzle sizes. The required p u m p hydraulic horsepower (PHHP) can b e calculated as (4-37)

P H H P = HHPclrc + HHPbi t

where HHPc~rc = total H H P loss due to pressure losses in the circulating system HHPb~ ¢ = hydraulic horsepower required at the bit T h e general hydraulic horsepower is H H P - Q AP 1714 where

(4-38)

Q = flow rate in g a l / m i n AP = pressure difference in psi

T h e m i n i m u m bit H H P is shown in Figure 4-104. T h e m a x i m u m useful bit H H P is shown in Figure 4-105 a n d Figure 4-106 [18].

Useful Formulas T h e o r e t i c a l o u t p u t Q t ( g a l / m i n ) for a d o u b l e action d u p l e x p u m p is

Q ~ = 0.0136NS(De2 - - ~ )

where N = S = De = d =

(4-39)

strokes p e r minute stroke length in in. liner d i a m e t e r in m piston r o d d i a m e t e r in in.

T h e o r e t i c a l output Q t ( g a l / m i n ) for a single action triplex p u m p is Q t = 0.0102 NS D~

(4-40)

T h e volumetric efficiency Tlv for d u p l e x p u m p s or triplex p u m p s is

qv

Qa m

Qt

(4-41)

where Q a = actual volumetric flow rate in gal I n p u t engine power IHP (hp) required for a given p u m p theoretical output Q t a n d p u m p working pressure PWP is

(text continued on page 650)

646

Drilling and Well Completions Table 4-42

Jet Velocity [15]

Mud Pumps Table

4-42

(continued)

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167

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319

'[79

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326

185

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of Drilling

647

Drilling and Well Completions

648

Table 4-43 Area of Nozzles

[17]

O = Diameter. Area = .78S3H1434 O~ 0ira.

k-ee

1/32 L.~OO75T I116

gl~.

~ree

i2

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ON.

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0ira.

3.1416

6"7•8

37.122

11-3/4

10~.434

16-518

~t7.00

21-1/2

2-1/8

3.544~

7

38.485

11.7/8

110.753

16.3/4

220.35

21.5/0

~13.0'~ 367.26

2.114

3.9761

7-1/8

39.871

12

113.10

16.7/8

~

21-314

371.54

3/32

.O~l~l

I/8

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2-3•8

4.4301

7.1/4

41.282

12.1/8

115.47

17

226.98

21-7/8

375.83

5/32

.01917

' 2-1/2

4.9080

7.3/8

42.710

12.1/4

117.09

17-1/8

230.33

22

360.13

llnT/l i: 91ZE

3/16

.02751

2-518

5.4119

7-1/2

44.179

12-3/8

120.20

17.1/4

233.71

22.1/8

384.46

7

7/32

.03758

2-3/4

5.9396

7.5/8

45.(~4

12.1/2

122.72

17.3/8

237.10,

22-1/4

309.62

8

1/4

.04099

2-7/8

64918

7.314

47.173

12.5/8

125.19

17.1/2

240.531

22-3/8

393.20

9

9/32

.09213

3

7.0626

7-7/8

48.707

12-3/4

127.60

17-5/8

243.g8

22-112

307.61

10

5/16

.07570

:3-1/8

7.0999

8

50.266

12-7/8

130.19

17-3/4

247.45

22-5/8

402.04

11

11132

.09201

3.1/4

6.2958

8.1/8

51.649

13

132.73

17-7/8

2"o0.95

22-3/4

4U.49

.1104

12

3/8

13

13/32 - ; t t m

'"

3"3•8

8.9462

8-1/4

53.456

13.118

135.30

18

254,47

22-7/8

410.97

3-1/2

0.6212

8-3•8

,~.0~8

13-114

137.09

18.118

2~.92

23

415.46 ..41~L60

14

7/16

3-5/8

J0,.3206

8-1/2

56.745.

13-3/8

140..,50

18-1/4

281.50.

23-1/8

15

15/32 " .17'26

3-3•4

11.0447

8-5•8

56.426

13.112

143.14

18-318

265,1|

23-114

41~4,~i

16

1/2

,1963

3-7•8

11.7933

8-3•4

09.132

13-518

145.09

18-I12

~.09

23-3•8

41n.13

17

17/32

.2217

4

12.566

8.718

61.862

13-3/4

148.40

18-5/8

272.45

23-112

433.74

10

9/16

.2465

4-1/8

13.364

9

63.617

13-7/8

151.20

18-314

276.12

23-5/8

438.36

19/32

.2769

4.114

14.186

9.118

65.397

14

153.94

18-718

279.61

23.314

443+01

518

.3068

4-3/8

15.033

9.114

67.201

14-I/8

156.70

19

283.53

23-7•8

447.09

21/32

.3382

4.112

15.904

9.3/8

69.029

14-114

159.48

19-118

207.27

24

452.39

11/16

.3712

4.518

16.000

9-112

70,882

14-3/8

162.30

19-t14

291.04

24-118

457.11

23•32

.4057

4-3/4

17.721

9-518

72.760

14-112

165.13

19-3/8

294.83

24-1/4

461.09

3/4

.4418

4"7•8

18.665

9-3•4

74.662

14-5/8

167.9g

19-I/2

290.65

24-3/8

4M.64

25/32

.4794

5

19.635

9-7•8

76.589

14-314

170.87

19.5/8

302.49

24-112

471.44

13/16

.511~

5-1/8

20.629

70.540

14.718

173.70

19.3/4

306.35

24-5•8

4716.26

27/32 .~1

5-1/4

~l.648

10.1/8

09.516

15

176.71

19-7/8

310.24

24-3/4

481,11

7/8

J013

5-3/8

22.691

10.1/4

82.510

15-1/8

175.07

20

314.16

24-7/8

485.N

29/32; ,044~

5-1/2

:L~.T56

10-3/8

84.541

15-1/4

182.65

~11.10

25

400,JI7

15116~ .26=

5-5/8

Z4.1109

1o-I/2

N.,T~O

15-3/8

105.06

20-1/4

32~J0e

25-1/8

496,79

31/32 - . ~

5-3/4

26.667

10-5/8

88.6e4

15-I/2

126.60

20-3/8

326.05

25-1/4

500.74

5-7/8

27.109

10-3/4

09.763

15-5/8

191.75

20.1/2

330.n¢

25.3/0

~.71

25-112 ~ o . n

2O

22

24

26

28

1

.71i84

1.1/8

.{I~I0

10

120.1/8

21.274

10-7/8

~12,~16

15-3/4

104.~I

20.5/8

3S4.10

1-114 La'n 1-318 ~.4e4g

6-1/8

21.465

11

95.033

15"7/8

197.03

20-3/4

3418.16

6-1/4

~10.1HI0

11-1/8

07.205

16

201.106

20-7/8

342.25

1.112 t.7571

6-3/8

31,910

11.1/4

99.402

16-1/8

204.22

21

346.36

I 25-7/8

525.64

1-5/8

2.0739

6-I/2

33.183

11-3/8

101.623

16-I/4

207.39

21 1/8

350.50

|26

530.93

1-314 2.4053

6-518

34.472

11-112

103.859

16-3/8

210.60

21-114

354.66

1-7/8

6-3/4

35.785

11-518

106.139

16-1/2

213.82

21-3/8

358.84

2.7612

Codrtesy Hughes Christensen.

25-5/0

515.1'2

I 25-3/4 "~.72"--

Mud Pumps

700

~IL.

650 600

~",~L ~

5oo 450 400 . . . . . . . . 300

I/ /

50

J'//

,

~ .q~l

~("

,

J

/r

////

100

150

/J--

/

200

-/"

~'7~7

~

250

/'/;

~.~,

350

./1

/

,, ~

300

/

"

If I ~ /,'/ / ,,'/ / / . . .~,~ . / / Z.... / . . , ! / , "

~'/

200

[

/, ~

649

:

400

J ~

450

I s~ . . ExampBIT e l : E4ZE10:625" I BITWEIGHT 50,000(4700/iNCH)

500

550

600

650

700

750

BIT HYDRAULIC HORSEPOWER

Figure 4-104. Minimum bit HHP to prevent hydraulic flounder [20] (Courtesy

Smith International, Inc.)

120

If Pa2~/

100 MINIMUM HYDRAULICS O -r Ill Ill LL

,,i 1-

,,%

80

f

/

AREAOLF / : rC f

6o

<

(9 Z m .J

INCOMPLETE BIT CLEANING

40

E:

!

I

?

I

\J

...=t~..~-6 1

2

3

i

MAXIMUM HYDRAULICS

0 0

i

/

f f

Q5 J

20

/ - I

/

5

6

I

I

7

8

9

BIT HHP/SQ. IN NOTE: PLACE POINT WHERE CONTROL BIT RUN IS LOCATED; USING SHIP CURVE, FIT Q-LINE BELOW POINT; MOVE SHIP CURVE UPTO POINT. EFFECT OF A CHANGE IN HYDRAULICS CAN THEN BE TRACED. POINTS OF COMPLETE BIT CLEANING ARE ON THE "MAXIMUM HYDRAULICS" CURVE.

Figure 4-105. Required bit hydraulic horsepower [21]. (Courtesy Hant

Publications. All rights reserved.)

650

Drilling a n d Well Completions

1000

900 rr

,+

/

8OO

f

uJ

O

Q.,. UJ

700

,

-

600 O o

J

'-'r

rr a

500 400

300 ~'

200

~

~ '

100 .~....~. ~

~.-

- ~

_..... -----

"~

~

~P

""-

o

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

HOLE DIAMETER, INCHES

Figure 4-106. Bottomhole hydraulic horsepower chart [18]. (Used by permission of the American Petroleum Institute, Production Department.)

(text continued from page 645)

IHP -

PWP (Q~) 1714 rl,.,,

(4-42)

~m = mechanical efficiency of the p u m p Pressure loss correction for m u d weight change is

where

~2 A P 2 = AP 1 _'z'-71

(4-43)

where AP 1 = Pressure loss in system calculated using m u d weight ~l in psi AP2 = pressure loss in system calculated using m u d weight 72 in psi 71,72 = m u d weight in l b / g a l

DRILLING MUDS AND COMPLETION FLUIDS Drilling Mud Drilling muds are a special class of drilling fluid used to drill most deep wells. T h e term "mud" refers to the "thick" consistency of the fluid after the appropriate materials have b e e n added to the water-liquid or oil-liquid base.

Drilling Muds a n d C o m p l e t i o n Fluids

651

=unctions T h e functions o f drilling fluid muds are: a. To remove rock bit cuttings from the b o t t o m o f the hole a n d c a r r y t h e m to the surface. b. To overcome f o r m a t i o n fluid pressure. c. To s u p p o r t a n d protect the walls o f the hole. d. To avoid damage to the p r o d u c i n g formation. e. To cool a n d lubricate the drill string a n d the bit. f. To prevent drill pipe c o r r o s i o n fatigue. g. To allow the acquisition o f i n f o r m a t i o n about the f o r m a t i o n b e i n g d r i l l e d (e.g., electric logs, cuttings analysis).

Classification T h e classification o f drilling muds is b a s e d on their fluid phase, alkalinity, dispersion, a n d type o f chemicals used.

Freshwater Muds--Dispersed Systems. T h e p H value o f low-pH muds may range from 7.0 to 9.5. Low-pH muds include spud muds, bentonite-treated muds, natural muds, phosphate-treated muds, organic t h i n n e d muds (red muds, lignite muds, lignosulfate muds), a n d organic c o l l o i d - t r e a t e d muds. T h e p H value o f high p H muds, such as alkaline t a n n a t e - t r e a t e d mud, is above 9.5. Inhibited Muds--Dispersed Systems. These are water-base drilling muds that repress the h y d r a t i o n a n d dispersion o f clays. T h e r e are essentially four types of inhibited muds: lime muds (high pH), gypsum muds (low pH), seawater muds (unsaturated saltwater muds, low pH), a n d s a t u r a t e d saltwater muds (low pH). Low Solids Muds--Nondispersed Systems. T h e s e muds contain less than 3-6% solids by volume, weigh less than 9.5 l b / g a l , a n d may be fresh o r saltwater base. T h e typical low solids systems are flocculent, m i n i m u m solids muds, beneficiated clay muds, a n d low solids p o l y m e r muds. Most low solids drilling fluids are c o m p o s e d o f water with varying quantities o f b e n t o n i t e a n d a polymer. T h e difference a m o n g low solids systems lies in the varying actions o f different polymers. Emulsions. Emulsions are formed when one liquid is dispersed as small droplets in a n o t h e r l i q u i d with which the d i s p e r s e d l i q u i d is i m m i s c i b l e . M u t u a l l y immiscible fluids, such as water a n d oil, can be emulsified by stirring. T h e s u s p e n d i n g liquid is called the continuous phase, a n d the droplets are called the dispersed (or discontinuous) phase. T h e r e are two types o f emulsions used in drilling fluids: oil-in-water emulsions that have water as the continuous phase a n d oil as the d i s p e r s e d phase, a n d water-in-oil emulsions that have oil as the continuous phase a n d water as the dispersed phase (invert emulsions). Oil-Base Muds. Oil-base muds contain oil as the continuous phase a n d water as the dispersed phase. Oil-base muds contain less than 5% (by volume) water, while oil-base emulsion muds (invert emulsions) have m o r e than 5% water in mud. Oil-base muds are usually a mixture o f diesel fuel a n d asphalt; the filtrate is oil.

652

Drilling and Well C o m p l e t i o n s

Testing of Drilling Fluids P r o p e r control o f the p r o p e r t i e s o f drilling m u d is very i m p o r t a n t for their p r e p a r a t i o n and maintenance. Although oil-base muds are substantially different from water-base muds, several basic tests (such as specific weight, API funnel viscosity, API filtration, and retort analysis) are run in the same way. T h e test interpretations, however, are somewhat different. In addition, oil-base muds have several u n i q u e p r o p e r t i e s , such as t e m p e r a t u r e sensitivity, emulsion stability, aniline point, and oil c o a t i n g - w a t e r wettability that require o t h e r tests. Therefore, testing o f water and oil-base muds will be c o n s i d e r e d separately.

Water-Base Muds

Specific Weight of Mud. Often shortened to m u d weight, this may be expressed as p o u n d s p e r gallon (lb/gal), p o u n d s p e r cubic foot (lb/fts), specific gravity (Sm), or pressure g r a d i e n t (psi/ft) (see Table 4-44). Any instrument o f sufficient accuracy within +0.1 l b / g a l or +0.5 l b / f t 3 may be used. T h e m u d balance is the instrument most commonly used [23]. T h e weight o f a m u d cup attached to one e n d o f the b e a m is b a l a n c e d on the o t h e r e n d by a fixed counterweight and a r i d e r free to move along a g r a d u a t e d scale.

Viscosity. Mud viscosity is a m e a s u r e o f the m u d ' s resistance to flow. T h e p r i m a r y function o f p r o p e r viscosity is to enable the m u d to t r a n s p o r t cuttings to the surface. Viscosity must be so high enough that the weighting material will remain suspended, but low enough to p e r m i t sand and cuttings to settle out and e n t r a i n e d gas to escape at the surface. Also, excessive viscosity creates high p u m p p r e s s u r e a n d m a g n i f i e s the swabbing or s u r g i n g effect d u r i n g t r i p p i n g operations.

Gel Strength. This is a measure o f the interparticle forces and indicates the gelling that will occur when circulation is stopped. This p r o p e r t y prevents the cuttings from settling in the hole and sticking to the drill stem. High p u m p pressure is required to "break" circulation in a high gel mud. T h e following instruments are used to measure the viscosity a n d / o r gel strength o f drilling muds: Marsh F u n n e l T h e f u n n e l is d i m e n s i o n e d so that, by following s t a n d a r d procedures, the outflow time o f 1 qt (946 ml) o f freshwater at a t e m p e r a t u r e o f 70+5°F is 26+0.5 seconds [23]. A g r a d u a t e d cup or 1-qt bottle is used as a receiver.

Direct Indicating Viscometer. This is a rotational type instrument powered by an electric m o t o r or by a h a n d crank. Mud is contained in the annular space between two cylinders. T h e outer cylinder or rotor sleeve is driven at a constant r o t a t i o n a l velocity; its rotation in the m u d p r o d u c e s a t o r q u e on the i n n e r cylinder or bob. A torsion spring restrains the movement. A dial attached to the b o b indicates its displacement. I n s t r u m e n t constants have b e e n so adjusted that plastic viscosity, a p p a r e n t viscosity, and yield point are o b t a i n e d by using readings from rotor sleeve speeds o f 300 and 600 rpm. Plastic viscosity (PV) is centipoises equals the 600 r p m reading minus the 300 r p m reading. Yield point (YP) in p o u n d s p e r 100 ft 2 equals the 300-rpm reading minus plastic viscosity. Apparent viscosity in centipoises equals the 600-rpm reading, divided by two. T h e i n t e r p r e t a t i o n s o f PV and YP m e a s u r e m e n t s are p r e s e n t e d in Figure 4-107.

Drilling Muds a n d Completion Fluids

653

Table 4-44 Specific Weight Conversion 1

2

3

4

5 Gradient,

lb/gal

lb/ft3

g/cm3or specific gravity

psi/ft of depth

(kg/cm2) m of depth

6.5 7.0 7.5 8.0 8.3

48.6 52.4 56.1 59.8 62.3

0.78 0.84 0.90 0.96 1.00

0.388 0.864 0.890 0.416 0.433

0.078 0.084 0.090 0.096 0.100

8.5 9.0 9.5 10.0 10.5

68.6 67.3 71.1 74.8 78.5

1.02 1.08 1.14 1.20 1.26

0.442 0.468 0.494 0.519 0.545

0.102 0.108 0.114 0.120 0.126

11.0 11.5 12.0 12.5 13.0

82.3 86.0 89.8 93.5 97.2

1.32 1.38 1.44 1.50 1.56

0.571 0.597 0.623 0.649 0.675

0.132 0.138 0.144 0.150 0.156

13.5 14.0 14.5 15.0 15.5

101.0 104.7 108.5 112.2 115.9

1.62 1.68 1.74 1.80 1.86

0.701 0.727 0.753 0.779 0.805

0.162 0.168 0.174 0.180 0.186

16.0 16.5 17.0 17.5 18.0

119.7 123.4 127.2 130.9 134.6

1.92 1.98 2.04 2.10 2.16

0.831 0.857 0.883 0.909 0.935

0.192 0.198 0.204 0.210 0.216

18.5 19.0 19.5 20.0 20.5

138.4 142.1 145.9 149.6 153.3

2.22 2.28 2.34 2.40 2.46

0.961 0.987 1.013 1.039 1.065

0.222 0.228 0.234 0.240 0.246

21.0 21.5 22.0 22.5 23.0

157.1 160.8 164.6 168.3 172.1

2.52 2.58 2.64 2.70 2.76

1.091 1.117 1.143 1.169 1.195

0.252 0.258 0.264 0.270 0.276

23.5 24.0

175.8 179.5

2.82 2.88

1.221 1.247

0.282 0.288

Gel strength, in units of l b f / 1 0 0 ft 2, is obtained by n o t i n g the m a x i m u m dial deflection when the rotational viscometer is t u r n e d at a low rotor speed (usually 3 rpm) after the m u d has r e m a i n e d static for some period of time. If the m u d is allowed to remain static in the viscometer for a period of 10 s, the m a x i m u m dial deflection obtained when the viscometer is t u r n e d o n is reported as the initial gel on the API m u d report form. If the m u d is allowed to remain static for 10 min, the m a x i m u m dial deflection is reported as the lO-min gel.

654

Drilling and Well Completions

0600

0300

F

o

~'SLOPE=PLASTICV I S C O S l y /

.

~ •

<_. Z

r "d la.. ~J

" INTE

i

'°"'i

300 RPM SETTING

I

600

Figure 4-107. Typical flow curve of mud using a direct-indicating viscometer.

API Filtration. A filter press is used to d e t e r m i n e the wall b u i l d i n g characteristics of mud. The press consists of a cylindrical mud chamber made of materials resistant to strongly alkaline solutions. A filter paper is placed on the bottom of the chamber just above a suitable support. The filtration area is 7.1 (+0.1) in. 2. Below the support is a drain tube for discharging the filtrate into a graduate cylinder. The entire assembly is supported by a stand so that ~- 100-psi pressure can be applied to the mud sample in the chamber. At the end of the 30-min filtration time volume of filtrate is reported as API filtration in milliliters. To obtain correlative results, one thickness of the proper 9-cm filter paper, Whatman No. 50, S&S No. 5765, or the equivalent, must be used. Thickness of the filter cake is measured and reported in ~s° of an inch. Also, the cake is visually examined and its consistency reported using such notations as "hard," "soft," tough," "rubbery," or "firm." Sand Content. The sand content in mud is d e t e r m i n e d using a 200-mesh sieve screen 2-~ in. in diameter, a funnel to fit the screen, and a glass measuring tube. The m e a s u r i n g tube is marked for the volume of mud to be added to read directly the volume percent of sand on the bottom of the tube. Sand content of the mud is reported in percent by volume. Also reported is the point of sampling, e.g., flowline, shaker, suction, pit, etc. Also, solids other than sand may be retained on the screen (lost circulation material, for example) and the presence of such solids should be noted. Liquids and Solids Content. A mud retort is used to d e t e r m i n e the liquids and solids content of the drilling fluid. Mud is placed in a steel container and heated until the liquid c o m p o n e n t s have been vaporized. The vapors are passed through a c o n d e n s e r and collected in a graduated cylinder, and the volume of liquids (water and oil) is measured. Solids, both suspended and dissolved, are d e t e r m i n e d by volume as a difference between mud in container and distillate in graduated cylinder. Specific gravity of the mud solids S is calculated as S s = 100Sm --(V w +0.8Vo) v,

(4-44)

Drilling Muds and C o m p l e t i o n Fluids where v = v° = vs = Sm =

volume volume volume specific

percent percent percent gravity

655

water in % oil in % solids in % o f the m u d

(Oil is assumed to have a specific gravity o f 0.8.) For freshwater muds, a rough measure o f the relative amounts o f barite and clay in the solids can be m a d e by using Table 4-45. As b o t h s u s p e n d e d and dissolved solids are r e t a i n e d in t h e r e t o r t for m u d s c o n t a i n i n g substantial quantities o f salt, corrections are m a d e for the salt [23].

pH. Two m e t h o d s for m e a s u r i n g the p H o f drilling m u d have b e e n used: (1) a m o d i f i e d colorimetric m e t h o d using p a p e r test strips, and (2) the electrometric m e t h o d using a glass electrode. T h e p a p e r strip test may not b e reliable if the salt concentration o f the sample is too high. The electrometric m e t h o d is subject to e r r o r in solutions containing high concentrations o f s o d i u m ions, unless a special glass electrode is used, o r unless suitable c o r r e c t i o n factors are a p p l i e d if an ordinary electrode is used. In addition, a t e m p e r a t u r e correction is required for the electrometric m e t h o d o f m e a s u r i n g pH. The p a p e r strips used in the c o l o r i m e t r i c m e t h o d are i m p r e g n a t e d with such dyes that the color o f the test p a p e r is d e p e n d e n t u p o n the p H o f the m e d i u m in which the p a p e r is placed. A s t a n d a r d color chart is s u p p l i e d for c o m p a r i s o n with the test strip. Test papers are available in a wide range type, which permits estimating p H to 0.5 units, and in narrow range papers, with which the p H can be estimated to 0.2 units. The glass electrode p H meter consists o f a glass electrode system, an electronic amplifier, and a meter calibrated in p H units. T h e electrode system is c o m p o s e d o f (1) the glass electrode, a thin walled bulb m a d e o f special glass within which is sealed a suitable electrolyte and an electrode; and (2) the reference electrode, which is a saturated calomel cell. Electrical c o n n e c t i o n with the m u d is established t h r o u g h a s a t u r a t e d solution o f potassium chloride c o n t a i n e d in a tube s u r r o u n d i n g the calomel cell. T h e electrical potential g e n e r a t e d in the glass e l e c t r o d e system by the h y d r o g e n ions in the drilling m u d is a m p l i f i e d and operates the calibrated p H meter.

Table 4-45 Relative A m o u n t s of Barite and Clay in Solids Specific Gravity of Solids 2.6 2.8 3.0 3.2 3.4 3.6 3.8 4.0 4.3

Barite, Percent by Weight

Clay, Percent by Weight

0 18 34 48 60 71 81 89 100

1O0 82 66 52 40 29 19 11 0

656

Drilling and Well Completions

Resistivity. Control of the resistivity of the m u d and m u d filtrate while drilling may be desirable to permit better evaluation of formation characteristics from electric logs. The d e t e r m i n a t i o n of resistivity is essentially the m e a s u r e m e n t of the resistance to electrical current flow through a k n o w n sample configuration. Measured resistance is converted to resistivity by use of a cell constant. The cell constant is fixed by the configuration of the sample in the cell and is determined by calibration with standard solutions of k n o w n resistivity. The resistivity is expressed in ohm-meters. Chemical Analysis. S t a n d a r d c h e m i c a l analyses have b e e n d e v e l o p e d for d e t e r m i n i n g the c o n c e n t r a t i o n of various ions present in the m u d [23]. Test for c o n c e n t r a t i o n of chloride, hydroxide and calcium ions are required to fill out the API drilling m u d report. The tests are based on filtration, i.e., reaction of a k n o w n volume of m u d filtrate sample with a standard solution of k n o w n volume and concentration. The e n d of chemical reaction is usually indicated by the change of color. The c o n c e n t r a t i o n of the ion b e i n g tested then can be d e t e r m i n e d from a knowledge of the chemical reaction taking place [7]. Chloride. The chloride c o n c e n t r a t i o n is d e t e r m i n e d by titration with silver nitrate solution. This causes the chloride to be removed from the solution as AgC1, a white precipitate. The e n d p o i n t of the titration is detected using a potassium chromate indicator. The excess Ag + present after all C1- has b e e n removed from solution reacts with the chromate to form Ag2CrO 4, an orangered precipitate. The m u d c o n t a m i n a t i o n with chlorides results from salt intrusion. Salt can enter and contaminate the m u d system when salt formations are drilled and when saline formation water enters the wellbore.

Alkalinity and Lime Content. Alkalinity is the ability of a solution or mixture to react with an acid. The phenolphthalein alkalinity refers to the amount of acid required to reduce the pH to 8.3, the p h e n o l p h t h a l e i n endpoint. The phenolphthalein alkalinity of the mud and mud filtrate is called the P m and Pf, respectively. The Pf test includes the effect of only dissolved bases and salts while the P m test includes the effect of both dissolved and suspended bases and salts. The methyl orange alkalinity refers to the a m o u n t of acid required to reduce the pH to 4.3, the methyl orange endpoint. The methyl orange alkalinity of the m u d and m u d filtrate is called the Mm and Mr, respectively. The API diagnostic tests include the determination of Pm' Pf' and Mf All values are reported in cubic centimeters of 0.02 N (normality = 0.02) sulfuric acid per cubic centimeter of sample. The Pf and Mf tests are designed to establish t h e concentration of hydroxyl, bicarbonate, and carbonate ions in the aqueous phase of the mud. At a pH of 8.3, the conversion of hydroxides to water and carbonates to bicarbonates is essentially complete. The bicarbonates originally present in solution do not enter the reactions. As the pH is further reduced to 4.3, the acid then reacts with the bicarbonate ions to form carbon dioxide and water. The Pf and Pm test results indicate the reserve alkalinity of the suspended solids. As the [OH-] in solution is reduced, the lime and limestone suspended in the m u d will go into solution and tend to stabilize the pH. This reserve alkalinity generally is expressed as an equivalent lime concentration, in l b / b b l of mud. Total Hardness. A c o m b i n e d c o n c e n t r a t i o n of calcium and m a g n e s i u m in the m u d water phase is d e f i n e d as total hardness. These c o n t a m i n a n t s are often present in the water available for use in the drilling fluid. In addition, calcium

Drilling Muds and C o m p l e t i o n Fluids

657

can enter the m u d when anhydrite (CaSe4) or gypsum ( C a S e 4° 2 H z e ) formations are drilled. C e m e n t also contains calcium and can contaminate the mud. T h e total hardness is d e t e r m i n e d by titration with a s t a n d a r d (0.02 N) Versenate (EDTA) solution. T h e s t a n d a r d Versenate solution contains S o d i u m Versenate, an organic c o m p o u n d capable o f f o r m i n g a chelate with Ca 2÷ and Mg ~÷. T h e hardness test sometimes is p e r f o r m e d on the m u d as well as the m u d filtrate. T h e m u d hardness indicates the a m o u n t o f calcium s u s p e n d e d in the m u d as well as the calcium in solution. This test usually is m a d e on gypsumtreated muds to indicate the a m o u n t o f excess C a S e 4 present in suspension. To p e r f o r m the hardness test on mud, a small sample o f m u d is first diluted to 50 times its original volume with distilled water so that any undissolved calcium or magnesium compounds can go into solution. T h e mixture then is filtered through h a r d e n e d filter p a p e r to obtain a clear filtrate. T h e total hardness o f this filtrate then is o b t a i n e d using the same p r o c e d u r e used for the filtrate from the lowt e m p e r a t u r e low-pressure AP! filter press apparatus.

Methylene Blue, Frequently, it is desirable to know the cation exchange capacity o f the d r i l l i n g f l u i d . To s o m e extent, this v a l u e can b e c o r r e l a t e d to the b e n t o n i t e content o f the mud. T h e test is only qualitative because organic material and some o t h e r clays present in the m u d also will absorb methylene blue. T h e m u d sample usually is treated with hydrogen peroxide to oxidize most o f the organic material. T h e cation exchange capacity is reported in milliequivalent weights (meq) of methylene blue p e r 100 ml o f mud. T h e m e t h y l e n e b l u e solution u s e d for t i t r a t i o n is usually 0.01 N, so that the cation exchange capacity is numerically equal to the cubic centimeters o f methylene blue solution p e r cubic centimeter o f sample required to reach an endpoint. If o t h e r adsorptive materials are not present in significant quantities, the m o n t m o r i l l o n i t e content o f the m u d in p o u n d s p e r b a r r e l is five times the cation exchange capacity. T h e m e t h y l e n e blue test can also be u s e d to d e t e r m i n e cation e x c h a n g e capacity o f clays and shales. In the test a weighed a m o u n t o f clay is d i s p e r s e d into water by a high-speed stirrer. T i t r a t i o n is c a r r i e d out as for drilling muds, except that hydrogen p e r o x i d e is not added. T h e cation exchange capacity o f clays is expressed as milliequivalents o f methylene blue p e r 100 g o f clay.

Oil-Base Muds [23-25] Specific Weight. Mud weight o f oil muds is m e a s u r e d with a m u d balance. T h e result o b t a i n e d has the same significance as in water-base mud.

Viscosity. T h e measurement procedure for API funnel viscosity is the same as for water-base muds. Since temperature affects the viscosity, API procedure recommends that the mud temperature should always be recorded along with the viscosity.

Plastic Viscosity and Yield Point. Plastic viscosity and yield point measurements are o b t a i n e d from a direct indicating viscometer. Due to the t e m p e r a t u r e effect on the flow p r o p e r t i e s o f oil-base mud, the testing p r o c e d u r e is modified. T h e m u d sample in the container is placed into a cup heater [23]. T h e heated viscometer cup provides flow p r o p e r t y data u n d e r a t m o s p h e r i c pressure and bottomhole temperature. Gel Strength. T h e gel s t r e n g t h o f oil-base muds is m e a s u r e d with a direct indicating viscometer exactly like that o f water-base muds.

658

Drilling a n d Well Completions

Filtration. The API filtration test for oil-base muds usually gives an all-oil filtrate. The test may not indicate downhole filtration, especially in viscous oils. The alternative high-temperature-high-pressure ( H T - H P ) filtration test will generally indicate a p e n d i n g mud problem by amount of fluid loss or water in the filtrate. The instruments for the H T - H P filtration test consist essentially of a controlled pressure source, a cell designed to withstand a working pressure of at least 1000 psi, a system for heating the cell, a n d a suitable frame to hold the cell a n d the h e a t i n g system. For f i l t r a t i o n tests at t e m p e r a t u r e s above 200°F, a pressurized collection cell is attached to the delivery tube. The filter cell is equipped with a t h e r m o m e t e r well, oil-resistant gaskets, a n d a support for the filter paper (Whatman No. 50 or the equivalent). A valve on the filtrate delivery tube controls flow from the cell. A nonhazardous gas such as nitrogen or carbon dioxide should be used for the pressure source. The test is usually p e r f o r m e d at a t e m p e r a t u r e of 300°F a n d a pressure of 600 psi over a 30-min period. W h e n other temperatures, pressures, or times are used, their values should be r e p o r t e d together with test results. If the cake compressibility is desired, the test should be repeated with pressures of 200 psi on the filter cell a n d 100 psi back pressure on the collection cell. Electrical Stability of Emulsions. The electrical stability test indicates the stability of emulsions of water in oil. The emulsion tester consists of a reliable circuit using a source of variable AC current (or DC current in portable units) connected to strip electrodes. The voltage imposed across the electrodes can be increased until a predetermined amount of current flows through the mud emulsion-breakdown point. Relative stability is indicated as the voltage at the breakdown point. Sand Content. Sand content m e a s u r e m e n t is the same as for water-base muds except that diesel oil instead of water should be used for dilution. Liquids and S o l i d s Content. Oil, water, a n d solids volume percent is determined by retort analysis as in a water-base mud. More time is required to get a complete distillation of an oil mud than of a water mud. T h e n the corrected water phase volume, the volume percent of low gravity solids, and the oil-water ratio can be calculated; the chart in Figure 4-108 can be used for the calculations [24].

Example. Find the volume fraction of brine, the low gravity solids content, the adjusted m u d weight, a n d the oil-to-water ratio from the test data below (use Figure 4-107). Mud weight (specific weight) = 15.7 l b / g a l Volume % water (retort) = 20% Volume % oil (retort) = 45% Strong silver nitrate = 4.3 ml (1 ml equivalent to 0.01 g C1)

Step 1. To d e t e r m i n e the percent by weight of calcium or of sodium chloride in the internal phase, locate the intersection of the line drawn horizontally from the cm 3 of strong silver nitrate required to titrate 1 cm s of whole mud with the line projected vertically from the volume percent of fresh water by retort. Percent by weight b r i n e in internal phase: Strong silver nitrate = 4.3 ml Volume % water (retort) = 20% Read 25% by weight brine in internal phase

0

=

Figure 4-108. Liquids-solids analysis of oil mud. (Courtesy M-I Drilling Fluids.)

660

Drilling and Well C o m p l e t i o n s

Step 2. Knowing the weight percent of b r i n e and using the volume percent of freshwater by retort, the c o r r e c t e d volume fraction, which represents the true volume percent of b r i n e in the solution, can be d e t e r m i n e d by r u n n i n g a line from the volume percent of water horizontally across until it meets the b r i n e concentration, then d r o p p i n g vertically to find the true volume percent of brine in the original mud. This n u m b e r will always be greater than the volume percent of freshwater by retort. Volume fraction b r i n e in internal phase: F v w = 20% Weight % b r i n e = 25% Read 21.5% volume fraction b r i n e in internal phase

Step 3. To d e t e r m i n e the gravity solids in the drilling mud, it is necessary to subtract from the m u d weight all of the m u d c o m p o n e n t s except diesel oil and low gravity solids. To do so, subtract from the m e a s u r e d m u d weight the fraction c o n t r i b u t e d by brine and basic emulsifier (this step and Step 4). Knowing the volume fraction of b r i n e in the internal phase (from Step 2) and the weight percent of b r i n e (from Step 1), follow the a p p r o p r i a t e value for the volume of b r i n e horizontally to intersect the weight percent of brine. Extend that point vertically down to d e t e r m i n e the weight in l b / g a l and subtract that weight from the m u d weight to correct for the weight of the internal phase. Weight adjustment due to the internal phase: Volume fraction of b r i n e in internal phase = 21.5% Weight percent of b r i n e in internal phase = 25% Read 0.69 l b / g a l density adjustment

Step 4. This step corrects the m u d weight and the volume percent of susp e n d e d solids as a function of the hydrocarbons distilled off by the m u d still. Knowing the volume percent of oil from the m u d still, follow this value vertically until it meets the line r e p r e s e n t i n g the system being run. T h e n e x t e n d this point horizontally to the left to d e t e r m i n e the weight to subtract from the initial m u d weight. Weight adjustment due to distilled hydrocarbons: Volume % oil = 45% Read 0.20 l b / g a l specific weight adjustment T h e initial m u d weight less the sum o f the weight adjustments from Steps 3 and 4 is the c o r r e c t e d m u d weight r e p r e s e n t i n g the weight of the diesel oil, low gravity solids, and barite only. Calculation of adjusted m u d weight: Weight a d j u s t m e n t - i n t e r n a l phase = 0.69 l b / g a l Weight a d j u s t m e n t - e m u l s i f i e r solids = 0.20 l b / g a l Mud weight = 15.7 l b / g a l Adjusted m u d weight = 15.7 - 0.69 - 0.20 = 14.81 l b / g a l

Drilling Muds and C o m p l e t i o n Fluids

661

Step 5. A f t e r having found the adjusted m u d weight, p r o c e e d horizontally from that point to the right to d e t e r m i n e the volume percent o f solids o c c u p i e d by the basic emulsifier package. T h e volume percent o f s u s p e n d e d solids is 100% less the sum o f the volume-percent oil, the true volume-percent b r i n e (Step 2), and the volume-percent emulsifier solids. Calculation o f volume-percent s u s p e n d e d solids: Volume Volume Volume Volume

% emulsifier solids = 1.03% fraction o f b r i n e = 21.5% % oil = 45% % s u s p e n d e d solids = 100 - 21.5 - 45 - 1.03 = 32.47%

Find the adjusted m u d weight value, extend that point downward until it meets the volume-percent s u s p e n d e d solids line. P r o c e e d horizontally to f i n d the p p g o f low gravity solids. Calculation o f low gravity solids, l b / b b l Adjusted m u d specific weight = 14.81 l b / g a l Volume % s u s p e n d e d solids = 32.47% Read 90 l b / b b l low gravity solids

Step 6. To f i n d the oil-to-water ratio, divide the volume percent o f oil in the liquid phase by (Vo) by the volume percent o f water in the liquid phase (vw). Calculation o f o i l - w a t e r ratio:

vw: 100E, + 01 69 Oil-to-water ratio = - 31

Aging. T h e

aging test is used to determine how the bottomhole conditions affect oil-base m u d p r o p e r t i e s . Aging cells were d e v e l o p e d to aid in p r e d i c t i n g the p e r f o r m a n c e o f drilling m u d u n d e r static, high-temperature conditions. If the bottomhole t e m p e r a t u r e is greater than 212°F, the aging cells can be pressurized with nitrogen, c a r b o n dioxide, or air to a desired pressure to prevent boiling and vaporization o f the mud. A f t e r aging p e r i o d , t h r e e p r o p e r t i e s o f the aged m u d are d e t e r m i n e d before the m u d is agitated: shear strength, free oil, and solids settling. Shear strength indicates w h e t h e r the m u d gels in the borehole. Second, the sample should be o b s e r v e d to d e t e r m i n e if free oil is present. S e p a r a t i o n o f free oil is a measure o f emulsion instability in the borehole, and is expressed in ~ o f an inch. Settling o f m u d solids indicates f o r m a t i o n o f a hard or soft layer o f sediment in the borehole. A f t e r the u n a g i t a t e d sample has b e e n examined, the usual tests for d e t e r m i n i n g rheological and filtration p r o p e r t i e s are p e r f o r m e d .

662

Drilling and Well Completions

Alkalinity and Lime Content. The whole m u d alkalinity test procedure is a titration m e t h o d which measures the volume of standard acid required to react with the alkaline (basic) materials in an oil m u d sample. The alkalinity value is used to calculate the pounds per barrel unreacted "excess" lime in an oil mud. Excess alkaline materials, such as lime, help to stabilize the emulsion and also neutralize carbon dioxide or hydrogen sulfide acidic gases. To approximately 20 ml of a 1:1 mixture of toluene (xylene):isopropyl alcohol, add 1 ml of oil-base m u d and 75 to 100 ml of distilled water. Add 8 to 10 drops of phenolphthalein indicator solution and stir vigorously with a stirring rod (the use of a Hamilton Beach mixer is suggested). Titrate slowly with H2SO 4 (N/10) until red (or pink) color disappears permanently from the mixture. Report the alkalinity as the n u m b e r of ml of H2SO 4 (N/10) per ml of mud. Lime content may be calculated as Lime, ppb = (1.5)(H2SO 4, ml)

Calcium Chloride [25]. C a l c i u m chloride e s t i m a t i o n is b a s e d on c a l c i u m titration. To 20 ml of 1:1 mixture of toluene (xylene):isopropyl alcohol, add a 1-ml (or 0.1-ml, if calcium is high) sample of oil-base mud, while stirring. Dilute the mixture with 75 to 100 ml of distilled water. Add 2 ml of hardness buffer solution a n d 10 to 15 drops of hardness i n d i c a t o r solution. Titrate m i x t u r e with s t a n d a r d versenate s o l u t i o n until the color changes from winered to blue. If c o m m o n s t a n d a r d versenate s o l u t i o n (1 ml = 20 g calcium ions) is used, then CaC12, ppb = (0.4)(standard versenate, ml) If strong standard versenate solution (1 ml = 2 g calcium ions) is used, then CaC12, ppb = (4.0)(strong standard versenate, ml)

Sodium Chloride [25]. Sodium chloride estimation is based on sodium titration. To 20 ml of a 1:1 mixture of toluene (xylene):isopropyl alcohol, add a 1-ml sample of oil-base mud, stirring constantly and 75 to 100 ml of distilled water. Add 8-10 drops of p h e n o l p h t h a l e i n indicator solution and titrate the mixture with H2SO 4 (N/10) until the red (pink) color, if any, disappears. Add 1 ml of potassium chromate to the mixture and titrate with 0.282N AgNO 3 (silver nitrate, 1 ml = 0.001 g chloride ions) until the water p o r t i o n color changes from yellow to orange. T h e n NaC1, ppb = (0.58)(AgNO 3, ml) - (1.06)(CaC12, ppb) Some other procedures for CaC12 and NaC1 content d e t e r m i n a t i o n are used by m u d service companies. Although probably more accurate, all of them are based on calcium filtration for CaC12 detection and on chlorides filtration for NaC1 detection.

Total Salinity. T h e salinity control of oil-base m u d is very i m p o r t a n t for stabilizing water-sensitive shales and clays. D e p e n d i n g u p o n the ionic concentration of the shale waters and of the m u d water phase, an osmotic flow of pure water from the weaker salt c o n c e n t r a t i o n (in shale) to the stronger salt c o n c e n t r a t i o n (in mud) will occur. This may cause a dehydration of the shale and, consequently, affect its stabilization.

Drilling Muds and Completion Fluids

663

A standard procedure for estimating the salt content of oil-base muds consists of the following steps [26]: 1. Determination of calcium chloride concentration, lb/bbl. 2. Determination of sodium chloride concentration, lb/bbl. 3. D e t e r m i n a t i o n o f soluble sodium chloride. By entering the g r a p h in Figure 4-109 with the lb/bbl of calcium chloride at the correct volume percent of water (by retort) line, the maximum amount of soluble sodium chloride can be found. If the sodium chloride content determined in Step 2 is greater than the maximum soluble sodium chloride determined from Figure 4-108, only the soluble portion should be used for calculating the total soluble salts. 4. Determination of total mud salinity. The total pounds of soluble salts per barrel of mud are calculated as Total soluble salts (lb/bbl) = CaC12 (lb/bbl) - soluble NaC1 (lb/bbl) 5. Determination of water phase salinity. By entering the graph in Figure 4-110 with total soluble salts, lb/bbl of mud, at the correct volume percent of water line, the water phase salinity can be read from the left-hand scale.

Example. Find the total salinity of the oil-base mud using the test data below and Figures 4-108 and 4-109. Volume % water = 12% From Ca titration, the CaC12 concentration is 18 lb/bbl mud From C1 titration, the NaC1 concentration is 9.9 lb/bbl mud

Step 1. The maximum soluble NaC1 (from Figure 4-109) = 3 lb/bbl. (There is excess insoluble NaC1 = 6.9 lb/bbl.) Step 2. The total soluble salts in the mud = 18 + 3 = 21 lb/bbl. Step 3. The water phase salinity (from Figure 4-110) = 330,000 ppm.

Water Wetting Solids. The water wetting solids test (oil-base mud coating test) indicates the severity of water wetting solids in oil-base mud [24]. The items needed are 1. 2. 3. 4.

Hamilton Beach mixer Diesel oil Xylene-isopropyl alcohol mixture 16-oz. glass jar

Collect a 350-ml mud sample from the flowline and place the sample in the glass jar. Allow the sample to cool to room temperature before the test is conducted. Mix at 70 V with the mixer for 1 hr. Pour the mud out, add 100 ml diesel oil, and shake well. (Do not stir with mixer.) Pour the oil out, add 50 ml xylene-isopropyl alcohol (1:1) mixture, and shake well. Empty jar, turn upside down, and allow to dry. Observe the film on the wall of the jar and report the evaluation as Opaque film-severe problem, probably settling of barite and plugging of the drill string. Slight film, translucent-moderate problem, mud needs wetting agent immediately. Very light film, highly translucent-slight wetting problem, mud needs some treatment. No f i l m - n o water wetting problem.

664

Drilling a n d Well C o m p l e t i o n s

60

50 "-I

E

.Q

40

uJD nO _1 "1"

o

30

D

O

CO

20

10

)0 Figure 4-109. Solubility chart for calcium and sodium chloride brines [26]. (Courtesy Baroid Drilling Fluids, /nc.)

Drilling Fluids: Composition and Applications Water-Base Mud Systems Bentonite Mud T h e bentonite muds include most types of freshwater muds. Bentonite is a d d e d to water-base muds to increase viscosity and gel strength, a n d also to improve

Drilling Muds a n d C o m p l e t i o n Fluids 5

500

10

WATER, % by volume of mud

~_ 450

665

]

25 &'" ~

30

y l lV, G,"

400

I11ff,,1./3

O O

o 350

d

'°

E

>_- 300 t..z ....J < 250 09 Lu 09 < 200 -1n re t.u 150 t<

¢ 4.o 1.,~o~'" IYllY,©" . w

V"

Ng .oil og°f I1

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100

50

0

10

20

30 40 50 60 70 SOLUBLE SALTS, Ib/bbl of mud

Figure 4-110. Total water phase salinity of Drilling Fluids, Inc.)

oil mud [26].

80

90

100

(Courtesy Baroid

the filtration a n d filter cake p r o p e r t i e s o f water-base muds. T h e c o m p a r i s o n o f the yield of commercial clays a n d active clays is shown in Table 4-46. T h e yield o f clays is d e f i n e d as the n u m b e r of barrels of 15 cp m u d that can be o b t a i n e d from 1 ton o f d r y material. T h e A P I r e q u i r e m e n t s for c o m m e r c i a l d r i l l i n g bentonite are as follows [27]. a. Bentonite c o n c e n t r a t i o n in distilled water--22.5 l b / b b l . b. Sample p r e p a r a t i o n : 1. stir for 20 min. 2. Age overnight. 3. Stir for 5 min. 4. Test. c. A p p a r e n t viscosity (viscometer dial r e a d i n g at 600 rpm)--30 minimum. d. Yield point, l b / 1 0 0 ft2-3 x plastic viscosity, maximum. e. API filtrate, m l / 3 0 min--15, maximum. f. Yield, bbl m u d / t o n - - 9 1 , minimum. Classification of b e n t o n i t e fluid systems is shown in Table 4-47 [28].

666

Drilling and Well C o m p l e t i o n s Table 4-46 Yield of Drilling Clays [28]

Concentration Drilling Clay Highest quality Common Lowest quality Native

Mud Weight

Yield, bbl/ton

% Volume

% by Weight

Ib/bbl Mud

Ib/bbl

100 50 25 10

2.5 6.0 10.0 23.0

6 13 20 40

20 50 75 180

8.6 9.1 9.6 11.2

Courtesy InternationalDrillingFluids Table 4-47 Classification of Bentonite Fluid Systems [28] Solid-Solid

Inhibition

Interactions

Level

Dispersed

Non-inhibited

Dispersed

inhibited

Non-dispersed

Non-inhibited

Non-dispersed

Inhibited

Drilling Fluid Type 1. Fresh water clay based fluids. Sodium chloride less than 1%, calcium ions less than 120 ppm a. Phosphate low pH (pH to 8.5) b. Tannin--high pH (pH 8.5-11+) c. Lignite d. Chrome lignosulphonate (pH 8.5-10) 2. Saline (sodium chloride) fluids a. Sea-water fluids b. Salt fluids c. Saturated salt fluids 3. Calcium treated fluids a. Lime b. Gypsum 4. Low concentration lignosulphonate fluids Fresh water--low solids a. Extended bentonite systems b. Bentonite--polymer systems Salt--Polymer fluids

Courtesy InternationalDrillingFluids

Dispersed Noninhibited Systems. Drilling fluid systems typically used to drill the u p p e r hole sections are d e s c r i b e d as d i s p e r s e d n o n i n h i b i t e d systems. They would typically be formulated with freshwater and can often derive many of their p r o p e r t i e s from d i s p e r s e d drilled solids or bentonite. They would not n o r m a l l y be weighted to above 12 l b / g a l and the t e m p e r a t u r e limitation would be in the range of 176-194°F. T h e flow p r o p e r t i e s are controlled by a deflocculant, or thinner, and the fluid loss is controlled by the a d d i t i o n of bentonite and low viscosity CMC derivatives. Phosphate-Treated Muds T h e phosphates are effective only in small concentrations. Phosphate treated muds are subject to several limitations:

Drilling Muds and C o m p l e t i o n Fluids • • • •

667

Mud t e m p e r a t u r e should be lower than 130°F. Salt c o n t a m i n a t i o n should be lower than 5000 p p m chloride. Calcium c o n c e n t r a t i o n should be kept as low as possible. p H should be 8 to 9.5; in continuous use, the p H o f some phosphates may d e c r e a s e below t h e r e c o m m e n d e d limits so that p H m a i n t e n a n c e with caustic soda is required.

Lignite Muds Lignite muds are usually c o n s i d e r e d to be high-temperature-resistant since lignite is not a f f e c t e d by t e m p e r a t u r e s below 450°F. L i g n i t e c o n s t i t u t e s an inexpensive chemical for controlling a p p a r e n t viscosity, yield point, gel strength, and fluid loss o f a mud. Since lignite is refined humic acid (organic acid), caustic soda (sodium hydroxide) is usually necessary to adjust the p H o f the m u d to above 8; the t r e a t m e n t n o r m a l l y consists o f a d d i n g 1 p a r t o f N a O H to 4 to 8 parts of lignite. If precausticized lignite (alkali + lignite) is being used, there is no n e e d for the a d d i t i o n o f caustic soda. T h e main limitations on lignite muds are • hardness lower than 20 p p m p H o f 8.5 to 10 • m u d t e m p e r a t u r e below 450°F •

Quebracho-Treated Muds Q u e b r a c h o - t r e a t e d freshwater muds were used in d r i l l i n g at shallow depths. T h e n a m e o f "red" m u d comes from the d e e p red color i m p a r t e d to the m u d by q u e b r a c h o . Muds t r e a t e d with a mixture o f lignite a n d q u e b r a c h o , or a mixture o f alkaline organic p o l y p h o s p h a t e chemicals (alkaline-tannate treated muds), are also included in the quebracho treated muds. The quebracho thinners are very effective at low concentrations, and offer g o o d viscosity and filtration control. T h e p H o f "red" muds should be 8.5 to 10; m u d t e m p e r a t u r e should be lower than 230°F. Q u e b r a c h o muds are used to increase the resistance to flocculation caused by c o n t a m i n a t i n g salts, high p H (11 to 11.5). These muds can tolerate c h l o r i d e c o n t a m i n a t i o n s up to 10,000 ppm.

Lignosulfonate Muds L i g n o s u l f o n a t e f r e s h w a t e r m u d s c o n t a i n f e r r o c h r o m e l i g n o s u l f o n a t e for viscosity and gel strength control. These muds are resistant to most types o f drilling c o n t a m i n a t i o n due to the t h i n n i n g efficiency o f the lignosulfonate in the presence o f large amounts o f hardness and salt. Lignosulfonate muds can be used efficiently at a p H o f 9 to 10, and have a t e m p e r a t u r e limitation o f about 350°F, above which lignosulfonates show severe thermal degradation. The recommended range of rheological properties of freshwater-base muds is shown in Figure 4-111 [29].

Dispersed Inhibited Systems. Dispersed inhibitive fluids a t t e m p t to c o m b i n e the use o f dispersed clays and deflocculants to derive the fundamental properties o f viscosity and fluid loss with other features that will limit or inhibit the hydration o f the f o r m a t i o n and cuttings. It will be realized these functions are in opposition; therefore the ability o f these systems to p r o v i d e a high level o f shale inhibition is limited. However, they have achieved a high level o f success and in

Drilling and Well Completions

668

60

(J >I0 40

> ¢J

i

I-

.J o.

20

I

I

I

I

(

10

12

14

16

18

30

2o ,,J

¢

/

Z

Q *J Lu

/

10

/ /

m

>.

[

I

I

I

I

10

12

14

16

18

M U D D E N S I T Y LBS/GAL.

Figure 4-111. Suggested range of plastic viscosity and yield point for bentonite muds [29].

Drilling Muds and C o m p l e t i o n Fluids

669

many formations represent a significant advance over d i s p e r s e d non-inhibited types of fluids. I n h i b i t i o n is sought t h r o u g h t h r e e mechanisms: a d d i t i o n of calcium (lime, gypsum), a d d i t i o n of salt, and a d d i t i o n of polymer.

Lime Muds Lime muds are muds treated with caustic soda, an organic thinner, h y d r a t e d lime, and, for low filtrate loss, an organic colloid. This treatment results in muds having a p H of 11.8 or higher, with 3 to 20 p p m of calcium ions in the filtrate. Lime-treated muds exhibit low viscosity, low gels, g o o d suspension of weighting material, ease of control at m u d weights up to 20 l b / g a l , tolerance to relatively large concentrations of flocculating salts, and easily m a i n t a i n e d low filtration rates. O n e of the most i m p o r t a n t economic advantages of lime-treated m u d is its ability to c a r r y large concentrations of clay solids at lower viscosities than o t h e r types of mud. Except for a t e n d e n c y to solidify u n d e r conditions of high bottomhole temperatures, lime-treated muds are well suited for deep drilling and for m a i n t a i n i n g high weight muds. Pilot tests can be m a d e on the m u d to d e t e r m i n e if the tendency to solidify exists; if so, solidification can be inhibited by chemical treatment for p e r i o d s of time sufficient to allow n o r m a l drilling and testing activities. A lime-treated m u d that exhibits a t e n d e n c y to solidify should not be left in the casing-tubing annulus when the well is completed. Lime-treated muds are prepared from freshwater drilling muds. The conversion should be made inside the basing. The initial step in conversion of freshwater m u d to a lime mud involves dilution of the m u d with water to reduce the clay solids content to avoid excessive m u d viscosity (breakover). The r e c o m m e n d e d sequence of material addition is a. b. c. d. e. f.

Dilution water: 10-25% by volume Thinner: 2 l b / b b l Caustic soda: 2 - 3 l b / b b l Lime: 4 - 8 l b / b b l Thinner: 1 l b / b b l Filtration control agent: 1-3 l b / b b l

The maintenance of lime-treated muds consists of monitoring the calcium content, i.e., the p r o p e r lime solubility. Since the lime solubility is controlled by the amount of caustic soda present in the mud, the p r o p e r alkalinity determination is of great importance. The recommended value of Pf is 5 to 8, and it is maintained with caustic soda; the r e c o m m e n d e d value of Pm is 25 to 40, and it is maintained with excess lime. The amount of excess lime should be from 5 to 8 lb/bbl. The limitation of lime-treated m u d is solidification at bottomhole temperatures higher than 250°F. Low lime m u d was designed to minimize this tendency toward solidification and can be used at b o t t o m h o l e t e m p e r a t u r e s as high as 350°F. In low lime mud, the total c o n c e n t r a t i o n of caustic soda and of lime is reduced. The r e c o m m e n d e d Pf is from 1 to 3, a n d the r e c o m m e n d e d Pm is from 10 to 15; the excess lime should be from 2 to 4 l b / b b l .

Gypsum-Treated Muds Gypsum-treated muds have proved useful for drilling a n h y d r i d e and gypsum, especially where these f o r m a t i o n s are i n t e r b e d d e d with salt and shale. T h e t r e a t m e n t consists o f c o n d i t i o n i n g t h e b a s e m u d with p l a s t e r ( c o m m e r c i a l calcium sulfate) before the a n h y d r i d e or gypsum f o r m a t i o n is p e n e t r a t e d . By

670

Drilling and Well C o m p l e t i o n s

a d d i n g the plaster at a controlled rate, the high viscosities and gels associated with this type o f contaminant can be held within workable limits. After the clay in the base m u d has reacted with the calcium ions in the plaster, no f u r t h e r thickening will occur u p o n drilling gypsum or salt formations. Gypsum-treated m u d s e x h i b i t f l a t gels, a n d t h e s e f l a t gels d e p e n d in p a r t u p o n t h e clay c o n c e n t r a t i o n in the mud. F i l t r a t i o n control is o b t a i n e d by a d d i n g organic colloids; because the p H o f these muds is low, preservatives are a d d e d to prevent the f e r m e n t a t i o n o f starch. Gypsum-treated muds are m o r e resistant to contamination and more inhibitive (700 p p m o f calcium ions) than lime-treated muds, and also have a greater t e m p e r a t u r e stability (350°F). A freshwater m u d can be converted to a gypsum m u d according to the following procedure: a. Dilute with sufficient water to reduce API funnel viscosity to 35 s. b. A d d t h i n n e r (lignosulfonate) and caustic soda to avoid excessive viscosity b u i l d up (breakover). c. A d d gypsum at the m u d hopper. To control the stability o f gypsum treated muds, the following m u d p r o p e r t i e s should be maintained: a. T h e m u d p H should be 9.5 to 10.5; the alkalinity should be increased by a d d i n g lime r a t h e r than caustic soda. b. The calcium ion concentration in the mud filtrate should be 600 to 1,000 ppm. c. A d d i t i o n o f gypsum is necessary to maintain the amount o f excess calcium sulfate (CaSO4) b e t w e e n 2 a n d 6 l b / b b l ; the relevant tests on excess calcium sulfate are subject to m u d service on the rig.

Seawater Muds Seawater muds or brackish water muds are saltwater muds. Saltwater muds are d e f i n e d as those muds having salt (NaC1) concentrations above 10,000 ppm, or over 1%, salt; the salt c o n c e n t r a t i o n can vary from 10,000 to 315,000 p p m (saturation). Seawater muds are commonly used on offshore locations, which eliminate the necessity o f t r a n s p o r t i n g large quantities o f freshwater to the drilling location. T h e o t h e r advantage o f seawater muds is their inhibition to the h y d r a t i o n and dispersion o f clays, because o f the salt c o n c e n t r a t i o n in seawater. T h e typical c o m p o s i t i o n o f seawater is p r e s e n t e d in Table 4-48; most o f the hardness o f seawater is due to magnesium. Calcium ions in seawater muds can be controlled and removed by f o r m i n g insoluble precipitates accomplished by a d d i n g alkalis such as caustic soda, lime, or b a r i u m hydroxide. Soda ash or s o d i u m b i c a r b o n a t e is o f no value in controlling the total hardness o f sea water. Seawater muds are c o m p o s e d o f bentonite, t h i n n e r (lignosulfonate or lignosulfonate and lignite), and an organic filtration control agent. The typical formulation o f a seawater m u d is 3.5 l b / b b l o f alkali (2 l b / b b l caustic soda and 1.5 l b / b b l lime), 8 to 12 l b / b b l o f lignosulfonate, and 2 to 4 l b / b b l o f b e n t o n i t e t o maintain viscosity and filtration. A n o t h e r a p p r o a c h is to use b e n t o n i t e / t h i n n e r (lignosulfonate)/freshwater premix, and mix it with seawater that has been treated for hardness. This technique will be discussed in the saturated saltwater muds section. Chemical maintenance involves control o f solids concentration, pH, alkalinity, and filtration, and p H control. Figure 4-112 shows the best o p e r a t i n g range for

Drilling Muds a n d C o m p l e t i o n Fluids

671

Table 4-48 Seawater Composition Concentration

Component

ppm

epm

Sodium Potassium Magnesium Calcium Chloride Sulfate

10440 375 1270 410 18970 2720

454.0 9.6 104.6 20.4 534.0 57.8

5O

30

~ 20

0 8

9

10

11

12 13 14 15 Mud Weight, lb/gal

16

17

Figure 4-112. Approximate solids range in seawater muds [24].

18

(Courtesy M-I

Drilling Fluids.) solids in seawater muds [24]. T h e p H control is quite important, and p H should be m a i n t a i n e d between 9 a n d 10. If the p H increases above 10, the m a g n e s i u m will begin to precipitate. Caustic soda is used to control pH. Filtrate alkalinity Pf should be m a i n t a i n e d at approximately 1.5 with caustic soda. Mud alkalinity Pm should be about 3.0 to 3.5; it is controlled with lime. If P~ is too low, the gel strength increases; if Pm is tOO lOW, m u d a e r a t i o n occurs; if Pf is too high, m u d viscosity decreases. Filtration is controlled by a d d i t i o n o f bentonite. Saturated Saltwater Muds T h e l i q u i d p h a s e o f s a t u r a t e d s a l t w a t e r m u d s is s a t u r a t e d with s o d i u m chloride. Saturated saltwater muds are most frequently used as workover fluids o r for drilling salt formations. These muds prevent solution cavities in the salt formations, making it unnecessary to set casing above the salt beds. If the salt f o r m a t i o n is too close to the surface, a s a t u r a t e d saltwater m u d may be mixed in the surface system as the spud mud. If the salt b e d is deep, freshwater m u d is converted to a saturated salt water mud. Saturated saltwater muds can be weighted to m o r e than 19 l b / g a l . Saturated saltwater muds c o n d i t i o n e d with organic colloids to control filtration can be

672

Drilling a n d Well C o m p l e t i o n s

used to drill below the salt beds, although high resistivity o f the muds may result in unsatisfactory electric logs. Conventional s a t u r a t e d salt muds are c o m p o s e d o f attapulgite or "salt" clay a n d a starch, mixed with s a t u r a t e d b r i n e water. T h e available make-up water or freshwater m u d has to be s a t u r a t e d with salt ( s o d i u m chloride). Freshwater requires about 125 l b / b b l o f salt to reach saturation; it then weighs approximately 10 l b / g a l . Saltwater m u d m a d e up o f 20 l b / b b l attapulgite clay has a f u n n e l viscosity o f a b o u t 40 s / q t , a n d a plastic viscosity o f a b o u t 20 cp. P r e p a r a t i o n o f the saturated saltwater m u d from freshwater m u d requires the d u m p i n g o f a p p r o x i m a t e l y h a l f o f the o r i g i n a l mud, t h e n s a t u r a t i o n o f the r e m a i n i n g original m u d with salt a n d simultaneous extensive water dilution to avoid excessive viscosity buildup. Starch is used for filtration control in saturated saltwater muds at temperatures below 250°F. For higher temperatures (to 300°F), organic polymers must be used. Polymers a n d starches are not effective in the presence o f cement or calcium c o n c e n t r a t i o n at high pH. If starches are used for filtration control, the salt c o n c e n t r a t i o n must be kept above 260,000 p p m or the p H above 11.5 to prevent fermentation. Alkalinity o f the filtrate (Pf) should be kept at approximately 1 to control free calcium. A m o d i f i e d s a t u r a t e d saltwater m u d is p r e p a r e d with b e n t o n i t e clay by a special t e c h n i q u e . First, b e n t o n i t e is h y d r a t e d in freshwater, t h e n t r e a t e d with lignosulfonate a n d caustic soda. This p r e m i x is then mixed with saltwater (one-part p r e m i x to three-part saltwater). T h e mixture builds up a satisfactory viscosity a n d develops filtration control. T h i n n i n g o f the m u d is accomplished by saltwater dilutions; a d d i t i o n a l p r e m i x is r e q u i r e d for viscosity a n d water loss control.

Nondispersed Noninhibited Systems. In nondispersed systems, no reagents are added to specifically deflocculate the solids in the fluid, whether they are formation clays or purposely a d d e d bentonite. T h e main advantage o f these systems is to use the higher viscosities and, particularly, the higher yield point to plastic viscosity ratio. These altered flow properties provide better hole cleaning. They p e r m i t lower annular circulating rates and help prevent bore hole washouts. Also, the higher d e g r e e o f shear thinning provides for lower bit viscosities. This enables m o r e effective use o f hydraulic horsepower a n d faster p e n e t r a t i o n rates. In addition, shear thinning promotes more efficient o p e r a t i o n o f the solids removal equipment. Low Solids-Clear (Fresh) Water Muds It is a well-known fact in drilling practice that clear (fresh) water is the best d r i l l i n g f l u i d as far as p e n e t r a t i o n rate is c o n c e r n e d . T h e r e f o r e , w h e n e v e r possible, drilling o p e r a t o r s try to use m i n i m u m density a n d m i n i m u m solids drilling fluids to achieve the fastest drilling rate. Originally, the low solids-clear (fresh) water muds were used in hard formations, b u t now they are also a p p l i e d to o t h e r areas. Several types o f f l o c c u l e n t s can be a d d e d to clear water to p r o m o t e the settling o f drilled solids by flocculation. They are effective in low concentrations. T h e manufacturer's r e c o m m e n d a t i o n s usually indicate lbs o f flocculent p e r 100 ft o f hole drilled. T h e typical application is p r e p a r e d as follows: a. Mix the p o l y m e r (flocculent) in a chemical barrel holding freshwater that has b e e n treated for hardness with soda ash; the p r o p o r t i o n s are approximately 5 lb o f p o l y m e r p e r 100 gal o f water.

Drilling Muds a n d C o m p l e t i o n Fluids

673

b. Inject the solution at the top of the flowline o r below the shale shaker. T h e injection rate d e p e n d s u p o n the hole size a n d the p o l y m e r efficiency ( l b / 1 0 0 ft of hole). c. Let the m u d circulate t h r o u g h all pits (tanks) available to increase the settling time; do not agitate the mud. d. If additional flocculation is required, use lime o r calcium chloride. T h e water at suction should be as clean as possible. e. Slug the drill string p r i o r to t r i p p i n g with a high viscosity bentonite slurry (about 30 bbl) to remove excessive cuttings from the annulus. Extended Bentonite Systems To obtain a high viscosity at a much lower clay concentration, certain watersoluble vinyl polymers called clay extenders can be used. In a d d i t i o n to increasing the yield of s o d i u m m o n t m o r i l l o n i t e , clay extenders serve as flocculants for o t h e r clay solids. T h e flocculated solids are much easier to separate using solids control equipment. T h e vinyl polymers increase viscosity by a d s o r b i n g on the clay particles a n d linking t h e m together. T h e p e r f o r m a n c e of c o m m e r c i a l l y available polymers varies greatly as a result of d i f f e r e n c e s in m o l e c u l a r weight a n d d e g r e e of hydrolysis. However, it is not u n c o m m o n to double the yield of commercial clays such as W y o m i n g b e n t o n i t e using clay extenders in fresh water. F o r low solids m u d s with b e n t o n i t e e x t e n d e r s the A P I f i l t r a t i o n rate is approximately twice that which would be o b t a i n e d using a conventional clay/ water m u d having the same a p p a r e n t viscosity. However, g o o d filtration characteristics often are not required when d r i l l i n g hard, consolidated, low-permeability formations. In these formations the only concern is the effective viscosity in the annulus to improve the carrying capacity of the drilling fluid. T h e use of c o m m o n g r a d e s of commercial clay to increase viscosity can cause a large d e c r e a s e in the drilling rate. That is where b e n t o n i t e extenders are mostly applicable. In a d d i t i o n to its viscosifying p r o p e r t y bentonite extenders flocculate f o r m a t i o n solids. A typical formulation of e x t e n d e d b e n t o n i t e system is shown in Table 4-49 [28]. T h e b e n t o n i t e should be specially selected for this type of system as being an u n t r e a t e d high yield W y o m i n g bentonite. T h e f l u i d has p o o r tolerance to calcium a n d salt, so the makeup water should be of g o o d quality a n d p r e t r e a t e d with s o d i u m carbonate, if any hardness exists. To increase viscosity b e n t o n i t e e x t e n d e r is a d d e d t h r o u g h the h o p p e r at the rate of one p o u n d for every five sacks of bentonite. T h e e x t e n d e r is dissolved in water in the chemical barrel a n d a d d e d at a rate d e p e n d e n t on the drilling rate. Excessively high viscosities a n d gel strengths are n o r m a l l y the result of too high a solids content, which should be kept in the range 2 - 5 % by dilution. Dispersants should not be a d d e d

Table 4-49 Extended Bentonite Mud System [28] Fresh water Bentonite extender Bentonite Soda ash Caustic soda

1 barrel 0.05 Ib

11 Ibs 0.25-0.5 Ibs pH 8.5-9.0

674

Drilling and Well C o m p l e t i o n s

as they c o m p e t e too effectively with the e x t e n d e r for the a d s o r p t i o n sites on the clay. A small excess o f soda ash, o f 0.57 k g / m 3 (0.2 lb/bbl), should be maintained to ensure the calcium level remains below 80 mg/1 and to improve the efficiency o f the extender. This level o f soda ash will p r o d u c e the required p H in most cases. T h e system can be weighted to a m a x i m u m o f 11 l b / g a l p r o v i d e d the ratio o f drill solids to clay solids is maintained at less than 2:1, by correct use o f the solids removal e q u i p m e n t and careful dilution and makeup with bentonite from a p r e m i x tank.

Bentonite Substitute Systems In this system, the high molecular weight polysaccharide polymer, is used to extend the rheological p r o p e r t i e s o f bentonite. A b i o p o l y m e r p r o d u c e d by a particular strain o f bacteria is b e c o m i n g widely used as a substitute for clay in low-solids muds. Since the p o l y m e r is attacked readily by bacteria, a bactericide such as paraformaldehyde or a chlorinated phenol also must be used with the biopolymer. T h e system has m o r e stable p r o p e r t i e s than the extended bentonite system, because biopolymer exhibits good rheological p r o p e r t i e s in its own right, and has a better tolerance to salt and calcium. T h e system can be formulated to include salt, such as potassium chloride. Such a system, however, would then be classed as a n o n d i s p e r s e d inhibitive fluid.

Nondispersed Inhibited Systems. In these systems, the n o n d i s p e r s e d character o f the fluids is reinforced by some inhibition system, or combination o f systems, such as (1) calcium ions, lime or gypsum; (2) salt-sodium chloride or potassium chloride; (3) polymers such as Polysaccharides, polyanionic cellulose, hydrolyzed polyacrylamide. In these systems, particularly systems such as potassium chloride polymer, the role o f bentonite is d i m i n i s h e d because the chemical e n v i r o n m e n t is designed to collapse and encapsulate the clays since this reaction is required to stabilize water-sensitive formations. T h e clay may have a role in the initial formulation o f an inhibited fluid to provide the solids to create a filter cake. Potassium Chloride-Polymer Muds K C l - p o l y m e r (potassium c h l o r i d e - p o l y m e r ) muds can be classified as low s o l i d s - p o l y m e r muds or as inhibitive muds, due to their application to drilling in water-sensitive, sloughing shales. T h e use o f polymers and the c o n c e n t r a t i o n o f potassium chloride provide inhibition o f shales and clays for maximum hole stability. T h e inverted flow p r o p e r t i e s (high yield point, low plastic viscosity) achieved with polymers and p r e h y d r a t e d bentonite provide g o o d hole cleaning with m i n i m u m hole erosion. T h e K C l - p o l y m e r muds are p r e p a r e d by mixing potassium chloride (KC1) with fresh or saltwater. T h e desired KC1 c o n c e n t r a t i o n d e p e n d s u p o n the instability o f the borehole and ranges from 3.5% by weight for drilling in shales containing illites and kaolinites to 10% by weight for drilling in b e n t o n i t e shales. T h e polymer is then mixed in slowly through the h o p p e r to the desired concentration (0.1 to 0.8 l b / g a l d e p e n d i n g u p o n the type o f polymer). For additional viscosity, p r e h y d r a t e d bentonite (salt makeup water) can be a d d e d (0 to 12 l b / b b l ) until satisfactory hole cleaning is achieved. T h e m u d is adjusted to a p H o f 9 to 10 with KOH or caustic soda. For filtration control, an organic filtration control agent should be used as r e c o m m e n d e d by the manufacturer.

Drilling Muds and C o m p l e t i o n Fluids

675

Oil-Base Mud Systems Oil-base muds are composed of oil as the c o n t i n u o u s phase, water as the dispersed phase, emulsifiers, wetting agents, a n d gellants. T h e r e are other chemicals used for oil-base m u d treatment such as degellants, filtrate reducers, weighting agents, etc. The oil for an oil-base m u d can be diesel oil, kerosene, fuel oil, selected crude oil, or mineral oil. There are several requirements for the oil: (1) API gravity = 36 ° - 37 °, (2) flash point = 180°F or above, (3) fire point = 200°F or above, and (4) aniline point = 140°F or above. Emulsifiers are more important in oil-base m u d than in water-base m u d because c o n t a m i n a t i o n oll the drilling rig is very likely, and it is very detrimental to oil mud. Thinners, on the other hand, are far more important in water-base m u d than in oil-base mud; oil is dielectric, so there are no interparticle electric forces to be nullified. The water phase of oil-base m u d can be freshwater, or various solutions of calcium chloride (CaC12) or s o d i u m chloride (NaC1). T h e c o n c e n t r a t i o n and composition of the water phase in oil-base m u d determines its ability to solve the hydratable shale problem. Oil-base muds c o n t a i n i n g freshwater are very effective in most water-sensitive shales. The external phase of oil-base m u d is oil and does not allow the water to contact the formation; the shales are thereby prevented from b e c o m i n g water wet and dispersing into the m u d or caving into the hole. The stability of an emulsion m u d is an important factor that has to be closely m o n i t o r e d while drilling. Poor stability results in coalescence of the dispersed phase, and the emulsion will separate into two distinct layers. Presence of oil in the emulsion m u d filtrate is an indication of emulsion instability. The advantages of drilling with emulsion muds rather than with water-base muds are (1) higher drilling rate, (2) reduction in drill pipe torque and drag, (3) less bit balling, and (4) reduction in differential sticking. Oil-base muds are expensive and should be used when conditions justify their application. It is more economic to use oil base mud. a. to drill troublesome shales that swell (hydrate) and disperse (slough) in water base muds, b. to drill deep, high temperature holes in which water base muds solidify, c. to drill water soluble formations such as salt, anhydride, carnallite, and potash zones, d. to drill in p r o d u c i n g zones. For additional applications, oil muds can be used a. as a completion and workover fluid, b. as a spotting fluid to relieve stuck pipe, c. as a packer fluid or a casing pack fluid. There is one shale problem, however, that can be solved only by an oil-base m u d with a CaC12 water solution. This shale problem is the "gumbo" or plastic flowing shale encountered in offshore Louisiana, the Oregon coast, Wyoming, and the Sahara desert. While drilling "gumbo" with water-base mud, the shale dispersion rate in the m u d is so high that the drilling rate has to be slowed down or the m u d will plug the annulus. All solids control problems are encountered, such as bit balling, collar balling, stuck pipe, shaker screens plugging, etc. A n oil-base m u d with a freshwater phase does not solve this problem, but

676

Drilling and Well C o m p l e t i o n s

only decreases the degree o f severity. If the water phase of the oil mud is a solution o f CaC12 (10 to 15 lb/bbl), dehydration o f the wet (20 to 30% water) g u m b o shale occurs; the shale becomes harder and it acts like a c o m m o n water sensitive shale. Ttie genei~at, practice is to deliver the oil-base m u d ready mixed to the rig, although some oil-base muds can be p r e p a r e d at the rig. In the latter case, the most i m p o r t a n t principles are (1) to ensure that ample energy in the form o f shear is a p p l i e d to the fluid, and (2) to strictly follow a definite o r d e r o f mixing. T h e following mixing p r o c e d u r e is r e c o m m e n d e d : a. P u m p the r e q u i r e d amount o f oil into the tank. b. A d d the calculated amounts o f emulsifiers and wetting agent, stir, agitate, and shear these c o m p o n e n t s until a d e q u a t e dispersion is obtained. c. Mix in all o f the water, or the CaCI 2 water solution that has been p r e m i x e d in t h e o t h e r m u d tank. This r e q u i r e s s h e a r energy. A d d water slowly t h r o u g h the s u b m e r g e d guns; o p e r a t i o n o f a -~-in. gun nozzle at 500 psi is considered satisfactory. A f t e r emulsifying all the water into the mud, the system s h o u l d have a s m o o t h , glossy, a n d shiny a p p e a r a n c e . O n close examination, there should be no visible droplets o f water. d. A d d all the o t h e r oil-base m u d p r o d u c t s specified. e. A d d the weighting material last; make sure that there are no water additions while mixing in the weighting material. When using an oil-base mud, certain rig equipment should be provided to control drilled solids in the m u d and to reduce the loss o f m u d at the surfaces, i.e., a. Kelly valve--a valve installed between the kelly and the drill pipe will save about one barrel p e r connection. b. Mud b o x - t o prevent loss o f m u d while pulling wet string on trips and connections; it should have a d r a i n to the flow line. c. W i p e r r u b b e r - t o keep the surface o f the p i p e d r y and save mud. Oil-base m u d maintenance involves close m o n i t o r i n g o f the m u d p r o p e r t i e s along with the m u d t e m p e r a t u r e , as well as the chemical treatment (in which the o r d e r o f additions must be strictly followed). T h e following general guidelines should be considered: a. T h e m u d weight o f an oil m u d can be controlled within the interval from 7 l b / g a l (aerated) to 22 l b / g a l . A m u d weight up to 10.5 l b / g a l can be achieved with sodium chloride or with calcium chloride. For densities above 10.5 l b / g a l , barite or g r o u n d limestone can be used. Limestone can weigh m u d up to 14 l b / g a l ; it is used when an acid soluble solids fraction is desired, such as in drill-in fluids or in c o m p l e t i o n / w o r k o v e r fluids. Also, iron carbonate may be used to obtain weights up to 19.0 l b / g a l when acid solubility is necessary. b. Mud rheology o f oil-base m u d is strongly affected by t e m p e r a t u r e . API p r o c e d u r e r e c o m m e n d s that the m u d t e m p e r a t u r e be r e p o r t e d a l o n g with the funnel viscosity. T h e general rule for maintenance o f the rheological p r o p e r t i e s o f oil-base muds is that the A P I funnel viscosity, the plastic viscosity, and the yield point should be maintained in a range similar to that o f comparable weight water muds. Estimated properties o f two oil m u d systems are shown in Figure 4-113 and Table 4-50. Excessive m u d viscosity can be reduced by dilution with a diesel oil-emulsifier mixture that has been

Drilling Muds a n d Completion Fluids

677

180 0

o 160 z 140 0 o_ 121 120 .J w

APPROXIMATE R,~NGE OF PROPERTIES FOR VERTOIL FIELD MUDS-115 ° F DATA /

~"i 100

I/i

Q.

o_ o 80

_--

I~11

40

p-,

>~20 . ~~.~.~- ~ 0~ " - - - - - -

8

7=

9

90

10

---

11

o 8O -~.

I

I

17

18

19

~

---"

12 13 14 15 16 MUD WEIGHT, Ibs/gal

IIII

O

II

APPROXIMATE RANGE OF PROPERTIES FOR OILFAZE FIELD MUDS-115 ° F DATA

=m

x 0 D_ a

--'-

I

I-/-

70

>"i

/

/

50

(n O_ O_

o

/

/

60

.J

uJ

/

20

//

40

30

I

/

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09

I0 i

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~

YIELD POINT _ _

~ "

,

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Q-

0 8

9

10

11

12

13

14

15

16

17

18

19

MUD WEIGHT, lbs/gal Figure 4-113. Approximate rheology of two oil-based mud systems. (VERTOIL = invert emulsion of oil and CaCI 2 brine; OILFAZE = invert emulsion of oil and freshwater)

20

678

Drilling and Well Completions

Table 4-50 Estimated Requirements for Oil Mud Properties Mud Weight ppg 8-10 10-12 12-14 14-16 16-18

c.

d.

e.

f. g.

h.

i.

Plastic Viscosity cP

Yield Point Ibs/100 ft 2

Oil-Water Ratio

Electrical Stability

15-30 20-40 25-50 30-60 40-80

5-10 6-14 7-16 10-19 12-22

65/35-75/25 75/25-80/20 80/20-85/15 85/15-88/12 88/15-92/8

200-300 300-400 400-500 500-600 above 600

agitated in a separate tank. Insufficient viscosity can be corrected either by adding water (pilot testing required) or by treatment with a gellant. There is no general upper limit on drilled solids concentration in oil muds, such as there is for water-base muds. However, a daily log of solids content enables the e n g i n e e r to quickly d e t e r m i n e a solids level at which the m u d 'system performs properly. Water wet solids is a very serious problem; in sever cases, uncontrollable barite settling may result. If there are any positive signs of water wet solids, a wetting agent should be added immediately. Tests for water wet solids should be r u n daily. The dispersed water phase of an oil-base m u d should be maintained in an alkaline pH r a n g e (i.e., pH above 7). T e m p e r a t u r e stability as well as emulsion stability depends u p o n the proper alkalinity maintenance. If the c o n c e n t r a t i o n of lime is too low, the solubility of the emulsifier changes and the emulsion loses its stability. O n the other hand, overtreatment with lime results in water wetting problems. Therefore, the daily lime maintenance has to be established and controlled by alkalinity testing. The recomm e n d e d range of lime content for oil-base muds is from 2 to 4 l b / b b l . CaC12 content should be checked daily and corrected. T h e oil-water ratio influences viscosity and H T - H P (high-temperaturehigh-pressure) filtration of the oil-base mud. Retort analysis is used to detect any change in the oil-water ratio, giving the e n g i n e e r a m e t h o d for controlling the viscosity of the liquid phase by m a i n t a i n i n g a relatively constant oil-water ratio. Electrical stability is a measure of how well the water is emulsified in the continuous oil phase. Since many factors affect the electrical stability of oil-base muds, the test does not necessarily indicate that a particular oilbase m u d is in good or in poor c o n d i t i o n . For this reason, values are relative to the system for which they are being recorded. Stability measurements should be made routinely, and the values recorded and plotted so that trends may be noted. Any change in electrical stability indicates a change in the system. H T - H P filtration should exhibit a low filtrate volume (about 3 ml). The filtrate should be water-free; water in the filtrate indicates a poor emulsion, probably caused by water wetting of solids.

Gaseous Drilling Mud Systems The basic gaseous drilling fluids and their characteristics are presented in Table 4-51.

Drilling Muds and C o m p l e t i o n Fluids

679

Tables 4-51 Gaseous Drilling Mud Systems Properties Density, ppg

pH

Temp.Limit °F

Application Characteristics

0

--

500

Mist

O.13-0.8

7-11

300

Foam

0.4-0.8

4-10

400

High energy type system. Fastest drilling rate in dry, hard formations. Limited by water influx and hole size. High energy system. Fast penetration rates. Can handle water intrusions. Stabilize unstable holes (mud misting). Very low energy system. Good penetration rates. Excellent cleaning ability regardless of hole size. Tolerate large water influx.

Type of Mud Aidgas

Air-Gas Drilling Fluids This system involves injecting air or gas d o w n h o l e at the rates sufficient to attain a n n u l a r velocity o f 2,000 to 3,000 f t / m i n . H a r d f o r m a t i o n s that are relatively free from water are most desirable for d r i l l i n g with a i r - g a s . Small quantities o f water usually can be d r i e d up or sealed off by various techniques. A i r - g a s drilling usually increases drilling rate by three or four times over that when drilling with mud as well as one-half to one-fourth the n u m b e r o f bits are required. In some areas drilling with air is the only solution; these are (1) severe lost circulation, (2) sensitive p r o d u c i n g formation that can be blocked by drilling f l u i d (skin effect), and (3) h a r d formations n e a r the surface that require the use o f an air h a m m e r to drill. T h e r e are two most important limitations on using air as a drilling fluid: large volumes o f free water and size o f the hole. Large water flow generally necessitates converting to a n o t h e r type o f drilling fluid (mist or foam). Size o f the hole d e t e r m i n e s a volume o f air r e q u i r e d for g o o d cleaning. Lift ability o f air is d e p e n d e n t u p o n annular velocity only (no viscosity or gel strength). Therefore, large holes require an e n o r m o u s volume o f air, which is not economical.

Mist Drilling Fluids Misting involves the injection o f air and m u d or water a n d foamer. In case o f "water mist" only enough water a n d f o a m e r is injected into the airstream to clear the hole o f p r o d u c e d fluids a n d cuttings. This unthickened water causes many problems d u e to wetting o f the exposed formation which results in sloughing a n d caving. Mud misting, on the o t h e r hand, coats the walls o f the hole with a thin film and has a stabilizing effect on water-sensitive formations. A m u d s l u r r y that has p r o v e d a d e q u a t e for most p u r p o s e s consists o f 10 p p b o f bentonite, 1 p p b o f soda ash, a n d less than 0.5 p p b o f foam stabilizing p o l y m e r such as high viscosity CMC. If a d d i t i o n a l foam stability is n e e d e d , a d d i t i o n a l

680

Drilling and Well C o m p l e t i o n s

organic filtration control agent should be added. O n e of the m o r e i m p o r t a n t requisites for p r o p e r m u d misting is foaming agent. T h e exact amount to be a d d e d d e p e n d s on the particular f o a m e r used, as most different b r a n d s have different amounts of active materials. Since air is the lifting m e d i u m in mist drilling fluid, the sufficient air velocity in the annulus should be from 2,000 to 3,000 f t / m i n . T h e a p p r o x i m a t e m u d or water p u m p i n g rate is 10 b b l / h r .

Foam Drilling Fluids Foam is gas-liquid dispersion in which the liquid is the continuous phase and the gas is the discontinuous phase. T h e first use of foam in drilling was r e p o r t e d in 1964. Foam has b e e n successfully used as a d r i l l i n g f l u i d in several geological conditions. 1. In air drilling areas, the use o f air drilling technique can be p r o l o n g e d when formation water enters the hole by adding a small stream of liquid surfactant to the air stream. T h e addition of surfactant forms foam at the contact with f o r m a t i o n water. T h e foam carries out cuttings and p r o d u c e d water. Considerable volumes of f o r m a t i o n water can be held using this technique. 2. In h a r d rock d r i l l i n g areas with loss of circulation, the a p p l i c a t i o n of p r e f o r m e d (mixed at the surface) stable foam shows four to ten times higher p e n e t r a t i o n rate than clay-based muds. 3. In oil-producing formations with high fluid loss, drilling in with foam and foam c o m p l e t i o n proves beneficial. Usually, these formations cannot stand a column of w a t e r - s o it is impossible to establish returns with conventional mud. T h e use of foam for drilling in and c o m p l e t i o n results in substantial increases in production. Stable foam systems consists of a detergent, freshwater, and compressed air. Gel-foam system includes bentonite a d d e d to the w a t e r - d e t e r g e n t mix. Additives may be included in the mixture for special purposes. To be used effectively as a circulating m e d i u m , foam must be p r e f o r m e d . That is, it must be g e n e r a t e d without contact with the solid and liquid contaminants naturally e n c o u n t e r e d in the well. O n c e f o r m e d , foam systems have stabilizing c h a r a c t e r i s t i c s that make t h e m resistant to well-bore c o n t a m i n a n t s . Foam s h o u l d have a gas-toliquid volume ratio from 3-50 ft3/gal d e p e n d i n g on downhole requirements. T h e w a t e r - d e t e r g e n t s o l u t i o n that is m i x e d with gas to f o r m foam can be p r e p a r e d using a wide r a n g e of o r g a n i c f o a m i n g agents ( 0 . 1 - 1 . 0 p a r t s of f o a m i n g agent p e r 100 p a r t s of solution). Foams can be p r e p a r e d with densities as low as 0.26 l b / g a l . Viscosity can be v a r i e d so high lifting capacities r e s u l t w h e n c i r c u l a t i n g at 300 f p m a n n u l a r velocity. B H P m e a s u r e m e n t s have i n d i c a t e d actual p r e s s u r e s o f 15 psi at 1000 ft a n d 50 psi at 2,900 psi while circulating.

Drilling Fluid Additives T h e classification of drilling fluid additives is based on the definitions of the International Association of Drilling Contractors [30]. a. Alkalinity or p H control additives are p r o d u c t s d e s i g n e d to control the d e g r e e of acidity or alkalinity of a drilling fluid. These additives include lime, caustic soda, and bicarbonate of soda.

Drilling Muds and C o m p l e t i o n Fluids

681

b. Bactericides r e d u c e the b a c t e r i a count. P a r a f o r m a l d e h y d e , caustic soda, lime, and starch are c o m m o n l y used as preservatives. c. C a l c i u m removers are chemicals used to prevent and to o v e r c o m e the c o n t a m i n a t i n g effects o f a n h y d r i d e and gypsum, b o t h forms o f calcium sulfate, which can wreck the effectiveness o f nearly any chemically treated mud. T h e most c o m m o n calcium removers are caustic soda, soda ash, b i c a r b o n a t e o f soda, and certain polyphosphates. d. C o r r o s i o n inhibitors such as hydrated lime and amine salts are often a d d e d to m u d and to a i r - g a s systems. Mud containing an adequate percentage o f colloids, certain emulsion muds, and oil muds exhibit, in themselves, excellent c o r r o s i o n inhibiting properties. e. Defoamers are products designed to reduce foaming action, particularly that o c c u r r i n g in brackish water and saturated saltwater muds. f. Emulsifiers are used for creating a heterogenous mixture o f two liquids. T h e s e i n c l u d e m o d i f i e d l i g n o s u l f o n a t e s , c e r t a i n surface-active agents, anionic and noionic (negatively charged and noncharged) products. g. Filtrate, or f l u i d loss, r e d u c e r s such as b e n t o n i t e clays, CMC ( s o d i u m carboxymethyl cellulose), and pregelatinized starch serve to cut filter loss, a measure o f the t e n d e n c y o f the liquid phase o f a drilling f l u i d to pass into the formation. h. Flocculents are used sometimes to increase gel strength. Salt (or brine), h y d r a t e d lime, gypsum, and s o d i u m t e t r a p h o s p h a t e s may be used to cause the colloidal particles o f a suspension to group into bunches or "floos," causing solids to settle out. i. F o a m i n g agents are most o f t e n c h e m i c a l s that also act as s u r f a c t a n t s (surface-active agents) to foam in the presence o f water. These foamers p e r m i t air or gas drilling t h r o u g h water-producing formations. j. Lost circulation materials (LCM) include nearly every possible product used to stop or slow the loss o f circulating fluids into the formation. This loss must be differentiated from the n o r m a l loss o f filtration liquid, and from the loss o f drilling m u d solids to the filter cake (which is a continuous process in an o p e n hole). k. Extreme pressure lubricants are designed to reduce torque by reducing the coefficient o f friction, and thereby increase horsepower at the bit. Certain oils, g r a p h i t e powder, and soaps are used for this p u r p o s e . 1. Shale control inhibitors such as gypsum, s o d i u m silicate, c h r o m e lignosulfonates, as well as lime and salt are used to control caving by swelling or hydrous disintegration o f shales. m. Surface-active agents (surfactants) reduce the interfacial tension between contacting surfaces (e.g., water-oil, water-solid, water-air, etc.); these may be emulsifiers, deemulsifiers, flocculents, or deflocculents, d e p e n d i n g u p o n the surfaces involved. n. Thinners and dispersants modify the relationship between the viscosity and the percentage o f solids in a drilling mud, and may f u r t h e r be used to vary the gel strength, improve "pumpability," etc. Tannins (quebracho), various polyphosphates, and lignitic materials are chosen as thinners or as dispersants, since most o f these chemicals also remove solids by precipitation or sequestering, and by d e f l o c c u l a t i o n reactions. o. Viscosifers such as bentonite, CMC, attapulgite clays, subbentonites, and asbestos fibers (all colloids) are employed in drilling fluids to assure a high viscosity-solids ratio. p. Weighting materials, including barite, lead c o m p o u n d s , iron oxides, and similar products possessing extraordinarily high specific gravities, are used

682

Drilling and Well Completions to control formation pressures, check caving, facilitate pulling dry drill pipe on r o u n d trips, and aid in combatting some types of circulation loss.

The most c o m m o n , commercially available drilling m u d additives are published annually by World Oil. The listing includes names and description of over 2,000 m u d additives.

Environmental Aspects of Drilling Fluids Much attention has been given in recent years to the e n v i r o n m e n t a l aspects of both the drilling operation and the drilling fluid components. Well-deserved c o n c e r n with the possibility of polluting u n d e r g r o u n d water supplies and of damaging marine organisms, as well as with the more readily observed effects on soil productivity and surface water quality, has stimulated widespread studies on this subject.

Drilling Fluid Toxicity Sources of Toxicity. There are three c o n t r i b u t i n g mechanisms of toxicity in drilling fluids, chemistry of m u d mixing and treatment, storage/disposal practices, and drilled rock. The first group conventionally has been k n o w n the best because it includes products deliberately added to the system to b u i l d and maintain the rheology and stability of drilling fluids. Petroleum, whether crude or refined products, need no longer be added to water-based muds. A d e q u a t e substitutes exist a n d are, for most situations, economically viable. Levels of 1% or more of crude oil may be present in drilled rock cuttings, some of which will be in the mud. C o m m o n salt, or sodium chloride, is also present in dissolved form in drilling fluids. Levels up to 3,000 mg,/L chloride and sometimes higher are naturally present in freshwater muds as a consequence of the salinity of s u b t e r r a n e a n brines in drilled formations. Seawater is the natural source of water for offshore drilling muds. Saturated b r i n e drilling fluids become a necessity when drilling with water-based muds through salt zones to get to oil and gas reservoirs below the salt. In onshore drilling there is no need for chlorides above these "background" levels. Potassium chloride has b e e n added to some drilling fluids as an aid to controlling problem shale formations drilled. Potassium acetate or potassium carbonate are acceptable substitutes in most of these situations. Heavy metals are present in drilled formation solids and in naturally occurring materials used as m u d additives. The latter include barite, bentonite, lignite, and mica (sometimes used to stop m u d losses downhole). There are background levels of heavy metals in trees that carry through into lignosulfonate made from them l ~ c e n t l y a t t e n t i o n has focused on the heavy metal i m p u r i t i e s i n barite. Proposed U.S. regulations would exclude many sources of barite ore. European and other countries are contemplating regulations of their own. C h r o m i u m lignosulfonates are the biggest contributions to heavy metals in drilling fluids. A l t h o u g h studies have shown m i n i m a l e n v i r o n m e n t a l impact, substitutes exist that can result in lower c h r o m i u m levels in muds. The less used c h r o m i u m lignites (trivalent c h r o m i u m complexes) are similar in character and performance with less chromium. N o n c h r o m i u m substitutes are effective in many situations. Typical total c h r o m i u m levels in muds are 100-1000 mg,/l. ' Zinc compounds such as zinc oxide and basic zinc carbonate are used in some drilling fluids. Their function is to react out swiftly sulfide and bisulfide ions 1

o

o

"

Drilling Muds and C o m p l e t i o n Fluids

683

originating with hydrogen sulfide in drilled formations. Because h u m a n safety is at stake, there can be no c o m p r o m i s i n g effectiveness, and substitutes for zinc have not seemed to be effective. Fortunately, most drilling situations do not require the a d d i t i o n of sulfide scavengers. Indiscriminate s t o r a g e / d i s p o s a l practices using drilling m u d reserve pits can contribute toxicity to the spent drilling fluid as shown in Table 4-52 [31]. T h e data in Table 4-52 is from the EPA survey of the most i m p o r t a n t toxicants in spent d r i l l i n g fluids. T h e survey i n c l u d e d s a m p l i n g active d r i l l i n g m u d (in circulating system) and spent drilling m u d (in the reserve pit). T h e data show that the storage disposal practices became a source of the benzene, lead, arsenic, a n d f l u o r i d e toxicities in the reserve pits because these c o m p o n e n t s had not b e e n detected in the active m u d systems. T h e third source of toxicity in drilling discharges is d r i l l e d rocks. A recent study [32] of 36 cores collected from three areas (Gulf of Mexico, California, a n d O k l a h o m a ) at various d r i l l i n g d e p t h s ( r a n g i n g from 300 to 18,000 ft) revealed that the total c o n c e n t r a t i o n of c a d m i u m in d r i l l e d rocks was over five times greater than c a d m i u m concentration in commercial barites. It was also estimated, using a 10,000-ft m o d e l well discharge volumes, that 74.9% of all c a d m i u m in drilling waste may be c o n t r i b u t e d by cuttings while only 25.1% originate from the barite and the pipe dope.

Mud Toxicity Test. Presently, the only toxicity test for drilling fluids having an EPA approval is the Mysid shrimp bioassay. T h e test was developed in the mid1970s as a j o i n t effort of the EPA and the oil industry. A bioassay is a test designed to measure the effect of a chemical on a test p o p u l a t i o n of organisms. T h e effect may be a physiological or b i o c h e m i c a l parameter, such as growth rate, respiration, or enzyme activity. In the case of drilling fluids, bioassays lethality is the m e a s u r e d effect. To quantify the effect of a chemical on a population, groups of organisms are e x p o s e d to different concentrations of the chemical for a p r e d e t e r m i n e d interval. T h e c o n c e n t r a t i o n at which 50% of the test p o p u l a t i o n r e s p o n d s is known as the EC50 (effective c o n c e n t r a t i o n 50%); when death is the m e a s u r e d response, it is called the LCs0 (lethal concentration 50%). T h e LCs0 c o n c e p t is v i s u a l i z e d in the d o s e - r e s p o n s e curve p r e s e n t e d in F i g u r e 4-114 [32A]. T h e dose or c o n c e n t r a t i o n is plotted on the abscissa, and

Table 4-52 Toxicity Difference between Active and Waste Drilling Fluids [31]

TOXICANT Benzene Lead Badum Arsenic Fluodde Courtesy SPE.

ACTIVE MUD

NO NO YES NO NO

DETECllON RAI~. %

RESERVE PiT

DETEC31ON RATE,%

100

YES YES YES YES YES

39 100 100 52 100

684

Drilling and Well Completions

too I

I I

. . . .

J"

Y"

l

!

UOITAUWl

jLC50 0~ 0

10 I00 CONCENTRATION(PPM)

1000

Figure 4-114. Determination of lethal toxicity LCso from the dose-response curve [32A]. (CourtesySPE.) the c o r r e s p o n d i n g response is plotted on the ordinate. T h e 50% value is interpolated from the resulting curve. A high LC~0 value indicates low toxicity, and a low LC~0 value indicates a high degree of toxicity. The 50% value is generally chosen because it represents the response of the average organism to the toxic exposure, thus providing the greatest predictive ability. The vast majority of bioassays on marine organisms have been conducted on toxicants that are soluble in seawater. Because drilling m u d contains solid particles, a special procedure had to be developed. The test divides the drilling fluid into three phases: the liquid phase, the suspended particulate phase, and the solid phase. These phases are designed to represent the anticipated conditions that organisms would be exposed to when drilling mud is discharged into the ocean. Certain drilling fluid components are water column, others are fine particulates which would stay suspended, and still water soluble and will dissolve in the other material would settle rapidly to the bottom. The procedure for phase separation follows the schematic in Figure 4-115 [32A]. To prepare the three test phases, a 1:9 ratio by volume of mud to seawater is mixed for 30 min. The pH is adjusted to that near seawater (pH = 7.8-9.0) by the addition of acetic acid. The slurry is allowed to settle for one hour. A portion of the supernatant is filtered through a 0.45-~tm filter. The filtrate is designated as the "liquid phase." The remaining unfiltered supernatant of the slurry is the "suspended particulate phase," while the "solid phase" is the settled solid material at the bottom of the mixing vessel. The filtered phase and suspended particulate phase of the 1:9 slurry represent the 100% concentration or 1,000,000 ppm. Serial dilutions of these two phases o f drilling fluids are used in the test p r o c e d u r e to expose mysid shrimp (Mysidopsis bahia) for 96 hr and determine the LC50.

Drilling Muds and Completion Fluids

685

FOII SETTLE :seams. -,-e,, ro| tim. I PiltT ORKUllii

FLUIO

q PAilS ~.AWAlrI~

l:qlV/V)

lillO/SEA|illl[I

gSi'EIIB l~Immu~ PMSi[(SPP!

(

IUZPitOPItllTE OILUTION$

l

K IlL I.Cfdl MYSIOOPSISBAHIA Figure 4-115. Schematic of toxicity test for drilling fluids [32A].

(Courtesy SPE.)

Results of these experiments usually give LCs0s ranging from 25,000 ppm to greater than 1,000,000 ppm of the phase for a variety of muds. The mysid shrimp, Mysidopsis bahia, is the test organism for the liquid and suspended particulate phases. This species has been shown to be exceptionally sensitive to toxic substances and is considered to be a representative marine organism for bioassay testing by EPA. An LCs0 is determined the suspended particulate phase (SPP) bioassay tests. Low-Toxicity Drilling Fluids The large number of existing oilfield facilities operation in or discharging produced water into surface waters of the United States has prompted EPA to issue general NPDES permits. The general permit allows discharge of low-toxicity drilling fluid directly to the sea. These "generic" muds were identified by reviewing the permit requests and selecting the minimum number of mud systems that would cover all those named by the prospective permittees. Eight different mud systems were identified that encompass virtually all water-based muds used on the OCS (Table 4-53) [32A]. Instead of naming a set concentration for each component in each mud system, concentration ranges were specified to allow the operators sufficient flexibility to drill safely. There are several significant permit conditions. As with all other OCS permits, the discharge of oil-based muds is prohibited. Similarly, the permit does not unconditionally authorize the discharge of any of the eight generic muds. Their discharge is subject to limitations on additives. To monitor the use of mud additives, the permit requires the additive not to drop or to decrease the 96-hr median lethal concentration (LCs0) test below 7,400 ppm on the basis of the suspended particulate phase or 740 ppm for the whole mud. This parameter is based on a test of Generic Mud 8, which is formulated with 5% mineral oil. There is a mud-discharge-rate limitation of 1,000 bbl/hr, with reduced rates near areas of biological concern. The discharge of mud containing diesel for lubricity purposes .is prohibited.

686

Drilling and Well Completions

Table 4-53 Low-Toxicity "Generic" Drilling Fluids [32A] 1. Potassium/Polymer Mud KCI Starch Cellulose polymer XC polymer Drilled, solids Caustic Barite Seawater or freshwater

5 to 50 2 to 12 0.25 to 5 0.25 to 2 20 to 100 0.5 to 3 0 to 450 as needed

2. Seawater/Lignosulfate Mud Attapulgite or bentonite Lignosulfonate Lignite Caustic Barite Drilled solids Soda ash/sodium bicarbonate Cellulose polymer Seawater

10 to 50 2 to 15 1 to 10 1 to 5 25 to 450 20 to 100 0 to 2 0,25 to 5 as needed

3. Lime Mud Lime Bentonite Lignosulfonate Lignite Barite Caustic Drilled Solids Soda ash/sodium bicarbonate Freshwater or seawater

2 to 20 10 to 50 2 to 15 0 to 10 25 to 180 1 to 5 20 to 100 0 to 2 as needed

4. Nondispersed Mud Bentonite Acrylic polymer Barite Drilled solids Freshwater or seawater

5 to 15 0.5 to 2 25 to 180 20 to 70 as needed

Courtesy SPE

5. Spud Mud (Slugged Intermittently with Seawater) Attapulgite or bentonite 10 to 50 Lime 0.5 to 1 Soda ash/sodium bicarbonate 0 to 2 Caustic 0 to 2 Barite 0 to 50 Seawater as needed 6. Seawater/Freshwater Gel Mud Attapulgite or bentonite Caustic Cellulose polymer Drilled solids Barite Soda ash/sodium bicarbonate Lime Seawater or freshwater

10 to 50 0.5 to 3 0 to 2 20 to 100 0 to 50 0 to 2 0 to 2 as needed

7. Lightly Treated Lignosulfonate Freshwater/Seawater Mud Bentonite Barite Caustic Lignosulfonate Lignite Cellulose polymer Drilled solids Soda ash/sodium bicarbonate Lime Seawater to freshwater ratio

10 to 50 0 to 180 1 to 3 2 to 6 0 to 4 0 to 2 20 to 100 0 to 2 0 to =1:1

8. Lignosulfonate Freshwater Mud Bentonite 10 to 50 Barite 0 to 450 Caustic 2 to 5 Lignosulfonate 4 to 15 Lignite 2 to 10 Drilled solids 20 to 100 Cellulose polymer 0 to 2 Soda ash/sodium bicarbonate 0 to 2 Lime 0 to 2 Freshwater as needed

Drilling Muds a n d C o m p l e t i o n Fluids

687

Typical Calculations in Mud Engineering Weighing Mud UpmUnlimited Volume It is desired to increase the specific weight of 300 bbl of 10.5-1b/gal m u d to l l.4-1b/gal using barite. The final volume is not limited. Determine the new volume of the mud. Also d e t e r m i n e the weight of the barite to be added [7]. The new volume, V 2 (bbl), is

v2 = v, (i~ - '7,) (Tb - 72) where V1 = Yl = ~ = ~b =

the the the the

(4-45)

initial volume in bbl specific weight of the initial m u d in l b / g a l specific weight of the final m u d in l b / g a l specific weight of barite (35.0 lb/gal).

Therefore, the final volume is V2 = (300)(35.0 - 10.5) (35.0 11.4) = 311.44 bbl The weight of the barite to be added is W b = (311.44 - 300.00)(35.0)(42) = 16,817 lb

Weighing Mud UpmLimited Volume Example. It is desired to increase the specific weight of 700 bbl of 12.0-1b/gal m u d to 14.0-1b/gal mud. To keep the new mixture from b e c o m i n g too viscous, 1 gal of water is to be added with each 100-1b sack of barite. A final m u d volume of 700 bbl is required. D e t e r m i n e the volume of initial m u d that should be discarded and the weight of barite to be added [7]. The initial and final volumes are related by

¢l+wVwb V 1 = V 2

_ ( 1 + 9w Vwb"~

(4-46)

a n d the weight of barite added is

Wb =

7b (V~ - V,) 1 +Tb Vwb

(4-47)

688

Drilling a n d Well C o m p l e t i o n s

where Vb~ is the water requirement for the a d d e d barite (gal/lb). Therefore, the initial volume is

VI

= 700/,______.~1+35.0(0.01) )

14.

[(1+8.33(0.01) 1_ 35.0 1 + 3 5 . 0 ( 0 . 0 1 ) ) 12.

°o]

= 612.99 bbl Thus 700 - 612.99 = 87.01 bbl is the volume o f initial m u d that should be discarded before a d d i n g barite. The weight of barite n e e d e d is 35.0 Wb --- 1 + 35.0(0.01) (87.01)(42) = 94,744 lb T h e total volume o f water to b e a d d e d with the barite, V (gal), often called dilution water, is Vw = v b W b

(4-48)

= 0.01 (94744) = 947.4 gal

Determination of Oil/Water Ratio from Retort Data To d e t e r m i n e the O / W ratio, it is first necessary to m e a s u r e oil a n d water percent by volume in the m u d by retort analysis. From the data o b t a i n e d the o i l / w a t e r ratio is calculated as follows:

% oil by vol x 100 % oil in the liquid phase = % oil by vol + % water by vol % water by vol % water in the liquid phase = % water of vol + % oil by vol x 100 T h e o i l / w a t e r ratio or O / W = % oil in liquid p h a s e / % water in liquid phase. For example, retort analysis: 51% oil by vol 17% water by vol 32% solids by vol

Drilling Muds and Completion Fluids

% oil in liquid phase =

689

51 x 100 = 75% 51+17

17 % water in liquid phase = - x 100 = 25% 17+51 C h a n g e of Oil/Water Ratio

It may become necessary to change the oil/water ratio of an oil mud while drilling. If the oil/water ratio is to be increased add oil, if it is to be decreased, add water. To determine how much oil or water is to be added to change the oil/water ratio, the following calculations are made: 1. Determine present oil/water ratio. 2. Decide whether oil or water is to be added. 3. Calculate how much oil or water is to be added for each h u n d r e d barrels of mud as follows: E x a m p l e A. Retort analysis:

51% oil by volume 17% water by volume 32% solids by volume O / W ratio is 75/25 (from previous example). Change oil/water ratio to 80/20. Use basis of 100 bbl of mud. Table 4-54 C o m p a r i s o n of Diesel Oil and Mineral Oil M u d s [33] Formulation or Property Oil, bbl Primary Emulsifier, Ib Secondary Emulsifier, Ib Lime, Ib High-Temperature Stabilizer, Ib Water, bbl Organophilic Bentonite, Ib Barite, Ib Calcium Chloride, Ib Aged at 300°F, hour Plastic Viscosity, cp Yield Point, Ib/100 sq. ft. 10°Min. Gel, Ib/100 sq. ft. Electrical Stability, volts API Filtrate, ml 300°F Filtrate, ml Coudesy SPE.

Diesel-Oil Mud

Mineral Oil Mud

0.59 9 2 5 8 0.2 3 214 37.2

0.59 9 2 5 8 0.2 3 214 37.2

-55 30 14 960 0.6 6.6

16 39 26 14 1030 1.6 6.8

-47 27 13 880 1.4 8.4

16 32 20 13 930 2.0 12.4

D r i l l i n g a n d Well C o m p l e t i o n s

690

In 100 bbl o f this m u d t h e r e are 68 bbl o f l i q u i d (oil a n d water). To get to t h e n e w o i l / w a t e r r a t i o we m u s t add oil. T h e t o t a l l i q u i d v o l u m e will b e i n c r e a s e d by t h e v o l u m e o f oil a d d e d but t h e water v o l u m e will n o t change. T h e 17 bbl o f water now in t h e m u d r e p r e s e n t s 25% o f t h e l i q u i d v o l u m e , but it will r e p r e s e n t only 20% o f t h e final o r n e w l i q u i d v o l u m e . T h e r e f o r e , let x = final l i q u i d v o l u m e ; t h e n 0.2x = 17 = 85

bbl

T h i s is t h e o f l i q u i d (oil bbl o f m u d . Check the what will be

new l i q u i d v o l u m e . N e w l i q u i d v o l u m e - o r i g i n a l l i q u i d vol = bbl in this case) to be a d d e d , o r 85 - 68 = 17. A d d 17 bbl o f o i i / 1 0 0 c a l c u l a t i o n as follows: I f t h e c a l c u l a t e d a m o u n t o f l i q u i d is added, t h e r e s u l t i n g o i l / w a t e r ratio?

% oil in liquid phase =

=

original vol o f oil + new oil a d d e d original vol + new oil a d d e d

x 100

51 + 17 x 100 68+17

68 = - - × 100 85 = 80%

100 - 80 = 20% water in l i q u i d phase. N e w o i l / w a t e r r a t i o is 8 0 / 2 0 .

Example B.

R e t o r t analysis:

51% oil by v o l u m e 17% w a t e r by v o l u m e 32% solids by v o l u m e oil/water ratio = 75/25 C h a n g e o i l / w a t e r r a t i o to 7 0 / 3 0 . As in E x a m p l e A, t h e r e are 68 however, w a t e r will be a d d e d a n d bbl o f oil r e p r e s e n t s 75% o f t h e l i q u i d v o l u m e . T h e r e f o r e , let

Use basis o f 100 bbl o f m u d . bbl o f liquid in 100 bbl o f m u d . In this case, t h e oil v o l u m e will r e m a i n constant. T h e 51 o r i g i n a l l i q u i d v o l u m e a n d 70% o f t h e final

x = final l i q u i d v o l u m e then 0.7x = 51 = 73 (new l i q u i d v o l u m e ) N e w l i q u i d vol - o r i g i n a l l i q u i d vol = a m o u n t o f l i q u i d (water in this case) to be a d d e d . 73 - 68 = 5 bbl o f w a t e r to be a d d e d Check:

Drilling Muds and C o m p l e t i o n Fluids

% water in liquid phase =

17+5×100= 68+ 5

691

original water vol + water a d d e d × 100 original liquid vol + water a d d e d

22× ~ 100 = 30% water in liquid phase

100 - 30 = 70% oil in liquid phase. New o i l / w a t e r ratio is 70/30.

Solids Control A mud system consists of the subsurface mud system and the surface mud system. The subsurface mud system consists only of the borehole and drill string, and its volume increases with the rate of drilling plus the rate of caving or sloughing. The surface mud system includes the equipment and the tanks through which the drilling mud passes after it flows out of the hole and before it is p u m p e d back into the hole. The low-pressure surface mud system tends to decrease in volume as the hole is drilled due to increasing hole volume, rate of filtration, and cuttings removal. A r a p i d t e m p o r a r y change in surface mud system volume may occur because of formation fluids influx (kick), the addition of mud chemicals, or loss of circulation. The unavoidable a d d i t i o n of solids comes from the continual influx of drilled cuttings into the active m u d system. U n d e s i r a b l e solids increase drilling cost because they reduce p e n e t r a t i o n rate through their effect on mud specific weight and mud viscosity. The surface mud system is designed to restore the mud to the required properties before it is pumped downhole. Most of the equipment is used for solids removal; only a small part of the surface mud system is designed to treat chemical contamination of the mud. There are three basic means of removing drilled solids from the mud" dilution-discard, chemical treatment, and mechanical removal. The dilution-discard m e t h o d is the t r a d i t i o n a l (sometimes the only) way to control the constant increase of colloidal size cuttings in weighted water-base muds. It is effective but also expensive, due to the high cost of barites used to replace the total weighting material in the discard. The daily mud dilutions amount to an average of 5 to 10% of the total mud system. The chemical treatment m e t h o d s reduce dispersability property, of drilling fluids t h r o u g h the increase of size of cuttings which improves s e p a r a t i o n and prevents the buildup of colloidal solids in the mud. These m e t h o d s include ionic inhibition, cuttings encapsulation, oil phase inhibition (with oil-base muds), and flocculation. The mechanical solids removal methods are based on the principles presented in Table 4-55. The surface m u d system consists of solids removal equipment, mud agitating equipment, mixing equipment, and a d d i t i o n a l equipment. Solids removal equipment includes pits or tanks, shale shakers, sand traps, desanders, desilters, mud cleaners, and centrifuges. Mud-agitating equipment includes mud guns and mixers, mud-mixing equipment, and mud hoppers. A d d i t i o n a l e q u i p m e n t includes the degasser, centrifugal pumps, suction lines, and discharge lines.

Solids Classification Solids can be classified as those required for drilling and those d e t r i m e n t a l to the drilling o p e r a t i o n . Required solids are viscosifers (bentonite), filtration control agents, and weighting materials (barite). Viscosifers and filtration control agents are usually colloidal in size, i.e., s m a l l e r than 2 ~tm--Table 4-56 [29].

692

Drilling and Well C o m p l e t i o n s

Table 4-55 Drill Cuttings Separation Principles Method

Sorting Mechanisms

Screening

Size exclusion

Settling

Characteristics

Devices

Adhesion of fines to coarse solids; High throuput; Dry underflow

Shakers. Mud cleaners

Gravity forces

No shear; Low throuput; Liquidous underflow

Settling tanks

Combination of drag and centrifugal forces

High shear High throuput Liquidous underflow

Desanders Desilters

Low shear; Low throuput underflow

Decanting centrifuge

Low shear; Low throuput Liquidous underflow

Peforated rotor centrifuge

Centrifugal forces

Table 4-56 Particle Size Terminology Solids size, microns

2

3eological Sediment Clay Rock

Shale

~,PI Bullentin RP 13C

Colloidal

Practical

Clay

44

74 200 250

2000

Silt

Sand

Gravel

Siltstone

Sandstone

Conglomerate

Ultra Fine J Fine Medium Intermediate Coarse I

Silt

API Sand or cuttings

Barites range in size from 2 to 74 txm; its typical size distribution is shown in Figure 4-116 [34]. Also, the API-approved barite should have a m i n i m u m specific gravity o f 4.2. U n d e s i r a b l e solids are d r i l l e d cuttings a n d those solids sloughed into the borehole. They usually occur in all size ranges from colloidal to coarse. The specific gravity of commonly encountered drilled solids ranges from 2.35 (shale), through 2.65 (sand), 2.69 (limestone), to 2.85 (dolomite); see Table 4-57 [29]. Drilled solids include active drilled solids and inactive drilled solids. Clays and shales are considered to be active drilled solids; they disperse into colloidal size readily a n d b e c o m e d e t r i m e n t a l to d r i l l i n g by i n c r e a s i n g t h e a p p a r e n t viscosity and gel strength o f the mud. Inactive drilled solids are sand, dolomite, limestone, etc.; if they occur in colloidal size, these solids may increase plastic viscosity of the drilling mud. For all practical purposes, solids in drilling m u d are considered to be either low-gravity solids (drilled solids a n d gel, SG = 2.5 or 2.6) o r high gravity solids (barite, SG = 4.2).

Drilling Muds and Completion Fluids

693

19.2 %----

=.o~--

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I

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PARTICLE SIZE MICRONS

B. Cumulative distribution curve

Figure 4-116. Particle size distribution of commercial barites [34]. (Copyright

PennWe// Books, 1986)

694

Drilling a n d Well C o m p l e t i o n s

Table 4-57 Specific Gravity of Liquids and Solids in Mud [29] Material Anhydrite Barite** Calcite Chlorite Dolomite Galena Gypsum Hematite IIlite Lignite Limestone Montmorillonite Pyrite Quartz Sodium Chloride Sulfur Water

Specific Gravity* 2.95 4.45 2.71 2.71 2.85 7.50 2.32 5.26 2.84 1.10 2.69 2.35 5.06 2.65 2.165 1.96 1.00

Composition CaSo4 BaSo4 Cao3 (Mg,AI,Fe)I 2 (Si,AI)802o(OH)16 CaMg (CO3)2 Pb S CaSo42H2o Fe203 KALsSi~02o (OH) 4

(OH)4SisAL4 O2o(H20) FeS2 NaCI

*Chemicallypure

Solids in Unweighted Muds Solids in u n w e i g h t e d muds i n c l u d e viscosifers a n d d r i l l e d solids. T h e most e x p e n s i v e p o r t i o n o f u n w e i g h t e d m u d s are t h e liquids a n d colloidals. T h e m a i n c o n c e r n in u n w e i g h t e d m u d s is to k e e p m u d weight as low as p o s s i b l e a n d to m a i n t a i n f l o w p r o p e r t i e s . T h u s , v i s c o s i f e r s a r e a d d e d as n e e d e d to u n w e i g h t e d m u d s to c o n t r o l f i l t r a t i o n , to s u s p e n d solids, a n d to p r o v i d e the p r o p e r t i e s n e c e s s a r y to clean t h e b o r e h o l e . T h e d e t r i m e n t a l solids in u n w e i g h t e d m u d s are t h o s e o f u l t r a f i n e size a n d larger, p r o d u c e d by t h e bit. It is essential to have a g o o d solids r e m o v a l system to p r e v e n t solids d i s p e r s i o n a n d m u d d e n s i t y b u i l d u p . Size a n d r a n g e o f solids in u n w e i g h t e d m u d s are shown in F i g u r e 4-117 [29].

Solids in Weighted Muds Solids in weighted muds consist o f viscosifers, weighting material, and drilled cuttings. T h e most expensive p o r t i o n o f weighted mud is the weighting material. T h e main problem related to solids control is the prevention o f viscosity increase caused by accumulation o f colloidal drilled solids. Chemical treatment can be used initially to control this viscosity, but it b e c o m e s ineffective as colloidal solids in the m u d increases. Eventually, m u d d i l u t i o n and mechanical removal o f solids are needed. T h e size range o f solids in a weighted m u d is illustrated in Figure 4-118 [29]. Figure 4-119 through 4-122 can be used to evaluate the extent o f drilled solids c o n t a m i n a t i o n [25].

Drilling Muds a n d C o m p l e t i o n Fluids

695

SCREEN MESH

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4-117, Size range of solids in unweighted m u d s [29].

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Figure

4 - 1 1 8 . S i z e r a n g e of s o l i d s in w e i g h t e d

Mud-Related

Hole

m u d s [29].

Problems

Table 4-58 s u m m a r i z e s g e n e r a l hole p r o b l e m s related to the use of their drilling m u d [25]. Tables 4-59 t h r o u g h 4-61 s u m m a r i z e f o r m a t i o n related hole p r o b l e m s in surface, intermediate, and p r o d u c t i o n drilling, respectively. (text continued on page 701)

696

Drilling and Well Completions

Figure 4-119. Practical limits on solids content in freshwater-base mud [26]. (Courtesy Baroid Drilling Fluids, Inc.)

Figure 4-120. Practical limits on solids content in saltwater mud (75,000 ppm chlorides) [26]. (Courtesy Baroid Drilling Fluids, Inc.)

Drilling Muds and Completion Fluids

Figure 4-121. Practical limits on solids content in saltwater mud (185,000 ppm chlorides) [26]. (Courtesy Baroid Drilling Fluids, Inc.)

.......... ~ ......... ~,~

iTC:

Figure 4-122. Minimum solids content in oil mud [26]. (Courtesy Ba~id

Drilling Fluids, Inc.)

697

698

Drilling and Well Completions Table 4-58 Drilling Fluids: General Trouble Shooting [25]

Problem 1. Mud Properties Mud weight

Viscosity

Filtration

Mud foaming

Symptoms Mud weight too low; low viscosity Mud weight too low; viscosity controlled Mud weight too high

Funnel viscosity too high; high PV; high gels and high solids High funnel viscosity, high YP, high gels; normal PV and solids Fluid loss too high, viscosity can be increased Fluid loss too high, viscosity controlled Fluid loss too high; thick, soft filter cake; low Methylene Blue Test. Treatment with filtration agent does not help Foam on surface at mud pits. No reduction in mud weight Reduction in mud weight. Increased funnel viscosity. Pump pressure drops. Internal foam

2. Contaminations Drilled solids

Cement

Gipsum or anhydrite

High viscosity and gel strength, slow drilling rate, chemical treatment ineffective High viscosity, gel strength, increase in pH, water loss and filtrate calcium.

High viscosity, high flat gel strength; increased water loss, filtrate calcium and sulfate

Treatment Add weighting material and bentonite Add weighting material, bentonite and thinner Run mechanical solids removal equipment. Dilute with water or thin with thinner Run mechanical solids removal equipment, dilute with water Add thinner

Treatment with filtration control agent Treatment with thinner and filtration control agent Add bentonite to the system

Spray water or diesel over the pit surface, use defoamer. Check surface system for air entraintment. Use defoamer. Thin the mud to reduce yield point. Consult mud service engineer. Dilute with water, make use of solids removal equipment. Displace mud. Chemical treatment: (1) Bicarb NaHCO3, (2) Thinner. If large concentration of Ca ions-change to an inhibitive mud Chemical treatment; soda ash Na2CO3 (0.02 ppb at soda ash for every epm of hardness) for drilling massive anhydrite change to gip mud.

Drilling Muds and Completion Fluids

Problem

699

Symptoms

Treatment

Salt rock

High viscosity, high gel strength increased water loss, filtrate chlorides

Salt water

Same as salt rock; increase in pit volume; reduction in mud Excessive viscosity and yield point. YP cannot be lowered with thinner. Increase in 10 min gel strength. Methyl Orange alkalinity Mf > 5

Chemical treatment: (1) thinners--to reduce apparent viscosity, gel strength and yield point; (2) caustic soda--to adjust pH; (3) CMC, filtration control agent. If massive salt is to be drilled--convert to saturated salt water mud. Weight-up to overcome salt water flow. Chemical treatment as for salt rock. Run alkalinity test and calculate CO 3 and HCO 3 ions concentration. Calculate lime required: • to remove CO

Overtreatment with soda ash or calcium bicarbonate

lime, ppb = 0.0013 x epm CO 3 • to remove HCO 3 lime, ppb = 0.026 x epm HCO 3

3. High Pressure Zones Gas/water influx

Gas cutting

4. Lost circulation

Increase in pit volume. Gas or salt water cut mud. Mud flows when pumps are shut off.

Normally shows up as gascut mud after trips. If encountered while drilling, it is usually accompanied by rapid change in filtrate chlorides.

Shut in well. Record drill pipe and casing pressure. Circulate out gas or water influx and separate on surface. Calculate mud weight necessary to balance formation pressure. Kill the well. Add weighting material to rise density. Thin mud with water and thinners. Use degasser to clear gas from mud. Continue to circulate and avoid use of blowout preventers if possible. Keep mud weight as low as possible. Maintain minimum flow resistance of mud. Consider air drilling or foam drilling.

700

Drilling and Well Completions Table 4-58 (continued)

Problem

Symptoms

• to porous formations

A very rapid seepage loss

• to permeable sandstones

Gradual seepage loss

• to cavernous formations

Immediate and complete loss Sudden but not total loss of fluid. It occurs often after trips (induced fractures) when heavy mud is in use. The loss zone is frequently below the deepest casing shoe.

• to fractured formations

5. Pipe stuck Differential sticking

Key-seat Undergauge hole Particles in the hole 6. Hole instability

The drilling string got stuck after remaining motionless in the hole circulation can be broken and continued at normal pressure. Permeable formation is exposed above the bit. The borehole is clean and in good condition. see "Diagnosis of stuck pipe" as above as above While drilling: tourgue, drag, difficulty with making connections, bridging, fill on bottom, stuck pipe, presence of slaughing material in cuttings. After drilling: caliper log shows caving.

Treatment "Gunk" squeeze or a high filtration squeeze 1. Increase colloidal content of mud 2. Add granular or flake LCM If the loss zone is located-a "soft plug" to be spotted. "Blind" drilling (no returns); then set casing or cement. Apply cement squeeze or attapulgite gel-barite squeeze.

1. Try spotting fluids 2. Wash over

Control mud weight to counter balance pore pressure. Keep fluid loss as low as possible. Keep viscosity and gel strength low to prevent swabbing. Convert to: 1) salt-polymer mud, or 2) potassium system, or 3) salinity controlled oil mud.

7. Corrosion • in water base muds

Internal and external pitting

1. Keep pH above 10. 2. Use cationic type inhibition. 3. Identify type of corrosion. 4. Add specific corrosion inhibition.

Drilling Muds a n d Completion Fluids

Problem

Symptoms

• in aerated muds

701

Treatment 1. Keep pH above 11 with caustic soda on line;

Severe pitting, black to red rust

2. Use cationic-type inhibition. 3. Identify type of corrosion contaminant.

4. Treat with specific corrosion inhibition.

8. High temperature High temperature gelatin

Dilute with water and add bentonite. Treat with

Difficult to start circulation. High viscosity and gel strength of mud off bottom. Deceased

thinner. Spot a slurry of mud treated with 1-2 ppb sodium chromate in the high-temperature section of the hole.

alkalinity and increased water loss. Adapted from IADC Drilling Manual, 10th edition, 1982; Courtesy IADC.

(text continued from page 695)

Completion and Workover Fluids Completion a n d workover fluids are those placed against the formation while killing well, c l e a n i n g out, p l u g g i n g back, stimulating, or perforating. T h e i r primary functions are (1) to transfer treating fluid to a particular zone in the borehole, (2) to protect the p r o d u c i n g formation from damage, (3) to control the well pressure d u r i n g servicing operations, (4) to clean the well, and (5) to displace other fluids or cement.

Design Considerations for Completion/Workover

Fluids

While designing completion/workover fluids the main consideration is given to the effect of the fluids on well's productivity. Low p r o d u c t i o n rates can be due to factors that are unrelated to the fluids introduced to the production zone. These would include poor or shallow perforations, cement filtrate invasion, paraffin wax deposition from crude oil, or movement of formation sand to block the well-bore. Productivity damage attributable to drilling or completion fluids results from three mechanisms: • Particulate invasion which blocks the formation pores. • Fihercake can fill u p a n d plug large cracks, fractures or perforations. This is difficult to remove by flowing the well or acidisation. • Filtrate invasion can interact in various ways with solids or liquids in the pores to cause a reduction in flow.

O

Table 4-59 FOILMATIONS

PROBLEMS Caving.

CONTROL A d e q u a t e gel s t r e n g t h to consolidate loose sand. M a i n t a i n filtration r a t e below 15-cc A P I to p r e v e n t h y d r o u s disinteg r a t i o n of shales. P r e v e n t erosion b y a d e q u a t e v i s c o s i t y a n d gel s t r e n g t h . M a i n t a i n sufficient v i s c o s i t y for liftlng c u t t i n g s a n d cavlngs,

t*~CONSOLIDATED

-

S.kN*DS A N D G R A V E L S

L o s t clrculation,

M a i n t a i n colloidal c o n t e n t to p r o v i d e good filtration properties, low d e n s i t y , a n d t h i c k m u d . V i s c o s i t y pill a n d lost circulation materials. C a r e in use of m e c h a n i c a l e q u i p m e n t .

R e t e n t i o n of s a n d in mud. ( W e i g h t build up. S a n d retained in m u d will increase d e n s i t y , w h i c h m a y a g g r a p a t e t e n d e n c y t o w a r d s lost circulation),

L o w e n o u g h v i s c o s i t y a n d gels to allow s a n d to d r o p out in d i t c h a n d [)its b y r e d u c i n g v i s c o s i t y a n d gels w i t h w a t e r dilution a n d chemical treatment. D i t c h a n d t~it arrangemel~t m a y be i m p r o v e d to p r o m o t e sand settling. Mechanical s a n d a n d shale s e p a r a t o r s or centrtfugatlon m a y aid.

Excessive v i s c o s i t y a n d gels. t i g h t hole. sloughing, b y d r o u s disintegration,

Redllce v i s c o s i t y a n d gels; r e d u c e filtration r a t e to p r e v e n t h y d r o u s disi~ttegration or sloughitlg.

ELkRD ROCK.

R e m o v a l of c u t t i n g s f r o m hole.

M a i n t a i n colloidal c o n t e n t h i g h e n o u g h to p r o v i d e gels a n d viscosities a d e q u a t e to r e m o v e c u t t i n g s or p r e v e n t settling. M a i n t a i n sufficient a n n u l a r velocity.

C~LkRGED

P r e s s u r e control.

W e i g h t m u d to give h y d r o s t a t i c pressure a b o v e f o r m a t i o n p r e u u r e . M a i n t a i n low v i s c o s i t y a n d gels for g a s r e m o v a l . K e e p llole full a t all times.

Cement contamination.

I f s a v i n g m u d . t h i n w i t h w a t e r a n d chemicals. I f not s a v i n g m u d . discard c o n t a m i n a t e d m u d a n d m i x fresh m u d .

CLt,"S

J..

crq

Drilling Fluids: Problems in Surface Drilling

I

AND SHALES

S.kND

O

O

Drilling Muds and Completion Fluids

703

Table 4-60 Drilling Fluids: Problems in Intermediate Drilling ~O I~MATI O NS

PROBLEMS

CONTROL

Sloughing. c~viog, heaving.

Employ mud with low filtration rate, low viscosity and gels. Utilize high c o - - a e r a t i o n ol ~lioidal material ~ d thin with chemiads Ule inhibited mud.

H y d r s t i ~ . ~relliog. and dispersion in pre~ence ol ~ n v ~ t i o n a l f~t ~ t ~ .

Maintain minimum f i l t r a t i ~ rate, If possible um chemicals instead of ~ t e r to thin mud. Reprem hydration by presen~ of caidum ion, U ~ oU.base or oil.ba~ emal~ion.

Internal h ~ h p ~ u n .

Maintain adequate m u d density, Maintain thin filter cake. low gel.. W t t h d ~ w bit slowly. Check to soe that hoio is taking mud through the ~ n u l u e .

SHALES

Lubricating effOct of fi~trate or mud on sha/e p l a ~ .

Maintain minimum filtration a t e . U t i l l ~ l ~ t c i r ~ t i o n m a t e r ~ to k ~ p mud in hole,

Overtreatment with cbemlctl thinners. Mud does not respond.

Change type of chemical t hinne~. Change type of mud. Add water. Add new mud,

Weight build up with formation ealid~

Dilute with water. Centrifuge mud. C o n v ~ t to l n h i b i t ~ mud.

Employ chemical thinners and water dilutinu if clay solids a n bigb

SALT OR SALT WATER BEARING FOJUtgATIONS

Chemically reactive shal~, making use of high pH muds difi~ulL

E m # o y low or medium pH mude. Convert to inhibited mud.

Increase in f~tration rate.

Add ~ i l o i d a l material. ChOck for c o n t a m i ~ n t s and if present chemi~lly tr,utt.

Mud-making n ~ i t i n g in Vlst'o~t y #nd gel build up.

Dilute with water. U ~ chemicai t hinner~. U ~ inhibited mud.

Fiooculation of drilling mud.

Prevent or overcome floccuindoa by use of ~ l t - ~ s i s t a n t materials sac chemical t~eatments ~ u l t i o g in salt tolerant m u d s Employ $~It-~slstant muds, Maintain adequate mud density. Add co~ollon kthibltor.

C o - - i o n of drill pip~ P t ~ r e from italt water intrusion. SILTSTONE

Weight build up.

Thin with w a t ~ or chemicals to release ~ n d by reduction in vi~o~ity Maintain adequate coiloide. Centrifuge mud.

Low-pr~n

Employ as light a mud ~ consistent with ~fet y, Use ~ t circu atlon materials if necessary, C h ~ k operation of m ~ h ~ i c a l e~uipment: spudding, bailing, pumt ~ r g ~ etc. S p o t - t r o t with [ ~ t c rculat on rnaterial~

c i ~ i o t i o n lo~es.

SAND

ANHYDRITE AND GYPSWM

Cake b~ihi up-sttenht hole. Dilferenrial 0ticking (wall sticking).

Add ~ l i o i d a l material to r e d u ~ cake thickness. Add su~factants.

High f ~ t ~ t i ~ rate.

Add colloidal material to r e d u ~ ~It~te 1o~

F ] ~ l a t i o n of dsilling mud. High fiat gels. High f~trasion rate. High viY~sity.

Cbemica y treat to counte~ct gypsum and anhydrite flio~.lation EmDioy mud t o k ~ n t to gypsum and anhydrite ~ntamtrmt on.

Add colloidal material. Employ lost ci~uiotion material~. Drilling with ~ t e r m y be feasible. Dr ng with a r or l a g may be f ~ i b l e , d Check ope~tion o mechanical equipment. Do not i e n e ~ t e flu p r o s u n ~ r g ~ by s~idding, going m hole rapidly, or starting ~ m ~ rapidly.

LI MF~TONE

H A R D ROCK (Schiot, t l n e o u e , etc.)

Transgorintioa of cuttings.

Iacrc~e v ~ m t y and g ¢ ~ Employ l o g rJrcuiotlon m t c f l a l . UN ioweJt density mud possible. Drilling with air or gas ~ y be fea~iole, C ks'ok operation of mechanical equipment. Prevent fluid l~ewmre ~ r g e L

~BJtCTUB~D FO~k~A'rl ON AND CONGLO MERATE8

MIBCELLANEOUS SALTBEARING frO JUtgATIONS M~we~um and ¢~d~um cmor~de. Magnesium a:~d c~dctum su~ate and off.

GAS AND OIL BEARING IrOIU4ATIONS

Incnmse alscotlry and gels by addltinn of colloidal ~ t e r i a ~

Floccuiot/ou of d r i l l ~ g mud. Co~oelon of drill ~pe.

Employ dr illiogmud not su~eptlble to flx~cculatlon. Chemical treatments t~mlting m salt t o l e ~ n t muds. Add c~rosion inhibitor much as X-COR.

BIowout~ G ~ u t mad.

Add weight mateflmls to r a l ~ de,sit y of drilling mud. Thin mud witb ~ t e r and thinners to permit r e ~ e e of entmioed~gage. 1ncve~e g u removal efficient y in ditches and pits: by changing deaden; e ~ e n t 0tirring, dega~lng riffles and vacuum e e ~ a t o r s .

Protection of formatio~.

Lover f~tmtion ~ t e and cake thickn¢~. Use I n - - t e d emulsion mud. Use OR base mud.

The invasion of particles can be eliminated either by using solids-free systems or by formation of a competent filter cake on the rock surface. If the components forming the filter cake are correctly chosen and blended, they will form a very effective "downhole" filter element. This ensures that colloidal sized clays or polymeric materials are retained within the filter cake and do not enter the formation. Further protection is provided by ensuring that a thin filter cake is formed due to low dynamic and static filtrate losses. Thus, the cake may be easily removed when the well is brought into production. Additionally, the filter cake can be soluble in acid or oil.

~CL

C~

Table 4-61 Drilling Fluids: Problems in Production Drilling CONTROL

PROBLEMS

FORMATIONS

Loss of c r u d e or diesel oil used as completims fluid.

M i n i m u m f i l t r a t i o n r a t e w a t e r - b a s e muds. M i n i m u m filtration rate water-base emulsions. M i m i n u m f i l t r a t i o n r a t e oil-base emulsions. Oil-base muds. Inhibited muds. M i n i m u m weight muds. C r u d e oil or diesel oil. A d d oil-soluble lost c i r c u l a t i o n m a t e r i a l .

Normal P r e s s u r e .

W a t e r or m u d b l o c k i n g , Screen plugging.

b l i n i m u m fihration rate muds. T h i n f r i a b l e filter c a k e s .

High Pressure.

Blowout prevention.

Maintain adequate mud density. M a i n t a i n hole full of m u d to p r e v e n t r e d u c e d h y d r o s t a t i c h e a d r e s u l t i n g f r o m s h o r t c o l u m n of m u d . W i t h d r a w tool~ s l o w l y to p r e v e n t s w a b b i n g a c t i o n .

SANDS

W a t e r or m u d b l o c k i n g .

L o w pressure.

Limestones. C o r a l reef. Dolomite. F r a c t u r e d shales. C o n g l o m e r a t e s a n d schists. Shales.

Lost C i r c u l a t i o n .

M a i n t a i n low gels a n d t h i n filter c a k e .

Formation Protectiu~.

D R I L L I N C r - - I n c l u d e s m u d s used before s e t t i n g c a s i n g . S t a r t i n g m u d s should m a i n t a i n a c l e a n , < o m p e t e n t hole a t r e a s o n a b l e cost. T h e p u m p v o l u m e s h o u l d c o n t r o l l e d to r e m o v e c u t t i n s w i t h o u t w a s h i n g o u t f o r m a t i o n s . . . . . . . . . . . . Ibe~'Pm'~Mm'rt|ATm• t ~ T l . l . l ~ g ~ I n e l , d e s m u d l used for dr/Sling b e t w e e n s u r f a c e c a s i n g a n d c o m p l e t i o n . A c c o u n t s for g r e a t e s t f o o t a g e a.na m s t e s t clrm~r~g U m e . - ~ u a . : , - - ~ : . . . . .,-x.~.~.- .~.. . . . . . . .-:::-__ .J,.-_ ~ L....... " : - - t r o u b l e s t h u s e x t e n d i n = t h e " s t r a i g h t d r i l l i n g " f o o t a g e a n d a~sowmg oxt to s t a y on n o , t o m xor m a z l ~ o u l d SpeL~l OrXllXngDy r e m o v i n g cuT.tings r~plu~y a n u u y vs~v~s~Jss * ~ . . . . . . . . rinds M e c h a m c a l c o n m d e r a t m n s i n c l u d e p r o p e r d r i l l i n g w e i g h t s for d r i l l s t e m design" a v o i d a n c e of d r i l l pspe compressson s e c t m n s to r e a u c e nose e n l a r g e m e n t s m u m pe • " " " • , ~, - ~ , ~ p r . ~ I N c . I n c l u d e s m u d s to p r o v i d e a c l e a n f u l l - g a u g e h o l e l n t o t h e p r o d u c i n g l h o r t e n i n g of b i t r u n s w h e r e d r i l l p i p e in t e n s i o n m i g h t c u t ,,vail o! song s h a l e seCtlon~. ~ v . . . . . . . . . . . -- -f o r m a t i o n , w i t h a m a x i m u m of s a f e t y a n d a m i n i m u m of i n t e r f e r e n c e w i t h p r o d u c t i o n ,

SURFACE

.

.

.

.

.

.

.

0

Drilling Muds and C o m p l e t i o n Fluids

705

T h e filtercake p l u g g i n g of p e r f o r a t i o n s or fractures is usually difficult to remove t h r o u g h acidizing or backflowing. T h e solutions are: • use of solids-free b r i n e ° use of b r i d g i n g solids that are a c i d / o i l soluble • use of commercial b r i d g i n g materials (large fractures or p e r f o r a t i o n s ) T h e compatibility of invading fluids with pay zone rocks may relate to swelling clays, water blocking, or emulsion blocking. In many sandstone reservoirs there are a g g l o m e r a t i o n s of clay minerals and o t h e r fine f o r m a t i o n particles are in equilibrium with the p o r e fluids. If the existing b r i n e is displaced with a lower salinity f l u i d from the Completion fluid, swelling clays such as m o n t m o r i l l o n i t e or some illites can expand, and non-swelling clays such as kaolinite can disperse. T h e swelling and disaggregation can lead to a blocking of the pores. In the water-blocking m e c h a n i s m large volumes of i n v a d e d liquid may be retained by low permeability or low-pressure formations. T h e blocking may occur for an oil wet and a water wet sandstones. T h e design factors to prevent blocking involve the use of low-viscosity fluids with m i n i m u m interracial tension, m i n i m u m capillary pressure, and m i n i m a l f l u i d loss. T h e emulsion blocking mechanism involves formation of emulsion in the pores either by self-emulsification of water-based filtrate with the c r u d e oil, or oil filtrate from an oil-based f l u i d emulsifying f o r m a t i o n water. T h e emulsions are viscous and can block the pores. T h e remedial design is to prevent emulsification either by eliminating oil from c o m p l e t i o n f l u i d or by the use of demulsifiers. C o m p o n e n t s in the invading water-based filtrate and in the f o r m a t i o n waters may react to form insoluble precipitates which can block the pores and give rise to skin damage. T h e scale can be f o r m e d by interaction of calcium-based brines with carbon dioxide or sulfate ions in the f o r m a t i o n water. Alternatively sulfate i o n s in t h e i n v a d i n g f l u i d may r e a c t with c a l c i u m or b a r i u m i o n s in t h e formation water. Analysis of the f o r m a t i o n water can identify whether such a p r o b l e m may arise. Table 4-62 contains a checklist for proper selection of completion/workover fluids.

Completion/Workover Fluid Systems Selection of c o m p l e t i o n / w o r k o v e r fluid system is entirely d e p e n d e n t u p o n its function, which, in turn, d e p e n d s on the c o m p l e t i o n m e t h o d . T h e m e t h o d may involve u n d e r r e a m i n g , gravel packing, p e r f o r a t i o n , or workover. C o m p l e t i o n fluids used for u n d e r r e a m i n g have to display f o r m a t i o n b r i d g i n g and low spurt loss and filtrate loss to s u p p o r t the sand and prevent sloughing. Because the filter cake will be t r a p p e d between the gravel pack and the formation, the f l u i d should be c o m p o s e d of particles, soluble in acid or oil, and small enough not to bridge off the gravel pack when the well is flowed. Gravel packing c o m p l e t i o n fluids should exhibit sufficient viscosity to c a r r y a n d place the gravel efficiently. However, high gel strengths for p r o l o n g e d suspension are not necessary. Thus the p o l y m e r solution can easily flow out of the pack on production. Also, the solution can be formulated with a breaker ( e n z y m e or oxidizer) such that the viscosity is c o m p l e t e l y b r o k e n allowing c o m p l e t e cleanup. Normally, filtrate loss control is not employed in the gravel c a r r y i n g fluid. Low-density p e r f o r a t i n g c o m p l e t i o n fluids for u n d e r b a l a n c e d p e r f o r a t i o n greatly reduce the possibilities of plugging. If overbalance p e r f o r a t i o n is needed,

706

Drilling and Well Completions Table 4-62 Checklist of Completion and Workover Fluids Considerations [26]

Factor Considered 1. Mechanical Annular velocity

Completion and Workover Fluid Considered Higher annular velocity-low viscosity system or low annular velocity-higher viscosity systems can be selected. Annular velocity can be substituted for viscosity in lifting particle. Annular velocity at 150 ft/min should be sufficient for borehole cleaning with 1 cp viscosity clear salt water.

Mixing facilities

If mixing facilities are poor to produce adequate shear, the completion/workover fluid should be prepared and maintained with very small amounts of material.

Annular space

The size of bottom hole equipment (liners, packers, etc.) reduces annular space and increases pressure losses. The fluid must maintain rheological properties which reduce pressure losses.

Circulation frequency

In the completion and workover operations, there are long periods when fluid in the hole is not circulated. Fluid suspension and thermal stability should be determined in order to evaluate the necessary circulation frequency.

Corrosion

Some workover fluids can produce high corrosion rates. Corrosion control can be accomplished through H control, inhibitors or bactericides. The practical corrosivity limit is 0.05 Ib/fF per operation.

Fluid components

Solubility at fluid components at the well bore conditions (pressure and temperature) should be considered. Glazing at jet and bullet tracks should not occur while perforating.

2. Formation Permeability damage

Fluid solids should be kept as low as possible. Fluid should not contain solids larger than two microns in size unless bridging material.

Formation pressure

Density control with calcium carbonate, iron carbonate, barium carbonate, ferric oxide.

Clay content

Fluid inhibition with electrolyte additive.

Vugular formation

In order to prevent "seepage loss" of circulation to the vugular formation, bridging the formation--by properly sized, acid-soluble on oil-soluble resin particles as well as colloidal particles--should be considered.

Formation sensitivity

Formations can be oil wet or water wet. The fluid filtrate depends on what is the continuous phase of the completion fluid. Thus the formation wettability can be reduced by wettability charge. This effect can be controlled either by proper fluid selection or by treatment with water wetting additives.

Temperature

In high temperature wells, the temperature degradation of polymens should be considered.

Drilling Muds and C o m p l e t i o n Fluids

Factor Considered 3. Fluid properties Density

707

Completion and Workover Fluid Considered Ideal requirements: Fluid density should not be greater than that which balances formation pressure. Practical recommendation: Differential pressure should not exceed 100-200 psi.

Solids content

Ideal requirements: no solids in completion and workover fluids. Practical recommendation: Solids smaller than two microns can be tolerated as well as the bridging solids. The bridging solids should be: (1) greater than one-half of the average fracture diameter; (2) readily flushed from the hole; acid or solvent soluble.

Fluid loss

Ideal requirements: no fluid loss. Practical recommendations: Fluid loss to the formation can be controlled by: (1) fluid-loss agents or vixcositiers such as polymens, calcium carbonate, gilsonit, asphalt etc., (2) bridging materials.

Rheology

Ideal requirements: low viscosity with the yield point and gels necessary for hole cleaning and solids suspension. Practical recommendation: A compromise should be found to minimize pressure losses and bring sand or cutting to the surface at reasonable circulating rate.

Courtesy BaroidDrilling Fluids, Inc.

low damaging fluids are r e c o m m e n d e d and often a solids-free fluid is preferred. T h i s is b e c a u s e f i l t e r cake f r o m a high solids f l u i d can c o m p l e t e l y fill a p e r f o r a t i o n and be difficult to remove on back flowing or acidizing. Perforating u n d e r diesel is sometimes employed. In this case, care is necessary to ensure that g o o d displacement o f the previous d e n s e r fluid occurs, and the c o m p l e t e d zone remains in contact with the diesel without density swapping. Perforating fluids used may be filtered clear b r i n e or CaCO~ type c o m p l e t i o n fluids, oil, seawater, acetic acid, gas or mud. W h e r e large losses to the f o r m a t i o n are probable, p e r f o r a t i o n u n d e r slugs containing d e g r a d a b l e b r i d g i n g and loss control materials is advised. At least, such materials should be on hand should the need arise. U n d e r these conditions, it is far better to fill p e r f o r a t i o n s with good, degradable, b r i d g i n g material than the c o m m o n mixture o f iron and rust particles, mud solids, and excess pipe dope. These foreign solids may be also not exhibit bridging and be injected into the rock a r o u n d the perforations, causing i r r e p a r a b l e damage. Clear Brines. Brine solutions are m a d e from f o r m a t i o n saltwater, seawater, or bay water, as well as from p r e p a r e d saltwater. They do not contain viscosifers or w e i g h t i n g m a t e r i a l s . F o r m a t i o n water-base f l u i d s s h o u l d be t r e a t e d for emulsion f o r m a t i o n and for wettability problems. They should be checked on location to ensure that they do not form a stable emulsion with the reservoir

708

Drilling a n d Well C o m p l e t i o n s

oil, a n d that they do not oil or wet the reservoir rock. T h e usual t r e a t m e n t includes a small a m o u n t (0.1%) o f the p r o p e r surfactant. S e a w a t e r o r bay w a t e r b a s e c o m p l e t i o n f l u i d s s h o u l d b e t r e a t e d with bactericides to inhibit bacterial growth. Since these fluids usually contain clays, i n h i b i t i o n with NaC1 or KC1 may b e n e c e s s a r y to p r e v e n t p l u g g i n g o f t h e p r o d u c i n g formation. P r e p a r e d saltwater c o m p l e t i o n fluids are m a d e o f fresh surface water, with sufficient salts a d d e d to p r o d u c e the p r o p e r salt c o n c e n t r a t i o n . Usually, the a d d i t i o n o f 5 to 10% NaC1, 2% CaC12, or 2% KC1 is c o n s i d e r e d satisfactory for clay i n h i b i t i o n in m o s t f o r m a t i o n s . S o d i u m c h l o r i d e s o l u t i o n s have b e e n extensively used for many years as c o m p l e t i o n fluids; these brines have densities up to 10 l b / g a l . Calcium chloride solutions may have densities up to 11.7 l b / gal. T h e l i m i t a t i o n s o f CaC12 s o l u t i o n s are (1) f l o c c u l a t i o n o f certain clays, c a u s i n g p e r m e a b i l i t y r e d u c t i o n , a n d (2) h i g h p H (10 to 10.5) t h a t may a c c e l e r a t e f o r m a t i o n clays dispersion. In such cases, CaC12-based c o m p l e t i o n fluids should be replaced with potassium c h l o r i d e solutions. O t h e r clear brines can be formulated using various salts over wide range o f densities, as shown in Figure 4-123 [28].

MgCl2

I

ZnBrJCaBr2 8

9

10

"Patents applied for by I.D.F.

11

12

13

14

15

16

17

18

19

20

BRINE DENSITY DPg

Figure 4-123. Salts used in clear brine completion fluids of various densities

[28]. (Courtesylnternational Drilling Fluids, Inc.)

Drilling Muds and C o m p l e t i o n Fluids

709

Material requirements for brine solutions are given in Tables 4-63 through 4-65. Brine-polymer systems are c o m p o s e d o f w a t e r - s a h solutions with polymers a d d e d as viscosifers or filtration control agents. If fluid loss control is desired, b r i d g i n g material must be a d d e d to build a stable, low p e r m e a b i l i t y b r i d g e that will prevent colloidal partial movement into the formation. T h e polymers used for c o m p l e t i o n and workover fluids may be either natural or synthetic polymers. G u a r g u m is a natural polymer that swells on contact with water a n d thus p r o v i d e s viscosity a n d f i l t r a t i o n control; it is u s e d in concentrations o f 1 to 3 l b / b b l . G u a r gum forms a filter cake that may create

Table 4-63 Material Requirements for Preparing Sodium Chloride Salt Solutions (60°F) Density Ib/gal 8.33 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0

Fresh Water (gal/final bbl)

Sodium Chloride (Ib/final bbl)

42 41.2 40.5 40.0 39.5 39.0 38.5 38.0 37.5

0 16 28 41 54 68 82 95 110

Based on 100% purity.

Table 4-64 Material Requirements for Preparing Calcium Chloride Solutions (60°F) Density Ib/gal 10.0 10.2 10.4 10.6 10.8 11.0 11.2 11.4 11.6 11.8 Based on 95% chloride.

Fresh Water (gal/flnal bbl)

Calcium Chloride (Ib/final bbl)

39.0 38.5 38.0 37.5 37.0 36.5 36.0 35.5 35.0 34.0

95 107 120 132 145 157 170 185 197 210

710

Drilling and Well Completions Table 4-65 Material Requirements for KCI Solutions (60°F) Density ppg 8.42 8.64 8.86 9.09 9.32 9.56 9.78

Fresh Water gal/bbl final

Potassium Chloride Ib/bbl final

41.7 41.0 40.2 39.4 38.6 37.6 36.7

7.0 21.1 35.2 53.6 70.5 88.2 105.0

problems for squeeze cementing, but is removed with production and increasing temperatures. Starch is also used for fluid loss control. It does not provide carrying capacity; therefore other polymers are required. Although starch is relatively cheap, it has two serious limitations: (1) starch is subject to fermentation, and (2) it causes significant permeability reduction due to plugging. The synthetic polymers commonly used in completion fluids are HEC and Xanthan gum (XC Polymer). Xanthan gum is a biopolymer that provides good rheological properties and that is completely soluble in HC1. HEC-hydroxyethyl cellulose is currently the best viscosifer. It gives good carrying capacity, fluid loss control, and rheology; it is completely removable with hydrochloric acid. The effect of HC1 on the restored permeability for HEC completion fluid is shown in Figure 4-124 and Table 4-68 [36]. It can be noticed that 100% of the original core permeability was restored by displacing acid-broken HEC with brine. The comparison of permeability damage caused by different polymers is given in Table 4-69 [36]. The bridging materials commonly used in completion and workover fluids are ground calcium carbonate, gilsonite, and asphalt. These materials should demonstrate uniform particle size distribution and be removable by acid or by backflow. Their mesh size should enable them to flush through the gravel pack; a mesh size of 200 is considered satisfactory for most completions. Calcium carbonate bridging materials are completely soluble in hydrochloric acid. Resins give effective bridging; they are soluble in oil solutions (2% by volume oil). A typical formulation of a brine-polymer completion fluid might include 8.5 to 11 lb/gal salt water solution (NaC1, CaC12, KC1, or a mixture), 0.25 to 1.0 lb/bbl polymer and 5 to 15% calcium carbonate. Density control in brine-polymer systems can be achieved with salt solutions or with weighting materials. When mixing heavy brine completion fluids, the following factors should be considered: 1. 2. 3. 4.

Cost--heavy brines are very expensive. Downhole temperature effect on the brine density--Table 4-69 [26]. Crystallization temperature--Figure 4-125 [37]. Corrosion--various salts have different acidities (pH of brine can be controlled with lime, caustic soda, or calcium bicarbonate). 5. Safety--burns from heat generated while mixing and skin damage should be prevented. 6. Toxicity--dispersal cost depends on type of salt and concentration.

Drilling Muds and Completion Fluids Table 4-66 Mixing Chart for Zinc Bromide/Calcium Bromide Solution Blend 13.7 Ib/gal CaBr2/CaCI2+ 19.2 Ib/gal ZnBr2/CaBr2 Desired Barrels Barrels Crystallization Brine 13.7 Ib/gal 19.2 Ib/gal Point Density Ib/gal CaBr2/CaCI 2 ZnBr2/CaBr2 (F) (C) 15.0 15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8 15.9 16.0 16.1 16.2 16.3 16.4 16.5 16.6 16.7 16.8 16.9 17.0 17,1 17.2 17.3 17.4 17,5 17.6 17.7 17.8

O. 7636 O. 7454 0.7273 0.7091 0.6909 0.6727 0.6545 0,6364 0.6182 0.6000 0.5818 0.5636 0.5454 0.5273 0.5091 0.4909 0.4727 0.4546 0.4364 0,4182 0.4000 0.3818 0.3636 0.3455 0.3273 0.3091 0.2909 0.2727 0,2546

0.2364 0.2546 0.2727 0.2909 0.3091 0.3273 0.3455 0.3636 0.3818 0.4000 0.4182 0.4364 0.4546 0.4727 0.4909 0.5091 0.5273 0.5454 0.5636 0.5818 0.6000 0.6182 0.6364 0.6545 0.6727 0,6909 0.7091 0.7273 0,7454

46 43 40 38 36 34 32 30 28 25 22 19 16 13 9 3 4 9 14 19 23 23 23 24 24 25 25 25 26

7 6 4 3 2 1 ± 0 - 1 - 2 - 3 - 5 - 7 - 8 - 10 - 12 -16 -15 - 12 - 10 - 7 - 5 - 5 - 5 - 4 - 4 - 3 - 3 - 3 - 3

17.9 18.0 18,1 18.2 18,3 18,4 18,5 18.6 18.7 18.8 18.9 19.0 19.1 19.2

0.2364 0.2182 0.2000 0,1818 0.1636 O. 1455 0.1273 0.1091 0.0909 0.0727 0.0545 0.0364 0.0182 0.0000

0,7636 0.7818 0.8000 0,8182 0.8364 0.8546 0.8727 0.8909 0.9091 0.9273 0.9455 0,9636 0.9818 0.1000

26 27 27 27 25 25 25 22 21 21 20 19 17 16

-

Courtesy Halliburton Co.

3 2 2 2 3 3 3 5 6 6 6 7 8 8

711

712

Drilling and Well Completions Table 4-67 Mixing Chart for Heavy Brines Using Calcium Bromide and Calcium Chloride Brines and Calcium Chloride Pellets Brine Density Desired

Pounds Barrels Barrels Calcium Crystallization 14.2 Ib/gal 11.6 Ib/gal Chloride Point CaBr2 Brine 38% CaCI2Bdne Pellets (F) (C)

11.7

.0254

9714

2.86

50

10

11.8

.0507

9429

6.06

52

11.1 11.6

11.9

.0762

.9143

9.09

53

12.0

.1016

.8857

12.13

54

12.2

12.1

.1269

.8572

15.15

55

12.7

12 2

.1524

8286

18.18

56

13.3

12.3

.1778

.8000

21.22

56.5

13.6

12.4

.2032

.7715

24.24

57

13.8

I2.5

2286

.7429

27.28

575

14.1

12.6

.2540

.7143

30.31

58

14.4

12.7

.2794

.6857

33.34

58.5

14.7

12.8

.3048

,6572

36.37

59

15.0

12.9

.3302

.6286

39.41

59.5

15.2 15.5

13.0

.3556

.6000

42.44

60

13.1

.3810

.5714

45.47

60

15.5

13.2

.4064

.5429

48.49

60.5

15.8

13.3

.4318

.5143

51.53

61

16,1

13.4

.4572

.4857

54.56

61

16.1

13,5

.4826

.4572

57.59

61.5

16.3

13.6

.5080

.4286

60.62

61.5

16.3

13.7

.5334

.4000

63.66

61.5

16.3

13.8

.5589

.3714

66.69

61.5

163

13.9

,5842

.3429

69.72

61.5

16.3

14.0

.6069

.3143

72.75

62

16.6

141

,6351

.2857

75.78

62

166

14.2

.6604

2572

78.81

62

16.6

14.3

.6858

.2286

81.84

62

16.6

14.4

.7113

.2000

84.88

62.5

16.9

14.5

.7366

.1715

87.90

63

17.0

14.6

.7620

.1429

90.94

63.5

17.5

14.7

.7875

1143

93.97

84

17.7

14.8

.8128

.0858

96.99

65

18.3

14.9

.8382

.0572

100.03

66

18.8

15.0

.8637

.0286

103.06

67

19.4

15.1

.8891

.0000

106.10

68

20.0

Courtesy Halliburton Co.

Drilling Muds and Completion Fluids

713

IO00 -

50C ~"

==

~

!

~-~-'T=J

!

.~ I000 43% OF ORIGINJ . P~IERMEABILITY

I I 1

500I

G

I00

_J

1 I -4 too% OF ORIGINAL PERMEABILITY .J

I

r"

¢o

io(

50

I I

5( HEC" HYDROXYETHYLCELLULOSE

IC

I el t } ~00 2(20 300 CUMULATIVE INJECTION, PV A, Effect of unbroken HEC solution on permeability of Cypress sandstone.

I I

I t

i I

I I

I I

] l

I I

I I

I t

HEC=HYDROXYETHYLCELLULOSE

I

I

I00

I I1

II

200

I

l

I

Ii

300

CUMULATIVE INJECTION, PV B. Effect of acid-broken HEC solution on permeability of Cypress sandstone.

Figure 4-124. Effect of HCI on HEC on permeability damage caused by completion fluid [36]. (Courtesy SPE.)

Effect of Polymers

Core Type 2,400-md Cypress sand 740-md Cypress sand 230-md Berea sand 4-md Bedford lime 740-md Cypress sand 740-md Cypress sand 740-md Cypress sand 230-md Berea sand 4-md Bedford lime 740-md Cypress sand

Table 4-68 on Core Permeability

P o l y m e r Solution (in 50-percent brine)

0.3% Polyoxyethylene 0.3% Polyoxyethylene 0.3% Polyoxyethytene 0.3% Potyoxyethylene 0.4% HEC 0.4% HEC acid 0.4% guar gum 0.2% guar gum 0.1% guar gum 0.4% guar gum + enzyme breaker

[36]

P e r c e n t of Original Permeability to B r i n e * (forward)

P e r c e n t of Original Permeability to B r i n e * (reverse)

100 100 1 O0 1 O0 15 76 1 17 6 10

100 100 1 O0 1 O0 43 92 25 30 15 54

*Permeability to 5-percent brine measured after resaturating core with brine for a period ranging from 2 to 24 hours following the polymer flood. Courtesy SPE.

714

Drilling and Well Completions Table 4-69 Fluid Density Adjustment for Downhole Temperature Effect [26]

Surface-measured density

Loss in density per 100°F rise in average circulating temperature above surfacemeasured temperature

Ib/gal

sp gr

Ib/gal

sp gr

8.5 9 10 11 12 13 14 15

1.020 1.080 1.201 1.321 1.441 1.561 1.681 1.801

0.35 0.29 0.26 0.23 0.20 0.16 0.13 0.12

0.042 0.035 0.031 0.028 0.024 0.019 0.016 0.014

CourtesyBaroid DrillingFluids,Inc.

CaCI2

/

+60 u_ +40

t< rr

KCl •

+20

IO~-

N

//

~ -20 -40

4ac,

-60 8

9

10

11

12

13

14

DENSITY, ppg

Figure 4-125. Crystallization temperature of various brines [37]. Weight materials commonly used in completion fluids are given in Table 4-70. Although they add solid particles to the fluid, their use can be economical where densities exceed 11.0 lb/bbl. Oil-Base Systems. Oil-base completion and workover fluids contain oil as the

continuous phase. Their application is limited by their density to formations with

Drill String: Composition and Design

715

Table 4-70 Density Increase with Weighting Materials Material

Specific Gravity

Practical Weight Increase, ib/gal

CaCO 3 FeCO 3 BaCO 3 Fe2CO 3

2.7 3.85 4.43 5.24

3.5 6.5 8.0 10.0

pressure gradients lower than 0.433 psi/ft (freshwater gradient). Weighted oil muds cannot be used for completion operations since they form mud plugs while perforating. Most of the oil-base systems contain asphalt that can plug the formation and reverse its wetting characteristic (from water-wet to oil-wet). Moreover, oil-based fluids are expensive. Their use can be justified. However, in oil-producing formations where water base fluids would cause serious permeability damage due to clay problems, or high-condensate gas wells oil-base fluids are feasible. In these formations the produced fluids will clean up the oil filtrate.

Foam Systems. The preparation, composition, and maintenance of foam completion and workover fluids is similar to that of foam drilling fluids. The advantage of foam is the combination of low density and high lifting capacity at moderate flow rates. The use of foam as a completion fluid can be justified by: 1. 2. 3. 4. 5.

Low hydrostatic pressure (0.3 to 0.6 psi). Circulation with returns where other fluids have no returns to the surface. Easy identification of formation fluids. No inorganic solids; other solids are discarded with the foam at the surface. In wells with sand problems, faster operation and more complete sand removal. 6. The ability to clean out low pressure wells without killing them.

The limitations of foam are (1) operational complexity, (2) high cost, and (3) the pressure effect on foam consistency, i.e., below about 3,000 ft, foam com-presses to a near liquid form.

DRILL STRING: COMPOSITION AND DESIGN The drill string is defined here as a drill pipe with tool joints and drill collars. The drill stem consists of the drill string and other components of the drilling assembly that includes the kelly, subs, stabilizers, reamers as well as shock absorbers, and junk baskets or drilling jars used in certain drilling conditions. The drill stem (1) transmits power by rotary motion from the surface to a rock bit, (2) conveys drilling fluid to the rock bit, (3) produces the weight on bit for efficient rock destruction by the bit, and (4) provides control of borehole direction. The drill pipe itself can be used for formation evaluation (Drill Stem TestingDST), well stimulation (fracturing, acidizing), and fishing operations.

716

Drilling and Well C o m p l e t i o n s

Therefore, the drill string is a f u n d a m e n t a l part, p e r h a p s one of the most i m p o r t a n t parts, o f any drilling activity. T h e schematic, typical a r r a n g e m e n t of a drill stem is shown in Figure 4-126. Drill Collar

T h e term "drill collar" originally derives from the short sub originally used to connect the bit to the drill pipe. M o d e r n drill collars are each about 30 ft in length, and the total length of the string of drill collars may range from about 100 to 700 ft a n d more.

I ROTARY BOX ~ , CONNECTION L . H . " ' ~

~

!

SWIVEL

ROTARY BOX CONNECTION'''~'~ =i~'J i

~TOOLJOINT

BOXMEMBER

U

SWIVEL STEM

I"I'11DRILL P PE

ROTARY PIN CONNECTIONL.H.~ t

SWIVEL SUB

'

STi 8A

ROTARY BOX CONNECTIONL H . ~

STD 7 KELLY COCK (OPTIONAL) i

ROTARY PiN CONNECTIONL,H.~

t

ROTARYBOX CONNECTO I N L.H,~ UPPERUPSET

, l!llT

~ ROTARY PiN ~

jJOOLJOINT PINM E M B E R

CONNECTION~ _ ~ ROTARY B O X ~ CONNECTION ROTARY PIN CONNECTION

CROSSOVERSUB

ROTARYB O X - - ~ ONN TON li! ?OLL COLLAR

(SOUAREORHEXAGON)

ALL CONNECTIONS BETWEEN " L O W E R UPSET"OFKELLY AND "BIT" ARE R.H.

~

ROTARY PiN CONNECTION

ROTARYBOX

LOWERUPSET

ROTARY PIN CONNECTION ROTARY B O X ~

KELLYCOCKOR

CONNECTION

CONNECTION~ K E L'L~YRaU~BI ~BpEPROTECToRSAVER jR ~ SUB (OPTIONAL) ROTARY PiN CONNECTION~

I ql ]

ROTARYBOX. _ . ~ . ~ CONNECTION ROTARY P I N ~ CONNECTION

BIT SUB jIBIT

F i g u r e 4 - 1 2 6 . Typical drill-stem assembly [13]. Requirements on swivel and swivel sub connections are included in API spec 8A.

Drill String: C o m p o s i t i o n a n d Design

717

Basically, the p u r p o s e o f drill collars is to furnish weight on bit. However, both size a n d length o f drill collars have an effect on bit p e r f o r m a n c e , hole deviation, a n d drill pipe service life. Drill collars may be classified according to the shape o f their cross-sections as r o u n d drill collars (conventional drill collars), square drill collars, or spiral drill collars (drill collars with spiral grooves). Square drill collars are used to increase the stiffness o f the drill string a n d are r e c o m m e n d e d for drilling in c r o o k e d hole areas. T h e spiral type o f drill collar is used for drilling formations in which the differential pressure can cause sticking o f drill collars. T h e spiral grooves on the drill collar side reduce the area o f contact between drill collar a n d wall, which considerably reduces the sticking force. Conventional drill collars are m a d e with u n i f o r m outside d i a m e t e r a n d with slip a n d elevator recesses. Slip a n d elevator recesses are designed to reduce drill collar h a n d l i n g time while t r i p p i n g by eliminating lift subs a n d safety clamps. However, the risk o f drill collar failure for such a design is increased. T h e slip a n d elevator recesses may be used together or separately. Dimensions, physical properties, a n d unit weight o f new, conventional drill collars are specified in Tables 4-71, 4-72, a n d 4-73, respectively. Technical d a t a on square a n d spiral drill collars are available from manufacturers.

Selecting Drill Collar Size Selection o f the p r o p e r outside a n d inside d i a m e t e r o f drill collars is usually a difficult task. Perhaps the best way to select drill collar size is to study results o b t a i n e d from offset wells previously drilled u n d e r similar conditions. T h e most i m p o r t a n t factors in selecting drill collar size are: 1. bit size 2. coupling d i a m e t e r o f the casing to be set in a hole 3. f o r m a t i o n ' s t e n d e n c y to p r o d u c e s h a r p changes in hole d e v i a t i o n a n d direction 4. hydraulic p r o g r a m 5. possibility o f washing over if the drill collar fails a n d is lost in the hole

To avoid an a b r u p t change in hole deviation (which may make it difficult or even impossible to run casing) when drilling in c r o o k e d hole areas with an unstabilized bit a n d drill collars, the required outside diameter o f the drill collar placed right above the bit can be found from the following formula [38]: Ddc = 2(casing coupling OD) - bit OD

(4-49)

Example The casing string for a certain well is to consist o f 13 {-in. casing with coupling outside d i a m e t e r o f 14.375 in. D e t e r m i n e the required outside d i a m e t e r o f the drill collar in o r d e r to avoid p o s s i b l e p r o b l e m s with r u n n i n g casing if the b o r e h o l e d i a m e t e r is assumed to be 17 { in. Ddc = 2(14.375) - 17.5 = 11.15 in. Being aware of standardized drill collar sizes, an 11 or 12-in. drill collar should be selected. To avoid such large drill collar OD, a stabilizer or a proper-sized square drill collar (or a c o m b i n a t i o n o f the two) should be placed above the

Drilling and Well C o m p l e t i o n s

718

Table 4-71 Drill Collars [13] (all dimensions in inches)

1

2

Drill Collar Number*

3 Bore, -b ~ - 0 d

Outside Dia, D

4 Length, ft. -+6 m. L

5

6

Bevel Dia, -+~ D,

Bendi~g Strengal~ Ratio

NC$3-31 (tentative)

31/b

11,~

30

3

2.57:1

NC26-35 ( 2 % I F ) NC31-41(2~.(~/F) NC35-47 NC38-50(3½/F)

3½ 4% 4~ 5

t½ 2 2 2~A

30 30 30 30

31] 3g~ 4~t 4~|

2.42:1 2.43:1 2.58:1 2.38:1

NC44-60 NCA4-60 NC44-62

6 6 61A

2~

2{|

30 or 31 30 or 31 30 or 31

5`}~ 5{~ 5%

2.49:1 2.84:1 2.91:1

NC46-62(4IF) NC46-65 ( 4 I F ) NC46-65(4IF) NC46-67(4IF)

61./4

2{I

6~ 61~ 6~

21~ 2~I 2~

30 30 30 30

31 31 31 31

5}t 6~ 6~ 6~

2.63:1 2.76:1 3.05:1 3.18:1

NC50-70(4 ½ I F ) NC50.70(4 V2IF) NC50-72(4 ½ I F )

7 7 71A

2~ 2~I 2`}t

30 or 31 30 or 31 30 or 31

6~ 61~ 6~

2.54:1 2.73:1 3.12:1

NC56-77 NC56-80

7~ 8

2,}i

2,}1

30 or 31 30 or 31

7~ 7t~

2.70:1 :L02:I

C,%REG

8~

2,}I

30 or 31

7~

2.93:1

NC61-90

9

2,}11

30 or 31

8%

3.17:1

7% REG

9'~

2

30 or 31

8{i

2.81:!

NC70-97 NC70-100

9sA 10

3 2

30 or 31 30 or 31

9~ 9~½

2.57:1 2.81:1

NC77-II0 (tentative)

II

3

30 or I3

2~

or or or or

lot}

~.78 :I

:' The drill collar nunlbcr {Col. 1) consists of two parts separated by a hyphen, Tile first part is tile connection number in tile NC style. The second part, consisting of 2 (or 3) digits, indicates tile drill collar outside diameter in units and tenths ot inches, Tile ¢Ollrleetiorls showll ill parentheses in Col. 1 are not a part of the drill collar number; they indicate interchangeability of drill collars made with the standard (NC) Connections as shown. If tile cOnlleCtlOllSshown in parentheses ill coiunln I are made with the V-0,038 R fllread from tile connections and drill collars are identical with those in tile NC style, Drill ctdlars with 8% and 9% inches outside diamelCl'S are shown with 6-5/8 and 7-5/8 REG connections, since lhere :Ire no NC connections in die recommended bending strength ratio range.

Table 4-72 Physical Properties and Tests--New Drill Collars [13] ......

i

..........

Drill Collar OD Range, inches 3% thru 6% 7 thru I0

2

3

4

Minimum Yield Strength, psi II0,000 I00,000

Minimum Tensile Streng.th, psi 140,000 135,000

Elongation, Minimum, With Gage Length Four Times Diameter, percent 13 13

N O T E I : Tensile properties shall be determined by tests on cylindrical specimens conforming to the requirements of A S T M A-$70, 0.$% offset method. N O T E ~: Tensile specimens from drill collars shall be taken u~ithin S feet of the end of the drill collar in a longitudinal direction, having the eenterline of the tensile specimen I inch from the outside surface or midwall, whichever is less.

Drill String: Composition a n d Design

719

Table 4-73 Drill Collar Weight (Steel) [51] (pounds per foot) 1 Drill Collar OD, in.

2

3

4

1

114

lI/2

2~

19

18

16

3 3~ 3¼ 3½ 3¾

21 22 26 30 35

20 22 24 29 33

18 20 22 27 32

4 4~ 4¼ 4½ 4¾

40 43 46 51

39 41 44 50

5

6

7

8

10

11

12

13

14

2~|

3

31A

3V2

3~

4

9

Drill Collar ID, in. lSA

2

21A

21/2

37 39 42 48 54

35 37 40 46 52

32 35 38 43 50

29 32 35 41 47

44

5 5¼ 5½ 5¾

61 68 75 82

59 65 73 80

56 63 70 78

53 60 67 75

50 57 64 72

60 67

64

60

6 6¼ 6½ 6s~

90 98 107 116

88 96 105 114

85 94 102 III

83 91 99 108

79 88 96 105

75 83 91 100

72 80 89 98

68 76 85 93

72 80 89

7 7¼ 71/z 7¾

125 134 144 154

123 132 142 152

120 130 139 150

117 127 137 147

114 124 133 144

110 119 129 139

107 116 126 136

103 112 122 132

98 108 117 128

93 103 113 123

84 93 102 112

8 8¼ 8½

165 176 187

163 174 185

160 171 182

157 168 179

154 165 176

150 160 172

147 158 169

143 154 165

138 149 160

133 144 155

122 133 150

9 9I/~ 93A

210 234 248

208 232 245

206 230 243

203 227 240

200 224 237

195 220 232

192 216 229

188 212 225

184 209 221

179 206 216

174 198 211

10

261

259

257

254

251

246

243

239

235

230

225

11

317

315

313

310

307

302

299

295

291

286

281

12

379

377

374

371

368

364

361

357

352

347

342

NOTE 1: Refer to API Spec 7, Table 6.1 for API standard drill collar dimensions. NOTE 2: For special configurations of drill collars, consult manufacturer for reduction in weight.

rock bit. If there is no tendency to cause an undersized hole, the largest drill collars that can be washed over are usually selected. T h e current tendency, i.e., not to r u n large drill collars that cannot be washed over, seems to be obsolete. Due to considerably improved technology in drill collar m a n u f a c t u r i n g , the possibility of losing the drill collar in the hole is greatly reduced; perhaps the gain in p e n e t r a t i o n rate by applying higher weight on the bit can overcome the risk of drill collar failure. In general, if the optimal drilling programs require large drill collars, the operator should not hesitate to use them. Typical hole a n d drill collar sizes used in soft a n d hard formations are listed in Table 4-74.

Length of Drill Collars T h e length of the drill collar string should be as short as possible, b u t adequate to create the desired weight on bit. O r d i n a r y drill pipe must never be used for exerting bit weight.

720

Drilling and Well C o m p l e t i o n s

Table 4-74 Popular Hole and Drill Collar Sizes [39]

....

Drill collar sizes and connections

Hole size, inches

Soft formation

Hard formations

3 ~ " OD x 1J~" ID with 2 ~ " PAC or

3 ~ ~' OD x l~j" ID with 2 ~ " PAC or 2s/~" Reg.

4~" O D x 2" ID with 2 ~ " IF

4s~# O D x 2" ID with 3~*' X H or 2 ~ " IF

4 ~ " OD x 2 ~ " ID with 3 ~ " IF

5"-5~" OD x 2" ID with 3 ~ " IF

7~-7~

6" OD x 2u,4" ID with 4" IF or 4" H-90

6 ~ " or 6 ~ " OD x 2" or 2 ~ " ID with 4 ~ " H-90, 4" IF or 4" H-90

8½-s~

6 ~ n OD x 21~ # ID with 4# IF 6 ~ # OD x 2 ~ # ID with 4" IF or 4½" I F

6 ~ " or 7" OD x 21~" ID with 5" H-90 or 4 ~ " IF

7" OD x 2 t ~ " ID with 4 ~ " IF or 5" H-90 8" OD x 2 ~ " ID with 6 ~ " Reg.

~4~

2~" Reg.

5~-6~

108,/8-11

7" OD x 2q~" ID with 4 ~ " IF or 5" H-90 8" OD x 2x~" ID with 6 ~ " Reg.

7" OD x 2 ~ " ID with 4 ~ " IF or 5" H-90 8" OD x 2L~" ID with 6aAi" H-90 or 6 ~ " Reg. 8" OD x 21~" ID with 6a,dl" H-90 or 6 ~ " Reg. 9" OD x 21s,/~" ID with 7a/l~" Reg.

12j~

8" OD x 21~6~' ID with 6 ~ # H-90 or 6 ~ " Reg.

6 ~ " Reg.

8" OD x 2qt~ n ID with 6 ~ " H-90 or

•

9"ODx21~ IDwith7~ Reg., I0" OD x 2t~" or 3" ID with 7 ~ H-90 or 7 ~ " Reg. 8" OD x 21s,~" ID with 6 ~ " H-90 or 6sA" Reg.

18~-26

8" OD x 2 ~ " ID with 6 ~ " H-90 or 6 ~ * Reg. 9" OD x 2t~6" ID with 7aAi" Reg. 10n OD x 21~6~' or 3" ID with 7a/~" H-90 or 7 ~ " Reg. 11" OD x 3" ID with 8 ~ n Reg.

Drill collar programs are the same as for the next reduced hole size. i

Abbreviations: Reg. - - AP1 Regular H-90 - - Hughes H-90 IF - - API Internal Flush PAC - - Phil A. Carnell XH - - Hughes Xtra Hole t Range of hole sizes commonly used in deepening, workovers and drilling below small liners. 2 Most planned drilling will fall within this range of hole sizes. s Range of hole sizes is gaining popularity because of large number of deep wells being drilled and because of large production strings needed for high volume wells.

In highly deviated holes, an excessive torque is encountered with conventional drill collars; therefore, a heavy wall drill pipe can be used to supply part o f the required weight. T h e required length o f drill collars can be obtained from La c =

(DF)W WacK b cos ot

(4-50)

Drill String: C o m p o s i t i o n and Design where DF = W = Wdc = IZ% = Kb = y~ = Y~t = {z =

721

design factor (DF = 1.1-1.2) weight on bit in lb unit weight of drill collar in air in l b / f t buoyancy factor 1 - ~m/~st drilling fluid density, e.g., in l b / g a l drill collar density, e.g., in l b / g a l (for steel, Y~t = 65.5 l b / g a l ) hole inclination from vertical in degrees (o)

Design factor (DF) is n e e d e d to place the n e u t r a l point below the top of the drill collar string. Some excess of drill collar weight is required to take care of inaccurate handling of the brake by the driller. For an "ideal driller," the design factor should be equal to 1. T h e excess of drill collars also helps to prevent transverse movement of drill pipe due to the effect of centrifugal force. While the drill string rotates, a centrifugal force is generated that may produce a lateral movement of drill pipe and, in turn, b e n d i n g stress and excessive torque. T h e centrifugal force also contributes to v i b r a t i o n of the drill pie. Hence, some excess of drill collars is suggested. T h e m a g n i t u d e of the design factor can be d e t e r m i n e d by field e x p e r i m e n t s in any particular set of drilling conditions. T h e pressure area m e t h o d (PAM), occasionally used for evaluation of drill collar string length, is wrong because it does not consider the triaxial state of stresses that actually occurs. It must be r e m e m b e r e d that hydrostatic forces cannot cause any buckling of the drill string as long as the density of the string is greater than the density of the drilling fluid.

Example D e t e r m i n e the required length of 7 by 2 ¼-in. drill collars if desired weight on bit is W = 40,000 lb, drilling fluid density y~, = 100 l b / g a l , and hole deviation from vertical c¢ = 20 °. From offset wells, it is known that a design factor DF of 1.1 is satisfactory.

Solution From Table 4-75 the unit weight of drill collar Wdc = 117 1b/ft. T h e buoyant factor is 10 Kb =1---=0.847 65.5 Applying Equation 4-50 gives (1.1)(40,000) = 376ft Ld¢ = (147)(0.847)(cos20) The closed length, based on 30-ft collars, is 390 ft or 13 joints of drill collars. Actually, drill collar sizes and lengths should be c o n s i d e r e d simultaneously. T h e o p t i m a l selection should result in the m a x i m u m p e n e t r a t i o n rate. Such an approach, however complex, is particularly i m p o r t a n t when drilling formations sensitive to the effect of differential pressure and also in cases where the amount of hydraulic energy delivered at the rock bit is a controlling factor of drilling efficiency.

722

Drilling a n d Well Completions

Drill Collar Connections It is current practice to select the rotary shoulder c o n n e c t i o n that provides the balanced b e n d i n g fatigue resistance for the pin a n d the box. The pin and the box are equally strong in b e n d i n g if the cross-section module of the box in its critical zone is 2.5 times greater than the cross-section module of the pin at its critical zone. These critical zones are shown in Figure 4-127. Section modulus ratios from 2 . 2 5 to 2.75 are c o n s i d e r e d to be very good a n d satisfactory p e r f o r m a n c e has b e e n experienced with ratios from 2.0 to 3.2 [39]. T h e above s t a t e m e n t s are valid if the c o n n e c t i o n is made up with the r e c o m m e n d e d makeup torque. For practical purposes, a set of charts is available from DRILCO, Division of Smith International, Inc. Some of these charts are presented in Figures 4-128 to 4-132. The m e t h o d to use the connection selection charts is as follows [38]: The best group of connections is defined as those that appear in the s h a d e d sections of the charts. Also, the nearer the c o n n e c t i o n lies to the reference line, the more desirable is its selection. T h e second best group of c o n n e c t i o n s is d e f i n e d as those that lie in the u n s h a d e d section of the charts on the left. The nearer the c o n n e c t i o n lies to the reference line, the more desirable is its selection. T h e third best g r o u p of c o n n e c t i o n s is d e f i n e d as those that lie in the u n s h a d e d section of the charts o n the right. The nearer the c o n n e c t i o n lies to the reference line, the more desirable is its selection. (text continued on page 731)

The section modulus, Zb, of the box should be 21/2 times greater than the section modulus, zp, of the pin in a drill collar connection. On the right side of the connection are the spots at which the critical area of both the pin (Ap) and box (Ab) should be measured for calculating torsional strength.

Figure 4-127. The drill collar connection. (After C. E. Wilson and W. R. Garrett.)

Drill String: Composition and Design

723

2" ID

6!h~

6%

L 44

;. 40

W W < Q, W

E,H ., 35

D O

"~ 3 1 REG E°H. RA,C,

] 26

Reference Li~

Figure 4-128. Practical chart for drill collar selection--2-in. ID. (From Drilco, Division of Smith International, Inc.)

724

Drilling and Well Completions 2W' ID

7¾

7½ ~H~ 56

7¼

7 ~EG 50 6¾

6½

W

6¼

46

< w F, ©

N C 44

NC. 40

N,C 38

3v# E.Ho N C 35

Re~erenceLine Figure 4-129. Practical chart for drill collar selection--2 ¼-in. ID. (From Orilco, Division of Smith International, Inc.)

Drill String: Composition and Design 21/= '' I D

10¸

9~

%LC, 70 91

7 ~ RE G

~

6% EH. 8~

W }W

8! 5~/2 l,E 7 H-90 *

8~

N.C: 61

W a 8 O

6% H.90 6% REG. 5~/2 EH,

REG, 50 Reference Line Figure 4-130a. Practical chart for drill collar selectionn2 ~-in. ID.

Drilco, Division of Smith International, Inc.)

(From

725

726

Drilling and Well Completions 21/y ' ID

REG

6¾

50

6¼ 146

w a w

N~C. 44 5

5 0

N,C, 40

N,C, 38

3~/~ E,Ho N~C 35

Reletence :Line Figure 4-1301}. Practical chart for drill collar selection--2 ½-in. ID. (From

Drilco, Division of Smith International, Inc.)

Drill String: Composition and Design 213/le '' ID

11~/=

111/4

11 3% H°90*

10%

10!/~

~4~C,77 ~% REG ~

10V4

w; w < a w

log \ 9¾ 7% H - ~ *

9½

~,C, 70

0 9¼

F% R E G * 8¾

8½

8¼

N,C 61

Reference Line

Figure 4-131a. Practical chart for drill collar selection--2~-in.

Dri/co, Division of Smith International, Inc.)

ID. (From

727

728

Drilling and Well Completions 213/16 '' ID

8 8¼

,61 8

7¾

7~

56 7¼

w w <

7

REG

6~

w a © 6¼

N,C. 46

5

N.C,~

Reference Li#e

Figure 4-131b. Practical chart for drill collar s e l e c t i o n - - 2 ~ - i n . ID. (From Drilco, Division of Smith International, Inc.)

DrillString:Compositionand Design 729 3" ID ¢

11V4

1t

--

8% H-~ ~

10%

v

w w < W

a

10~

~

N,C, 77 8% REG,"

\ \

O

7% H - ~ ~ NC, 70

il

7% REG. ~ 8 % EH,

8½

Reference Line F i g u r e 4-132a. Practical chart for drill collar selection--3-in. ID.

Division of Smith International, Inc.)

(From Drilco,

730

Drilling and Well Completions

3" ID

~E 8i

REG:

EiH~ 56

~ v

W

S < W REG

0

50

N.C 4~

~ 44 Reference Lir~e

Figure 4-132b. Practical chart for drill collar selection--3-in. ID. (From Drilco,

Division of Smith International, Inc.)

Drill String: Composition and Design

731

(text continued from page 722)

Example Suppose you want to select the best connections for 9 ~ x 2 ~-in. ID drill collars. For average conditions, you should select in this order of preference (see Figure 4-131): 1. Best = N.C. 70 (shaded area and nearest reference line.) 2. Second best = 7 ~8 in. REG. (low torque). (Light area to left a n d nearest to reference line.) 3. Third best = 7 ~8 in. H-90. (Light area to right and nearest to reference line.) But in extremely abrasive a n d / o r corrosive conditions, you might want to select in this order of preference: 1. Best = 7~ in. REG. (Low torque) = strongest box.* 2. Second best = N.C. 70 = second strongest box. 3. Third best = 7 ~ in. H-90 = weakest box.

Recommended Makeup Torque for Drill Collars The rotary shoulder connections must be made up with such torque that the shoulders will n o t separate u n d e r d o w n h o l e c o n d i t i o n s . This is of critical i m p o r t a n c e because the shoulder is the only area of seal in a rotary shoulder connection. Threads are designed to provide a clearance between crest and root that acts as a channel for lubricant and also accommodates the small solid particles. To keep the shoulders together, t h e shoulder load must be high enough to create a compressive stress at the shoulder face capable of offsetting the b e n d i n g that occurs due to drill collar buckling. This backup load is generated by a makeup torque. Field observations indicate that an average stress of 62,500 psi in pin or box, whichever is weaker (cross-sectional area), should be created by the makeup torque to prevent shoulder separation in most drilling conditions. It should be pointed out that the makeup torque creates the tensile stress in the pin and, consequently, the n u m b e r of cycles for fatigue failure of the pin is decreased. Therefore, too high a makeup torque has a detrimental effect on the drill collar service life. T h e r e c o m m e n d e d m a k e u p torque for drill collars is given in Tables 4-75 a n d 4-76.

Drill Collars Buckling In a vertical straight hole with no weight on the bit, a string of drill collars remains straight. As the weight for which the straight form of the string is not stable is reached, the drill string buckles and contacts the wall. If weight on the bit is further increased, the string buckles a second time a n d contacts the borehole wall at two points. With still further increased weight on the bit, the third and higher order of buckling occurs. The problem of drill collars buckling (text continued on page 734)

*The connection furthest to the left on the chart has the strongest box. This c o n n e c t i o n should be considered as possible first choice for very abrasive f o r m a t i o n s or corrosive conditions,

732

Drilling and Well Completions Table 4-75 Recommended Makeup

RECOMMENOEO Size iml Type of C~nl¢t~on

MAKEUP 00

_~-_L

TORQUE

I

(ft-lb)

.... i~,

2 5 0 0" -1~"-~- 1

. . . .

Torque

[38]

lSee Note 2l I~18 o! 0rib C4111irJ;(in)

l

2500t1'/'

1,

2

2"

&fl NC. 23 2~"P.A.C. (SeeNolo 4| 2~s"API LF. or APtN¢ 215~"

3~/*

52110

42O0 4210

2:4" Eltra ~ Or 3Y~"0hi. $tteamlk~of

3VI 3~ 3~ 3~

2~"/Ipt LF Or

3,/. 4~

4NM~t ~ 4100? 33~0t Sp00t 46011 73001 81001

4W}001 47~1~ 41011 53001 uoct 4ii~t 73001 11441

3~* SXm Hokl

4~ 4',~ 4~ 5 4% 4YI 4~ 5 sv~ 4~ 5 5% SYz 4~ S S~ 5~,~ S

2900 3700 3T~ 41001 5.1101 7~oo

4600t 7~t I1N

Iglt ltKtP 19600 510Sf 14001" 11700 11700 11zoo 99oo? t 00001 146410 145041 37N? 12700? 117041 16700 101041+ 13100? 10600 18600 18§00 IZr,~ot 113410t 22300? 23500 ;?~1 154001' 20300? 23400 23400

lint ~ 8200 51001 14Olt IlIQQ8 t0e0e 100ae 09~0, 12N0 12800 ] 2,.6~.. 3700f 127(IQ? 150041 1~00 10~ tS100~" 15900 1Sin 1§~. 12r~t 113W? 21514 21in 21500 154Nt 203N? 21&N 21rd00

a~ slim? l(lin |0gN 109~0 |7001 12700? 13100 t31N 1N00? t4&0O 14in 14840 141J~ IZ~e.f 11000? 19400 19400 1~M4~ 1S40~ 19400 10400 194410

33~ $300 07001 10400 10400 104414 101JOJ~ 12190 12100 12100 12100 tz~t lt~500 III~U0 16500 I(100(I 154001 112000 11004 16200

2SON 25104 ~ 12901? 17900f 233001 2710~0 27101

~ 23~10 23300 1~? 17~0~t 23300? 25000 25NI 17~01 ,200* 2N~0 ~ ;Nee

212~1 21200 21200 12iNf 17iN? 22800 220Q0 22100 17600? 2320e1 25610 25500 ?H11e

11111 11100(I 18140 12910? 129101" 17iNf 1770(I 19100 17709 1~ 177N the0 17700 17in? 171~f- " .211e 29200 22201 20200 22~1f~ 20200 ~

I IV4 i~ .. 6~,, llY~ ~

23404~ 00f~ 00540 2a5oo 25oo9t

s~,

7 7% 7%

6~ "APIitquler

Nooet 41500? 42540 42500 3liNt S~

7~ 7~i

42000 42OO1

4W" APt I.F. o, APt ,.¢. 00 or S"ExtraHOleor 5" M~4 Openor Svs'Obl Sireliml01e

iV, ,~ $~ 7 7V*

2"Zlle0t 29500t 000S~ 31000 39000

23444 2~ 230re 21000 210~4 23400 21000 26ooo 23ooo 210oo 25ooot 25001? 25000f 27000 31~o~ z.~ 33001 215~ 2"tg4¢ p,sCn~ ~ 2xee 3000¢t ~ 3410e 000N 30500 34000 40000 36540 34in 40000 36540 340~t 31590 3tl~i01 ~60~ t 315"? 33814 39500 ~ 33510 3H 31~ Z00N? 2,?1~t ~'00~t !'211¢1' 2~ 29¢~M1 29500t 2~iN 30N0 35500 32N0 355~1 32900 30~4~ 26500 355(10 32N0 30~00

H.C. 35 3YI~IEilri H0le or 4"~lm HOleW 3~" Ided0tim 3VI"APeI.F. or APIN.C. 36 Of 4VI"Slim Hole 3W )1-91 |IN See 3)

Iw 4" APtN.C, 40 ~t 51/I 4 MN OLIIO0r 5~ 4~ 1 0~l.itrj . . . . . I~0~(~ . . . . . 5. s~,, 5~ 4"I~M 5~ (lies N01e3) ii I~ 51/I 5~ 4~" APt Rqller 6 liY* API H.C.44

4~1~1 hill Hole

i~ 11~'1 5~ 5~ 5 6

4V~' Eslri H01eOr ,.C. 4 1 , 4" APtI.F. or 3" ~ld. Slrlamlloeof 4~"i100 o m

6v~ 5h , 6Y* i~ ~

4VI"H-N |S4e H0103) 5 Hdl0 ~s., ~ . 3) S~'H-H ($4¢ No~e3)

_~

lint 121041 12101 51001 8400~" 11g0et 132041 ~ s94tot 131HIO? 19 li~OO ITOH? 12700? 1liNt llffdl0 I0~ 1SI~Q? 19700f 2041141 0040Q

41001 1840

~o~

740t 744)0 74N 5100f I1~

1314;

NOTE: 1 The calculations for recommended m a k e u p torque assume the use of a thread compound containing 40% to 60°/. by w e i g h t of finely powdered metallic zinc, or 60% b y w e i g h t of freely powdered metallic lead, applied thoroughly to all threads and shoulders; the uSe of the modified jackscrew formula as shown in the IADC Drilling Manual and the API Spec RP 7G (latest addition); and a unit stress of 62,500 psi in the box or pin, whichever ~s weaker. 2. Normal torque range - - tabulated minimum value to 10°/= greater. Largest diameter s h o w n for each connection is the m a x i m u m recommended for that connection. If the connections are used on d~l! collars larger than the m a x i m u m shown, increase the torque values s h o w n by 10% for a m i n i m u m value.

-

Drill String: Composition and Design

733

Table 4-76 Recommended Makeup Torque [38] RECOMMENDED MAKEUPTORQUE (ft-lb) ISee Note 2] Sizeand Type

S½"APIFUUHeTO

API N.C. 54

811"API Re0011t 811"H-00 {SIs Ne~eSt

APt N,C, 8'

IV, 7Y~ 7~ 7Y~ T~ 711 1 7½ 711 I Y~ 7~ 711 l

8Y, t 8% l½ 8t~ eev,

~½" ~1 I.F.

S~ l~

111" ~ FHI Pale

9~ I~ I~ S g~ S~ 9%

~I N.C. 70

#4q N.C. t7

Soceo, Oriii COllarS(k~)

OO

9½ 91~ 10 10% 10 10~4 lIt~ ISI~ "

325~t ~r~lot 450~ 51100 40000t 48~11t 5'100 51000 40000t ~mlt ~7000 57OO4 46000? S00Ut 59500

5S550 5000et M000t 72000 72000 711o0 ~ 74000 74000 74800 74000

3--00T 4e~50t 47~ 47000 400~t ~ 41000 40000 4000~t ~ ~S00 53OOO 5000ot S~000t 50000 56000 50I~t MII00t

60000 00800 ~00o ~50ot 5000et

70000 75000 70500 70000 $7000t 78000t 03000 50000 1~500 75000t 00000t 10'000t 107000 107000 107000

u~Ol ] ~t 4e50It 41500 45000 41500 450Mt 40000t 450410 42000 45000 42000 4~0 4~00 45000? 4~00lt ~ 47000 50000 47000 5~00 4750e 4004ot 40000T 53000 49500 50ST~ 45500 53050 49500 50~t 54000t 500~t !1000 $5000 61008 00000 I,O00 r~sppp 8,50o ~o00t ~ ~00et 63000 59000 67000 63000 50000 87050 4J0000 55050 67000 00000 59000 87500 53090 Sg500 lt700GT 87000? 87(100t T5000T 75000 72000 80050 7S000 700re 76000 72000 50000 50000 70000 72600 75HOT 70000t 70000t 00000t $0000t 00000t 101000t 100000 ~ 105000 100000 95~ 105000 '05050 $5000 10~000 100~ . $ ~ 107000~ 107000t l l 7 ~ t 111501? ,2200~ 122504t ; 135004t l i t 1330~1 143009 138500 133000 II 1I '30000

00500 I~ 005al 645500 50800 750001 500001 90040 00050 50000 I

1870001 '220001

1211000 12SO 1211~

C l i t O r i S Wla FUllFace

T" H'00 f S , Mo~ ~i 711"APt RellUlaz

711~H.00 I ~ Mote S|

I~" API Re~14tr S~~14-00 (See NoW 3)

~, J~" '~*" 111" 9* gY~* g~" tP 1~ 10" iOY** '8½ ° 10¼" ISYm"

,%~mot 50~? IklNIt 13®et 7,500 ~8500 60000 T,000I 83500t 100G0 88000 72050? 00500t 50000t 100000t 11500e'~" 13~ 112500?

001100t S,I~0t |5D00 ~I01~I 0000S? 15000 83008 72900t 85500? H00~ 150000T 113000T ,34000 112500t '211500~" 12P500?

500011t $050e 00500 50500, 71000t 79000 79500 70000 72000t 80000t It

100000t 110000t ,19000 1125041 t 11S500t

0000e 7IS00 74000 74~ 74000 720661 855001 I

111~1 11~D~41 113000 1125001 '20000t

CN]lealees writ LowTorq4HJFSU 7* H-00

7~'A~ R e ~ r

T11"14.50 (14e Note I) IW~"Al~ Renv4atr StY"H-00 ISle N4KIIt

ika s 9Y~ g~ 911 10 9~ 10 IS~ 10~ ,~ 11 101~ 11 11Y4

67500t 740N

i7500t 71100 72000t 00~07 910041 $1000 $10007 105000t 112500 112500 .100~ 1200001" 00500? '10~t 12500It

[l~ 50500 7Ht 15000T 17000 17080 9t000t 185004lt 10~ 111~ .1000t 110000t t250OT 110000t 1S0000t

|0000 62000 72000t 12000 1~000 1/201N_ t100Ot 103500 103500 11 .1mr 120050t 91500t 11001It 1200~

72t100t 17050 77000 77000 $1500t 50000 .amt 120000t 92500 110~' 125000t

In addition to the increased minimum torque value, it is also recommended that a fishing neck be machined to the m a x i m u m diameter shown. 3. The H - 9 0 connection makeup t o q u e is based on 56,250 psi stress end other factors as stated in note I . 4. T h e 2 W ' RA.C. m a k e u p torque is b a s e d on 8 7 , 5 0 0 psi stress a n d other factors as stated in note I. "5. The largest diameter shown is the m a x i m u m recommended for those full-face connections. If larger diameters are used, machine connections with low torque faces and use the torque values shown under the low torque face t a b l e If low torque faces are not used, see note 2 for increased torque v a l u e s t 6 Torque figures succeeded by a ( t ) indicate that the weaker member in torsion for the corresponding outside diameter and bore is the BOX, For all other torque values, the weaker member in torsion is the PIN

734

Drilling a n d Well Completions

(text continued from page 731)

in vertical holes has b e e n studied by A. Lubinski [171] and the weight o n the bit that results in first a n d second order buckling can be calculated as WCr~ = 1.94( EIp 2)vs

(4-51)

WcrH = 3.75(EIp 2)vs

(4-52)

where E = module of elasticity for drill collars in l b / f t 2 (for steel, E = 4320 × 106 l b / f t 2) p = unit weight of drill collar in drilling fluid in l b / f t I = m o m e n t of inertia of the drill collar cross-section with respect to its diameter, in ft I = ( n / 6 4 ) ( D 4 - d~) Dd~ = outside diameter of drill collars in ft dd~ = inside diameter of drill collars in ft

Example Find the m a g n i t u d e of the weight on bit and c o r r e s p o n d i n g length of drill collars that result in second order of buckling. Drill collars: 6 ¼ in. × 2 ¼ ft, m u d density = 12 l b / g a l .

Solution Moment of inertia:

I = ~

-

64

= 4.853 × 10-s ft 4

Unit weight of drill collar in drilling fluid:

p=108

1 - 6 512 . 4 ] = 88.181b/ft

For weight o n the bit that results i n the second o r d e r of buckling, use Equation 4-61: W r,n = 3.75(4320 x 106 × 4.853 x 10 -~ x 88.182) vs = 20,468 lb C o r r e s p o n d i n g length of drill collars: 20,468 Ldc -- - = 232ft 88.18 If the total length of drill collar string would be, for example, 330 ft, then the n u m b e r "232 ft" would indicate the distance from the bit to the neutral point.

Drill String: C o m p o s i t i o n a n d Design

735

A. Lubinski also found [171] that to drill a vertical hole in homogeneous formations, it is best to carry less weight on the bit than the critical value of the first o r d e r at which the drill string buckles. However, if such weight is not sufficient, it is advisable to avoid the weight that falls between the first and second buckling o r d e r a n d to carry a weight close to the critical value o f the third order. For practical purposes, in many instances, the above statement holds trues if formations being d r i l l e d are horizontal. W h e n drilling in d i p p i n g formations, a p r o p e r drill collar stabilization is required for vertical or nearly vertical hole drilling. In an inclined hole, a critical value of weight on the bit that p r o d u c e s b u c k l i n g may be c a l c u l a t e d f r o m t h e f o r m u l a given by R. Dawson a n d P. R. Paslay [40]:

(4-53) hole inclination m e a s u r e d from vertical in degrees (o) where ~ r = radial clearance between drill collar a n d b o r e h o l e wall in ft E,I,p = as for Equations 4-51 a n d 4-52 =

Few straightforward c o m p u t a t i o n s can reveal that, in regular drilling conditions, the critical weight is very high. The reason why drill collars in an inclined hole are very resistant to buckling is that the hole is s u p p o r t i n g the drill collar along its contact with the b o r e h o l e wall. This explains why heavy-weight drill p i p e is successfully used for creating weight on the bit in highly deviated holes. However, in drilling a vertical or nearly vertical hole, a drill p i p e must never be run in effective compression or, in o t h e r words, the neutral point must always reside in the drill collar string.

Rig Maintenance of Drill Collars [38] It is r e c o m m e n d e d practice to break a different j o i n t on each trip, giving the crew an o p p o r t u n i t y to look at each pin a n d box every third trip. Inspect the shoulders for signs of loose connections, galls, a n d possible washouts. T h r e a d protectors should be used on pin a n d box when picking up or laying down the drill collars. Periodically, based on drilling conditions a n d experience, a magnetic particle inspection should be p e r f o r m e d using a wet fluorescent a n d black light method. Before storing, the drill collars should be cleaned. If necessary, reface the shoulders with a shoulder refacing tool, a n d remove the fins on the shoulders by beveling. A g o o d rust preventative or drill collar c o m p o u n d should be applied t~ the connections liberally, and t h r e a d protectors should be installed.

Drill Pipe T h e major p o r t i o n of drill string is c o m p o s e d of drill pipe. The drill p i p e is m a n u f a c t u r e d by the seamless process. A c c o r d i n g to A P I S p e c i f i c a t i o n 5A (Thirty-fifth Edition, March 1981), seamless p i p e is d e f i n e d as a wrought steel tabular p r o d u c t m a d e without a welded seam. It is manufactured by hot working steel or, if necessary, by subsequently cold finishing the hot worked tabular p r o d u c t to p r o d u c e the desired shape, dimensions a n d properties.

736

Drilling and Well Completions

Classification of Drill Pipe Drill pipe is classified according to: • • • • •

type of ends upset sizes (outside diameter) wall thickness (nominal weight) steel g r a d e length range.

S t a n d a r d i z e d pipe upsets are: • internal upset (IU) • external upset (EU) • internal and external upset (IEU). G e o m e t r i c a l data of upset drill pipe for weld-on tool joints are specified in Table 4-77 (steel grades D and E) and Table 4-78 (steel grades X, G and S). API standardized new drill pipe sizes and unit weights are given in Table 4-79. Drill pipe is m a n u f a c t u r e d in the following r a n d o m length ranges: Range 1 - 1 8 to 22 ft Range 2--27 to 30 ft Range 3--38 to 45 ft T h e drill pipe most c o m m o n l y used is Range 2 pipe. To meet specific downhole requirements, seamless drill pipe is available in five steel grades, namely D, E, X, G and S*. (Grades X, G a n d S are considered to be high-strength pipe grades.) The mechanical properties of these steel grades are as follows:

API Steel Grade Property Minimum yield strength, psi Maximum yield strength, psi Minimum tensile strength, psi

D

E

X(95)

105(G)

135(S)

55,000 85,000 95,000

75,000 105,000 100,000

95,000 125,000 105,000

105,000 135,000 115,000

135,000 165,000 145,000

For practical e n g i n e e r i n g calculations, the m i n i m u m yield strength is usually used; however, for some calculations, the average yield strength is used.

Minimum Performance Properties of Drill Pipe T h e t o r s i o n , tension, c o l l a p s e a n d i n t e r n a l p r e s s u r e r e s i s t a n c e for new, p r e m i u m class 2 a n d class 3 drill pipe are specified in Tables 4-80, 4-81, 4-82 and 4-83, respectively. Calculations for the m i n i m u m p e r f o r m a n c e properties of drill pipe are based on formulas given in A p p e n d i x A o f API RP 7G. It must be r e m e m b e r e d that numbers in Tables 4-80-4-83 have b e e n o b t a i n e d for the uniaxial state o f stress, e.g., torsion only or tension only, etc. The tensile stress resistance is d e c r e a s e d when the drill string is subjected to both axial tension and torque; a collapse *The above data are obtained from the IADC Drilling Manual, Section B, p. 1, revised January 1975.

Drill String: Composition and Design

737

Table 4-77 Upset Drill Pipe for Weld-on Tool Joints (Grades D and E) [30] Pipe 8lz@~ Outsldt DIS.. ira.

2

3

4

5 6 Calculated Weight

Nomlnat Wt.s I Ib/ft

Wall Thickuus, in,

Inside Diameter, in.

Plain End Ib/ft

Upset' |b

t

d

wl,~

ew

7

8

9

10 1L SUpset Dimensions, in.

12

13

OuC-

D

side Inside Length of Length Length Length of Diam- Diameter Internal of of External eter,= at End of Upset internal External Taper, -~-~, piPe, s ~-1~ Taper, Upset, ~ -- ~ -t- ~6 __ I~ rain. rain. rain. max.

Do,,

do~

~i.

rot.

2% 3½ 3½ 3½ *4 4 *4½ 4½ *5

10.40 9.50 13.30 15.50 11.85 14.00 13.75 16.60 16.25

0.362 0.254 0.368 0.449 0.262 0.330 0.271 0.337 0.296

2.151 2.992 2.764 2.602 3.476 3.340 3.958 3.826 4.408

INTERNAL-UPSET DRILL PIPE 9.72 3.20 2.875 15A~ 1~ 8.81 4.40 3.500 2zA 1~ 12.31 4.40 3.500 lt~ 1~ 14.63 3.40 3.500 11~G 1% 10.46 4.20 4.000 2x~G 1% 12.93 4.60 4.000 2% 1% 12.24 5.20 4.500 3% 1% 14.98 5.80 4.500 35/~2 1~ 14.87 6.60 5.000 3~ 1~

2~ 2% 3½ 3½ 3½ *4 4 *4½ 4½ 4½

6.65 10.40 9.50 13.30 15.50 11.85 14.00 13.75 16.60 20.00

0.280 0.362 0.254 0.368 0.449 0.262 0.330 0.271 0.337 0.430

1.815 2.151 2.992 2.764 2.602 3.476 3.340 3.958 3.826 3.640

EXTERNAL-UPSET 6.26 1.80 2.656 9.72 2.40 3.219 8.81 2.60 3.824 12.31 4.00 3.824 14.63 2.80 3.824 10.46 5.00 4.500 12.93 5.00 4.500 12.24 5.60 5.000 14.98 5.60 5.000 18.69 5.60 5.000

4½ 5 5 5½ 6½

20.00 19.50 25.60 21.90 24.70

0.430 0.362 0.500 0.361 0.415

INTERNAL-EXTERNAL-UPSET DRILL PIPE 3.640 18.69 8.60 4.781 3 2~. 2 4.276 17.93 8.60 5.188 31~G 2~ 2 4.000 24.03 7.80 5.188 3~G 2~ 2 4.778 19.81 10.60 5.563 4 2zA 2 4.670 22.54 9.00 5.563 4 21A 2

Lr.

m~,

1½ . . . . . . . . . . . . . . . . . . . . . . . 1½ . . . . . . . . . . 1½ . . . . . . . . . . . . . . . . . . . . ½" " .. . . . . . . . . . . . . . . . . . . 2"" .. . . . . . . . . . . . . . . . . . . . . .

DRILL PIPE 1.815 ...... 2.151 ...... 2.992 ...... 2.602 2~A 2.602 ...... 3.476 ...... 3.340 ...... 3.958 ...... 3.826 ...... 3.640 ......

2

Length End of pipe to Taper Fadeout. max.

Lr. + m~,

. . . . . . . . . . . . . . . . . .

. . . . . . . . .

1½ 1½ 1½ 1½ 1½ 1½ 1½ 1Yz 1½ 1½

1½ 1½ 1½ 1½ 1½ 1½ 1½ 1½ 1½ 1½

.. .. .. .. .. .. .. .. .. ..

4 4 4 4 4 4 4 4 4 4

1½ 1½ 1½ 1½ 1½

1 1 1 1 1

1½ 1½ 1½ 1½ 1½

.... .... .... .... ....

1Nominal welgh~ (CoL E) are shown for the purpose of identification in ordering. ZThe endl of Internal-upset drill pipe shall not be smaller in outside diameter than the values shown in Col. 7. including the minul tolerance. They may be furnished with slight external upset, within the tolerance specified. lMaximum taper on inside diameter of internal upset and internal-external upset is Y4in. per ft. ou diameter. ~Widght l a i n or low due to end finishing. SThe specified upset dimensions do not necessarily agree with the bore and OD dimeusions Of finished weld-on assemblies. Upset dimensions were chosen to accommodate the various bores of tool ~oinL~ and to maintain a satisfactory cross section in the weld zone aftGr final machining of the auemblY. *Thlse sizm and weighbl are tentative and applicable to grade E only.

I IJJ JJJA INTERNAL UPSET

EXTERNAL UPSET

INTERNAL-EXTERNAl.UPSET

pressure resistance is also decreased when the drill pipe is simultaneously affected by collapse and tensile loads.

Load Capacity of Drill Pipe In normal drilling operations, as well as in such operations as DST or washover, drill pipe is subjected to combined effects of stresses. To evaluate the load capacity of drill pipe (e.g., allowable tensile load while simultaneously a torque is applied), the maximum distortion energy theory is

738

Drilling and Well Completions Table 4-78 Upset Drill Pipe for Weld-on Tool Joints (Grades X, G and S) [30] 1

2

3

4

5

6

7

Calculated Weight

8

9

10

11

SUpset DimensiOnS, in.

]Pipe SIS*,: Outside Dis.. in. D

~omina] Wt. Ib/ft:~

2~ 3~ 4 4~ 5

10.40 13.30 14.00 16.60 16.25

0.362 0.368 0.330 0.337 0.296

INTERNAL-UPSET 2.151 9.72 5.40 2.764 12.31 7.40 3.340 12.93 8.80 3.826 14.98 13.60 4.408 14.87 13.60

DRILL 2.875 3,500 4.000 4.500 5.000

PIPE 1~6 lX~e 2% 2z~6 39~6

3~ 3~ 3½ 3~ 3~

2~ 2% 3~ 3½ 4 4½ 4½ 5 5

6.65 10.40 13.30 15.50 14.00 16.60 20.00 19.50 25.60

0.280 0.362 0.368 0.449 0.330 0.337 0.430 0.362 0.500

EXTERNAL-UPSET 1.815 6,26 4.60 2.151 9.72 6.20 2.764 12.31 10.20 2.602 14.63 8.20 3.340 12.93 14.40 3.826 14.98 17.20 3.640 18.69 16.00 4.276 17.93 21.60 4.000 24.03 21.20

DRILL 2.656 3.250 4.000 4.000 4.625 5.188 5.188 5.750 5.875

PIPE 1~6 llrfie 2½ 2½ 3~6 39A6 3~6 3z~6 3z~z6

4~A 4~ 4Y~ 4~. 4~ 4~ 4~. 4¼ 4~

3 3 3 3 3 3 3 3 3

5½ 5~ 5½ 5½ 5½ 5½ 5½ 5~ 5½

3~ 4½ 5 5 5~ 5~

15.50 20.00 19.50 25.60 21.90 24.70

INTERNAL-EXTERNAL-UPSET DRILL 0.449 2.602 14.63 11.00 3.781 1Wz6 0.430 3.640 18.69 17.60 4.781 2x~io 0.362 4.276 17.93 16.80 5.188 3~6 0.500 4.000 24.03 15.40 5.188 3'~ 0,361 4.778 19.81 21.00 5.563 3L~6 0.415 4,670 22.54 18.40 5,563 3x~6

PIPE 4~A 4~ 4~ 4~ 4~ 4~A

3 3 3 3 3 3

5½ 5½ 5~A 5~ 5~ 5~

Wall Thickn/n~.,. t

Inside Diameter. in . d

]plain End Ib/ft w,,

UPset4 Ib e,

OutL~n~th side Inside Lmmgthof I~n~th End of ]PiPe Diam- Diameter Intt~na! of to Taper ~er. ~ at End of Upset External Fadeout. + ~, ]Pipe.~ "~-I~ UmI~z~. Ext.max. Upset --~ .++~s Do. d.. L,. L,, L,, + m,,

ll~ominal weights (Col. 2). are shown for the purpose of identification in ordering. ~rhe ends of Internal-uPset drill pipe shall not be smaller in outside diameter than the values shown in Col. 7, including the minus tolerance. TheY may be furnished with slight external upset, within the tolerance specified. lMaxlmum taper on inside diameter of internal upset and internal-extarngl upset is ~ in. per ft. on diameter. 'Weilht gain or loss due to end finishing. a'rhe sl~ifled upset dimensions do not necessarily agree with the bore and OD dimensions of finished weld-on assemblis~ UImet dimensions were chosen to accommodate the various bores of tool joints and to maintain a satisfactorY cross section in the weld zone after final machining of the assembly.

~,--Liu

INT[RNAL UPSET

EXTERNAL UPSET

tN T[R N A L-

EXTERNAL UPSET

Note: Permissible internal taper within ~ength L~, shaft not exceed V, in. per fl (21 mm per m) on diameter.

usually applied. This theory is in good agreement with experiments on ductile materials such as steel. According to this theory, the equivalent stress may be calculated from the following formula [42A]:

2 ~ = ( ~ , - ~ t ) z + ( ~ t - ~ r ) z+(~r-~,)z+6~z

(4-54)

where 6 e = equivalent stress in psi 6 z = axial stress in psi ( 6 > 0 for tension, 6 < 0 for compression)

739

Drill String: C o m p o s i t i o n and Design

Table 4-79 New Drill Pipe--Dimensional Data [51] 1

Size OD in. D

2

Nominal Weight Threads & Couplings Ib/ft

3

Plain End Weight' Ib/ft

4

5

6

Wall

ID

Thickness

in,

in.

d

Section Area Body of Pipe 2 sq. in. A

7

Polar Sectional Modulus ~ cu, in. Z

2~

4,85 6,65

4,43 6,26

•I gO .280

1.995 1.815

1.3042 1.8429

1.321 1.733

2~

6,85 10,40

6.16 9,72

.217 .362

2.441 2.151

1.8120 2,8579

2,241 3,204

3½

9.50 13.30 15.50

8,61 12.31 14,63

.254 .368 .449

2,992 2.764 2.602

2.5902 3.6209 4.3037

3.923 5.144 5.847

4

11,85 14,00 15,70

10.46 12,93 14.69

,262 ,330 ,380

3.476 3.340 3.240

3.0767 3.8048 4.3216

5,400 6,458 7.157

4½

13.75 16.60 20,00 22,82

12.24 14,98 18.69 21,36

.271 .337 .430 ,500

3.958 3.826 3,640 3.500

3.6(X)4 4.4074 5.4981 6,2832

7.184 8.543 10.232 11,345

5

16,25 19.50 25,60

14.67 17.93 24,03

.296 .362 ,500

4,408 4.276 4.000

4,3743 5.2746 7,0686

9,718 11.415 14,491

5½

19,20 21,90 24,70

16,67 19,61 22.54

,304 .361 .415

4,892 4,778 4,670

4,9624 5,8282 6,6296

12,221 14,062 15,688

25.20

22.19

.330

5.g~5

6,5262

19.572

' lb/ft = 3.3096 x A (col. 6) ZA = 0,7854 (Dz - d s) .z o 0 1 ~

(~--~

tyt = tangential stress in psi (tyz > 0 for burst pressure, ty < 0 for collapse pressure) tyr = radial stress (usually neglected for the drill p i p e strength analysis) = shear stress in psi T h e yielding o f pipe does not occur provided that the equivalent stress is less than the yield strength of the drill pipe. For practical calculations, the equivalent stress is taken to be equal to the m i n i m u m yield strength of the pipe as specified by API. It must be remembered that the stresses being considered in Equation 4-54 are

the effective stresses that exist beyond any isotropic stresses caused by hydrostatic pressure of the drilling fluid. (text continued on page 744)

".4

Table 4-80 New Drill Pipc Torsional, Tensile, Collapse and Internal Pressure Data [30] Torsional Data* Torsional Yield Strength, ft4b

Size OD in.

Nora. Wt. New Pipe w/TJ.

D

23/8

4.85 6.65

.......... 4580

4760 6240

6.85 10.40

.......... 8460

9.50 13.30 15.50

27/8

3 1/2

4

4 I/2

5

5 1/2

65/8

E

Tensile Data Based on Minimum Values Load at the Minimum Yield Strength, lb.

Collapse Pressure Based On Minimum Values, psi.

Internal Pressure At Minimum Yield Strength, psi.

O~

95

105

135

D

E

95

105

135

D

E

95

105

135

D

E

95

105

135

6020 7900

6660 8740

8560 11240

............ 101360

97820 138220

123900 175080

136940 193500

176060 248780

8100 11440

11040 15600

13980 19760

15460 21840

19070 28080

11350

10500 15470

13300 19600

147(10 21660

18900 27850

8070 11530

10220 14610

11300 16150

14530 20760

............ 157190

135900 214340

172140 271500

190260 300080

244620 385820

7680 I~.110

10470 16510

12930 20910

14010 23110

17060 29720

12120

9910 16530

12550 20930

13870 23140

17830 29750

.......... 13580 15440

14120 18520 21050

17890 23460 26660

19770 25930 29470

25420 33330 37890

............ 199160 236720

194260 271570 322780

246070 343990 408850

271970 380190 451890

349680 488820 581000

7400 10350 12300

10040 14110 16770

12060 17880 21250

13050 19760 23480

15780 25400 30190

I0120 12350

9520 13800 16840

12070 17480 21330

13340 19320 23570

17150 24840 30310

11.85 14.00 15.70

.......... 17050 18890

19440 23250 25760

24620 29450 32630

27220 32550 36070

34990 41840 46380

............ 209280 237710

230750 285360 324150

292290 361460 410590

323050 399500 453810

415360 513650 583420

6590 8330 9460

8410 11350 12900

9960 14380 16340

10700 15900 18050

12650 20170 23210

7940 9140

8600 10830 12470

10890 13720 15790

12040 15160 17460

15480 19490 22440

13.75 16.60 20.00 22.82

.......... 22550 27010 30000

25860 30750 36840 40910

32760 38950 46660 51820

36210 43050 51570 57280

46550 55350 66300 73640

............ 242380 302390 345580

270030 330560 412360 471240

342040 418700 522320 596900

378050 462780 577300 659740

486060 595000 742240 848230

5720 7620 9510 10860

7200 10390 12960 14810

8400 12750 16420 18770

8950 13820 18150 20740

10310 16800 23330 26670

7210 9200 10690

7900 9830 12540 14580

I0010 12450 15890 18470

11070 13760 17560 20420

14230 17690 22580 26250

16.25 19.50 25.60

.......... 34980 30135 41090 38250 52160

44310 52050 66070

48970 57530 73030

62970 73970 93900

............328070 290100 395600 388770 530140

415560 501090 671520

459300 553830 742200

590530 712070 954260

5560 7390 9900

6970 I0000 13500

8090 12010 17100

8610 12990 18900

9860 15700 24300

6970 9620

7770 9500 13120

9840 12040 ]6620

10880 13300 18380

13990 17110 2362{)

t9.20 21.90 24.70

.......... 37120 41410

44180 50620 564"/0

55960 64120 71530

61850 70870 79060

79520 91120 101650

............ 320550 364630

372180 437120 497220

471430 553680 629810

521050 611960 696110

669920 786810 895000

4910 6610 7670

6070 8440 10460

6930 I0000 12920

7300 10740 14000

8120 12710 17050

6320 7260

7250 8610 9900

9190 109i0 12540

10160 12060 13860

13060 15510 17830

25.20

51740

70550

89360

98770

..........

358930

489460

619990

685250

............

4010

4810

5300

5480

6040

4790

6540

8280

9150

*Based on the shear strength equal to 57.7% of minimum yeidl strength and nominal wall thickness. NOTE: Calculations are based on formulas in Appendix A, API RP7G Table is based on API RP7G. Tables 2.1 and 2.2.

O

O

Table 4-81 Torsional, Tensile, Collapse and Internal Pressure Data [30]

Premium (Used) Drill Pipe Size OD

Num. Wl. New ~ wfrJ.

1,2Tocsioml Yield Strenlflh Bssed On Uniform W ~ , fl-lb

2Tensile Data Based On Uniform Wear Load AI Minimum Yield S/tength, lb.

3Coliepse F r e s ~ e Based On Minimum Values, psL

31nl~nal F r a m e At Minimum YieM Strensth , psi.

in.

Fo~f!

D

E

95

105

135

D

E

95

105

135

D

E

95

105

135

95

105

135

2 3/8

4.85 6.65

2730 3520

3720 4800

4710 6080

5210 6720

6690 8640

56400 78925

76910 107620

97420 136320

107680 150670

138440 193720

6690 9810

8550 13380

10150 16950

10900 18730

12920 24080

7040 9600 10370 14150

12160 17920

13440 19810

17280 25470

27/8

6.85 10.40

4640 6480

6320 8840

8010 I1200

8850 12380

11370 15920

78450 122100

106970 166500

135500 210990

149760 233100

192550 299700

6060 10430

7670 14220

9000 18020

9620 19910

11210 25600

6640 11080

9060 15110

11470 19140

12680 21150

16300 27200

3 I/2

9.50 13.30 15.50

8120 10510 11820

11070 14340 16120

14030 18160 20420

15500 20070 22560

19930 25800 29010

112220 155650 183700

153020 212250 250500

193830 268850 317300

214230 297150 305700

275440 382050 450900

5650 8810 10610

7100 12020 14470

8270 15220 18330

8800 16820 20260

10120 21630 26050

6390 9250 11290

8710 12620 15390

11030 15980 19500

12190 17660 21550

15680 22710 27710

4

11.85 14.00 15.70

11210 13320 14690

15280 18160 20030

19360 23010 25370

21400 25430 28040

27510 32690 36050

133510 165715 186160

182060 225980 253860

230610 286240 321560

254890 316360 355400

327710 406760 456950

4670 7000 8000

5730 9040 10910

6490 10780 13820

6820 11610 15180

7470 13870 18630

5760 7260 8340

7860 9900 11380

9960 12540 14410

11000 13860 15930

14150 17820 20480

~°

4 I/2

13,75 16.60 20.00 22.82

14940 17670 21000 23150

20370 24100 38630 31570

25800 30520 36270 39990

28510 33740 40090 44200

36660 43370 51540 56820

156420 190740 236830 269550

213310 260100 322950 367570

270190 329460 409070 465590

298630 364140 452130 514590

383950 468180 581310 661620

3940 5980 8050 9280

4710 7550 10980 12660

5170 8850 13900 16030

5340 9460 15340 17120

5910 10990 18840 22780

5300 6590 8410 9820

7230 8990 11470 13400

9150 11380 14520 16970

101~0 12580 16050 18750

13010 16180 20640 24112

~°

5

16.25 19.50 25.60

20210 23630 29680

27560 32230 40470

34910 40820 51270

38580 45120 56660

49610 58010 72850

190100 228360 306000

259220 311400 417500

328350 394440 535000

362910 435960 585000

466600 560520 750000

3800 5630 8400

4510 7070 11460

4920 8230 14510

5060 8760 16040

5670 10050 20540

5210 6370 8800

7100 8690 12000

9000 I1000 15200

9950 12160 16800

12790 15640 21600

19.20 21.90 24.70

29180 32450

39790 44250

50400 56050

55710 61950

71630 79650

215790 252910 304095

294260 344880 391282

372730 436840 525260

411970 482820 580540

529670 620770 746420

3260 4690 6060

3760 5760 7670

4140 6530 9000

4340 6860 9620

4720 7520 11200

4860 5780 6640

6630 7880 9050

8400 9980 11470

9290 11030 12680

11940 14180 16300

25.20

40870

55740

70600

78030

100320

284150

387480

490810

452470

697460

2510

2930

3250

3350

3430

4290

5850

7420

8200

10540

5 1/2

65/8

1Based on the sbaaz strength equal to 57.7% of minimum yield strcngth. 2Torsinnal and Tensile data based on 20% uniform wear. 3Collapse and Internal wessurc data based on minimum wall of 80% of nominal (new) wall, NOTE: Calcularions for Premium Class drill pipe are based on formulas in Appendix A, API RP7G. Tabie is based on API RP7G, tables 2.3 and 2.4.

D

E

"0 ~°

Table 4-82 Class 2 (Used) Drill Pipe--Torsional, Tensile, Collapse and Internal Pressure Data [30] Size

Nom,Wt.

OD

New ~pe

in,

wfrJ.

1~ Torsional Yield S~ength B~ed On Umform Wear, ft-lb

2Tensile Data Based On Uniform Wear Load At Minimum Yield Strength, lb,

D

E

95

105

135

,.

3Collapse l~essure Based On Minimum Values, psi

3 Internal l~essure At Minimum Yield Strength, psi.

D

E

95

IO5

135

D

E

95

105

135

D

E

95

105

135

2 3/8

4.85 6,65

2230 2880

3040 3920

3850 4970

4250 5490

5470 7060

56400 78925

76910 107620

97420 136320

107680 150670

138440 193720

4880 8420

6020 11480

6870 14540

7240 16080

8030 20630

8430

11490

14560

16090

20680

2 7/8

6.85 10.40

3790 5300

5160 7220

6540 9150

7230 10110

9290 13000

78450 122100

106970 166500

135500 210900

149760 233100

192550 299700

4340 8990

5270 12260

5900 15520

6150 17160

6610 22060

5390 8990

7360 12260

9320 15530

i0300 17170

13240 22070

3 1/2

9.50 13.30 15.50

6630 8590 9650

9040 11710 13160

11450 14830 16670

12660 16390 18430

16280 21070 23690

ll2220 155650 183700

153020 212250 250500

193830 268850 317300

214230 297150 305700

275440 382050 450900

3990 7520 9150

4790 10250 12480

5270 12420 15810

5450 13450 17480

6010 16310 22470

5185 7510 9170

7070 10240 12510

8960 12970 15850

9900 14340 I7520

12730 18440 22530

4

11.85 14.00 t5.70

9150 10880 12000

12480 14830 16360

15810 18790 20720

17470 20770 22900

22460 26700 29450

133510 165715 186160

182060 225980 253860

230610 286240 321560

254890 316360 355400

327710 406760 456950

3160 5180 6700

3620 6440 8560

4020 7410 10150

4210 7850 10910

4550 8840 12930

4670 5880 6970

6370 8020 9260

8070 10165 11730

8920 11240 12970

11470 14440 16670

4 1/2

13.75 16.60 20,00 22,82

12190 14430 17150

16630 19680 23380

21060 24920 29620

23280 27550 32740

29930 35420 42090

156430 190740 236830 269550

213310 260100 322950 367570

270190 359460 409070 465590

298630 364140 452130 514390

383950 468180 581310 661620

2540 4270 6770 9940

2960 5170 8660 10830

3290 5770 10280 137[0

3400 6010 11050 14950

3480 6490 13120 18320

5350 6840 7940

7300 9330 10830

9250 11820 13720

10220 13070 15170

13140 16800 19500

5

16.25 t9.50 25.60

i6500 19300 24240

22500 26320 33050

28500 33330 4[870

31500 36840 46270

40500 47370 59490

190100 228360 306000

259220 311400 417500

328350 394440 535000

362910 435960 585000

466600 560520 750000

2420 3970 7150

2850 4760 9420

3150 5230 11270

3240 5410 12160

3300 5970 [4590

4220 5190 7150

5760 7080 9750

7300 9070 12350

8060 9910 13650

10370 12740 17550

5 1/2

19.20 21.90 24.70

23830 26490

32490 36130

41150 45760

45490 50580

58480 65030

215790 252910 304095

294260 344870 391282

372730 411970 436840 482820 525260 580540

529670 620770 746420

2110 3170 4340

2440 3640 5260

2610 4040 5890

2650 4230 6140

2650 4580 6610

3960 4700 5400

5400 6410 7360

6840 8120 9330

7560 8970 10310

9720 11540 13250

284150

387480

490810

697460

1690

1870

[900

1900

1900

3550

4840

6137

6783

8721

65/8

25,20

IBased on the shear strength equal to 57.7% of minimum yield st~ngth, 2Torsional data based on 35% eccentric we:at and tensile data based on 20% uniform wear. 3Data is based on minimum wall of 65% nominal wall, NOTE: Calculations for Cla~ II driU pipe are based on formu~s in Appendix A, API RPTG, Table is based on AP[ RPTG, tables 2.5 and 2,6.

542470

Oq

Table 4-83 Class 3 (Used) Drill Pipe--Torsional, Tensile, Collapse and Internal Pressure Data [30] Nom.Wt. New Pipe wrl'J. Ib/ft

D

E

95

105

135

D

E

95

105

135

D

E

95

105

135

D

E

95

105

135

2 318

4.85 6.65

1870 2390

2550 3260

3230 4130

3570 4570

4590 5870

43380 60170

59]60 82050

74940 I03930

82820 I14870

I06490 147690

3620 7400

4260 I0030

4590 12050

4810 13040

5350 15760

4860 7132

6631 9730

8400 12320

9280 13620

11940 17510

2 7/8

6.85 10.40

3180 4400

4340 6000

5490 7590

6070 8390

7810 I0790

60380 93060

82340 126900

I04300 160740

I15280 177660

148220 228420

3140 7920

3600 10800

4010 13680

4190 14880

4530 18230

4630 7610

6320 10380

8000 13150

8840 14540

I1370 18690

3 I/2

9.50 13.30 15.50

5580 7170 8010

7600 9770 I0920

9630 12380 13830

I0640 13680 15290

13680 17590 19660

86450 118965 139700

I17880 162220 190500

148320 205480 241300

165040 227120 266700

212190 292000 342900

2840 6320 8070

3230 8040 II010

3650 9480 13950

3790 I0160 15420

4000 I1930 18960

4400 6350 7770

6000 8660 I0590

7600 I0970 13410

8400 12120 14820

10800 15580 19050

4

II.85 14.00 15.70

7700 9130 I0040

10500 12440 13690

13310 15760 17340

14710 17420 19160

18910 22400 24640

I03010 126555 142700

140470 172580 194600

177930 218600 246490

196650 241600 272430

252840 310640 350270

2210 3880 5210

2570 4630 6490

2790 5070 7480

2840 5230 7920

2850 5810 8940

3960 5000 5750

5400 6820 7840

6840 8640 9930

7560 9560 I0970

9720 12280 14110

4 I/2

13.75 16.60 20.00 22.82

I0280 12130 14350

14010 16530 19560

17750 20940 24780

19620 23150 27390

25220 29760 35210

120800 ]46800 181665 205860

164730 200180 247720 280720

208660 253560 313780 355380

230620 280240 346820 393000

296510 360320 445900 505290

1850 3080 5280 6960

2090 3520 6580 8960

2170 3930 7590 10680

2170 4110 8040 11500

2170 4420 9100 13710

3630 4520 5770 6720

4950 6170 7870 9170

6270 7810 9960 I1610

6930 8630 II010 12830

8910 11100 14160 16500

16.25 19.50 25.60

13910 16220 20260

18960 22120 27620

24020 28020 34990

26550 30970 38670

34130 39820 49720

146860 176220 232870

200260 240300 317550

253660 304380 402230

280360 336420 444570

360460 432540 571590

1780 2820 5760

1990 3210 7250

2050 3630 8460

2050 3770 9020

2050 3960 10410

3590 4380 6050

4890 5970 8250

6190 7560 I0450

6850 8360 I1550

8800 I0750 14850

19.20 21.90 24.70

20060 22260

27350 30350

34640 38450

38290 42490

49230 54640

166840 195700 221045

227510 266040 301420

288180 336980 381800

318520 372460 422000

409520 478870 542560

1520 2220 3140

1640 2580 3600

1640 2810 4000

1640 2860 4190

1640 2870 4520

3340 3980 4560

4550 5430 6220

5770 6870 7880

6380 7600 8710

8200 9770 II190

219960

299950

379930

419930

539900

I160

I170

1170

I170

I170

3020

4120

5220

5770

7420

Size OD in.

5

5 I/2

65/8

25.20

1,2Torsional Yield Strength Based On Eccentric Wear, ft-lb

2Tensile l ~ t a Based On Umform We~ur Load at Minimum Yield Strength, lb.

1 IBased on the shear strength equal to 57.7% ofminimum yield strength. 2Torsioml data based on 45% eccentric wear and Tensile data based on 37.5% uniform wear. 3Data is ba~d on minimum wall of 55% nominal wall. NOTE: CMculafions for Cla~ III drill pipe are based on formulas in Append~ A, API RPTG. Table ~ ba~d on API RPTG, tables 2.7 and 2.8

1Col~pse Pressure Based On Minimum Values, psi.

1Internal Preasure At Minimum Yidd Strength, psi.

~" "" 0 "~ ~" 0

~"

",4

744

Drilling a n d Well C o m p l e t i o n s

(text continued from page 739)

C o n s i d e r a case in which the drill p i p e is e x p o s e d to an axial load (P) and a torque (T). T h e axial stress (tyz) a n d the shear stress (z) are given by the following formulas: P ty, = - A =

-

(4-55)

T Z

(4-56)

-

where P = A = TZ = Z = J Ddp ddp

axial load in lb cross-sectional area of drill p i p e in. 2 torque in in-lb p o l a r section m o d u l u s of drill pipe, i n ? 2J/DaD (~/32)(D 4. - d 4. ) p o l a r m o m e n t of inertia, in. 4 outside d m m e t e r of drill p~pe m m . inside d i a m e t e r of d r i l l p i p e i'n in. .

qp

ap

.

.

.

.

-

Substituting Equation 4-55 a n d Equation 4-56 into Equation 4-54 a n d p u t t i n g 0 (tangential stress equals zero in this case), the following formulas are obtained:

(Ire = Ym, G, =

(4-57)

(4-58)

where P = Ym A = tensile load capacity of drill pipe in uniaxial tensile stress in lb Equation 4-58 p e r m i t s calculation of the tensile load capacity when the p i p e is subjected to rotary torque (T).

Example Determine the tensile load capacity of a 4 ~-in., 16.6-1b/ft, steel grade X-95 new drill p i p e subjected to a rotary torque of 12,000 ft-lb if the required safety factor is 2.0.

Solution F r o m Table 4-71, cross-sectional area body of p i p e A = 4.4074 i n ? and Polar section modulus Z = 8.542 i n ? F r o m Table 4-80, tensile load capacity of drill p i p e at the m i n i m u m yield strength P = 418,700 lb (P, = 4.4074 x 95,000 = 418,703 lb). Using Equation 4-58,

Drill String: Composition and Design

745

P = I(418700) 2 - 3 ( 4. 4079× 144,000 / 2iV2 \ 8.542 J J =398,4321b

L

Due to the safety factor of 2.0 the tensile load capacity of the drill pipe is 398432/2 = 199,216 lb.

Example Calculate the maximum value of a rotary torque that may be applied to the drill pipe as specified in Example 5 if the actual working tension load P = 300,000 lb. (For instance, pulling and trying to rotate a differentially stuck drill string.)

Solution From Equation 4-58, the magnitude of rotary torque is

T= A

SO 8.542 I(418,7002 300,000)2] v2 T = 4.4074 L ~ = 353,571 in-lb or 29,464 ft-lb Caution: No safety factor is included in this example calculation. Additional checkup must be done if the obtained value of the torque is not greater than the r e c o m m e n d e d makeup torque for tool joints. During normal rotary drilling processes, due to frictional pressure losses, the pressure inside the drill string is greater than that of the outside drill string. The greatest difference between these pressures is at the surface. If the drill string is thought to be a thin wall cylinder with closed ends, then the drill pipe pressure produces the axial stress and tangential stress given by the following formulas: (For stress calculations, the pressure loss in the annulus may be ignored.)

PdpDdp

o, = ~

o~ =

4t

PdpDdp 2t

where o a = ot = Pdp = t = Ddp =

axial stress in psi tangential stress in psi internal drill pipe pressure in psi wall thickness of drill pipe in psi outside diameter of drill pipe in in.

(4-59)

(4-60)

746

Drilling and Well Completions

Substituting Equations 4-59, 4-60, 4-56, and 4-55 into Equation 4-54 and solving for the tensile load capacity of drill pipe yields

p

=L

t

16~

t

- 3 ( - ~ ) ~ ] I/2

(4-61)

Example Find the tensile load capacity of 5-in., nominal weight 19.5-1b/ft, steel grade E, premium class drill pipe exposed to internal drill pipe pressure Pdp = 3,000 psi and rotary torque T = 15,000 ft-lb.

Solution From Table 4-79 Nominal D d = 5 in., nominal ddp = 4•276 in., nominal wall thickness t = 0•362• Reduced ~vall thickness for p r e m i u m class drill pipe = (0•8)(0•362) = 0•2896 in. Reduced D d for premium class = 4.276 + (2)(0•2896) = 4•8552 in. Cross-sectional area for premium class = Area based on reduced Odp - Area based on nominal ddp: •

p

ddp =-~-/~(4•8552) 2 --~-~(4•276) 2 =

.

4•1538inf

Section modulus for premium class:

(D4dp-- d4"~ dp|=

x | Z=-]-~(

bd;

)

X ~

( 4. 85524-4.2764 )

=8.9526in.3

4.8552

From Table 4-81, Pt = 311,400 lb (using Equation 4-61),

I

3 F(3,000)(4•8552)(4•1538)I 3F(4•1538)(180,000)I (

P = [ (311'400)-I"6"L

0.2-8-96

J -

L

~

J J

= 260,500 lb The reduction in the tensile load capacity of the drill pipe is 311,400 260,500 = 50,900 lb. That is about 17% of the tensile drill pipe resistance calculated at the minimum yield strength in uniaxial state of stress. For practical purposes, depending upon drilling conditions, a reasonable value of safety factor should be applied• During DST operations, the drill pipe may be affected by a combined effect of collapse pressure and tensile load. For such a case, c~ = P....~.~ Ym Pc

or

(4-62)

Drill String: C o m p o s i t i o n a n d Design

6, = Ym Pc_._.~¢ Pc

747

(4-63)

where Pc = m i n i m u m collapse pressure resistance as specified by API in psi Pcc = c o r r e c t e d collapse pressure resistance for effect o f tension in psi Ym = minimal yield strength o f p i p e in psi Substituting Equation 4-63 and Equation 4-55 into Equation 4-54 (note: 6 r = 0, = 0, 6 e = Ym) a n d solving Pcc yields

[ cc

2 V2 ~2AY m ) ]

2AYm

(4-64)

or

P¢¢ = Pc

1-0.75

-0.5

cz Ym

(4-65)

Equation 4-65 indicates that i n c r e a s e d tensile l o a d results in d e c r e a s e d collapse pressure resistance. The decrement o f collapse pressure resistance during normal DST o p e r a t i o n s is relatively small; nevertheless, u n d e r certain conditions, it may be quite considerable.

Example D e t e r m i n e if the drill pipe is strong enough to satisfy the safety factor on collapse o f 1.1 for the DST c o n d i t i o n s as below: • • • •

Drill pipe: 4~-in., 16.6-1b/ft n o m i n a l weight, G-105 steel grade, class 2 Drilling fluid with a density o f 12 l b / g a l and drill p i p e e m p t y inside Packer set at the d e p t h o f 8,500 ft Tension load o f 45,000 lb, a p p l i e d to the drill p i p e

F r o m Table 4-84, the collapse pressure resistance in uniaxial state o f stress, P - 6,010 psi. Reduced wall thickness for class 2 drill pipe = (0.65)(0.337) = 0~219 in. R e d u c e d Da_ for class 2 drill p i p e = 3.826 + (2)(0.219) = 4.264 in. R e d u c e d cross-sectional area o f class 2 drill p i p e equals:

(4.264) 2 - 4 (3.826) 2 = 2.783 in.2 T h e axial tensile stress at packer level is 45,000 _- 16,170psi 6~ = 2.783

748

Drilling and Well Completions

The corrected collapse pressure resistance according to Equation 4-65 is

P¢¢ = 6,010

1-0.75

1--2Z--2-~"

0.5

105,000

= 5,493psi

Hydrostatic pressure of the drilling fluid behind the drill string at the packer level is Ph = (0.052)(12)(8,500) = 5,304 psi Obtained safety factor = 5,493/5,304 = 1.0356. Since the obtained magnitude of safety factor (1.03) is less than desired (1.1), the drill pipe must not be run empty inside.

Tool Joints The heart of any drill pipe string is the threaded rotary shoulder connection (Figure 4-133), known as the tool joint. Today, the only API standard tool joint is the weld-on joint shown at the bottom of Figure 4-133. Tool joint dimensions for drill pipe grades E, X, G and S (recommended by API) are given in Table 4-84. Selection of tool joints should be discussed with the manufacturer. This is due to the fact that, up to the present time, there are no fully reliable formulas for calculating load capacity of tool joints. It is r e c o m m e n d e d that a tool joint be selected in such a manner that the torsional load capacity of the tool joint and the drill pipe would be comparable. The decision can be based on data specified in Tables 4-85 through 4-88.

Makeup Torque of Tool Joints The tool joint holds drill pipe together, and the shoulders (similar to drill collars) form a metal-to-metal seal to avoid leakage. The tool joint threads are designed to be made up with drilling fluid containing solids. Clearance must be provided at the crest and root of threads in order to accommodate these solids. Therefore, the shoulder is the only seal. To keep the shoulders together, proper makeup torque is required. However, makeup torque applied to the tool joint produces as axial preloading in the pin and the box as well as a torsional stress. In particular, makeup torque induces a tensile state of stress within the pin and compression stress in the box. Thus, when the tool joint is exposed to the additional axial load due to the weight of the drill string suspended below the joint, the load capacity of the tool joint is determined by the tensile strength of the pin. The magnitude of the makeup torque corresponding to the maximum load capacity of the tool joint is called the r e c o m m e n d e d makeup torque. Therefore, the actual torque applied to the drill string should not exceed the recommended makeup torque; otherwise, the load capacity of the tool joint is reduced. The API recommended makeup torque for different types of tool joints and classes of drill pipe is given in Table 4-89.

Drill String: Composition and Design

749

~AT A~FECT~D ZONE 'T V~$,~E O . , R I L L STE.)

P~N

(uoT

v)S~BL~ oN

DRILL STEM)

UPS{T OR!LL P~PE~SEE sEc B-I PAGE9 TONG AREA

r PIN

I

P~;N RELIEF GROOVE P)N BA${ RADIUS

BOX

. . . . . . . . . . . . . . ~K SHOULDER

ELEVATOR SHOUL~

(SCAT)

LAST ENGAGED ?HREAD~

PiN

L£NGTH O~ PIN

L E N G T H OF BOX

HARDFAC~NG ~$ AN OPTIONAL ?EATURC

Figure 4-133. Tool joint nomenclature [30]. Heavy-Weight Drill Pipe

Heavy-weight drill pipe (with wall thicknesses of approximately 1 in.) is frequently used for drilling vertical and directional holes (Figure 4-134). So far, there is no sound, consistent, engineering theory of drill string behavior while (text continued on page

760)

750

Drilling and Well Completions Table 4-84

Tool Joint Dimensions for Grade E, X, G and S Drill Pipe [30] 1

2

Tool Joint Desirnationl

She and StYle

3 4 DRILL ^ PIPE Nora. Grade ~ Wt,S Ib Per ft

NC26(2%IF)

2% E U

0.65

E"/5 X95 G105

3%* 3% e 3%*

1% a 1%* 1%*

3t| 3~ 31~

9 9 9

6 6 6

7 '7 7

13 13 13

2,~ 2,~ 2,?s

2,~s 2,~s 2,?s

1.10 .87 .79

NC31(2%IF)

2% E U

10A0

E75 X95 G105

4~* 4~* 4JA *

2~* 2 2

30~ 3Ri 3|;t

9½ 9½ 9½

6 6 6

8 8 8

14 14 14

3~ 3~ 3~

3~ 3~ 3~

1.03 .90 .82

S135

4%

1%

3|t

9½

6

8

14

3,~

3,~

.82

NC384

3½ E U

9.[;0

E75

4%*

3

41"~

10½'

'7

9~

16½

3%

3%

.91

NC38(3½IF)

3½ E U

13.30

E75 X95

4%* 5

2~I* 2~

4i~ 4J]

11 11

7 7

9½ 9½

16½ 16½

3% 3%

3% 3%

.98 .87

G105 $155

5 5

21z~ 2~

4t~ 41"~

11 11

7 7

9½ 9½

16½ 16½

3% 3%

3% 3%

.86 .80

15.50

NC40(4FH )

NC46(41F)

6 7 8 9 10 TOOL~ JOINT Inside Bevel Total Pin Box Dla Di~ of L e ~ Tong Tong of Pins Pin and Tool SPace Spaee -{-1/64 Box Joint .~+~ ± ~ --1/$2 ShoUlder Pin ::t:l/g4 " ~

11 Combined Length of Pin and BOX

12 13 14 , Dis Dta Totof Pin of Box siona/ at Ele- at Ele. Rstio, vator wtor Pin Upset, Upset. to Max Max Drill Pipe

E75

5

2~

4t¼

11

7

9½

16½

3%

3%

.9.7

X95 G105

5 5

21z~ 2~

4t~ 41¼

11 11

7 7

9½ 9½

16½ 3% 16½ 3%

3% 3%

.83 .90

3½ E U

15.50

$155

5½

2~4

5~

11½

7

10

17

3%

3%

.87

4

14.00

E75 X95 G105 $135

5~4" 51/, * 5½ 5½

23|* 2}~ 2~ 2

5~ 5~ 5~'~ 5~

I1½

i0 10 10 10

17

11½ 11½

7 7 '7 '7

17 17

4~ 4~ 4,~s 4~

4~ 4~ 4~ 4~

1.01 .86 .93 .87

E75 X95 G105 $135

6* 6* 6* 6*

3~4" 3~4" 3~4" 3

5J| 5|| 5§~ 5~

11½ 11½ 11½ 11½

7 7 7 '7

10 10 10 10

17 17 17 17

4½ 4½ 4½ 4½

4½ 4½ 4½ 4½

1.43 1.13 1.02 .94

5~] 5§| 5|~ 5|~

11½ 11½

'7 '7

10 10

17 17

4~r 4~

4~r 4~r

1.09 1.01

11½

7

10

17

4~

4~

.91

11½

'7

10

1'7

4~

4~r

.81

7

10 10 10

17 17 17

4~

4~

7 7

4~

4~ 4~r 4~r

1.07 .96 .96

4~r 4}i 4~r

1,12 1.02 -q2

4

IU

EU

14.00

4½ I U

16.60

4½ I E U

4½ FH*~

5 "Outside Din of Pin &nd Box ~1/$2

20.00

E75 X95

6* 6*

3~4" 3

G105

6*

3

$135

61/,

2%

11½

E75

6*

3

5~|

X95 G105

6~A 61/,

2% 2½

5~| 5||

11½ 11½ 11½

17

$135

6~4

2~,

5~

11½

7

10

17

4~r 4}~r

4~A I U

16.60

E75 X95 G105

3" 2% 2%

7 7 7

I0 10 10

17 17 17

4~r 4~ 4~r

2½

5~ 5|~ 5|| 5|~

11 11 11

$135

6* 6* 6* 6~A

11

7

10

17

4}~

4}t

.81

4½ I E U

20.00

E75 X95 G105

6* 6* 6*

3* 2~A 2½

5|| 5|~/ 5|~

11 11 11

'7 7 7

10 10 10

1'7 17 17

4~ 4}~ 4}~

4~I 4}~ 4~

.95 .9g .86

.81

ODenotes standard OD or standard ID. **Obsolescent connection. XTho tool Joint designation (CoL 1) indicates the size and style of the applicable connection. SNominal weights, threads and coupnnp, (Col. 3) are shown for the purpose of identification in ordering. SThe inside diameter (Col. 6) does not apply to box members, which are optional with the manufacturer. 4Length of pin thread reduced to 8 ~ inches ( ~ inch short) to accommodate 3 inch ID. NOTE 1: Neck diameters (D~s & D~) and inside diameters (d) of tool joints p r ~ r to welding are at manufacturer's option. The above table specifies finished dimensions after final machining of the assembly. NOTE 2: Appendix H contains more.dimenslons of obsolescent connections and for square elevator shoulders. NOTE 3: No torsional ratio (tool Joint pin to drill pipe) less than 0~0 is shown. In particular areas, tool Joints having much smaller torsional yields may prove to be adequate.

Drill String: Composition and Design

751

Table 4-84

(continued) 1

2

3 DRILL PIPE

TOol Joint Designation1

Size and Style

Nora. Wt.~

4

5

Grade

Ibpe]

~t

Outside Dis of Pin and Box ~---1/82

D NC50(4½IF)

5½ FH'*

6

7

Inside Bevel Dia Dia of of pi~3 Pin a~d -~1/64 Box --I/32 Shoolde] --~I/64 d

8 9 10 TOOL JOINT

11

12

Total Pin Box Com. iDi~ Length Tong Space bined of pin T~] Space ----.¾ Length at Eleof Pin ~tor Joint Pin ~d U~set, +IA BOx Max L

13

14

Dia of Box at EIe. vator Upset. Max

Tcrsional Ratio. Pin to Drill

D~

L~

L~s

La

D~

Dr~

4% E U

16.60

E75 X95 G105 S135

6%* 6%* 6%* 6%*

3%* 3~* 3%* 3½

5t~ 5t~ 5{~ 5J~

11½ 11½ 11½ 11½

7 7 7 7

10 10 10 10

17 17 17 17

5 5 5 5

5 5 5 5

1.23 .97 .88 .81

4½ EU

20.00

E75 X95 G105 S135

6%* 6% ~ 6%* 6%

3%* 3½ 3½ 3

5~; 5t~ 5~ 5~

11½ 11½ 11½ 11½

7 7 7 7

10 10 10 10

17 17 17 17

5 5 5 5

5 5 5 5

1.02 .96 .86 .87

5

IEU

19.50

E75 X95 G105 S135

6%* 6%* 6½ 6%

3%* 3½ 3% 2~

5t~ 5~ 5~ 5~

11½ 11½ 11½ 11½

7 7 7 7

10 10 10 10

17 17 17 17

5% 5½ 5½ 5½

5½ 5½ 5½ 5½

.92 .86 .89 .86

5

IEU

28.60

E7~ X95 G105

6%* 6½ 6%

3½ 3

2%

5~ 5~ 5t~

11½ 11½ 11½

7 7 7

10 10 10

17 17 17

5½ 5½ 5½

5% 5½ 5%

.86 .86 .87

5

IEU

19.50

E75 X95 GI05 S135

7* 7* 7* 7%

3% 3% 3% 3½

6~ 6~ 6~ 6~.

13 13 13 13

8 8 8 8

10 10 10 10

18 18 18 18

5% 5½ 5½ 5½

5½ 5½ 5½ 5½

1.53 1.21 1.09 .98

5

IEU

25.60

E75 X95 G105 S135

7* 7* 7~ 7%

3½ 3½ 3½ 3%

6~ 6~ 6~ 6~

13 13 13 13

8 8 8 8

10 10 10 10

18 18 18 18

5% 5½ 5½ 5~

5% 5½ 5½ 5½

1.21 .95 .99 .83

5½ IEU

21.90

E75 X95 G105 S135

7~ 7* 7% V½

4 3% 3½ 3

6.~ 6~ 6~.~ V~

13 13 13 13

8 8 8 8

10 10 10 10

18 18 18 18

5{?, 5{~ 5{~ 5~

5{~ 5½~ 5{~ 5~

1.11 .98 1.02 .96

5½ IEU

24.70

E75 X95 G105 S135

7~ 7% 7~ 7½

4* 3½ 3½ 3

6~ 6~ 6~ 7~

13 13 13 13

8 8 8 8

10 10 10 10

18 18 18 18

5{~ 5}~ 5{~ 5{~

5{~ 5l~

.99 1.01

5½~

.92

5{~

.86

~'Denotes standard OD or standard ID. o*Obsolescent connection. IThe tool joint designation (Col. 1) indicates the size and style of the applicable connection, ZNomlnaI weights, threads and couplings, (Col, 3) are shown for the purpose of identification in ordering. 3The inside diameter (Col. 6) does not apply to box members, which are optional wlth the manufacturer. LLength of pin thread reduced to 3 ~ inches ( ~ inch short) to accommodate 3 inch ID. NOTE 1: Neck diameters ( D ~ & Dw) and inside diameters (d) of tool joints prior to welding are a t manufacturer's option. The above table specifies finished dimensions after final machining of the assembly. NOTE 2: Appendix H contains more dimensions of obsolescent connections and for square elevator shoulders. NOTE 3: No torsional ratio (tool joint pin to drill pipe) less than 0.80 is shown. In particular areas, tool joints having much smaller torsional yields may prove to be adequate. '

L Lp -

• ~,~,,L I 7 ~ J - - ~

"*r

Lp~-~-~------- L. ~

d | --

..

~

~

--IL-L ~

-------~ I

.+2" /

~

Sh'O,.X.OZREO s~

S~CT. )

Le--

]

d D l .

I

[

. . . .

|

TAPER SHOULDER)

.

R

Table 4-85 Selection ChartmTool Joints Applied to Standard Weight Drill Pipe--Grade E [30] DRILL PIPE DATA - TOOL JOINT ATTACHED

TOOL JOINT DATA

MECHANICAL PROPERTIES

Nora. Size

Nom. Wt. Ib/ft

Adj. Wt. Ib/ft (1)

Type

Upset Max. O.D. in.

Drift Dia

Conn.

2 3/8

6.65

6.75 6.87 7.00

1.815

IU EU EU

2 I/2 2 9/16 2 9/16

1.312 1.627 1.627

PAC O.H. NC26(I.F.)

O.D. in. 2 7/8 3 1/4 3 3/8

I.D. in. I 3/8 I 3/4 1 3/4

7 7 7

6 6 6

2 7/8

10A0

10.29 11.20 10.37 10.82 10.57 10.53 14.06 13.51 13.86 13.86

2.151

IU IU IU EU EU EU IU [U EU EU

3 3 3 3 3/16 3 3/16 3 3/16 3 11/16 3 11/16 3 7/8 3 7/8

1.438 1.812 1.688 1.963 1.963 2.006 2.313 2.000 2.446 2.446

PAC E.H. NC26(S.H.) NC31(I.F.) O.H. SL-H90 E.H. NC31(S.H.) NC38(I.F.) O.H.

3 1/8 4 1/4 3 3/8 4 1/8 3 7/8 3 7/8 4 3/4 4 1/8 4 3/4 4 3/4

I 1/2 I 7/8 I 3/4 2 1/8 2 5/32 2 5/32 2 7/16 2 1/8 2 11/16 2 I 1/16

8 8 8 8 8 8 9 8 9 9

3 I/2

13.30

i.D. in.

2.764

Tong Space in.

4

14.00

15.13 14.29 15.50 15.56 15.07

3.340

IU IU IU EU EU

4 4 4 4 4

3/16 3/16 3/16 1/2 1/2

2.688 2A38 2.688 3.125 3.125

NC40(F.H.) S.H. H90 NC46(I.F.) O.H.

5 4 5 6 5

I/4 5/8 1/2

4 1/2

16.60

17.94 17.70 16.66 17.94 17.64 17.22

3.826

IU IU IU IU EU EU

4 4 4 4 5 5

11/16 11/16 11/16 11/16

3.125 2.875 2.562 3.125 3.625 3.125

NC46(E.H.) R.H. NC38(S.H.) H90 NCS0(I.F.) O.H.

6 6 5 6 6 3/8 5 7/8

1/2

Tensile Yield Ib

Torsional Yield ft-lb

Tool Joint (3)

ripe (4)

138220 138220 138220

262000 287280 323760

6240 6240 6240

Tool Joint (5) 5200 6400 6800

1/2 1/2 1/2 I/2

6 214340 6 214340 6 214340 6 214340 6 214340 6 214340 7 271570 6 1/2 271570 7 271570 7 271570

269470 516840 323760 459120 345840 384600 584880 459120 602160 560040

11530 11530 11530 11530 11530 11530 18520 18520 18520 18520

5800 13400 6800 12000 8600 11800 17300 12000 18700 14900

2 13/16 10 2 9/16 9 I/2 2 13/16 10 3 1/4 10 3 1/4 10

7 285360 6 1/2 285360 7 285360 7 285360 7 285360

727440 525840 913680 918960 760080

23250 23250 23250 23250 23250

24000 15400 35520 34100 26800

3 3 2 3 3 3

7 330560 7 330560 6 1/2 330560 7 330560 7 330560 7 330560

918960 976440 601880 938280 958800 718080

30750 30750 30750 30750 30750 30750

34100 34600 18700 37400 37900 27400

Box

1/4

10 10 11/16 9 1/2 1/4 10 3/4 10 3/4 10

Pin

Pipe (2)

5

19.50

20.99

4.276

IEU

5 1/8

3.625

NCS0(E.H.)

6 3/8

3 3/4

10

7

395600

958800

41090

37900

5 1/2

21.90

23.94

4.778

IEU

5 11/16

3.875

F.H.

7

4

10

8

437120

1265880

50620

55700

6 5/8

25.20

27.14

5.965

IU

6 3/4

4.875

F.H.

8

5

14 1/2

9 1/2 489460

70550

73000

1448880

I Tool Joint Plus 29.4' of Drill Pipe. 2 Tensile yield Strength of Drill Pipe Based on 75,000 psi. 3 Tensile Yield Strength of the Tool Joint Pin is based on 120,000 psi Yield and the Croga Sectional Area at the Root of the Thread 5/8 inch from the Shoulder. 4 Torrional Yield Strength of the Drill Pipe is Based on a Shear Strength of 57.7•of the Minimum Yield Strength. $ ToNional Yield Strength of the Tool Joint BaSed on Tensile Yield Strength of the Pin and Compressive Yield Strength of the Box - Lowest Value Prevailing.

O~

<3

<3

Table 4-86 Selection Chart--Tool Joints Applied to Lightweight Drill Pipe---Grade E [30] DRILL PIPE DATA - TOOL JOINT ATTACHED

TOOL JOINT DATA

Upset Nora. Size

Nora. Wt. ~/fl

Adj. Wt. ro/ft (1)

2 3/8

4.85

5.15 4.94 4.87 5.09

1.995

EU EU EU EU

2;//8

6.85

7.33 6.97 6.91 7.25

2.441

3 1/2

9.50

10.39 10.12 9.95 10.25

11.85

4 1/2

13.75

I.D. in.

Max. O.D. in.

MECHANICAL PROPERTIES Tong Space in.

Drift Dia

Conn.

O.D. in.

I.D. in.

Box

Pin

2 9/16 2 9/16 2 9/16 2 9/16

1.688 1.850 1.807 1.807

NC26(I.F.) S.L.-H90 O.H. W.O.

3 3/8 3 1/4 3 1/8 3 3/8

1 3/4 1.995 2 2

7 7 7 7

6 6 6 6*

EU EU EU EU

3 3/16 3 3/16 3 3/16 3 3/16

2.063 2.296 2.253 2.253

NC31(I.F.) S.L.-Hg0 O.H. W.O.

4 1/8 3 7/8 3 3/4 3 7/8

2 1/8 2.441 2 7/16 2 7/16

8 8 8 8

6* 6 6 6*

2.992

EU EU EU EU

3 7/8 3 7/8 3 7/8 3 7/8

2.563 2.847 2.804 2.804

NC38(I.F.) S.L.-Hg0 O.H. W.O.

4 4 4 4

3/4 5/8 1/2 3/4

2 11/16 2.992 3 3

9 9 9 9

13.09 13.13 12.16 13.03

3.476

IU EU EU EU

4 4 4 4

3/16 1/2 1/2 1/2

2.688 3.125 3.287 3.287

H90 NC46(I.F.) O.H. W.O.

5 5 5 5

1/2 3/4 1/4 3/4

2 13/16 3 1/4 3 15/32 3 7/16

15.24 14.98 14.10 14.90

3.958

IU EU EU EU

4 11/16 5 5 5

3.125 3.625 3.770 3.770

H90 NCS0(I.F.) O.H. W.O.

6 6 1/8 5 3/4 6 1/8

3 1/4 3 3/4 3 31/32 3 7/8

"I~ype

Tensile Yield Ib

Torsional Yield ft-4b

Tool Joint(3)

Pipe(4)

Tool Joint(5)

323760 204550 206400 205920

4760 4760 4760 4760

6800 5500 4400 4500

135900 135900 135900 135900

459120 259180 224040 289080

8070 8070 8070 8070

12000 7600 5800 7500

7* 194260 6 1/2194260 7 194260 7* 194260

602160 370970 392280 434400

14120 14120 14120 14120

18700 13200 11800 13400

10 10 10 10

7 7* 7 7*

230750 230750 230750 230750

913680 918960 621960 801120

19440 19440 19440 19440

35500 34100 22100 29300

10 10 10 10

7 7* 7 7*

270030 270030 270030 270030

938280 958920 559440 868920

25860 25860 25860 25860

37400 37900 21100 34100

1/2 1/2 1/2 1/2

Pipe (2) 97820 97820 97820 97820

*If weight is of paramount importance, these connections can be supplied with a smaller O.D. or shorter tong space on box and pin, or a combination of tile two to afford maximum weight reduction without sact'ificing safety in the joint. However, where possible, the manufacturers recommend ordering the joints shown to obtain the maximum economical tool joint service. Other tool joint sizes to accommodate special situations can be furnished on request. I Tool Joint Pins 29A' of Drill Pipe. 2 Tensile Yield Strength of Drill Pipe Based on 7S.000 psi. 3 Tensile Yield Strength of the Tool Joint Pin ts based on 120,000 psi Yield and the CrosS Sectional Area at the Root of the Thread 5/8 inch from the Shoulder, 4 Torsional Yield Strength of the Drill Pipe is Based on a Shear Strength of 57.7~ of the Minimum Yield Strength, 5 Torsional Yield Strength of the Tool Joint Based on Tensile Yield Strength of the Pin end CompresSive Yield Strength of the Box - Lowest Value Prevailing.

O

2. O g0

ffq

Table 4-87 Selection Chart--Tool Joints Applied to Heavy-Weight Drill Pipe--Grade E [30] DRILL PIPE DATA - TOOL JOINT A'FrACHED

TOOL JOINT DATA

MECHANICAL PROPERTIES

Upset

Tong Space

Tensile Yield

Torsional Yield

Max.

in.

lb

ft-lb

Nom.

Adj.

Som. Size

Wt. Ib/ft

Wt. Ib/ft (1)

I.D. in.

Type

O.D. in.

Drift Dia

3 I/2

15.50

16.42

2.602

EU

3 7/8

2.414

NC38(LF.)

5

2 9/16

9 1/2

7

4

15.70f

16.99 17.30 17.43

3.240

IU IU EU

4 3/16 4 3/16 4 I/2

2.562 2.688 3.052

NC40(F.H.) Hg0 NC46(I.F.)

5 1/4 5 I/2 6

2 11/16 2 13/16 3 I/4

10 I0 10

21.73 21.73 21.73 22.33 24.53 24.53 24.53 24.54

3.640

IEU IEU IEU EU IEU IEU IEU EU

4 4 4 5 4 4 4 5

2.875 2.875 2.875 3.452 2.875 2.875 2.875 3.312

NC46(E.H.) F,H. Hg0 NC50(I.F.) NC46(E.H.) F~. H-90 NC50 (I.F,)

6 6 6 6 3/8 6 6 6 6 3/8

3 3 3 3 3/4 3 3 3 3 I/2

25.60

27.17 28.08

4.00

IEU IEU

5 1/8 5 I/8

3.375 3.375

NC50(E.H.) 5 I/2F,H.

6 3/8 7

24.70

26.86

4.670

IEU

5 11/16

3.875

F.H.

7

4 I/2

20.00

22.82

5

5

1/2

3.500

11/16 11/16 11/16 11/16 11/16 11/16 1/8

Conn.

O.D. in.

I.D, in.

Oq

Tool Joint (3)

Pipe (4)

Tool Joint (5)

322780

663550

21050

20600

7 7 7

324150 324150 324150

791620 913680 918960

25760 25760 25760

25900 35500 34100

10 I0 10 10 10 10 10 10

7 7 7 7 7 7 7 7

412360 412360 412360 412360 471240 471240 471240 471240

1066030 976130 1085380 95800 1066030 976130 1085380 958800

36840 36840 36840 36840 40910 40910 40910 40910

39400 34600 44600 37900 39400 34600 44600 37900

3 I/2 3 I/2

I0 10

7 8

53180 530180

1128960 1268540

52160 52160

44600 59000

4

10

8

497220

1265880

56470

55700

Box

Pin

Pipe (2)

tNot API weight I Tool Joint Plus 29.4' of Drill Pipe. 2 Tensile Yield Strength of Drill Pipe Based on 75,000 psi. 3 Tensile Yield Strength of the Tool Joint Pin is based on 120,000 psi Yield and the Cross Sectional Area at the Root of the Thread 5/8 inch from the Shoulder. 4 Torsional Yield Strength of the Drill Pipe is Based on a Shear Strength of 57.7% of the Minimum Yield Strength. 5 Torsional Yield Strength of the Tool Joint Based on Tensile Yield Strength of the Pin and Compressive Yield Strength of the Box - Lowest Value Prevailing.

O

Table 4-88 Selection Chart--Tool Joints Applied to High Strength Drill Pipe [30] DRILL PIPE DATA - TOOL JOINT ATTACHED

TOOL JOINT DATA

Upset

Nora. Size 2 7/8

3 I/2

Nom. Adj. Wt. Wt. lb/ft lb/ft (I) 10.40 9.94 10.53 11.09 I 1.45 13.30

15.50

4

14.32 13.72 14.38 14.95 16.54 16.88

14.00

15.29 15.45 15.56 i5.55 15.45 15.56 16.17 15.70"~ 17.41 17.30 18.18

LD. in. 2.151

2.764

2.602

3.340

3.240

Min. Tensile Yield SUength p.s.i. 95,000 95,000 105,000 135,000

Type EU EU EU EU

95,000 95,000 105,000 135,000 95,000 105,000 95,000 95,000 95,000 105,000 105,000 105,000 135,000 95,000 95,000 135,000

Recommended

MECHANICAL PROPERTIES Tong Space in.

Tensile yield Ib Tool Pipe (2) Joint (3)

Torslonal yield ft-lb

Max. O.D. in.

l~ifl Dig in.

Conn.

O,D. in.

I.D. in.

Box

Pin

3 3/16 33/16 3 3/16 3 3/16

1.781 2.006 1.875 1.781

NC31(I.F.) SL-H90 NC31(I.F.) 3 I/2E.H.

4 I/8 37/8 4 I/8 4 3/4

2 25/32 2 2

8 8 8 8

6 6 6 6

271330 271330 300080 370080

507670 384600 507670 767520

14610 14610 16150 19968

13400 11500 13400 23040

EU EU EU EU EU EU

3 7/8 3 7/8 3 7/8 3 7/8 37/8 3 7/8

2.313 2.563 2.313 2.125 2.313 2.313

NC38(LF.) SL-II90 NC38(I.F.) NC40(4FH) NC38(I.F.) NC40(4FH)

5 4 5/8 5 5 I/2 5 5 I/2

2 9/16 2 11/16 2 7/16 2 I/4 27/16 2 7/16

9 I/2 9 I/2 9 I/2 IO 91/2 I0

7 6 I/2 7 7 7 7

343990 343990 380190 488820 408850 451890

667300 536520 726220 995460 726220 912580

23460 23460 25930 33330 26660 29470

20600 19200 22100 32500 22100 30200

IU IU EU IU IU EU EU IU IU EU

4 3/16 4 3/16 4 I/2 4 3/16 4 3/16 4 I/2 4 1/2 4 3/16 4 3/16 4 1/2

2.562 2.688 2.875 2.313 2.688 3.125 2.875 2.562 2.688 2.625

NC40(F.H.) H90 NC46(I.F.) NC40(F.H.) H90 NC46(I.F.) NC46(I.F.) NC40(F.H.) H90 NC46(|.F.)

5 5 6 5 5 6 6 5 5 6

2 11/16 2 13/16 3 I/4 2 7/16 13/16 I/4

I0 10 10 10 10 10 10 10 I0 10

7 7 7 7 7 7 7 7 7 7

361460 361460 361460 399500 399500 399500 513650 410590 410590 583420

791620 913680 918720 912580 913680 9t8720 1066030 791620 913680 1201540

29450 29450 29450 32550 32550 32550 41840 32630 32630 46380

25400 35500 34100 30200 35500 34100 39400 25400 35500 44200

IU IU IU EU IU IU IU EU IU EU IEU IEU IEU EU IEU EU EU

4 11/16 4 II/16 4 11/16 5 I/8 4 11/16 4 11/16 4 11/16 5 I/8 4 11/16 5 I/8 4 11116 4 11/16 4 11/16 5 1/8 4 11/16 5 I/8 5 1/8

2.625 2.875 2.875 3.375 2.625 2.875 2.875 3.375 2.375 3.375 2.375 2.625 2.875 3.375 2.375 3.375 2.875

F.H. NC46(E.H.) H90 NCS0(I.F.) F.H. NC46(E.H.) H90 NCSO(I.F.) NC46(E.H.) NCS0(I.F.) F.H. NC46(E.H.) H90 NC50(I.F.) NC46(E.H.) NCS0(I.F.) NCS0(I.F.)

6 6 6 6 3/8 6 6 6 6 3/8 6 I/4 6 3/8 6 6 1/4 6 6 3/8 6 I/4 6 3/8 6 5/8

10 I0 10 10 I0 10 I0 10 10 10 I0 10 10 10 10 10 10

7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7

418700 418700 418700 418700 462780 462780 462780 462780 595000 595000 522320 522320 522320 522320 577300 577300 742240

1111680 1066080 1085380 958800 1111680 1066030 I085380 958800 1201540 1128460 1235040 1201440 1085380 1128460 1325280 1128460 1416510

38950 38950 38950 38950 43050 43050 43050 43050 55350 55350 46660 46660 46660 46660 51570 51570 66300

38900 39400 44600 37900 38900 39400 44600 37900 44200 44600 43400 44600 44600 44600 49400 44600 57120

I/4 I/2 I/2 I/2

1/4 I/2

11/16 13/16 3/4

Pipe (4)

Tool Joint (5)

O~ °°

C~ O

4 i/2

16.60

20.000

18.31 18.19 18.19 17.99 18.38 18.31 18.19 17.99 18.92 18.80 21.69 21.84 21.73 22.11 22.06 22.26 22.47

3.826

3.640

95,000 95,000 95,000 95,000 105,000 105,000 105,000 105,000 135,000 135,000 95,000 95,000 95,000 95,000 105,000 105,000 135,000

2 3/4 3 3 3 3/4 2 3/4 3 3 3 3/4 2 3/4 3 I/2 2 I/2 2 3/4 3 3 1/2 2 I/2 3 I/2 3

High Strength table continued on n e x t page.

o

¢3,

O'q

"~ ~r~ ~r~

Table 4-88 (continued) DRILL PIPE DATA - TOOL JOINT ATTACHED

Nora. Size 4 112

Nora. Wt. Ib/ft 22.82

Adj. Wt. Ib/ft (I) 24.60 25.08

LD. In.

Min.

Upset

Tensile Yidd SUe~ ill

Max. O.D. in..

3.500

105,000

24.83

3.500 3.500 3.500

105 ~000 135,000 135,000

21.34

4.276

95,000

IEU

1/8

21.55 21.60

95.000 105,000

1/8 I/8 1/8

4.000

135.000 95,000 105,000

IEU IEU IEU

25.60

23.24 28.62 28.99

IEU IEU

1/8 1/8

21.90

24.24

4.778

IEU IEU IEU

24.71 24.71 25.60

3.500 3.500

95,000 95,000

Type lEO IEU EU IEU EU IEU EU

24.55

3.500

TOOL JOINT DATA

95,000

Recommended* l)rift Dia in.

4 11/16 2.625 4 11116 2.125 5

3.375

4 11/16

2.375

5

3.125

4 11116 2.875 5 2.875

Conn.

O.D. in.

NC46(E.H.) 6 1/4 F.H. 6 1/4 NCSO(I.F.) 6 3/8 NC46(E.H.) 6 1/4 NCSO(LF.) 6 3/8 NCSO(I.F.) 6 5/8 NCSO(I.F.) 6 5/8

I.D. in. 2 314 2 1/4 3 1/2

2 112 3 1/4 3

3

O~

MECHANICALPROPERTIES Tong Space in.

Box

Pin

10 I0 10 10 10 10 10

Tensile Yidd lib

Pipe (2)

Tool JOint (3)

Tmliomd yield fI-Ib

Pipe (4)

Tool Joim O )

596,900 596,900

1201440 1235040

51800 51800

596,900

I 128960

S 1800

44600 43400

44600

659.740 659,740 848,230 848,230

1325280 1287840 1436050 1436050

57280 57280 73640 73640

49400 49900 59400 59400

1128460

44600 51100 49900

O

O 5

5 1/2

19.50

24.36 24.98 25.86

25.66 24.70

27.89

27.89 28~1

95,000 95,000 105,000 135,000

135,0~O 4.670

95,000 105.000

135,OOO

IEU IEU

IEU IEU IEU

3.375 3.125

NCSO(E.H.) 6318 H90 6 1/2

31/2 3 114

3.125

NCSO(E.H.) 6 1/2 5 I/2F.H. 7 1/4

3 114 3 1/2

5 II2F.H. 5 I/2F.H.

7 7 1/4

3 112 3 I/2

11116 3.625 11116 3.375

F.H. H90

11116

7 7 7 1/4

3 3/4 3 112 3 I/2

7 I/2

3

3.375 3.375 3.375

111t6

2.874

F.H. F.H.

11/16

3.375

6 5/8Reg.

7 I/2

3

F.H. F.H. F.H.

7 I/4 7 I/4 7 I/2

3 I/2 3 112 3

3.375

11/16 3.375 5 11116 3.375 5 11116 2.874

1/2

10 10 10 10 I0 10

7 7 7

501090 501090 553830

1176000 1287840

52050 52050 57530

8 8 8

712070 671000 742000

1619520 1619520 1619520

73970 66070 73030

71000 62400 71000

10 10 10 10 I0 10 10 10

8 8 8 8 8 8 8 8

553680 553680 611960 786810 786810 629810 696110 895000

1448640 1268540

64120 64120 70870 91120 91120 71530 79060 101650

62400 59000 71000 85000 82560 71000 71000 85000

1619520

1925760 1802320 1619520 1619520 125760

l Too~ Join! Flus 29A' of DriU Pipe. 2 Tensile Yield Slrength of Drill Pipe Based ~ ?S,OOo psi. 3 Tensile Yield S,trenglh of the Too] Jo~n! Pin is based on ! 20.000 Fud Yield and the Crou SecfionM Area at the Roo! of lhe Thread $/8 inch from lhe ShouMer. 4 Torsional Yield Sl~ngth of lhe Drill Pipe is Based on a Shear Slrenglh of S?.7c~ of the Minimum Yisld Strenglh. S Torsional Yield Stl~engthof lhe Tool Jolet Based on Tensile Yield Slrength of lhe Pin and Comp~uive Yield Slrength of lhe Box - Lowest Vldue Prevaillng. Nol© - Tool joints wi h outalde dtlmelers shown f ~ Grade E on Tables B • , 2 and 3 ate adequale for high slrength dri0 pipe when used in combinxlion slrings wilh Grade E drill pipe. Thus, sizes shown for NC joints u e designed so l h l ! lotsional yield of lhe join! is • minimum of 8Oc~of tha! of the pipe Io wh ch t • attached. Others haw balanced lorsional strength between pipe and joinL

Drill String: Composition and Design

757

Table 4-89 Recommended Minimum OD and Makeup Torque of Weld-on Type Tool Joints by Class [30] 2

3

4

DRILL PIPE DATA

Nora NO~ S~zl= Wt. in.

2'~

2~

)~n

Ib/ft

Type Upset an¢~ Grade

4.85 4.85 4.85 4.85

E.U. 75 E.U. 75 E.U. 75 E.U. 75

W.O. NC26 (I.F.) O.H. SL-H00

6

7

8

New OD

New ID

9

10

11

12

~PREMIUMCLASS

14

15

16

CLASS3

~Min. BOx~Make*Up @MinBox@Make-Up ~Mi~. BOx @Make-Up ~Min Shoulder Torque ®Min Shoulde~ Torque @Mln.Sho~lclor Torque OD With FOrMin. OO With ForMin OD With FOrMin (~Make-up Tool Eccentric ODToOl TOOlEccen(rlc ODTOO# ToolConcentfic ODTool Torque Joint Wear Joint Joint Wear Jo;nt Joint Wear JOint ft-~b i . in. ft-lb in in. ft-lb fl-lb in. in

in.

in.

3~ 3~ 3~ 3¼

2 1~ 2 2

220O 3600 2400 28OO

3~= 3~ 3~'~ 3

~.~ Y= ~/M ~

2200 2300 2300 2300

3Y~ 3~ 3 2~m~

~e Y= ~M ~.~ Y,~

6.65

E.U. 55

NC26 (I.F.)

3~

1¾

3600

3~

~,

2000

3~,.z

I.U. 75 E.U. 75 E.U. 75 E.U. 75

P.A.C. NC26(LF.) SL-H00 O.H.

~'27/e 3~ 3¼ 31/4

l~/e 1~, 2 1¾

2500 3600 2800 3300

2~e

t~/e4

2500

27/8 Is/~

2500 3~,

~'~

3Y~ ~, 35/32 ,3/64

2800 3100

6.85 6.85 685 6.55

E.U. 75 E.U. 75 E.U. 75 E.U, 75

NC31 (I.F.) W.O. O.H. SL-HgO

4~ 4~ ~3~ 3~

2'/, 27,, 2~ 2~

6300 3800 29O0 3900

3:~ 3~ 3'].~ 3~

~; y~, ~; ~M

10.40 10.40 10,40 10.40

E.U, 55 I,U. 55 I.U. 55 E.U. 55

NC31 (I.F.) 4~ E.H. 4¼ NC26 (~S.H.) ~3~ O.H. 3~

2y, 1~; 1~, 2~

6300 7000 3600 4500

3~ 3~ 3"~ 3~

10.40 10.40 10.40 10.40 10.40 10.40

E.U. 75 IU. 75 I.U. 75 E.U. 75 E.U. 75 E.U. 75

N C 3 1 (I.F.) 4~ E.H. 4¼ NC26 (~S.H.) ~3~ O.H. ~)3~ SL-H00 3~ P.A.C. ~3~

2y, 1~; 1~

~

S300 7000 3600

1½

10.40 E.U. 95 10.40 E.U. 95

N C 3 1(I.F.) 4~ SL-HgO ~3~

10.40

E.U. 105

13

CLASS2

6.65 6.65 6.65 e.65

10.40 E.U. 135 3~

5

NEWTOOLJOINTDATA

2100 1800 1800 1700

3 3~,e 2~ ~

~ ~,~ ,~ ~.~ ~

1600 1500 1500 1500

1800

3~

2500

223/3Z %2

23OO 2600

3~

~=

~'" Y,, 3~32 V8

20oo

3 33/32 ~

3600 3700 2900 39(30

3=)~ 3~ 3~ 3'~%

~, ~/M

3000 3400 2900 3200

3N 3~ 3~ 3~

~, ~/M

2500 2600 2600 2800

~ ~ ~~'~ " ~

4000 3700 3600 3700

3"; 3~ 3¼ 3~

~ ~ ~ ~/~

3200 2900 3100 3400

3~; 3~ 3~'=s 3~

~ ~/M ~ ~/~

2500 2500 2500 2600

Y=z ~ ~/~ ~ ~ 17f64

5200 5100 3600 4500 5200 3100

3~ ~ 3~ ~v~, 3~ ~ 3~'~ ~= 3~6 ~ 31/e 17/e4

4300 4100 3600 4500 4300 3100

3~,~ 3~ 3~ 3~ 3~ 3~

'~

3100

3:~ ~, 3~ 3~ 3~ 3~ 31/e

3600 3300 3800 3700 3600 3100

2 2N

7000 600O

33)~ 3~

~ ~¢~

6800 6(~0

3~a 3~

',',~ ~

5600 5500

3~ ;'~, 3~J~ ~

NC31 (I.F.) ~4~

2

7000

4y~

~

7000

3~

~,

6200

3~

~

5200

NC31 (I.F.) (~4y=

2

7000

4~

~v~

7000

4y,

¼

7000

3;~

y,

6400

47~"

~

6800

4~

~,

5500

4~=,," ~

4,:;, 4¼

~-'. ~

6ooo 6500

4~ 4~

Yo, ~

5800 5200

4~ 4~

4~

~2

8600 6300 6600 8700

4~% 4 4~ 4~

,"-'~ ".'. ~

7000 ~ ,~ 6900

4;% 3;'~ 4~= 4~,

')~,

5900

~',";, ~

83006800 5600

~Y= ¼ ~

10700 9700 105C0

4~/~ 4~ 4~

Y~ ~ ~

8600 9100 9200

4~ 4~= 4;':~

y~ ~, ;'~,

7600 7400 7500

4~

9.50 9.50 9.50 9.50

E.U. 75 E.U. 75 E.U. 75 E.U 75

NC38 (W.O.) ¢,4~ NC38 (I.F.) 4~4 O.H. ~43/, SL-H90 4~

3 2~'~ 3 3

68OO 9800 60CO 6500

13:30 13.30 13.30 13.30

E.U. 75 I.U. 75 E.U. 75 E.U. 75

NC38 (I.F.) 4~ NC31 (®S.H.) 4~ O.H. ~43/~ H90 5¼

2~,~ (~2~ 2~ 2~

9800 6300 8800 12000

13.30 E.U.95 13.30 E.U. 95 13.30 E.U. 95

NC38 (I.F.) SL-H90 H 90

13.30 E.U. 105

NC38 (LF.)

3~= ~

4~,

~=

4~ ~ 4~.% ;'~,

5 4~ 5¼

2~ 11500 ~)2~,~ 9700 2~ 12000

4~(8 4~ 4~.~

esoo

y,

230o

54oo

.~,

~ ~ ~//64

1500 2200

2OOO 2300

4400 4700

490o

~

4300

Yo, ~

48o0 4700

5

(~2,V~

11500

4~

~

11500

4~

~

9700

4~

~

8100

13.30 E.U. 135 NC40 (4 F.H.) 13.30 E.U. 135 NC38(3V2 LF.)

5~ 5

2~/~ ~2~

16000 11500

5~

~

15700

~

12500

4~

~:

10600

4~,~

~." 11soo

4~'~

4~

'X, 11soo

4~

15.50 E.U. 75

NC38 (I.F.)

5

27/~

11000

4~

y~,

4~'~

~

8100

4~

~

6500

15.50 E.U. 95

NC38 (LF.)

5

2~

11500

4~

~

11500

4~

~

9700

4~'~

~

8100

5¼

2~'~

15000

5Y~

~

13200

4~

~

11300

4y~

~-~-

9400

15.50 E.U. 105 NC40 (4 FH.)

9700

.:'~, I0200

D r i l l i n g a n d Well C o m p l e t i o n s

758

Table

4-89

(continued) 1

2

3

4

NOra Nora. S~e wt t~. 4

,~/ft

Type Upset

5

6

7

NEWTOOLJOINTDATA

DRILLPIPEDATA

Coni.~.

Grade

New O0 in.

11.65 E.U.75 NC46 (LF.) 5~ 11.85 E.U.75 NC46 (W.O.) 5~

6

9

10

11

~PREMIUMCLASS

12

13

~Min.Box~Make-Up @M~n,Box~Make'Up q~M~n.Shou{d~r Torque @Min.ShOulOer Torque New O0 With For M~ OD With FOrI~n. ID ~Make-Up Tool Eccentric ODTOO( Tool Eccentric ODToOl Torque Joint Wear Joint Joint Wear Joint in. fl-lb in. in. fl-lb in. in. ft-lb 3¼ 3~,~

18000 15400

2~

18500

5¼ ~ 5~{,,z ~

8800 9500

5,~ ~ 5~ ~ ~ 4'~ ,.

~ ~. ~= ~

5800 6500 6600 6ooo

88oo 8800 8000 8900

4~ 5,~ 411. .= 4~

~ ',~ ~ n-

76oo 72o0 80o0 7400

4~

~p

9400

,

~

9000

4~ 4~

5¼

,~ ,~ '~

5Y~ ~ 5~% ¼ 5~ ~

13200 14000 13800

4~

,s~ 11300

5~ 5~ 5~

~ ~ Y~

15000 14800 15000

4~r 5~

22000

5~

~.~ 19600

13500 18000

4~ 5¼

~ ~4

6800 6800

5,%

~4 ~,

2.~"" 3~ 2~

13500 18000 18500

4~ 5~ 5~

¼ " ~

11900 11700 12300

42~

~4

15,70 I,U, 95 NC40 (F,H.) 5~ 15.70 E.U.95 NC46(I.F.) 5~ 15.70 I.U. 95 H 90 5~

2~ 3 2~

15700 18000 18500

5~ 5~ 5~

~ ¼ ~

15000 14800 15000

4.~ 5~ 5~

15.70 E.U. 105 NC46 (I,F.) 5~ 15.70 ].U. 100 H 90 5~

3 2~

20200 18500

5~ 5¼

~ 16400 ..m~ 16800

15,70 [.U. 135 NC46 (LF,) 6~ 15,70 E,U. 135 NC46 (LF,) 6~

2~ 2~,

24900 23500

5~ 5~

~ ~

E.U.75 NC50 (W.O.) 6~ E.U. 75 NC50 (I.F.) 65~ E.U. 75 O.H. 5~ E.U. 75 H 90

3~ 3~ ~)3,~ 3¼

17500 19700 10800 20000

~ 5.-~ 5~ 5~

~-~" /~ ~

16.60 I.U.55 F.H. 5~ 16.60 I.U. 55 NC46 (E.H.) 6 16.60 E.U. 55 NC50 (I.F.) 6~

3 3¼ 3~

18000 18000 19700

16.60 16.60 16.60 16.60 16.60

I.U. 75 O.H. (~57/a I.U. 75 F.H. 5~ I.U. 75 NC46 (E.H.) t) E.U.75 NC50 (I,F.) 6~.; E.U. 75 H 90 6

33/4 3 3~ 3~ 3¼

16.00 16.60 16.60 16.60

LU.95 F.H. 6 I,U.95 NC46 (E.H.) 6 E.U.95 NCS0(I.F.) ¼ I.U. 95 H 90

16.60 I.U. 105 F.H. 6 16.60 I.U, 105 NC46 (E,H.) 6 16.60 E.U.105 NC50(I.F.)6¼

~,

2~ 3~ ~ 3~ 2~-~

12500 18000 8000 14000 18500

4~ 5~ 4y~ 5~ 5

~s~ ,~ ~,~ ~ ~

14,00 LU. 95 NC40 (F,H,) 5¼ 14.00 E.U. 95 NC46 (I.F.) 5~ 14.00 I.U. 95 H 90 5~

2~ 3¼ 2~

15000 18000 18500

14.00 LU. 105 NC40(F,H,) 5~ 14.00 E.U. 105 NC46 (LF.~ 5~ 14.00 I.U. 105 H 90 5~

2~ 3¼ 2~-~

16000 18000 18500

14.00 E.U. 135 NC46 (I.F,) 6

2,~

15,70 [.U, 55 NC40 (F,H.) 5~ 15.70 E.U, 55 NC46 (].F,) 5~

2" 3~"

15.70 I.U, 75 NC40 (F.H.) 5¼ 15,70 E.U. 75 NC46(I.F,)5~ 15.70 E.U. 75 H 90 5~

3,.~

LU, 75 NC40 (F,H,) 5¼ E.U.75 NC46 (I.F.) 5~ I.U. 75 @S.H. 4~ E.U. 75 O.H. 5~ E.U. 75 H 90 5~

11,85 E.U,75 14,00 14.00 14.00 14.00 14.00

4~ 13.75 13.75 13.75 13.75

16.00 LU. lO~

H 90

~00

5~

6

4~s~. ~".~. 9000

5Yj.2 ~

~0Min.Bo~ ~M41ke-Up ~Min. ShOulder Torque O0 With ForMin, Tool Concentric ODTool Joint Welt Joint in. in. ft-lb

5~ 5~ 4;~

10600 11000 8000 11100 10800

5~,

5¼

18

CLASS3

4~s~

73oo

4="

11300

0.~.

15

8000 7400 6000

~oo

11,85 ~ u 7 5

14

CLASS2

11400

4~ 5~ 5

~-~~4 ,~

10600 10300 10800

5~'~= ~'~ 15600

5~.~

~

13300

4~";

7000 72o0

4~ 5~

~4 ',~

5800 580o

10000

4~

~

8200

9900

4~

N

7500

y.-. 12600 ~4 12500 ~ 12300

4¼ 5~s~ 4~

'X, ~'~ ~

10600 10300 9900

5~ 5~

~ 13300 ~s~ 13800

5~ 5~.~

~-~~4

11700 11400

21200 21200

5%

~

~

18000

100oo

5~

5~

~,

~

1480o 14800

12100 12100 10800 12000

5.~

,~

10400

5:~

~

88oo

5~,, 5¼

~ ~

1o4oo 10200

s.~ 5~

,%

5~,~ 5~ 5~

~-~. 10300 ~-~- 10300 ~ 10400

5~ 5¼

5~

~ ~, ~,

8200 6800 8800

5~ 5~ 5%

~ ,~ ~,

6800 73O0 710o

19600 18000 18000 19700 20000

5~ 5~ 5,s~ 5~ 5~

~ ,s~ ~s~ "~.~ ~s~

15700 14000 14000 14800 14400

5:y~ "~%,. 12500 5'.~ ~v. 11800 5~- ~, 11800 5~. ~ 11300 12000

5% 5~ 5~-,z 5% 5¼

'%4 ,~ ~.~ ~ ~,

10200 9600 9500 9600 10000

32~ 3N

19000 21000 21500 23500

i~

i;

18400 16000 18700

14800 14800 14800 15300

5~ 5 5~, 5~"~

~

~(,

5~ 5~ 5 5~.~

12500 12500 13000 12700

2~ 2~ 3~

20300 220C0 22000

5~ 5~ 6

~

19900 20400 20000

16200 16400 16500 17000

5~ 5~ ~ 5~

~

3

235oo

5~,

~

~

2o4oo

~7~. 12600 ~ 12500 12300

,~

5~

5y~

~ ~

5~" ~z ~ 5~/~ 5~ ~(, 5;~ ¼

10400

5.,~

~

¼

880o

85oo

84oo

14100 14000 13900 1360o

Drill String: Composition and Design

759

Table 4 - 8 9 (continued) 1

2

3

4

NOra. Nora. S~z= Wl

4~

5

5

6

7

NEWTOOLJOINTDATA

DRILLPIPEDATA

Type U~t ano

I~D ,n

8

I.U. 135 NC46 (E.H.) 61/, E.U. 135 NC50 (LF.) 6~

20.00 20.00 20.00

I.E.U.55 NC45(E.H.) 5 I.E.U 55 FH. 5 E.U. 55 NC50 (I.F.) 5~

20.00 20.00 20.00 20.00

I.E.U. 75 F.H. I.E.U. 75 NC45 (E.H.) E.U. 75 NC50 (LF.) LE.U. 75 H 90

5 5 6~ 6

20.00 20.00 20.00 20.00

LE.U. 95 F.H. I.E.U. 95 NC4.6(E.H.) E.U. 95 NCS0 (I.F.) I.E.U. 95 H g0

6 6~ 5~

23oo0 5~

s

23500

20.00 20.00

I.E.U. 1C~INC46(E.H.) E.U. 105 N'CS0(I.F.)

6~,, 5~

2~ 3¼

20.00 19.50

E.U. 135 NCS0 (I.F.) I.E.U.75 NCS0(E.H)

5~ 5~;

2~

31100

6~'~,

3~,

2ooo0

~

,9.~o 19.50

i.E.U.~S NCSO~E.H.) ~

3Y, 3y,

19.50 19.50

I.E.U. 105NC50 (E.H.) 6~ L E g 105 H 90 6~

H90

2~

3

11

25600

29O00

5"~

6~

.~.

.~

12

13

14

15

CLASS2

25600 25400

~Min Box~Make-Up ~M~n Shoulder Torq~ OD Witi~ ForMm Tool Eccentric ODTool J~nt Wear Jorm in'n. m. ftqb 5~4 6~.~

16

CLASS3

~ ~'

2,200 20900

~Mm Box (~Mak~Up ®Min Shou~e~ Torque OD W~th For M~O TOO[Concentric OD TO<>[ Joint Weal Joint m m ff-lt~ 5~ 5~

~ ~

18000 18300

2,000

3 3~ 3 3

3~ 3

,8000 22000

5~,

,8000 21000

5~ ~ 5/32

22ooo 23,5o0

12500

5~ 5Y,

~, ~" /M

5~',Y~

,040o

5~

~,

88oo

17000 17200

5~ 5'~

~ ,s~

14100 14000

5~'~, 5~

~, ~

11800 11800

17000

5~.~

y~

5~ 5~ 5~ 5~.'~

3o,00 ,920o

28ooo ¢y= ~, 267OO P.~,

3 3

29OOO 3O2OO

2~00 ~ 26O0O 6~~

8200

~,

21400 22000 21800 21400

5~

5~

5~

~'~

23500

10300

,30oo

14400

5~6

%

5~ 5~ 5~ 5~,e

~ ~,

~

17700 18000 17400 17800

y~

%

14800: 14800 14800 15300

s~, ~

~ ~

26400 ,6600

5y~ 5~,

~ ~

209o0 ,3oo0

24500 24200

6 5"~

~= 20000 ~v=z 19900

5~ ~.~

~ ~v~

16500 18900

5~; 5~.~ ~

~ ~

18300 18900 24200

~ y~,

12000

~ ~

5% 6~

~, ,~,

27300 26500

6~ 5~

~e ~

21800 21700

~,~

34300

~

~'~, 28700

6~

~"~

23200 24200

6 6~

~ 20000 ,s~ 19900

5~ 5~

~ ~

16500 16600

6'/,

~

253o0

6~

~,

2o90o

19.50

I.E.U. 135

7~

3~

37000

5~

25.60 25.60 25.60

I.E.U. 75 NCS0 (E.H.)~)6~ I.E.U. 75 5Y2FH 7 I.E.U 95 5~FH 7

3~ 3~

23200 32300 32300

6y~ 6~ ~

~;

309oo

25.60

I.E.U. 105

5~FH

7~

31/2

37000

6~/~

~

33700

6~;

~,

27500

6~

~

23100

I.U. 75 I.E.U. 95 I.E.U. 95

F.H. F.H. H gO

7 7 7

4 3~, 3~

~ 323oo 3o3oo

6,"~ 6~, 6~,

,% ~;

24200 29800 3OOOO

6~ 5~~ 6~

~

18800

6~,~

~s~

16600

24~ 2~oo

~ 5~.

~

3~

37000

6~

33200

6')~

~-/. 27500

~

~,

23100

42300

5~

%

34300

5~

~.~

29800

5~ 21.g0 21.90 21.90

5~/~FH

5~

10

~MJn Box ~Make-Up ~Mm. Shoulder Torque New oo With For Min ID ~M~ke-Up TOO[ EcCentric OD TOOl Torque Joint Wear Joint ~n ff-]b in m It-am

16.60 15.60

I.E.U. 95

9

®PREM;UMCLASS

209o0

21.90

I.E.U 105

F.H.

7~

21.90

I.E.U. 135

F.H.

7~

24.70

LU. 75

F.H.

7

4

2880o

~,

26400

6~,

Y~

22000

6'~

¼

17700

24.70

I.E.U. 95

F.H.

7~

3~

37000

6~/~

33200

6~;

~-/- 27500

6~

~,

23100

24.70 I.E.U. 105 F.H. 7~ 36500 6~ ~ 29800 6~ ~ 25300 3~ 37000 6~,~ @Basis of calculations for recommended tool joint make-up torque assumed the use of a thread compound containing 4060% by weight of finely powoered metallic zinc applied thoroughly to all threads and shoulders, and a tensile strsssof62.500psiforcolumn7end75000,osiforco umnsl0 13 end16 min mum wal dnl p pe. O.D. of too io nts sled for Premium Class dril pipe are based on drill pipe having uniform wear and a minimum wall thickness of 80%. ~Minimum box shoulder disregards bevel. (~O.D. of tool joints shown for class 2 drill pipe are based on drill pipe having all the wear on one side and a minimum wall thickness of 55%. • O.D. of tool joints shown for class 3 drill pipe are based on drill pipe having all the wear on one side and a minimum wall thickness of 55%. ®The use of O.D.'s smaller than those listed in the table may he acceptable on Slim Hole Tool Joints due to special service Cequirements. (~TOOl Joint with dimensions shown has a lower torsional yield strength than the drill pipe to which it is attached. /rTool joint outside diameters (OD) specified are required to retain torsional strength in the tool joint comparable to the toraiooat strength of the attached drill pipe, The use of tool joints with outside diameters smaller than those listed may he acceptable in special service requirements to provide sufficient clearance in casing programs, In such cases, the torsional strength of the loins may be considerably below that of the drill pipe body to which it is attached. Toot joints with outside diameters shown from Grade E drill pipe are adequate for high strength drill pipe when uud in combinetiol~ strings with Grade E drill pipe.

760

Drilling and Well Completions

/

EXTRA LONG JOINTS (A) MORE BEARING AREA REDUCES WEAR (B) MORE LENGTH FOR RECUTTING CONNECTIONS

.~• ".".".".".".".~

~,~ ~

HEAVY WALL TUBE PROVIDES MAXIMUM WEIGHT PER FOOT

HARDFAClNG ON ENDS AND CENTER SECTION (OPTIONAL) FOR LONGER LIFE

, ~

CENTER UPSET (A) INTEGRAL PART OF TUBE (B) REDUCES WEAR ON CENTER OF TUBE

EXTRA LONG JOINTS (A) MORE BEARING AREA REDUCES WEAR (B) MORE LENGTH FOR RECUTTING CO N N ECTIONS F i g u r e 4-134. Drilco's Hevi-Wate ® drill pipe [42]. (text continued from page 749)

drilling. However, based on field experience, if a heavy-weight drill pipe above the drill collars is used, it reduces drill pipe failure. The failure of regular drill pipe and tool joints is influenced by several factors. Probably the most important one is a cyclic bending stress reversal resulting from the accidental running of drill pipe in compression, the centrifugal force effect or passing through short and sharp dog-legs, or a combination of these factors. In directional drilling, a

Drill String: Composition and Design

761

heavy-weight drill pipe is used to create weight on the bit if, for some reason (e.g., excessive torque and drag or differential problem sticking), a long string of drill collars cannot be run. The best performance of the individual members of the drill string is obtained when the bending stress ratio of subsequent members is less than 5.5 [38]. Bending stress ratio (BSR) is defined as a ratio of the bending section moduli of two subsequent members, e.g., between the drill collar and the pipe right above it. To maintain the BSR at less than 5.5, the string of drill collars must frequently be composed of different sizes. For severe drilling conditions (hole enlargement, corrosive environment, hard formations), reduction of the BSR to 3.5 helps to reduce frequency of drill pipe failure. Geometrical and mechanical properties of heavy-weight drill pipe (Hevi-Wate ®) manufactured by Drilco are given in Table 4-90.

Example Calculate the required length of 4 ~ in. Hevi-Wate ® drill pipe for the following conditions: • • • • * • •

Hole size: 9~ in. Hole angle: 40 ° Desired weight on bit: 40,000 lb Drill collars: 7 × 2 ~ in. Length of drill collars: 330 ft Drilling fluid specific gravity: 1.2 Desired safety factor for neutral point: 1.15

Solution Check to see if the BSR of drill collar and Hevi-Wate/~/ drill pipe is less than 5.5. Bending section modulus of drill collar is

n I (7)4 - (2"8125)4 t ___65. 592in.S 7 Bending section modulus of Hevi-Wate ® drill pipe is I(4.5)4 - ( 2 . 7 5 ) 4

] J

15.397in. 3

65.592 BSR=--=4.26<5.5 15.397 Unit weight of drill collar in drilling fluid is 1.2 ) 110 1 - 7.85 = 93.181b/ft

762

Drilling and Well Completions Table 4-90 Properties of Hevi-Wate ® Drill Pipe (® Drilco Trademark) [38] DIMENSIONAL DATA RANGE II i iii TUBE

Mlmh Properties Tube Ildctton

Nom Tube Dimension Wail ThickheSS (in)

iD (in)

3V2

21/1s

,719

6,280

4

3~6

345,400

19,575

4

2~y~s

.719

7,409

41/2

4Y6

407,550

27,635

,875

9,965

5

4%

548,075

40.715

5Vz

5Vs

691,185

4~/2

23/,

5

3

Cetnter Elevator Upset ! Upset (in) (in)

Torsional Yield (ft-lb)

Nom Size (in)

Area (in 2)

1,000 12.566

TOOL

JOINT

Mech Propedles Torslonel ~D ID Yield in) (in) (ff-lb), i 3~,~ N,C,38(3V~IF.) 43/4: 23/+~ 748+750 17.575

Nora Size (in)

Tensile Yield (ib)

Conn Size (in)

IN,C+40(4F.H+) 5V+ 2"/+e

4

i

56.495

WEIGHT Approx. WI Incl Tube & Joints (Ib)

MakeUp Wt/ Y/tilt. Toque ft 30 ft (ff-ib) 25.3

760

29.7

890 13,250

9.900

6~/4 27/6 1+024.500 38.800

41.0 1230 21,8(X)

N.C.50(4Y2LF. 6 ~ 3Vls 1+266.000 51.375

49.3 1480 29,400

4'.3 N.C.46(4LF.) 5

7_11.475 23.525

Tenelio yield (Ib)

DIMENSIONAL DATA RANGE III TUBE

Mech Properties Tube Section

Nora Tube Dimension Nom Size (in)

ID (In)

41'2

23/,

5

3

Wall Thick* hen (In) .875

Ares (in2) 9,965

1,000 12.656

TOOL

Center [levator Upset Upset (in) (in)

Corm Size (in)

5

4%

548.075

40,715

5Y8

691,185

56,495

JOINT

OD i ID (in) I (in)

Top elonal Yield (fl-lb)

5~/z

Mech Properties Nora Size (in)

Tensile Yield (Ib}

Tensile Yield (lb)

WEIGHT Approx. Wt In¢l Tube & Joints ([b)

rocsionel Yield Wt/ {ft*ib) It

MakeUp Wt/JL Torque 44 ft (It-lb)

4:'z N.C,46(41.F.)

6~/, 27/e 1,024.50( 38.800

5

6~,~i 3~/~6 1.266,00( 51.375 48.~ 2180 29.400

NC50(4~/2I.F.

39.S 1795 21.800

Drill String: Composition a n d Design

763

Unit weight of Hevi-Wate(c~ drill pipe = (41)(0.847) = 34.72 lb/ft. Part of weight on bit that may be created using drill collars = (93.18)(330)(cos 40) = 23,555 lb. Required length of Hevi-Wate/~ drill pipe is ( 4 0 0 0 0 - 23555)(1.5) = 711ft (34.72)(cos 40) Assuming an average length of one joint of Hevi-Wate(c) drill pipe to be 30 ft, 24 joints are required.

Fatigue Damage of Drill Pipe It should be understood that the majority of drill pipe and tool j o i n t failures occur as a result of a fatigue damage. T h e problem of fatigue failure is not adequately researched; however, it is basically agreed that tension a n d b e n d i n g (reversing tension and compression of the same drill pipe fiber), magnified by vibrations, contribute the most to such type of failure. Cycling stress results in a crack that spreads across the cross-section a n d causes ultimate failure. A fracture begins at a point on or near the surface that is weaker than any other due to a n u m b e r of reasons (e.g., surface imperfections or stress raisers). Fatigue cracks can also initiate at points below the surface of the drill string if the proper conditions exist. It should also be r e m e m b e r e d that drill pipe fatigue is cumulative in nature, so the changes that affect failure are usually long delayed and require a certain a m o u n t of time to be detected. T h e drill collars and particularly their connections are also exposed to cyclic stresses. Subsequently, these are susceptible to fatigue damage, but the changes that may i n f l u e n c e failure are more quickly discovered. Based on work done by A. Lubinski, J. E. Hansford and R. W. Nicholson (API RP 7G, Section 6), gives the formula for the m a x i m u m permissible hole curvature in order to avoid fatigue damage to drill pipe. C = 432,000 (ib tanh(KL) n EDdp KL

K

=(T] ~2

(4-66)

(4-67)

\ EI)

For Grade E drill pipe (ib = 19,500 - (0.149)(i t = 1.34 10 -6 ((lt - 33,500) 2

(4-68)

For Grade S-135 drill pipe

14(~t00/ T (it = - A

4-69, (4-70)

764

Drilling and Well Completions

where c = maximum permissible dog-leg severity in °/100 ft (Yb = maximum permissible bending strength in psi tensile stress due to the weight of the drill string suspended below a dog-leg in psi E = Young's modulus, E = 30 × 106 psi Ddp = outside diameter of drill pipe in in. L = half the distance between tool joints, L = 180 in. for Range 2 drill pipe. Equation 4-75 does not hold true for Range 3 drill pipe. T = weight of drill pipe suspended below the dog-leg in lb I = drill pipe moment of inertia with respect to its diameter in in. 4 A = cross-sectional area of drill pipe in in. 2 By intelligent application of these formulas, several practical questions can be answered, both at the borehole design state and while drilling.

Example Calculate the maximum permissible hole curvature for data as below: • New EU 4-~-in. Range 2 drill pipe, nominal weight 16.6 lb/ft, steel grade S-135, with NC50 (IF) tool joint • Drill collars, 7 x 2¼ in., unit weight 117 l b / f t • Length of drill collars, 550 ft • Drilling fluid density, 12 lb/gal • Anticipated length of the hole below the dog-leg, 8,000 ft • Assume the hole is vertical below the dog-leg

Solution From Table 4-79: D d = 4.5 in., d d - 3.826 in., A = 4.4074 in.; and from Table 4-100: u m t weight of drill pipe adjusted for tool joint, Wdp = 18.8 lb/ft. Weight of drill collar string is .

.

12,

.

.

.P

(550)(117)(1 - 61524) = 52,543 lb Weight of drill pipe is

( 8 , 0 0 0 - 5 5 0 ) ( 1 8 . 8 ) ( 1 - 65.124) = 114,3611b Weight suspended below the dog-leg, T = 166,904 lb,

Tensile stress <~

166,904 4.4074 - 37,869 psi

Maximum permissible bending stress,

( 145,000) 37,869)__14,7761b

<~b = 20,000 1

Drill String: Composition and Design

765

Drill pipe moment of inertia, I = ~4[(4.54)4 - ( 3 . 8 2 6 ) 4 ] = 9.61in. 4 166,904 K = ~(30)(10)6(9.61) = 2.406110 -2 in. -1 Maximum permissible hole curvature, c = 42,00.__.___0 14,776 tanh(2.406110-2)(180) = 3.47o/100f t (30)(10)6(4.5) (2.4061)(10)-2(180) The calculations, although based on reasonable theory, must be approached with caution. For practical purposes, some safety factor is recommended.

Drill Pipe Inspection Procedure To avoid costly fishing operations, loss of material and time, the drill pipe must be carefully inspected according to the following procedure [30]: 1. Determine the pipe and joint cross-sectional area. 2. Determine tool joint outside diameter. Tool joint box should have sufficient OD and tool joint pin sufficient ID to withstand the same torsional loading as the pipe body. When tool joints are eccentrically worn, determine the minimum shoulder width acceptable for tool joint class in Table 4-101. 3. Check the inside and outside surfaces for presence of cracks, notches and severe pitting. 4. Check slip areas for longitudinal and transverse cracks and sharp notches. 5. Check tool joints for wear, galls, nicks, washes, fins, fatigue cracks at root of threads, or other items that would affect the pressure holding capacity or stability of the joint. 6. Ascertain if joint has proper bevel diameter. 7. Random check 10% of the joints for manufacturer markings and date of tool joint installation to determine if tool joint has been reworked. Optional: 1. Using data in Table 4-89, determine minimum shoulder width acceptable for tool joint in class. 2. Check for box swell a n d / o r pin stretch. These are indications of overtorquing, and their presence greatly affects the future performance of the joint. 3. Use thread profile gauge for indications o f overtorque, lapped, or galled threads and stretching. 4. Magnetic particle inspection for cracks should be made if there is evidence of stretching or swelling. Check box and pin threaded area, especially last engaged thread.

Drill Strlng Design The drill string design is to determine an optimum combination of drill pipe sizes and steel grades for the lowest cost of string or the lowest total load (in

766

Drilling and Well Completions

very deep drilling) that has sufficient strength to successfully accomplish expected goals. Having in mind that the drill string is subjected to many loads that may exist as static loads, cycling loads and dynamic loads, the problem of drill string design is complex. Due to the complexity of the problems, some simplifications are always made and, therefore, several decisions are left up to the person responsible for the design. In general, a reasonably bad working condition should be assumed and, for that reason, a g o o d knowledge of expected problems much as hole drag, torquing, risk of becoming stuck, tendency to drill a crooked hole, vibrations, etc., is of critical importance. The person responsible for the design must know drill string performance properties, data from wells already drilled in the nearest vicinity and current prices of the drill string elements. The designer should simultaneously consider the following main conditions: 1. The working load at any part of the string must be less or equal to the load capacity of the drill string member under consideration divided by the safety factor. 2. Ratio of section moduli of individual string members should be less than 5.5. 3. To minimize pressure losses, the ratio of drill pipe outside diameter to borehole diameter, whenever possible, should be about 0.6. Normally, based on hole diameter, the designer can select drill collar diameter and drill pipe diameter. Next, specific pipe is chosen; the maximum length of that pipe must be determined based on condition 1. For this purpose, the following equation is used: (LdcWdp + Lh~Wh~ + Ldp,Wdpi)Kb = "P' ~

(4-71)

where Ldc = length of drill collar string in ft = unit weight of drill collar in air in lb/ft hw length of heavy-weight drill pipe (if used in the string) in ft Whw = unit weight of heavy-weight drill pipe in lb/ft gdp I = length of drill pipe under consideration above the heavy-weight drill pipe in ft Wdpl = unit weight of drill pipe (section 1) in lb/ft Kb = buoyant factor P, = tension load capacity of drill pipe (section 1) in lb SF = safety factor Solving Equation 4-71 for Ldp, yields Ldp, =

P, SF KbWdp1

LdcWd¢ - LhwWhw Wdp1 Wap1

Ldp'WdP~ Wdp1

(4-72)

If the sum of L. + L. + L . . is less than the planned borehole depth, the stronger pipe must be"selecte~l or a heavier pipe must be used in the upper part of the hole. The maximum length of the upper part in a tapered string may be calculated from Equation 4-73:

Drill String: Composition and Design P~ SF KbWdp I

Ldp~ =

Ld~Wa~ Wdp ~

LhwWhw Wdp ~

LdplWdpl Wap ~

767

(4-73)

where P~ = tension load capacity of next (upper) section of drill pipe in lb Laps = length of section (2) in ft Wdp~ -- unit weight of drill pipe (section 2) in lb/ft Normally, not more than two sections are designed but, if absolutely necessary, even three sections can be used. To calculate the tensile load capacity of drill pipe, it is suggested to apply Equation 4-58 and use the r e c o m m e n d e d makeup torque of the weakest tool joint for the rotary torque. The magnitude of the safety factor is very important and usually ranges from 1.4 to 2.8 depending u p o n downhole conditions, drill pipe quality and acceptable degree of risk. It is r e c o m m e n d e d that a value of safety factor be selected to produce a margin of overpull of at least about 70,000 lb. Additional checkup, especially in deep drilling, should be done to avoid drill pipe crushing in the slip area. The maximum load that can be suspended in the slips can be found from Equation 4-74:

Wm= =

Pt SF I + L

where Wmax

=

Pt = K=

f= ~= SF=

2

L--~ ~ 2

(4-74) Ls) j

maximum allowable drill string load that can be suspended in the slips in lb load capacity of drill pipe based on minimum yield strength in lb outside diameter of drill pipe in in length of slips (L s = 12-16 in.) lateral load factor of slip, K = (1 - f tan cz)/(f + tan cz) friction coefficient between slips and bushing slip taper (cz = 9 ° 27'45") safety factor to account for dynamic loads when slips are set on moving drill pipe (SF = 1.1)

Normally, if the drill pipe is sufficiently strong for tension, it will have satisfactory strength in torsion, collapse and burst; however, if there is any doubt, additional checkup calculations must be performed.

Example Design a drill string for conditions as specified below: • • • • • • • •

Hole depth: 10,000 ft Hole size: 97 in. Mud weight: 12 lb/gal Maximum weight on bit: 60,000 l b Neutral point design factor: 1.15 No crooked hole tendency Safety factor for tension, SF = 1.4 Required margin of overpull: 100,000 lb

768

Drilling a n d Well C o m p l e t i o n s

• From offset wells, it is k n o w n that six j o i n t s of heavy-weight drill pipe are desirable • Assume vertical hole.

Solution Selection drill collar size, Table 4-73, 7 ~ x 2 ~ in., unit weight = 139 l b / f t . Such drill collars can be caught with overshot or washed over with washpipe. Length of drill collars = (60,000)(1.15) = 608ft (139)(0.816) Note: Buoyant factor K b = 0.816. Select 21 joints of 7 ~ x 2 ~ in. drill collars that give the length of 630 ft. Section modulus of drill collars calculate to be 89.6 in?. D e t e r m i n e size of heavy-weight drill pipe. To maintain BSR of less than 5.5, selection 5-in. heavy-weight drill p i p e with unit weight of 49.3 l b / f t (see Table 4-91) a n d section m o d u l u s of 21.4 in s. L e n g t h of heavy-weight drill p i p e Lhw = (5)(30) = 180 ft. Selection 5 in. IEU new drill p i p e with unit n o m i n a l weight 19.5 l b / f t (see Table 4-79), steel g r a d e X-95, with NC 50 tool j o i n t (see Table 4-89). Unit weight of drill p i p e c o r r e c t e d for tool j o i n t is 21.34 l b / f t . Section modulus of this p i p e can be calculated to b e 5.7 in 3. From Table 4-80, the m i n i m u m tensile l o a d capacity of selected drill p i p e P, = 501,090 lb. From Table 4-89, the r e c o m m e n d e d m a k e u p torque T = 26,000 f t / l b . T h e tensile load capacity of drill pipe corrected for the effect of the maximum allowable torque, a c c o r d i n g to Equation 4-58 is

P =

f

(501090) 2 - 3

E

(6.2832)(312,000) 11.416

iI

= 403,2711b

D e t e r m i n e t h e m a x i m u m a l l o w a b l e l e n g t h of t h e s e l e c t e d drill p i p e f r o m Equation 4-72: 403,271 Ldp = (1.4)(0.816)(21.34)

(630)(139) 21.34

(180)(49.3) = 12,022ft 21.34

Required length of drill p i p e Ldp = 10000 - (630+180) = 9,190 ft. Since the required length of drill pipe (9,190 ft) is less than the m a x i m u m allowable length (12,022 ft), it is a p p a r e n t that the selected drill p i p e satisfies tensile load requirements. O b t a i n e d margin of overpull: MOP -- (0.9)(501090) - [(630)(139) + (180)(49.3) + (9190)(21.34)](0.816) s 212,253 lb (greater than required 100,000 lb). In the above example, the cost of drill string is not considered. From a practical standpoint, the calculations outlined above should be p e r f o r m e d for various drill

Drilling Bits and Downhole Tools

769

pipe unit weights and steel g r a d e s and, finally, the design that p r o d u c e s the lowest cost should be selected. T h e m a x i m u m load that can be s u s p e n d e d in the slips, from Equation 4-83 (assume K = 2.36, L s = 12 in.) is

Wm~ =

501090

Total weight of string = 238,727 lb. The drill pipe will not be crushed in the slips. T h e drill string design satisfies the specified criteria.

DRILLING BITS AND DOWNHOLE TOOLS Classification of Drilling Bits N u m e r o u s i n d i v i d u a l r o t a r y bit d e s i g n s are available from a n u m b e r of manufacturers. All of them are designed to give o p t i m u m performance in various f o r m a t i o n types. T h e r e is no universal a g r e e m e n t on this subject; variations in o p e r a t i n g practices, type of e q u i p m e n t used or hole c o n d i t i o n s r e q u i r e an e x p e r i m e n t a l approach. It has been noted in d e v e l o p m e n t drilling that those o p e r a t o r s who consistently drill the "fastest" wells usually employ several types of bits. All manufacturers use their own classification numbers for their bits. This results in mass confusion about which bit to use in what f o r m a t i o n and whose bit is better. T h e International Association of Drilling Contractors (IADC) has a d d r e s s e d this classification p r o b l e m t h r o u g h the d e v e l o p m e n t of a u n i f i e d system. But whose bit is better is left to trial-and-error e x p e r i m e n t a t i o n by the individual operator. Rotary drilling bits are classified into the following types: 1. 2. 3. 4.

Roller rock bits (milled Tungsten carbide insert D i a m o n d bits and core Polycrystalline d i a m o n d

tooth bits) roller bits bits compacts (PCD) bits

The cutting mechanics of different types of bits are shown in Figure 4-135 [43].

IADC Classification Chart and Bit Codes In 1987, I A D C d e v e l o p e d a revised s t a n d a r d n o m e n c l a t u r e for roller bits which includes a classification chart and a four-character bit code. All manufacturers must classify their bits in a p r e s c r i b e d m a n n e r on the I A D C classification chart. T h e classification includes four categories: series, types, feature, and additional features. Figure 4-136 shows an IADC classification chart. A letter used in the fourth position of the four-character IADC code indicates additional design features specified in Table 4-91.

Series. Numbers 1, 2 and 3 are for milled tooth bits and designate soft, m e d i u m and hard formations, respectively. N u m b e r s 4, 5, 6, 7 and 8 are for insert bits

770

Drilling and Well Completions i~]

=.1 i l J

, : .~": .-.:.+! .. :'.~. :-..'..:.:.: : .:+' +. +.+..++ +.....-.': . : ) . . . .

- ,

Diamond Bit (Plowing / Grinding)

Roller Cone Bit (Crushing)

Diamond Compact PCD Bit (Shearing)

Figure 4-135. Rock cutting m e c h a n i c s of different bit types [43A]. (Courtesy

Hughes Christensen.)

rrATUR~S

ut ka

IK w

FORMATIONS

L )" t-

STANDARO ROLLL~ ROLLER BRG.,AIR SEARING C O O l ~ (I)

| MILLr.D TOOTH

INSET

SOFT FORMATIONS WITH 2l LOW COMPRrS$1VE STRENGTH 3 AND HIGH ORILLABIU]rY 4

2

MEDIUM TO MrD|UM HARD FORMATIONS WITH HIGH COMPRESS|VE STRENGTH

1 2 43

3

HARD SEMI-ABRASIVl[ AND ABRASIVE FORMATIONS

1 2 3 4

4

SOrT FORMATIONS WITH I LOW COMPR~r,.SSIV[STRENGTH 2 3 ANO HIGH ORILLAOILiTY 4

S

SOrT TO MEDIUM FORMATIONS WITH LOW COMPRrqtsIVI[ S~ENGTH

| 2 45

6

MI~DIUM HARD FORMATIONS WITH HIGH CO MPRESSlVE STR~GTH

I 2 3 4

HARD SEMi-ABRASIVE AND ABRASIVE FORMATIONS

I 2 43

F.XI~EMLPLYHARD AND ABRASIVE FORMATIONS

I 2 45

7

S

(Z)

ROLLJ[R S[ALJ[D SEALJ[D SEAU[O IIRG.,GAG[ ROLLER ROLLER, FRICTION, PJIOT[G1T.D IIEANING IIRG.,GAG[ 11131JtlNG SRG*,GAGE PROI"£C'ff.D PROTECIT.D (3) (4) (5) (*) (7)

NOT~: Bit ©lolslfJ(=otlons a r e g e n e r a l guidelines only. All bit types will drtll effectively In forrnatlons other thon t h o l e Ipeclfled.

t Umlted

Avolloblllty

Figure 4-136. 1987 IADC roller bit classification chart. and designate soft, soft to medium, medium, hard, and extremely hard formations, respectively. T y p e s . There are four grades of hardness in each series. These four grades (or

types) are numerically 1, 2, 3 and 4.

Features. Seven categories o f bearing design and gauge protection are defined as features. Features 8 and 9 are reserved for future use.

Drilling Bits and Downhole Tools

771

T a b l e 4-91 Roller Bit A d d i t i o n a l D e s i g n F e a t u r e [44] Code A B C D E F G H I J K L M

Feature Air application1 Center jet Deviation control Extended jets Extra gauge/body protection

Jet deflection

Code N O P Q R S T U V W X Y Z

Feature

Reinforced welds2 Standard steel tooth modeP

Chisel insert Conical insert Other insert shape

~Journalbearing bits with air circulationnozzles 2For percussionapplications 3Milledtooth bits with none of the extra features listed in this table Courtesy SPE

A d d i t i o n a l F e a t u r e s . Additional features are i m p o r t a n t since they can affect bit cost, applications a n d performance. The fourth character of the IADC code is used to indicate additional features. Eleven such alphabetic characters are presently d e f i n e d as shown in Table 4-91 [44]. Additional alphabetic characters may be utilized as required by future roller bit designs. Although the fourth character does not appear on the IADC bit comparison chart, it appears everywhere else that the IADC code is recorded such as on the shipping container a n d bit record. The IADC code should be interpreted as shown in the following examples: (1) 1 2 4 E - a soft formation, sealed roller bearing milled tooth bit with extended jets, (2) 4 3 7 X - a soft formation, sealed friction b e a r i n g insert bit, with gauge protection a n d chisel-shaped teeth. Some bit designs may have a combination of additional features. In such cases the manufacturer selects the most significant feature for the fourth character of the classification code. IADC publishes the current bit classification charts for nearly all of the major roller bit m a n u f a c t u r e r s . In a d d i t i o n , IADC publishes reference charts for "obsolete" bits that are no longer available. These are useful when reviewing older bit records in order to plan a well. The current IADC classification charts for seven roller bit manufacturers are shown in Ref. [44]. Bit classification is g e n e r a l a n d is to be used simply as a guide. All bit types will drill effectively in formations other than those specified. It is the responsibility of the manufacturer to classify his bits at his or her own discretion. R o l l e r R o c k Bit D e s i g n

The elements of the roller rock bit are shown in Figure 4-137 [45]: Roller rock bits have three major components: the cone cutter, the bearings and the bit body. The cutting elements are circumferential rows of teeth extending from

772

Drilling and Well Completions

TUNGSTEN~RB~DEB!T

Figure 4-137. Roller (rock) bit elements [45]. (Courtesy Canadian Association of Oilwell Drilling Contractors.) each cone and interfitting between rows of teeth on the adjacent cones. The teeth are either steel and machined as part of the cone, or tungsten carbide compacts pressed into holes machined in the cone surfaces. The cutters are mounted on bearings and bearing pins that are an integral part of the bit body. The size or thickness of the various bit c o m p o n e n t s depends on the type of formation to be drilled. For instance, soft formation bits generally require light weights and have smaller bearings, t h i n n e r cone shells a n d t h i n n e r bit leg sections t h a n hard formation bits. This allows more space for long, slender cutting elements. Hard formation bits, which must be r u n u n d e r heavy weights, have s t u b b i e r c u t t i n g elements, larger b e a r i n g s and sturdier bodies. Shown in Figure 4-138 are the changes of various bit design factors across the IADC classification chart.

Drilling Bits and Downhole Tools

STEEL TOOTH BITS BIT TYPE DESIGNATION TOOTH HARDFACING METALLURGY

GAUGE HARDFACING BEARING CAPACITY TOOTH SPACING

DESIGN FEATURES

TOOTH DEPTH CHIPPINGCRUSHING ACTION GOUGINGSCRAPING ACTION

GEOMETRY

JOURNAL ANGLE OFFSET

TUNGSTEN CARBIDE BITS TYPE DESIGNATION BEARING CAPACITY INSERT 8PACING DESIGN FEATURES

GEOMETRY

INSERT EXTENSION CHIPPINGCRUSHING ACTION GOUGINGSCRAPING ACTION JOURNAL ANGLE OFFSET

Figure 4-138. Roller cone bit design trends [44].

(Courtesy SPE.)

773

774

Drilling a n d Well C o m p l e t i o n s

Cone Cutter Design To u n d e r s t a n d how cone g e o m e t r y can effect the way rock bit teeth cut rock, consider the m o d e r a t e soft f o r m a t i o n cone shown schematically in Figure 4-139 [45]. Such cones are d e s i g n e d to d e p a r t substantially from true rolling action on the b o t t o m of the borehole. They have two or m o r e basic cone angles, n o n e of which has its apex at the center of bit rotation. The conical heel surface tends to rotate about its theoretical apex and the i n n e r row surface about the center of its own apex. Since the cones are forced to rotate about the bit centerline, they slip as they rotate a n d p r o d u c e a tearing, gouging action. This action is o b t a i n e d by moving the cone centerline away from the center of bit rotation, as shown in Figure 4-139. Bits for hard f o r m a t i o n have cones that are m o r e nearly true rolling and use little or no cone offset. As a result, they break rock p r i m a r i l y by crushing. T h e b e a r i n g j o u r n a l angle specified in Figure 4-139 (relative to horizontal) is r e d u c e d for softer bits and increased for h a r d e r bits. This alters the cone profile which in t u r n affects tooth action on the b o t t o m h o l e a n d gauge cutter action on the wall of the hole. No roller cone bit has truly conical-shaped cones, but softer bits have m o r e highly profiled, i.e., less-conical cones than h a r d e r bits. T h i s i n c r e a s e s the s c r a p i n g a c t i o n of b o t h b o t t o m h o l e c u t t e r s a n d g a u g e surfaces. T h e scraping action is beneficial for drilling soft formations but it will result in accelerated tooth and gauge wear if the formation is relatively abrasive. Scraping action is minimized on hard formation bits where strength and abrasion resistance are e m p h a s i z e d in the design.

Bearing Design T h e major b e a r i n g design used in present rock bits are shown in Fig. 4-140 [44]. T h r e e styles of b e a r i n g designs are generally available: non-sealed roller bearings, sealed roller bearings, a n d sealed friction bearings. A n o t h e r name for friction bearings is j o u r n a l bearings. A fourth style features air-cooled non-sealed roller bearings i n t e n d e d for air d r i l l i n g applications.

O~r~

o~ Rotation

Centeflli'Je Of Bfl " 1 Centedlne of ~dng

i

/

/"--. I (

~ F ~'"''c'''

SOFT FORMATIONCONEDESIGN

OFFSET

Figure 4-139. Roller bit cone design features. (Courtesy Canadian Association of Oilwell Drilling Contractors.)

Drilling Bits and Downhole Tools

mu~o ~-E~

BALED

BEARINe

775

SEA-EO~ . n ~ . II,tRINe

mine LOCK IIEJUINe

I~WHUD

COOLED

Figure 4-140. Roller cone bit bearings design [44].

(Courtesy SPE.)

Sealed Friction Bearing (Journal Bearing). T h e j o u r n a l bearing, developed to match the life of carbide cutting structures, does not contain rollers; but contains only a solid j o u r n a l pin mated to the inside surface of the cone. This j o u r n a l becomes the p r i m a r y load carrying element for the cone loads. Advances in p r o d u c t design, metallurgy and m a n u f a c t u r i n g processes have p r o d u c e d a j o u r n a l - b e a r i n g featuring precisely controlled j o u r n a l , pilot pin and thrust-bearing surfaces. T h e b e a r i n g is designed and manufactured to ensure that all b e a r i n g elements are uniformly loaded. Substantially higher weights and rotary speeds can be run without decreasing bearing life. Sealed j o u r n a l bearings provide the best wear resistance at n o r m a l rotary speeds through a c o m b i n a t i o n of better load distribution and precision-machined surfaces. Sealed Ball and Roller Bearing (Self-Lubricating). The sealed ball and roller bearing was introduced in carbide tooth bits, but is now primarily in steel tooth bits and generally lasts as long as the cutting structure. Some carbide tooth bits of 12 ¼-in. and larger sizes also are available with this type bearing. Sealed roller bearings are lubricated by clean grease r a t h e r than drilling m u d and thus tend to last longer than standard roller bearings. Nonsealed Ball and Roller Bearings. T h e n o n s e a l e d ball and roller bearings were introduced to replace the primitive friction j o u r n a l bearing at a time when only steel tooth bits were available. They o p e r a t e d well in mud, and in many cases were adequate to last as long as or longer than the cutting structures they served. Today, the nonlubricating bearings are used in steel tooth bits to drill the top section of the hole where trip time is low and rotary speed are often high. T h e major p o r t i o n o f the radial load on the cone cutter is a b s o r b e d by the roller race, with the nose bearing absorbing a lesser amount. T h e thrust surface

776

Drilling and Well Completions

is p e r p e n d i c u l a r to the pilot p e n and the thrust b u t t o n is designed to take outward thrust. The ball bearings allow the cutter to take inward thrust. W h e n other b e a r i n g parts are worn out, the balls will also take some radial a n d outward loading.

Air Circulating Ball and Roller Bearings. W h e n air, gas or mist are used as

a

drilling fluid, nonsealed ball land roller bearing bits are used. The design allows a p o r t i o n of the drilling fluid to be diverted through the bearing for cooling, cleaning and lubrication. Since free water in contact with loaded bearing surfaces will reduce their life, bits are equipped with a water separator to prevent this action in cases where water is injected into the air or gas. Also available for the prevention of bit plugging are backflow valves that prevent cuttings suspended in water from backing up through the bit into the drill pipe when the flow of air or gas is interrupted. T h e "ring lock" bearing is a newer f r i c t i o n b e a r i n g design which is also classified u n d e r C o l u m n s 6 or 7 on the IADC chart. Instead of ball bearings, a snap-ring retainer holds the cone shell in place. This provides greater load-bearing area and cone shell thickness in the region where the ball bearing race has been eliminated. A compressed O-ring seal prevents drilling m u d from contaminating the bearing grease.

Steel Tooth Cutting Structure Design The designs of steel tooth bits cutting structure are shown in Figure 4-141 [44]. Steel tooth bits are employed in soft formations where high rotary speeds can be used. All steel tooth cones have tungsten carbide hardfacing material applied to the gage surface of the bit body and to the teeth as dictated by the intended use of a specific roller cone design. Tooth hardfacing improves wear resistance but reduces resistance to chipping and breaking. For this reason, hard formation steel tooth cones usually have gage hardfacing only, while soft formation steel tooth cones usually have hardfacing on tooth surfaces as well as the gauge surface.

Soft Formation Bits. Bits for drilling soft formations are designed with long, widely spaced teeth to permit m a x i m u m p e n e t r a t i o n into the formation and removal of large chips. Medium Formation Bits. Medium and medium-hard formation bits are designed with more closely spaced teeth, since the bit cannot remove large pieces of the harder rock from the bottom of the borehole. The teeth also have slightly larger angles to withstand loads needed to exceed formation strength and produce chips. Hard Formation Bits. The heel or outermost row on each cone is the driving row, that is, this row generates a rock gear pattern on the bottom of the borehole that, in the case of these strong rocks, is not easily broken away from the wall of the borehole. The n u m b e r s of heel row teeth used on each of the three cones are selected to prevent the heel teeth from "tracking," or exactly following in the path of the preceding cone, which would cause abnormally deep rock tooth holes on the borehole bottom.

Insert Bit Tooth Design The c o m p a n i o n of insert bits cutting structure is shown in Figure 4-142 [44]. Initially, the tungsten carbide tooth bit was developed to drill extremely hard, abrasive cherts and quartzites that had b e e n very costly to drill because of the

Drilling Bits a n d Downhole Tools

~BC CODE a i

!~SC C008 !2!

b~DC CODE !3!

IAD8 @DE ~I I

777

IAOC 80B~ S! I

@ge

~ 6 CODE111

Figure 4-141.

~D8 OO~)E~31

Steel tooth bit cutting structure design [44].

~8C CODE3i 1

(Courtesy SPE.)

relatively short life o f steel tooth bits in such formations. In this type o f bit, tungsten c a r b i d e a n d forged alloy steel are c o m b i n e d to p r o d u c e a c u t t i n g structure having a high resistance to abrasive wear and extremely high resistance to compressive loads. C o m p a c t s o f cylindrical tungsten c a r b i d e with various s h a p e d ends are pressed into precisely m a c h i n e d holes in case-hardened alloy steel cones to form the teeth. T h e g r a i n size a n d cobalt content o f tungsten carbide inserts is varied to alter the impact toughness and abrasion resistance o f the cutter. Softer f o r m a t i o n inserts, which are usually r u n in less abrasive rocks at higher rotary speeds, require increased toughness to resist breakage o f the relatively long cutters. A cobalt content o f 16% and average grain size o f 6 Ixm is typical for such inserts. H a r d f o r m a t i o n inserts are generally r u n in m o r e a b r a s i v e rocks at h i g h e r W O B levels. H a r d f o r m a t i o n i n s e r t s have a m o r e breakage-resistant g e o m e t r y so a b r a s i o n resistance becomes the most i m p o r t a n t factor. Thus the cobalt content is r e d u c e d to about 10% a n d the average g r a i n size is approximately 4 Ixm.

778

Drilling and Well Completions

I/~gCCO~I~E537

~(~CCODE67

Figure 4-142. Cutting structures of insert bits [44]. (Courtesy SPE.)

Dull Grading for Roller Cone Bits Grading a dull bit and evaluating the findings can increase drilling efficiency while lowering drilling cost. Also, the examination of the dull bit can often furnish information that will assist the selection of bit types and also help determine the advisability of changing operating practices. The bit life need not be totally used before it is graded, since the grading is to determine what happened to the bit during a specific drilling run. The condition of each bit should be reported in the "Bit Record" section of the IADC Daily Drilling Report form.

Drilling Bits a n d Downhole Tools

779

Tooth Wear. Tooth wear is estimated in eighths (!8) of the initial tooth height. Since tooth wear is likely not u n i f o r m on any row of teeth of a given cone, it is advisable to take several readings a n d report an average figure. The following is the terminology used to report tooth wear:

Tooth Dullness

Milled Tooth

Insert Bits

T1

Tooth height ~ gone

-18 of inserts lost or broken

T2

Tooth height ¼ gone

¼ of inserts lost or broken

T3

Tooth height } gone

} of inserts lost or broken

T4

Tooth height ~ gone

½ of inserts lost or broken

T5

Tooth height } gone

} of inserts lost or broken

T6

Tooth height ~ gone

¼ of inserts lost or broken

T7

Tooth height } gone

-~ of inserts lost or broken

T8

Tooth height all gone

All of inserts lost or broken

Bearing Condition, The m e a s u r e m e n t of the b e a r i n g wear is very subjective. It is r e c o m m e n d e d to estimate it in eighths of the life of the bearing. Since mechanical aids are not available, it is necessary to eyeball the b e a r i n g wear and estimate rotating hours left. Knowing the rotating hours of the bit at the bottom of the well, it is possible to calculate the ratio. A n estimation of the total b e a r i n g life is expressed by a ratio of eighths of the b e a r i n g life as follows:

Bearing Condition B1 B2

Bearing life used: Bearing life used:

¼ (tight)

B3

Bearing life used:

_3 8

B4

Bearing life used:

½ (medium)

B5

Bearing life used:

5__ 8

B6

Bearing life used:

~ (loose)

B7

Bearing life used:

B8

Bearing life all gone:

(Locked or lost)

Example A roller rock bit is pulled out of the hole after 12 hr of rotation at the bottom. The driller estimates that the worst cone could rotate 4 hr more before being completely worn out; thus total b e a r i n g life estimated is 16 hr. 12 Therefore: 16

3 4

6 8 ' i.e. B6 is reported.

780

Drilling and Well C o m p l e t i o n s

G a u g e Wear. W h e n the bit pulled out o f the hole is in gage, this is r e p o r t e d by the letter "I." W h e n the bit pulled out o f the hole is out o f gage, this is r e p o r t e d by the amount o f gage wear in ~ o f an inch. To measure the amount o f gage wear on a used bit, set the ring gauge on two cones and measure the distance b e t w e e n the ring gauge and the third cone in fractions o f an inch, or in millimeters. Dull G r a d i n g of Roller Cone Bits. T h e g r a d i n g is accomplished by using an eight-column dull code as follows [46].

Cutting Structure

B

G

Remarks

Inner

Outer

Dull

Bring

Gage

Other

Reason

Rows

rows

char.

Location

seal

~

dull

pulled

(o)

(D)

(L)

(B)

(G)

(O)

(R)

(0

l. C o l u m n I (I) is used to r e p o r t the c o n d i t i o n o f the cutting structure on the i n n e r two-thirds o f the bit. 2. C o l u m n 2 (O) is used to r e p o r t the c o n d i t i o n o f the cutting structure on the outer one-third o f the bit. In columns 1 and 2 a linear scale f r o m 0 to 8 is used to describe the c o n d i t i o n o f the cutting structure as explained above. For example: a bit missing half o f the inserts on the i n n e r two-thirds o f the bit due to loss or breakage with the r e m a i n i n g teeth on the i n n e r twothirds having a 50% r e d u c t i o n in height due to wear, should be g r a d e d a 6 in c o l u m n 1. If the inserts on the outer one-third o f the bit were all intact but were reduced by wear to half o f their original height, the p r o p e r g r a d e for c o l u m n 2 would be 4. 3. Column 3 (D) uses a two-letter code to indicate the major dull characteristic o f the cutting structure. Table 4-92 lists the two-letter codes for the dull characteristics to be used in this column.

Table 4-92 Major/Other Dull Characteristics [46] * BC-BT - BU - * CC-* CD-CI - CR - CT-ER - FC - HC-JD - * LC--

Broken cone Broken teeth/cutters Bailed up Cracked cone Cone dragged C o n e interference Core

Chipped teeth Erosion Flat crested w e a r Heat checking Junk d a m a g e Lost cone

LN-LT - OC -PB - PN - RG - RO - SD - SS - TR - WO -WT-NO - -

Lost nozzle Lost teeth/cutters

Off center wear Pinched bit Plugged nozzle Rounded gauge Ring out Shirttail d a m a g e

Self sharpening wear Tracking Wash out on bit Worn teeth/cutters No other major/other dull characteristic

*Show cone number(s) under LOCATION (L) column 4 of the IADC dull code. Courtesy SPE

Drilling Bits and Downhole Tools

781

4. C o l u m n 4 (L) uses a letter or n u m b e r code to indicate the location on the face of the bit where the major cutting structure dulling characteristic occurs. Table 4-93 lists the codes to be used for describing locations on roller cone bits. 5. C o l u m n 5 (B) uses a letter or a n u m b e r code, d e p e n d i n g on bearing type, to indicate bearing c o n d i t i o n on roller cone bits. For nonsealed b e a r i n g roller cone bits a linear scale from 0 to -8 is used to indicate the a m o u n t of bearing life that has been used. A 0 indicates that no b e a r i n g life has b e e n used (a new bearing), a n d an 8 indicates that all of the bearing life has been used (locked or lost). For sealed bearing (journal or roller) bits a letter code is used to indicate the condition of the seal. A n "E" indicates an effective seal, and an "F" indicates a failed seal(s). 6. C o l u m n 6 (G) is used to report on the gage of the bit. The letter "I" indicates no gage reduction. If the bit does have a reduction in gauge it is to be recorded in ~ of an inch. The "two-thirds rule" is correct for threecone bits. The two-thirds rule, as used for three-cone bits, requires that the gauge ring be pulled so that it contacts two of the cones at their outermost points. T h e n the distance between the outermost point of the third cone and the gage ring is multiplied by two-thirds and r o u n d e d to the nearest ~ of an inch to give the correct diameter reduction. 7. C o l u m n 7 (O) is used to report any dulling characteristic of the bit, in a d d i t i o n to the major c u t t i n g structure d u l l i n g characteristic listed in c o l u m n 3 (D). Note that this c o l u m n is not restricted to only c u t t i n g structure dulling characteristics. Table 1 lists the two-letter codes to be used in this column. 8. C o l u m n 8 (R) is used to report the reason for pulling the bit out of the hole. Table 4-94 lists the two-letter or three-letter codes to be used in this column.

Location N --

Table 4-93 ( R o l l e r C o n e B i t s ) [46]

Nose rows

Cone # or # ' s

M -- Middle rows

1

H m Heel rows

2

A - - All r o w s

3

Courtesy SPE

Table 4-94 Reason Pulled [46] assembly - - Down hole motor failure - - Drill s t r i n g failure - - Drill stem test - - D o w n hole tool f a i l u r e - - R u n logs

BHA -- Change bottom hole DMF DSF DST DTF LOG

CM -- Condition mud CP --

Core point

D P - - Drill p l u g FM --

Formation change

Courtesy SPE

H P - - H o l e problems HR - - Hours on bit PP -- Pump pressure

PR - - Penetration rate RIG - - Rig repairs T D - - Total depth/casing depth TQ -- Torque

off WC - - Weather conditions TW -- Twist

782

Drilling a n d Well C o m p l e t i o n s

Example [46] We will g r a d e t h r e e d u l l e d r o l l e r c o n e bits, a n d discuss s o m e p o s s i b l e interpretations of the wear as it relates to bit selection and application. It should be n o t e d that there may be m o r e than one "correct" dull g r a d i n g for each bit. This can h a p p e n if two persons should disagree on the p r i m a r y cutting structure dulling characteristic or on what the o t h e r dulling characteristic should be. Regardless, the I A D C dull g r a d i n g system provides the man on the rig with a m p l e o p p o r t u n i t y to r e p o r t what he sees when e x a m i n i n g a dull. T h e first dull bit is a 7 ~" I A D C 5-1-7-X bit and has been g r a d e d as a 6, 2, BT, M, E, I, NO, PR (see Table 4-95). The bit looks to have been dulled by encountering a h a r d e r f o r m a t i o n than the bit was designed for. This is indicated by the heavy tooth breakage on the i n n e r teeth, a n d by the bit having been p u l l e d for p e n e t r a t i o n rate (the r e d u c e d p e n e t r a t i o n rate having been caused by the tooth breakage o c c u r r i n g when the bit e n c o u n t e r e d the hard formation). Excessive weight on the bit could also cause the dull to have this a p p e a r a n c e . If the r u n was of reasonable duration, then the bit application was p r o p e r as evidenced by the lack of "other" dulling features, the effective seals, and the fact that the bit is still in gage. However if the bit had a shorter than expected run, it is probable that the application was improper. The bit may have been too "soft" for the formation, or it may have been run with excessive weight on the bit. The s e c o n d dull bit is a 7-~-in. I A D C 8-3-2-A bit that was g r a d e d 5,8,WT, A,3,2,FC,HR (see Table 4-95). This dull g r a d e indicates p r o p e r bit selection and application. T h e tooth wear (WT is n o r m a l in the h a r d e r tungsten carbide insert bits as o p p o s e d to c h i p p e d or broken teeth which could indicate excessive WOB or RPM) is not a great deal m o r e on the outer cutters than on the inner cutters, i n d i c a t i n g p r o p e r RPM a n d WOB. The bit was still drilling well when p u l l e d as indicated by listing HRS as the reason pulled. However the bit was slightly u n d e r gage ( ~ in.) at this point a n d may well have lost m o r e gage rapidly if left in

Table 4-95 Example of Dull Bit Gradings [46] BIT

RECORD

.2

I

BIT t~0. SIZE

:t ,I

IADC CODE

o!31 !.

j c?-r. TRVC. J l][/ O| D/ L

i

L

B

C

Coudesy SPE

0

R

~ I II~ II ~

~~

B

~

~

0

0 ~

~

Drilling Bits a n d Downhole Tools

783

the hole. This s u p p o r t s the decision to pull the bit based o n the hours. A b e a r i n g c o n d i t i o n of 3 on the air bearings indicates g o o d b e a r i n g life still remaining. Since there are no harder bits available, a n d the dull grade indicates that a softer bit would not be a p p r o p r i a t e , this seems to have b e e n a p r o p e r bit application. The third dull bit is a 12¼-in. IADC 5-1-7-X bit a n d was g r a d e d 0,0,NO, A,E,I,LN,PP (see Table 4-95). Since there is no evidence of any cutting structure dulling, the 0,0,NO,A is used to describe the cutting structure. If this bit had b e e n r u n for a long time before losing the nozzle, this dull g r a d i n g would indicate that a softer bit (possibly a milled tooth bit) might be better suited to drill this interval. If the r u n was very short, then the indication is that the nozzle was not the proper one, or that it was improperly installed. If this was the case, then no other i n f o r m a t i o n c o n c e r n i n g the proper or i m p r o p e r bit application can be determined.

Steel Tooth Bit Selection T h e decision to r u n a specific bit can only be based on e x p e r i e n c e a n d j u d g m e n t . Usually, a bit manufacturer provides qualitative r e c o m m e n d a t i o n s on selection of his bits. G e n e r a l considerations are: 1. Select a bit that provides the fastest p e n e t r a t i o n rate when drilling at shallow depths. 2. Select a bit that provides maximum footage rather than maximum penetration rate when drilling at greater depths where trip time is costly. 3. Select a bit with the p r o p e r tooth depths, as m a x i m u m tooth d e p t h is sometimes overemphasized. When drilling at 200 rpm at a rate of 125 ft/hr, only ~ of the hole is cut per revolution of the bit. Bits are designed with long teeth a n d tooth deletions for tooth cleaning. 4. Select a bit with enough teeth to efficiently remove the formations, as that often can be more i m p o r t a n t than using a bit with m a x i m u m tooth depth. 5. Select a bit with enough gage tooth structure so that the gage structure will not r o u n d off before the inner-tooth structure is gone. 6. Select a bit with t u n g s t e n carbide inserts on gage if sand streaks are expected in the formation. Do not d e p e n d on gage hardfacing alone to hold the hole to gauge. Crooked hole considerations are: 1. Select a bit with less offset. 2. Select a bit with open gage teeth to straighten hole. 3. Selecting a bit with more teeth a n d with shorter crested teeth results in smoother r u n n i n g a n d reduced rate of tooth wear. 4. Selecting a bit with "T'-shaped gage teeth reduces the tendency for the bit walk. Pinching considerations are: 1. Select a bit with less offset a n d harder formation type (more vertical gage angle). 2. Do not select a bit with reinforced gage teeth unless excessive gage tooth r o u n d i n g is the reason for pinching.

784

Drilling and Well Completions

Reaming considerations are: 1. Select a bit with m i n i m u m offset. 2. Select a bit with "L" or "T'-shaped gage structure.

Insert Bit Selection The decision to r u n a specific insert bit can only be based on experience and j u d g m e n t . G e n e r a l considerations are: 1. Select a t u n g s t e n carbide bit with chisel crest inserts when d r i l l i n g a formation that is p r e d o m i n a n t l y shale. Use bit type 4-2, 5-2, 6-1 or 6-2. 2. Select a tungsten carbide bit with high offset and chisel inserts if the shale content of the formation increases a n d / o r the m u d density is high. Use bit type 5-2 or 5-3. 3. Select a tungsten carbide bit with shorter chisel inserts and less offset if the formations become more abrasive and unconsolidated. Use bit type 6-3 or 6-4. 4. Select a tungsten carbide bit with projectile or conical inserts when drilling a formation that is p r e d o m i n a n t l y limestone. Use bit type 6-3 or 6-4. 5. Select a tungsten carbide bit with projectile or conical inserts if the sand content and abrasiveness of the formation increases. Use bits type 7-1 to 8-3. Specific considerations are: 1. Select a tungsten carbide insert with the greatest a m o u n t of offset and the longest chisel crested inserts when drilling shale and soft limestone. 2. Select a tungsten carbide insert bit with a m e d i u m offset and long chisel crested inserts when drilling sandy shale with limestone and dolomite. Use bits type 4-1 to 5-3. 3. Select a tungsten carbide insert bit with a m i n i m u m offset and projectile or conical inserts when drilling limestone, brittle shale, nonporous dolomite and broken formations. Use bit type 6-3 to 7-3. 4. Select a tungsten carbide bit with m e d i u m or no offset and chisel crested inserts when drilling sandy shales, limestones and dolomites. Use bit type 5-3 or 6-4. 5. Select a tungsten carbide insert bit with no offset and conical or double cone inserts when drilling hard and abrasive limestone, hard dolomite, chert, pyrite, quartz, basalt, etc. Use bit type 7-4 to 8-3.

Quantitative Method of Bit Selection This method is based on cost comparison between bit records and the current bit run. T h e following example illustrates the application of cost-per-foot data in evaluating the economics of insert bits [34].

Example Determine the economics for insert bits using the data below. Applicable costs are:

Drilling Bits a n d D o w n h o l e T o o l s

Mill tooth bits, each Insert bits Mud, per day Water, per day Desilter, per day Supervision, per day Total daily cost

$ 260.00 1,250.00 500.00 200.00 150.00 250.00 $2,610.00

Hourly rig cost

$ 108.00

785

T r i p t i m e is 0.7 p e r h o u r p e r 1,000 ft. T h e cost e q u a t i o n is (4-75)

C = B/F + CdTd/F + C T/F where C = B = F = Cd= Yd = Yt = Ct =

d r i l l i n g cost p e r f o o t in $ / f t bit cost in $ f o o t a g e d r i l l e d in ft rig cost for d r i l l i n g in $ / h r d r i l l i n g t i m e in h r trip t i m e in h r rig cost for trip in $ / h r

A s s u m p t i o n s are (1) c o m p a r a b l e lithology, (2) C d = C t = $ 1 0 8 / h r , a n d (3) t h e well in q u e s t i o n is to b e d e e p e n e d f r o m 6000 to 7650 ft. T h e bit r e c o r d f r o m t h e offset c o n t r o l well is p r e s e n t e d in T a b l e 4-96. T h e cost p e r foot for e a c h bit r u n is c a l c u l a t e d as follows: Bit No. 1 D r i l l i n g h o u r s = 10.5 T r i p h o u r s = (0.7 h r / 1 0 0 0 ft)(5.958 x 1000 ft) = 4.1 h r Total h o u r s = 14.6 h r Total f o o t a g e = 160 ft Therefore, C = I / F [B + C d ( T d + T ) ] = 1 / 1 6 0 ft[$260 + $ 1 0 8 / h r (10.5 + 4.1)hr] = $11.51/ft

Table 4-96 Cost of Steel Tooth Bits [34] Bit No 1 2 3 4 5

Depth out, ft

Footage, ft

Bottom time, hr

6008 6268 6518 7444 7650

174 260 250 926 206

19.0 19.5 25.0 99.75 25.5

CopyrightPennWellBooks,1986.

786

Drilling and Well Completions

Similar calculations are made for each bit r u n a n d recorded on the bit record. The bit record is presented in Table 4-97. Inserts were r u n below 6500 ft. Costper-foot data was calculated for each bit and is presented. From Table 4-98 insert bits drilled 1132 ft at a cost of $17,205.00. Cost of conventional bits from the offset well were $27,803.00. Savings with inserts: $10,597.00.

Roller Rock Bit Hydraulics Roller rock bit nozzle sizes are given in Table 4-98. The total pressure drop across a roller rock bit, Pb(psi), is [47]

Pb = 7430C2(d~ + d~ + d~) 2 where ? q d v d~, d~ C

= = = =

(4-76)

specific weight of drilling m u d in l b / g a l volumetric rate of flow of drilling m u d through the bit in g a l / m i n the diameters of the three bit nozzles, respectively in in. the nozzle coefficient (usually taken to be about 0.98 or else)

Table 4-97 Cost of Insert Bits [34] Bit No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Depth out, ft

Footage, ft

Bottom time, hr

5958 9260 6329 6469 6565 6692 6873 7031 7180 7243 7295 7358 7425 7460 7527

160 302 69 140 96 127 181 158 149 63 52 53 67 35 67

10.5 19.0 3.5 15.5 9.5 9.0 15.5 16.0 18.5 11.0 11.0 12.5 12.5 10.0 10.5

Copyright PennWell Books, 1986.

Table 4-98 Jet Nozzles Sizes Inches(32's) 8 9 10 11 12 13 14 15 16 18 20 22 24 26 28 Millimeters(mm) 6.4 7.1 7.9 8.7 9.5 10.3 11.1 11.9 12.7 14.3 15.9 17.5 19.0 20.6 22.2

D r i l l i n g Bits a n d D o w n h o l e T o o l s

787

T h e bit hydraulic h o r s e p o w e r H P h is H P h = qAPb 1714

(4-77)

J e t nozzle i m p a c t force Fb(lb ) is F b = 0.01823 Cq(TAPb) 1/2

(4-78)

T h e velocity o f f l o w f r o m the nozzles v ( f t / s ) is g i v e n by

v"

= q.._L~= q_.~2= q.__2_~ A1 A2 As

(4-79)

w h e r e q v q2' q3 = the v o l u m e t r i c f l o w rate f r o m each nozzle in, ft ~ ° s A,, A 2, A s = the cross-sectional area o f each nozzle (i.e., Ai = (~r/4)dF) in ft 2 T h e total v o l u m e t r i c f l o w rate q (ft3/s) can also b e e x p r e s s e d as q = Vn(A1 + A 2 + A s) = ~n A,

(4-80)

where A = A I + A2 + A3 T h e nozzle velocity vn(ft/s ) is

vn-

3. lQ 17a,

(4-81)

w h e r e a = the total nozzle area, in. 2 T h e m a x i m u m cross f l o w velocity u n d e r the bit, v (ft/s), is [48]

5.9 Qv.

vc - -d-

- -n

(4-82)

w h e r e d = the b o r e h o l e d i a m e t e r in in. n = t h e n u m b e r o f o p e n nozzles Figure 4-143 gives convenient graphs for nozzle selection for roller rock bits [47].

Example D e t e r m i n e the p r e s s u r e d r o p across the bit and the velocity o f the nozzle flow w h e r e t h e total rate o f f l o w t h r o u g h the drill string ( a n d bit) is 300 g a l / m i n , the specific w e i g h t o f t h e m u d is 12.0 l b / g a l , a n d the t h r e e nozzle o p e n i n g s are to be ~ in. in d i a m e t e r . Use c = 0.95. T h e p r e s s u r e d r o p across the bit is f o u n d by e q u a t i o n 4-76.

O0 O0

Nozzle Selection Chart for Given Drilling String, Hole Size & Working Pressure With Varying Depth & Mud Density 500

N

3 x 11/32"

- 3/8"

13/32'~

7/16"

DRILLING STRINGS: 400' of 6 1/4" O.D. Drill Collars +5" Extra Hole Drill Pipes Hole size: 8 1/2" Working Pressure= 2250 P.S.L

15/32"

300

]0 go 100 1 Scale-2

Scale-1

250

I

Circu[at~onRate-G.RM.(U.S.) 400 500 ~ Originf~r Slant Line

300

2250 2000

1000

[

~..-:~..~ , r,

I

EXAMPLE: Assume Annular Velocity= 230 Ft/m[n Mud Density= 11 Ibs/gal Depth= 7000' 0 Start at 230 EP.M Reach 'A' (7000' Line) Turn for 'B' (on 10 £P.G. Line) Slant to 'C' (on 11 P.P.G.Line) Stant beck to 'D' (on 10 P.P.G.Line) Reach for 'E' (on 230 EP.M. Line)

000

(Nearest higher nozzle tine to be taken) Nozzle set 3 x 13/32" Follow 230 EP.M Line to 'F' Find Jet Velocity (360 EP.S.)

250

A typical nozzle program

750

Mud Anrt.Ve~ G,PM Oep~ DLeb~c~

500 500

I

[ ! ! ! Lbs/GallO . 1112 13 14 15

500 1500

Oq

750 !000 3 X11/32" I I ~.

Lines

!250 200

300 i

,

i

,

1J

3/~'*

13/32'

400 500 CirculationRate-G,RM.(US.) i

,

i

,

[

i

~

i

,

t

600 ,

i

,

i

700 i

i

i

}

,

800 i

,

i

120 140 160 180 200 220 240 260 280 300 320 340 360 380 400 ANNULARVELOCITYFt./Min.

,

205

390 3000

80

205

390 5000

78

205

390 8000

78

205

390 12,00C

78

NoZZle 2 x 11/13". 1 x3/8" 1 x 11/32", 2 x 3/8" 3 x 3/8" 2X3/8 , 13/32"

Curves drawn for 10 Ibs/gal. for 10 P.P.G. A&E will be the same point

USED "SECURITYHYDRAULICCALCULATOR"

Figure 4-143. Bit nozzle selection nomogram [47]. (Courtesy Harcourt Brace & Co.)

5"

==

Drilling Bits and Downhole Tools

789

This becomes 12.0(300) 2 -- 370.7 psi APb = 7430(0.95)2[3(0. 4688) 2]2 T h e velocity of the nozzle flow is found by equation 4-81. T h e total area of the nozzle openings is a t = 3 4 (0.04688) 2 = O. 5178 in 2 Equation 4-81 becomes ~, -

300 = 185.9 ft/s 3.117(0.5178)

Diamond Bits D i a m o n d bits are being employed to a greater extent because of the advancements in m u d motors. High r p m can destroy roller rock bit very quickly. O n the other hand, d i a m o n d bits rotating at high r p m usually have longer life since there are no moving parts.

Diamond Selection. Diamonds used as the cutting elements in the bit metal matrix has the following advantages: 1. 2. 3. 4.

Diamonds Diamonds Diamonds Diamonds

are the hardest material. are the most abrasive resistant material. have the highest compressive strength. have a high thermal conductivity.

Diamonds also have some disadvantages as cutting elements such as: they are very weak in shear strength, have a very low shock impact resistance, and can damage or crack u n d e r extremely high temperatures. W h e n choosing diamonds for a particular drilling situation, there are basically three things to know. First, the quality of the d i a m o n d chosen should d e p e n d on the formations being drilled. Second, the size of the d i a m o n d and its shape will be d e t e r m i n e d by the formation and anticipated p e n e t r a t i o n rate. Third, the n u m b e r of diamonds used also is d e t e r m i n e d by formation and the anticipated p e n e t r a t i o n rate. There are two types of diamonds, synthetic and natural. Synthetic d i a m o n d s are man made and are used in PDC STRATAPAX type bit designs. STRATAPAX PDC bits are best suited for extremely soft formations. T h e cutting edge of synthetic d i a m o n d s are round, half-moon shaped or pointed. Natural d i a m o n d s are divided into three categories. First are the carbonate or black diamonds. These are the hardest and most expensive diamonds. They are used primarily as gage reinforcement at the shockpoint. Second are the West African diamonds. These are used in abrasive formations and usually are of g e m s t o n e quality. A b o u t 80% of the West A f r i c a n d i a m o n d s are p o i n t e d in shape and, therefore, 20% are the desirable spherical shape. Third are the Congo or coated d i a m o n d s . T h e s e are the most c o m m o n category. Over 98% of these d i a m o n d s are spherical by nature. They are extremely effective in soft

790

Drilling and Well Completions

formations. T h e o t h e r 2% are usually c u b e d shaped, which is the weakest of the shapes available. By studying specific formations, d i a m o n d s application can be generalized as follows: Soft, g u m m y f o r m a t i o n s - C o n g o , c u b e d s h a p e d Soft f o r m a t i o n - l a r g e Congo, spherically s h a p e d Abrasive f o r m a t i o n - p r e m i u m West Africa H a r d and a b r a s i v e - S p e c i a l p r e m i u m West Africa

Diamond Bit Design. D i a m o n d drill bit g e o m e t r y and descriptions are given in Figure 4-144 [49]. D i a m o n d core bit g e o m e t r y and descriptions are given in Figure 4-145 [50]. T h e r e are two main design variables of d i a m o n d bits, the crown profile and face layout (fluid course configuration). T h e crown profile dictates the type of f o r m a t i o n for which the bit is best suited. They include the round, parabolic, t a p e r e d and flat crown used in hard to extremely hard formations, m e d i u m to hard formations, soft formations and for fracturing formations or sidetracks and for kick-offs, respectively. Cone angles and throat depth dictate the bit best suited for stabilization. Cone angles are steep (60 ° to 70°), m e d i u m (80 ° to 90°), flat (100 ° to 120°), best suited for highly stable, stable and for fracturing formation, respectively. D i a m o n d drill bits with special designs and features include: 1. L o n g gage bits, used on d o w n h o l e motors for drilling ahead boreholes. 2. Flat-bottom, shallow-cone bit designs, used on s i d e t r a c k i n g sidetracking j o b s with d o w n h o l e motors. 3. Deep cones having a 70 ° apex angle are n o r m a l l y used in drill built-in stability and to obtain greater d i a m o n d c o n c e n t r a t i o n cone apex.

in vertical j o b s or in bits to give in the bit-

Diamond Bit Hydraulics. T h e hydraulics for d i a m o n d bits should accomplish r a p i d removal of the cuttings, and cooling and lubrication of the d i a m o n d s in the bit metal matrix. Bit Hydraulic Horsepower. T h e effective level of hydraulic energy (hydraulic horsepower p e r square inch) is the key to o p t i m u m bit p e r f o r m a n c e . T h e ruleof-thumb estimate of d i a m o n d bit hydraulic horsepower HP h and p e n e t r a t i o n rates is shown in Table 4-99. T h e bit hydraulic horsepower is d e p e n d e n t u p o n the pressure d r o p across the bit and the flowrate. Bit Pressure Drop. T h e pressure d r o p across the bit is d e t e r m i n e d on the rig as the difference in s t a n d p i p e pressure when the bit is on bottom, and when the bit is off bottom, while maintaining constant flowrate.

Maximum Drilling Rate. In fast d r i l l i n g o p e r a t i o n s (soft f o r m a t i o n s ) , the m a x i m u m p e n e t r a t i o n rate is limited by the m a x i m u m pressure available at the bit. This is the m a x i m u m allowable s t a n d p i p e pressure minus the total losses in the circulating system.

Optimum Pump Output. In h a r d e r formations where drilling rates are limited by m a x i m u m available bit weight a n d r o t a r y speed, the o p t i m u m value of

Drilling Bits a n d Downhole Tools

791

Collector ~~.-,. f (Secondary)'~ Crowfoot~ ~ \\ I H f/~'~-b_...-Feeder ~ FLUIDCOURSES Opening ~2~----~%.~.\" ~.\ (( /],F-,~a'~ (Primary) .} DiamondSetPad~

~

JuNKSLOT

"a~L'l:LY~'~--- controlDiameters (TFACollector) I~lnoc~ D,~t,lh t o

Ap £ Shoulc Ga Ga!

Alignment

CROWNPROFILE

BLANK SHANK !) :ion

Figure 4-144. Diamond drill bit nomenclature[49]. (Courtesy Hughes Christensen.) flowrate should be adjusted to achieve the bit hydraulic horsepower required. T h e m i n i m u m p u m p discharge required to maintain annular velocity a n d bit cooling is shown in Figure 4-146.

Hydraulic Pumpoff. T h e bit pressure d r o p acts over the bit face area between the cutting face of the bit a n d the f o r m a t i o n a n d tends to lift the bit off the

792

Drilling and Well Completions

InsideDiameter(I.D.) I

DiamondSet

JunkSlot ~, FaceDischarge , ~ Ports ,,,-Feeder(Primary) FLUID COURSES Collector (Secondary)

Pad O.D.FlankAngle~ - - -

ControlDiameters (TFA& Collector)

I.D.FiankAngle

NoseRadius

"~ . ~ I.D.GagePoint..~,.~ ~_.~'~_l~l_~l'~'~'~--~ > O.D.GagePoint----,,~[ MatrixCrown ,.J,!:il~ll!~i~l~l~ H ~IL Port ---~-~;;;~,]~------4 [Jl[llJJl Imll) AlignmentThreads~ ~[J. ~' "%-" ~ \ Blank""'1 ~ [ ~ ~ ~ Weld- ~ ShankScallops ,,, Shank ' (alsoC'BBLSize)

z_~

Nose "~ Shoulder CROWN Gage (O.D.)(API) / PROFILE Crown / ChamferJ GageLands

- BreakerSlots

C'BBLThreads~ I1

!

Figure 4-145. Diamond core bit nomenclature [50]. (Courtesy Hughes

Christensen.)

Table 4-99 Bottomhole Hydraulic Horsepower Required for Diamond Drilling [49]

Penetration Rate,ft/hr HydraulicHorsepower Required, HPh;/Sq. inch

1-2

2-4

4-6

6-10

over 10

1-1.5

1.5-2

2-2.5

2.5-3

3-3.5

bottom of the hole. This force is large at the higher bit hydraulic horsepower being utilized today and in some cases may require additional bit weight to compensate. For example, the pumpoff force on an 8 ~-in. diamond bit having a pressure drop across the bit of 900 psi would be about 6,000 lb.

Drilling Bits and Downhole Tools

793

900 800

3000

" 700 2500

6OO 2000 E

- -

ai aI

m

ira!

J

I A

1500

R~

iN='V.N

~ 400

300

imam

200

mm,,~j,~m,,-~,m

4

5

6

7

100

8

9

10

11

12

BitSize Figure 4-146. Pump discharge for diamond bits [50]. (Courtesy Hughes

Christensen.)

T h e hydraulic p u m p o f f force Fpo(lb) can be a p p r o x i m a t e d by [50] Fpo = 1.29(APb)(d h - 1)

(4-83)

for the radial flow watercourse design bits, and Fpo = 0.32(APb)(d h - 1)

(4-84)

for cross flow watercourse system (refer to IADC classification of fixed-cutter bits).

Diamond Bit Weight on Bit and Rotary Speed Weight on Bit. Drilling weight should be increased in increments of 2,000 lb as the p e n e t r a t i o n rate increases. As long as no problems are e n c o u n t e r e d with t h e hydraulics a n d torque, weight can be a d d e d . However, when a d d i t i o n a l weight is a d d e d a n d the p e n e t r a t i o n rate does not increase, the bit may be bailing up, and the weight on the bit should be decreased.

Rotary Speed. D i a m o n d bits can usually be rotated at up to 150 r p m without any p r o b l e m when hole conditions and drill string design permit. Rotary speeds of 200 a n d 300 r p m can be used with stabilized drill strings in selected areas. D i a m o n d bits have also o p e r a t e d very successfully with downhole motors at 600 to 900 rpm. T h e actual rotary speed limits are usually i m p o s e d by safety. Core Bits Most core barrels utilize d i a m o n d s as the rock cutting tool. T h e r e are t h r e e types o f core barrels.

794

Drilling and Well Completions

Wireline Core Barrel Systems. The wireline system can be used for continuous drilling or coring operations. The inner barrel or the drill plug center of the core bit can be dropped from the surface and retrieved without pulling the entire drill string.

Marine Core Barrels. Marine barrels were developed for offshore coring where a stronger core barrel is required. They are similar to the conventional core barrels except that they have heavier outer tube walls. Rubber Sleeve Core Barrels. Rubber sleeve core barrels are special application tools designed to recover undisturbed core in soft, unconsolidated formations. As the core is cut, it is encased in the rubber sleeve that contains and supports it. U s i n g face discharge ports in the bit, the c o n t a m i n a t i o n of the core by circulating fluid is reduced. The rubber sleeve core barrel has proven to be a very effective tool, in spite of the fact that the rubber sleeve becomes weak with a tendency to split as the temperature increases about 175°F. Core Barrel Specifications. Core barrel sizes, r e c o m m e n d e d make-up torques, maximum r e c o m m e n d e d pulls and r e c o m m e n d e d fluid capacities are shown in Tables 4-100 and 4-101 [50].

Table 4-100 Core Barrels: Recommended Makeup Values [50] ICore Barrel Size13.5 x1.75 4.12x2.12 4.50x2.12 4.75x2.6215.75x3.50 Recommended 1,700 3,000 $,000 4,050 7,400 Make up Torque to to to to to foot-pounds 2.050 3,600 6,000 4,850 8,800 c ~ c~ ..J o . j > " 0 : c -J ~. ~ ~ o ~ p ~. O. a

60"" 55"" 53"" 47"' 44" 42"j 36"[

3}'5 410 425 480 510 540 625

660 720 750 840 900 940 1.100

1 .t00 1.200 1.250 1.40(] 1,500 1.570 1 830

890 970 1.010 1!40 't.210 1.270 1.,;80

1.520 1.770 1.~3(~ 2.070 2.200 2.310 2.700

6.25x3 14,900 to 17,800

6 . 2 5 x 4 6.75x4 8.0x5.25 8.t50 9,900 19,000 to to to 9.800 12.000 22,700

3,270 3.570 3.700 4.170 4.460 4.670 5.450

t.795 1.960 2.030 2 290 2 450 2.560 2.990

Courtesy Hughes Christensen

Table 4-101 Core Barrels Characteristics [50] Size

' (ft) . # ot Turns In (GPM) Reeomm4mda $tandar¢l SeMty Joint Fluid Maximum Length Capacity Pun i

3 - I I 2 x 1-3/4 30 7 4-1t8 x 2-1/8 60 7 4-I/2 x2~lt8 60 7 4-3t4 x 2-5/8 60 t3 5-314 x 3-1t2 60 6 6-1 i4 x 3 60 7 i-1/4 x 4 £~'~,, 6 5-3!4 x 4 60 6 8 x 5-1/4 60 ? The Maximum P u l l is based upon the ultimate tensile strength in the pin thread area with a

salety lactor ol three. Courtesy Hughes Christensen

118 141 141 164 204 245 227 387 295

74~000 101,400 t94,700 137,400 200,000 290,000 t93.500 275,000 310,000

I [ ! i

2.190 2.390 2.480 2.800 2,990 ] 3,130 j 3.650

4.170 4.550 4.720 5.320 5,690 5960 6.950

Drilling Bits a n d Downhole Tools

795

Weight on Bit and Rotary Speed for Core Bits Weight on Bit. F i g u r e 4-147 shows the drilling weights for d i a m o n d core bits in various formations. These are average values d e t e r m i n e d in field tests [50]. T h e p r o p e r weight on the bit for each core run can be d e t e r m i n e d by increasing the bit weight in steps o f 1,000 to 2,000 lb, with an average speed o f 100 rpm. C o r i n g s h o u l d be corttinued at each interval while carefully o b s e r v i n g t h e p e n e t r a t i o n rate. O p t i m u m weight on the bit has b e e n reached when additional weight does not p r o v i d e any f u r t h e r increase in p e n e t r a t i o n rate o r require excessive torque to rotate the bit. Using too much weight can cause the diamonds to p e n e t r a t e too deeply into a soft f o r m a t i o n with an insufficient amount o f m u d flow able to pass between the d i a m o n d s and the formation, resulting in p o o r r e m o v a l o f t h e cuttings. T h e c o r e bit c o u l d clog o r even b u r n , a n d p e n e t r a t i o n rate a n d bit life will be reduced. In h a r d e r formations, excessive weight will cause b u r n i n g on t h e tips o f t h e d i a m o n d s o r s h e a r i n g with a resulting loss in salvage.

Rotary Speed. T h e best rotational speed for c o r i n g is usually established by the limitations o f the b o r e h o l e a n d drill string. T h e size and n u m b e r o f drill collars in the string a n d the f o r m a t i o n b e i n g cored must be considered when establishing the rotational speed. Figure 4-148 shows the r e c o m m e n d e d rotating s p e e d range for o p t i m a l core recovery in different formations [49]. C o n c e r n should also be given to the harmonic vibrations o f the drill string. Figure 4-149 gives critical rotary speeds [51] which generate h a r m o n i c vibrations. Polycrystalline Diamond Compacts (PDC) Bits PDC bits get t h e i r n a m e f r o m t h e p o l y c r y s t a l l i n e d i a m o n d c o m p a c t s u s e d f o r t h e i r c u t t i n g s t r u c t u r e . T h e t e c h n o l o g y that led to t h e p r o d u c t i o n o f STRATAPAX drill blanks grew from the G e n e r a l Electric Co. work with polycrystalline m a n u f a c t u r e d d i a m o n d materials for abrasives a n d metal working tools. G e n e r a l Electric Co. researched and d e v e l o p e d the STRATAPAX (trade

40,000 35,000

' ~

o,ooo ~5 o

,5,000

,o,ooo ,,ooo

'i'"" 4

5

6

7

8

9

10

11

12 1/4

Bit size (inches)

Figure 4-147. Bit weight for core bits [50]. (Courtesy Hughes Christensen.)

796

Drilling and Well Completions

160

150

IIIlltlllllt 1~ flOPPER LIMI II ililllHIHJlhHiIl~ iilllillill| 120 llllllllllllllllll[lll[llt[ll I~11t]| 1111 IllHilllllll~ • 110 I1111111111111111111111t ~II|ltlllillltllll ~Illllllllilt[lllllllllll 130

140

~; n

tr

100 lillllililll[llU~ u'~ 9O

80

liilmlll ] f ]111111~ [ LOWER LIMIT

70 6O 5O 4O

I

Hardness

"~ 111_11111~ '~111111[111

P loft

Formation Figure

u~lll]llllltll~

Sand Clay Salt

n~dium

medium

Anhydrlte L*mestone

h,rd Sittstone Shale Dolomite

]

very hard hlrd abrlliva ddste~o n Mu • Schist Sandstone Quartz*tic Dense Shale Sllndsto ne

ultra hard

ffa~.

Quartzite Volclni¢ Rock

4-148. Recommended rotary speed for c o r e bits [49]. (Courtesy

Hughes Christensen.)

name) drill blank in 1973 and Christensen, Inc. used these in PDC bit field tests. The bits were successfully applied in offshore drilling in the North Sea area in the late 1970s and in on-shore areas in the United States in the early 1980s. In some areas, the PDC bits have out-drilling roller rock bits, reducing overall cost per foot by 30 to 50% and achieving four times the footage per bit at higher penetration rates [52,53]. Figure 4-150 shows the major components and design of the PDC bit. The polycrystalline diamond compacts, shown in Figure 4-151. The polycrystalline d i a m o n d compacts (of which General Electric's) consist of a thin layer o f synthetic diamonds on a tungsten carbide disk. These compacts are produced as an integral blank by a high-pressure, high-temperature process. The diamond layer consists of many tiny crystals grown together at r a n d o m orientations for maximum strength and wear resistance. The tungsten carbide backing provides mechanical strength and f u r t h e r reenforces the diamond compact wear-resistant properties. During drilling, the polycrystalline diamond cutter wears down slowly with a self-sharpening effect. This helps maintain sharp cutters for high penetration-rate drilling throughout the life of the bit. P D C B i t D e s i g n . Figures 4-152 and 4-153 show typical PDC bits. Figure 4-152 is for soft formation. Figure 4-153 is for hard and abrasive formation [43A].

Bit Body Material (Matrix). There are two c o m m o n body materials for PDC bits, steel and tungsten carbide. Heat-treated steel body bits are normally a "stud" bit design, incorporating diamond compacts on tungsten carbide posts. These stud cutters are typically secured to the bit body by interference fitting and shrink fitting. Steel body bits also generally incorporate three or more carbide nozzles (often interchangeable) and carbide buttons on gauge. Steel body bits have limitations of erosion of the bit face by the drilling mud and wear of the gauge section. Some steel body bits are offered with wear-resistant coatings applied to the bit face to limit mud erosion.

Drilling Bits and Downhole Tools

797

100

200

300

500

I,-W W I,.I-

I

-r I--

1000

Z U.I .._1

2000 I,-._1

•r~t -

3000

r~

5000

10,000 15,000 20,000 30,000 20

30

50

100

200

300 400

600 800

ROTARY SPEED-RPM Figure 4-149. Critical rotary speed for core bits [51].

(Courtesy API.)

Greater bit design freedom is generally available with matrix body bits because they are "cast" in a moldlike natural diamond bits. Thus, matrix body bits typically have more complex profiles and incorporate cast nozzles and waterways. In addition to the advantages of bit face configuration and erosion resistance with matrix body bits, diamond compact matrix bits often utilize natural

798

Drilling and Well Completions JunkSlots GageChamfer

Stratapax GageAngleGageCompact / / DrillBlanks--~ / / ]\ ,.+,1' ] [~,

T-BitSize

GageCutter 3 Carbide------------" InsertConeAngle-SnapRing Jet Nozzle Insert i - . Angle Taper , O-Ring

\\

--~19) e ,~D'/ e [ ~

Nose

/

* • • •

|

/

i F'~/

ShankBore

"

I "~

i

/

It

I J[lltlL',llJl+i"+--mt,s

High~e~sure

~-,

MARKINGONTOP0 F UPPERSECTION CompanyName-SBC ] BitlraaemarK / A P I T h d . Size

Bit BreakerSLot ] Pin Chamfer

I~Gage Section~ Bit Head =[ ~

o......

RetainingRingGroove

SteelShank UpperSection

Figure 4-150. PDC bit nomenclature.

(Courtesy

I

I Strata

Bit Corp.)

Source: Strata Bit Corporation, 600 Kenrick, Suite A-l, Houston, TX 77060 ph (713) 999-4530.

unknown booklet of the company.

Diamond Compact

Stud Cutter Long Cylinder Cutter Figure 4-151. Polycrystalline diamond compacts [43A]. (Courtesy Hughes

Christensen.)

d i a m o n d s to maintain full gage hole. Matrix body bits generally utilize long cylinder-shaped cutters secured to the bit by brazing.

BR Profile. Bit p r o f i l e can significantly affect bit p e r f o r m a n c e b a s e d u p o n the influence it has on bit cleaning, stability and hole deviation control. The "doublecone" profile will help maintain a straight hole even in c r o o k e d hole country. T h e sharp nose will attack a n d drill the f o r m a t i o n aggressively while the apex and r e a m i n g flank stabilize the bit. This sharp profile may be m o r e vulnerable to damage when a h a r d stringer is e n c o u n t e r e d as only the cutters on the s h a r p nose will s u p p o r t the impact loading. A shallow cone profile appears to be the easiest to clean due to the c o n c e n t r a t i o n o f hydraulics on the r e d u c e d surface a r e a o f the bit face. This p r o f i l e relies heavily u p o n the gage s e c t i o n for directional stability. T h e shallow cone profile will h o l d direction and angle with sufficient gauge length and p r o p e r stabilization o f the bit.

Drilling Bits and Downhole Tools

799

Figure 4-152. PDC bit designed for soft formations [43A]. (Courtesy Hughes Christensen.)

Cutter Exposure. Figure 4-154 shows the types of cutter exposure on PDC bits [43]. Cutter exposure is the distance between the cutting edge and the bit face. Stud bits typically have full e x p o s u r e that proves very aggressive in soft formation. In harder formations, less than full exposure may be preferred for added cutter durability and enhanced cleaning. Matrix body bits are designed with full or partial exposure depending on formation and operating parameters. Cutter Orientation. Figure 4-155 shows the cutter orientation for typical PDC bits. The displacement o f cuttings can be affected by side and back rake orientation of the cutters. Back rake angle typically varies from 0 to -25 °. The greater the degree of back rake, generally the lower the rate of penetration, but the greater the resistance to cutting edge damage when encountering a hard section. Side rake has been found to be effective in assisting bit cleaning in some formations by mechanically directing cuttings toward the annulus. Matrix body bits allow greater flexibility in adjusting cutter orientation for best drilling performance in each formation.

800

Drilling and Well Completions

Figure 4-153. PDC bit designed for hard and abrasive formations [43A].

(Courtesy Hughes Christensen.)

I Diamond Compact

Diamond Compact

Figure 4-154. Types of cutter exposure [43A]. (Courtesy Hughes Christensen.)

Drilling Bits a n d Downhole Tools

801

Figure 4-155. Cutter orientation [43A]. (Courtesy Hughes Christensen.) IADC Fixed Cutter Bit Classification System T h e term fixed cutter is used as the most correct d e s c r i p t i o n for the b r o a d category o f n o n r o l l e r cone rock bits. T h e cutting elements may be c o m p r i s e d o f any suitable material. To date, several types o f d i a m o n d materials are used almost exclusively for fixed cutter p e t r o l e u m drilling applications. This leads to the widespread use o f the term "diamond" bits a n d PDC bits in reference to fixed cutter designs. T h e IADC Drill Bits Subcommittee began work on a new classification m e t h o d in 1985. It was d e t e r m i n e d from the outset that (1) a completely new a p p r o a c h was r e q u i r e d , (2) the m e t h o d m u s t be s i m p l e e n o u g h to gain w i d e s p r e a d acceptance a n d u n i f o r m application, yet provide sufficient detail to be useful, (3) emphasis should be placed on describing the form o f the bit, i.e., "paint a mental picture o f the design", (4) no attempt should be m a d e to describe the function o f the bit, i.e., do not link the bit to a particular f o r m a t i o n type or drilling technique since relatively little is certain yet about such factors for fixed cutter bits, (5) every bit should have a unique IADC code, a n d (6) the classification system should be so versatile that it will not be readily obsolete. T h e resultant four-character d i a m o n d bit classification code was f o r m a l l y p r e s e n t e d to the IADC Drilling Technology C o m m i t t e e at the 1986 S P E / I A D C D r i l l i n g C o n f e r e n c e . It was s u b s e q u e n t l y a p p r o v e d by the I A D C B o a r d o f Directors a n d d e s i g n a t e d to take effect c o n c u r r e n t with the 1987 S P E / I A D C Drilling Conference. A description o f the 1987 IADC Fixed Cutter Bit Classification S t a n d a r d follows [54]. Four characters are utilized in a p r e s c r i b e d o r d e r (Figure 4-156) to indicate seven fixed cutter bit design features: cutter type, body material, bit profile, fluid discharge, flow distribution, cutter size, a n d cutter density. These design traits were selected as being most descriptive o f fixed cutter bit a p p e a r a n c e . T h e four-character bit code is e n t e r e d on an IADC-API Daily Drilling R e p o r t F o r m as shown in Figure 4-157. T h e space requirements are consistent with the four-character IADC roller bit classification code. T h e two codes are readily distinguished from one a n o t h e r by the convention that d i a m o n d bit codes begin with a letter, while roller bit codes begin with a number. Each o f the four characters in the IADC fixed cutter bit classification code are f u r t h e r d e s c r i b e d as follows:

Cutter Type and Body Material T h e first character o f the fixed cutter classification code describes the p r i m a r y cutter type a n d body material (Figure 4-156).

802

Drilling and Well Completions FIRST

SECOND

FOURTH

THIRD HYDRAULIC

DESIGN I-9

D M S T O

1-9. R. X. 0

CUTTER SIZE AND DENSITY I-9.

0

- N A T U R A L DIAMOND ( M A T R I X BODY) - M A T R I X BODY PDC - STEEL BODY PDC - TSP ( M A T R I X BODY) - OTHER

Figure 4-156. Four-character classification code for fixed-cutter bits [54]. (Courtesy SPE.)

roller c o n e b i t l L ,

zT

. z c o . ~,

I,,,,o. ~114is,,,

iil, z

/'rl,,~

FK861 1132" In 2

II

~2~"

3-15" / - 18

~

"B"

~2301 .665"

N m oct

3153

6187

Nm

z.

23G'7

3f53

~,L

r~:.

I 58G

2234-

~¢

.u.

6 !. 0

~ 4 . 5"

I D

¢ u t t e r bit

Isle Mlsl41s

,~oel. ~ "

in..o. Jcr$

s

/TS~"

,"0< =o,

aLflXed

. I"R C.

I.

L I

c o IE~,IDIOSxZIF/~

=~ ImCe-esz '~ ~01 2/50

,¢30122F0

Figure 4-157. Fixed-cutter bit code entry in IADC-API Daily Report [54]. (Courtesy SPE.)

Drilling Bits and Downhole Tools

803

Five letters are presently defined: D--natural d i a m o n d / m a t r i x body, M - P D C / matrix body, S - P D C / s t e e l body, T - T S P / m a t r i x body, O - o t h e r . T h e term PDC is d e f i n e d as "polycrystalline d i a m o n d compact." T h e term TSP is d e f i n e d as "thermally stable polycrystalline" diamond. TSP materials are c o m p o s e d o f m a n u f a c t u r e d p o l y c r y s t a l l i n e d i a m o n d which has the t h e r m a l stability o f natural diamond. This is accomplished through the removal o f trace i m p u r i t i e s a n d in some cases the filling o f lattice structure pore spaces with a material o f c o m p a t i b l e t h e r m a l expansion coefficient. The distinction o f primary cutter types is made because fixed cutter bits often contain a variety o f d i a m o n d materials. Typically one type o f d i a m o n d is used as the p r i m a r y cutting element while a n o t h e r type is used as b a c k u p material.

Profile. The n u m b e r s 1 through 9 in the second character o f the fixed cutter classification code refer to the bit's cross-sectional profile (Figure 4-158). T h e

BIT PROFILE CODES DRILL BIT

CORE BIT

i

_

Lc 0= B I T D I A M E T E R

G-GAGE HEIGHT HIGH MEO LOW

O ) 3/80

",~o0:00-10

C-CONE HEIGHT H I ~ ~'1 C )l/4D

ilB

I |

MEDIUM 1/80 • C • 1/40

| }

LOW C (I/80

m

1/80 • G • 3/80 G ( I/SD

Figure 4-158. Bit profile codes for fixed cutter bits [54]. (Courtesy SPE.)

804

Drilling and Well Completions

term profile is used here to describe the cross-section of the cutter/bottomhole pattern. This distinction is made because the cutter/bottomhole profile is not necessarily identical to the bit body profile. Nine basic bit profiles are defined by arranging two profile parameters-outer taper (gage height) and inner concavity (cone height)-in a 3 x 3 matrix (Figure 4-159). The rows and columns of the matrix are assigned high, medium and low values for each parameter. Gage height systematically decreases from top to bottom. Cone height systematically decreases from left to right. Each profile is assigned a number.

BIT PROFILES

LONG TAPER DEEP CONE

I4

LONG TAPER MEDIUM CONE

LONG TAPER SHALLOW CONE "PARABOLIC"

7

5

1

MEDIUM TAPER DEEP CONE

I 7

MEDIUM TAPER MEDIUM CONE "DOUBLE CONE"

MEDIUM TAPER SHALLOW CONE "ROUNDED"

9

8

I

SHORT TAPER DEEP CONE "INVERTED" Figure

I

SHORT TAPER MEDIUM CONE

SHORT TAPER SHALLOW CONE "FLAT"

4-159. Nine basic profiles of fixed-cutter bits [ 5 4 ]

(Courtesy SPE)

Drilling Bits and Downhole Tools

805

Two versions of the profile matrix are presented. O n e version (Figure 4-158) is primarily for the use o f manufacturers in classifying their bit profiles. Precise ranges o f high, m e d i u m and low values are given. In Figure 4-158 gage height and cone height dimensions are n o r m a l i z e d to a reference d i m e n s i o n which is taken to be the bit d i a m e t e r for drill bits a n d the ( O D - I D ) for core bits. Figure 4-159 provides a visual reference which is better suited for use by field personnel. Bold lines are drawn as examples o f typical bit profiles in each category. Crosshatched areas represent the range o f variation for each category. Each of the nine profiles is given a name. For example, "double cone" is the term used to describe the profile in the center o f the matrix (code 5). The double-cone profile is typical o f many natural d i a m o n d and TSP bits. The n u m b e r 0 is used for unusual bit profiles which cannot be d e s c r i b e d by the 3 x 3 matrix o f Figure 4-158. For example, a "bi-center" bit which has an asymmetrical profile with respect to the bit pin centerline should be classified with the n u m e r a l 0.

Hydraulic Design. The numbers 1 through 9 in the third character o f the fixed cutter classification code refer to the hydraulic design o f the bit (Figure 4-160).

HYDRAULIC DESIGN

CHANGEABLE FIXED JETS PORTS

OPEN THROAT

1

2

5

R I BBED

4

5

6

OPEN FACED

7

8

9

BLADED

,ALTERNATI~ CODES

Figure

R -

RADIAL FLOW

X -

CROSS FLOW

0 -

OTHER

4-160. Hydraulic design code for fixed-cutter bits [54]. (Courtesy SPE.)

806

Drilling a n d Well Completions

T h e hydraulic design is described by two components: the type of fluid outlet and the flow distribution. A 3 x 3 matrix of orifice types and flow distributions d e f i n e s 9 n u m e r i c h y d r a u l i c d e s i g n codes. T h e o r i f i c e type varies f r o m changeable jets to fixed ports to open throat from left to right in the matrix. The flow distribution varies from bladed to ribbed to open face from top to bottom. There is usually a close correlation between the flow distribution and the cutter a r r a n g e m e n t . The term bladed refers to raised, continuous flow restrictors with a standoff distance from the bit body of more than 1.0 in. In most cases cutters are affixed to the blades so that the cutter a r r a n g e m e n t may also be described as bladed. The term ribbed refers to raised c o n t i n u o u s flow restrictors with a s t a n d o f f distance from the bit body of 1.0 in. or less. Cutters are usually affixed to most of the ribs so that the cutter a r r a n g e m e n t may also be described as ribbed. The term openface refers to nonrestricted flow arrangements. O p e n face flow designs generally have a more even distribution of cutters over the bit face than with bladed or ribbed designs. A special case is defined: the n u m b e r s 6 and 9 describe the crowfoot/water course design of most natural d i a m o n d a n d many TSP bits. Such designs are further described as having either radial flow, crossflow (feeder/collector), or other hydraulics. Thus, the letters R (radial flow), X (crossflow), or O (other) are used as the hydraulic design code for such bits.

Cutter Size and Placement Density. The numbers 1 through 9 and 0 in the fourth character of the fixed cutter classification code refer to the cutter size and placement density o n the bit (Figure 4-161). A 3 x 3 matrix of cutter sizes a n d placement densities defines 9 n u m e r i c codes. The placement density varies from light to m e d i u m to heavy from left to right in the matrix. The cutter size varies from large to m e d i u m to small from top to b o t t o m . T h e u l t i m a t e c o m b i n a t i o n of small cutters set in a high density pattern is the i m p r e g n a t e d bit, designated by the n u m b e r 0. Cutter size ranges are defined for natural diamonds based on the n u m b e r of stones per carat. PDC a n d TSP cutter sizes are defined based o n the a m o u n t of usable cutter height. Usable cutter height rather than total cutter height is the functional measure since various a n c h o r i n g a n d attachment methods affect the "exposure" of the cutting structure. The most c o m m o n type of PDC cutters, which have a diameter that is slightly more than -~ in., were taken as the basis for d e f i n i n g m e d i u m size synthetic d i a m o n d cutters. Cutter density ranges are not explicitly defined. The appropriate designation is left to the j u d g m e n t of the m a n u f a c t u r e r . I n many cases m a n u f a c t u r e r s b u i l d "light-set" a n d "heavy-set" versions of a standard product. These can be d i s t i n g u i s h e d by use of the light, m e d i u m , or heavy d e s i g n a t i o n which is encoded in the fourth character of the IADC fixed cutter bit code. As a general guide, bits with m i n i m a l c u t t e r r e d u n d a n c y are classified as h a v i n g light placement density and those with high cutter redundancy are classified as having heavy placement density. Examples of Fixed-Cutter Bits ClassificaUon Figure 4-162 shows a natural d i a m o n d drill bit which has a long outer taper and m e d i u m i n n e r cone, radial flow fluid courses, a n d five to six stones per carat (spc) diamonds set with a m e d i u m placement density. Using the definitions in Figures 4-156, 4-158, 4-159, and 4-160, the characteristics of this bit are coded D 2 R 5 as follows:

Drilling Bits a n d Downhole Tools

807

CUTTER SIZE AND DENSITY lisht

DENSITY medium

heavy

SIZE

"',"

m.,,oo •m.,,

1 4 7

2 5 8

3 6 9

-- imprqnsted

CLII"I'EIRSIZE: NAI1JRALDIAMONDS SYNTHETICDIAMONDS RANGES stone= per carat uuble cutter h e i s t iarlpe <3 >5,/8" medium

3-7

~V4B-5/8"

smell

>7

< ~/B"

CUTTERDENSITY IS DL'TE~MIN£D BY MANUFACTURER

Figure

4-161. Code of cutter size and placement [54].

Cutter/Body Type Bit Profile Hydraulic Design Cutter Size/Density

(CourtesySPE.)

D--natural diamond, matrix body 2--long taper, medium cone R--open throat/open face radial flow 5--med. cutter size, med. placement density

Figure 4-163 shows a steel body PDC bit with standard-size cutters lightly set o n a deep i n n e r cone profile. This bit has c h a n g e a b l e nozzles a n d is best d e s c r i b e d as h a v i n g a r i b b e d flow p a t t e r n a l t h o u g h t h e r e are o p e n face characteristics near the center a n d bladed characteristics near the gage. T h e IADC classification code in this case is S 7 4 4. Figure 4-164 shows a steel body core bit with a long-taper, stepped profile fitted with impregnated natural d i a m o n d blocks as the primary cutting elements. T h e bit has no i n n e r cone. Since there is no specific code for the n a t u r a l d i a m o n d / s t e e l body combination, the letter O (other) is used as the cutter t y p e / body material code. The profile code 3 is used to describe the long outer taper with little or no i n n e r cone depth. The hydraulic design code 5 indicates a fixed

808

DriXi~g a~ld WcH (2om~ietio~s

Natu~a~ . . . . . Diamond Cubers / /

D2R5

.... ",\

TaperedDouble ConeProfile

Medium Stone S~ze(5~6SPC) and MediumSet

RadiN Row Hydraulics

Figure 4-162. Example of natural diamond bit with radial flow hydraulic design [54]. (Courtesy SPE.)

Stee~Body o - - - ~ P~}C

$744

........... Med~omSize Cutters with

Light Cutter oensit~

~nve~ed / ' / / / P~ofi~e

'\ Ribbedwith Chat e Nozzles

Figure 4-163. Example of steel body PDC bit with inverted profile [54].

(Courtesy SPE.)

Drilling Bits and Downhole Tools

°o

WITH NATUR~

°'

~N~g~ATg~ CUTTER|

809

0350

/

LONG T ~ R P~QF ILE

\..

~ ~SBEO WlT~ POAT$

Figure 4-164. Example of steel body impregnated core bit with face discharge flow [54]. (Courtesy SPE.)

port, r i b b e d design. Finally, the n u m b e r 0 is used for i m p r e g n a t e d n a t u r a l d i a m o n d bits. Therefore the complete IADC classification code for this fixed cutter bit is 0 3 5 0. Although the classification code for this bit does not explicitly indicate the cutter type and body material, it can be inferred from the rest of the code that this is an i m p r e g n a t e d n a t u r a l diamond, n o n m a t r i x body bit, in which case steel is the most likely body material.

Dull Grading for Fixed Cutter Bits The section describes the first IADC standardized system for dull g r a d i n g n a t u r a l diamond, PDC, and TSP (thermally stable polycrystalline diamond) bits, otherwise k n o w n as fixed cutter bits [55]. The new system is consistent with the recently revised dull grading system for roller bits. It describes the condition of the c u t t i n g s t r u c t u r e , the p r i m a r y (with l o c a t i o n ) a n d s e c o n d a r y dull characteristics, the gage condition, and the reason the bit was pulled. The format of the dull grading system is shown in Figure 4-165. For completeness, Figure 4-165 contains all of the codes n e e d e d to dull grade fixed cutter bits and roller bits. Those codes which apply to fixed cutter bits are in boldface. Eight factors about a worn fixed cutter bit can be recorded. The first four spaces are used to describe the cutting structure. In the first two spaces, the amount of cutting structure wear is recorded using the linear scale 0 to 8, based on the initial useable cutter height. This is consistent with g r a d i n g tooth wear

810

Drilling a n d Well Completions

c - Cone N - Nose (Row) T - Taper S - Shoulder G - Gauge A- All Areas/Rows M - Middle Row H - Heel Row

= I - In Gauge 1/16 - 1/16" Undergauge 2/16 - 1/8" Undergauge

Cutting Structure Inner Rows

Outer Rows

I Dull Char.

Location

B

G

Brng/ Seals

Gauge, 1/16J

~/~emarks her Char.

Reason Pulled

i o - No Wear Nonsealed Bearings 0 - No Life Used

8 - No Usable Cutting Structure

8 - All Life Used

BC* - Broken Cone BT :en Teeth/Cutters BU - Balled Up CC* - Cracked Cone CD* - Cone Dragged CI interference CR - Cored CT - Chipped Teeth/Cutters ER - Erosion FC CrestedWear HC - Heat Checking JD ~Damage LC* t Cone LN Nozzle LT - Lost Teeth/Cutters OC - Off-Center Wear PB - Pinched Bit PN - Plugged Nozzle/Flow Passage RG - Rounded Gauge RO - Ring Out SD [tail Damage SS Sharpening Wear TR - Tracking WO - Washed Out-Bit WT - Wom Teeth/Cutters NO - No ,,lajor/Other Dull Characteristics

Sealed Bearings E - Seals Effective F - Seals Failed X - Fixed Cutter Bits

BHA - Change Bottomhole Assembly DMF - Downhole Motor Failure DSF - Drill String Failure DST - Drill Stem Test DTF - Downhole Tool Failure LOG - Run Logs RIG - Rig Repair CM - Condition Mud CP - Core Point DP - Drill Plug FM - Formation Change HP - Hole Problems HR - Hours PP - Pump Pressure PR - Penetration Rate TD - Total Depth/Csg. Depth TQ - Torque TW - Twist-Off WC - Weather Conditions WO - Washout-Drill String

*Show Cone Number(s) Under Location.

Figure bits

4-165.

[55].

IADC

bit

dull

grading

codes--bold

characters

for

fixed-cutter

(CourtesySPE.)

o n roller bits. The a m o u n t of cutter wear represented by 0 through 7 is shown schematically in Figure 4-166. A n 8 means there is no cutter left. This same scale is to be used for TSP and n a t u r a l d i a m o n d bits, with 0 m e a n i n g no wear, 4 m e a n i n g 50% wear, and so forth. The first two spaces of the dull g r a d i n g format are used for the i n n e r twothirds of the bit radius a n d the outer one-third of the bit radius, as shown

Drilling Bits and Downhole Tools INNER AREA

215 RADIUS

811

OUTER AREA 1/3 RADIUS

Figure 4-166. Schematics of cutters wear [55]. (Courtesy SPE.)

schematically in Figure 4-166. W h e n g r a d i n g a dull bit, the average a m o u n t of wear in each area should be recorded. For example, in Figure 4-166 the five cutters in the i n n e r area would be graded a 2. This is calculated by averaging the grades of the individual cutters in the i n n e r area as follows: (4+3+2+1+0)/5=2. Similarly, the grade of the outer area would be a 6. O n an actual bit the same procedure would be used. Note that for a core bit, the centerline in Figure 4-166 would be the core bit ID. The third space is used to describe the primary dull characteristic of the worn bit, i.e., the obvious physical change from its new condition. The dull characteristics which apply to fixed cutter bits are listed in Figure 4-165. The location of the p r i m a r y dull characteristic is described in the fourth space. There are six choices: cone, nose, taper, shoulder, gauge, and all areas. Figure 4-167 shows four possible fixed cutter bit profiles with the different areas labeled. It is recognized that there are profiles for which the exact boundaries between areas are debatable and for which certain areas may not even exist. Notice that in the bottom profile there is no taper area shown. However, using Figure 4-167 as a guide, it should be possible to clearly define the different areas on most profiles. The fifth space will always be an "X" for fixed cutter bits, since there are no bearings. This space can be used to distinguish dull grades for fixed cutter bits from dull grades for roller bits. The measure of the bit gauge is recorded in the sixth space. If the bit is still in gauge, an "I" is used. Otherwise, the a m o u n t the bit is undergauge is noted to the nearest ~6 of an inch. The seventh space is for the secondary dull characteristic of the bit, using the same list of codes as was used for the primary dull characteristic. The reason

812

Drilling and Well C o m p l e t i o n s

LIaR R

O EE 1RNOs\ET.t:.o I c oERN

/ 2 H~LI~R LIaR

/NOs~

\ ~

Figure 4-167. Locations of wear on fixed-cutter bit [55]. (Courtesy SPE.)

POST OR STUD GUTTERS

NO WEAR

WORN BROKEN LOST CUTTER CUTTER CUTTER (WT} (BT) (LT)

LOST CUTTER {LT)

CYLINDER GUTTERS

NO WEAR

WORN CUTTER (WT)

LOST CUTTER ( L T)

LOST CUTTER (LT}

Figure 4-168. Schematic of common dull characteristics [55]. (Courtesy SPE.)

the bit was pulled is shown in the eighth space using the list o f codes shown in Figure 4-165.

Downhole Tools Downhole drilling tools are the c o m p o n e n t s of the lower part of a drill string used in n o r m a l drilling operations such as the drill bits, drill collars, stabilizers, shock absorbers, hole openers, u n d e r r e a m e r s , drilling j a r s as well as a variety o f drill stem subs.

Drilling Bits and Downhole Tools

813

As drill bits, drill collars and drill stem subs are discussed elsewhere this section regards shock absorbers, jars, u n d e r r e a m e r s , and stabilizers.

Shock Absorbers Extreme vertical v i b r a t i o n t h r o u g h o u t the drill string are caused by hard, b r o k e n or changing formations, and the drilling bit chafing against the b o t t o m f o r m a t i o n as it rotates. In shallow wells, the drill string transmits the v i b r a t i o n oscillations all the way to the crown block o f t h e drilling rig. T h e affect can be devastating as welds fail, seams split and drill string connections break down u n d e r the accelerated fatigue c a u s e d by the vibrations. In d e e p holes, these v i b r a t i o n s are rarely n o t i c e d d u e to elasticity and s e l f - d a m p e n i n g effect o f the l o n g drill string. Unfortunately, the d a n g e r o f fatigue still goes on and has resulted in many fishing operations. T h e drill string vibration dampeners are used to absorb and transfer the shock o f d r i l l i n g to the drill collars where it can be b o r n e without d a m a g i n g or destroying other drill string equipment. Their construction and design vary with each manufacturer. To effectively absorb the vibrations i n d u c e d by the drill bit, an e l e m e n t with a soft spring action and g o o d d a m p e n i n g characteristics is required. T h e r e are six basic spring elements used: (1) vulcanized elastometer, (2) elastomeric element, (3) steel wool, (4) spring steel, (5) Belleville steel springs, (6) gas compression.

Types of Shock Absorbers. T h e r e are e i g h t c o m m o n l y u s e d c o m m e r c i a l shock absorbers.

Drilco Rubber Type. See Figure 4-169 and Table 4-102 [56]. Shock is a b s o r b e d by an e l a s t o m e t e r s i t u a t e d b e t w e e n the i n n e r a n d o u t e r barrels. This shock absorbing element is vulcanized to the barrels. T h e torque has to be t r a n s m i t t e d from the outer into the i n n e r barrel. This tool is able to absorb shocks in axial or in radial directions. T h e r e is no n e e d to absorb shocks in the torque because the drill string itself acts like a very g o o d shock a b s o r b e r so the critical shocks are in axial directions. These tools cannot be used at t e m p e r a t u r e s above 200°F. T h o u g h they p r o d u c e a small stroke the d a m p e n i n g effect is g o o d [56].

Christensen Shock-Eze. See Figure 4-170 [57]. A double-action v i b r a t i o n and shock a b s o r b e r employing Belleville spring elements are i m m e r s e d in oil. T h e tool features a spline assembly that transmits high torque loads to the bit through its outer tube, while the inner assembly absorbs vibration through a series o f steel-disc springs. The spring system works in both suspension and compression. T h e high shock-absorbing capabilities o f this tool are attained by compression o f the stack o f springs within a stroke o f five inches. T h e alternating action o f the p a t e n t e d s p r i n g a r r a n g e m e n t p r o v i d e s a wide working range, u n d e r all possible c o n d i t i o n s o f thrust and m u d pressure drop. Placement of Shock Absorber in Drill String. Many o p e r a t o r s have their own way o f placing shock absorbers in the drill string (see Figure 4-171) [57]. In general, the o p t i m u m shock absorbing effect is o b t a i n e d by r u n n i n g the tool as near to the bit as possible. W i t h no deviation expected, the tool should be installed immediately above the bit stabilizer as shown in Figure 4-171C. In holes with slight deviation problems, the shock a b s o r b e r could be r u n on top o f the first or second string stabilizer. For situations where there are severe

814

Drilling and Well Completions

LY

~CE

~C

'RE

r~

~B

Figure 4-169. Drilco rubber-spring shock dampener. (Courtesy Smith /nternationa/, /nc.)

Drilling Bits and Downhole Tools

815

Table 4-102 Drilco Rubber Spring Shock Dampener Model "E"* Body SpeelflcMIons Nominal Size Tool (A)

•Suggested Hole Size Recommended for Best Performance

~

Main

Bore

Body Bore

End Conn.

OD (B)

S

M

12 10 9 8 7 671,

1 7 ~ thru 30 121/4thru 15 9-~ thru 12V4 8Y2thru 11 7"tA~thtu9 6~'4 thru 9

21~e 21~'Is 21~s 21~'1s 21/4 2~/4

21~e 21/4 2V4 2~/4 2 1~/2

Specify

To Be Specified Same OD As Drill Collar

160 148 149 145 143 144

38 23 23 23 23 23

Size and Type

R

Approx. Complete Weight (Ib)

t-,Joint Center Packing Joint Makeup Torque (fl-lb)

126 116 116 112 ~ 111 tll

3070 2050 1635 1400 1100 890

70,000 55,000 41,000 35,000 27,000 20,000

Misc. Lengths

Nell: I. All dimensions are given in inches, unless otherwise stated. "2. Recommended for optimum too} life.

*Courtesy Smith International, Inc.

deviation problems, the shock absorber should be place as shown in Figures 4-171B and 4-171D. For turbine drilling, it is r e c o m m e n d e d that the shock absorber be placed on top of the first stabilizer above the turbine as in Figure 4-171A.

Jars Jars provide an upward or downward shock (or jar) to the entire drill string. Early attempts to recover stuck drill pipe motivated the development of jars.

Types of Jars. There are two general classes of jars: fishing jars and drilling jars. A fishing jar is used to free stuck drill string, and is added to the drill string only when the string becomes stuck. The drilling jar is used as a part of the drill string to work any time it is needed. With m o d e r n drilling requiring more safety and less cost per foot, it has become more economical to use drilling jars. In areas where possible sticking conditions exist, the drilling jar is ready to free a stuck pipe through calculated string over-pull or slack-off. The jars are used immediately when the string becomes stuck, which prevents excessive downtime and costly tripping. Unlike the fishing jar, the drilling jar has the additional function of transmitting the high amount of drilling torque to the bit.

Drilling Jar Design. The jarring and bumping characteristic of drilling jars is determined by their specific type of release elements and stroke. There are three basic types of release elements: (1) hydraulic, (2) mechanical, and (3) a combination of hydraulic and mechanical. Hydraulic mechanism employs a sleeve, or valve that is pulled through a restricted area that allows only a small amount of hydraulic oil to pass through. Once the sleeve, or valve passes through the restricted area and enters the larger chamber, it is free to travel upwards until reaching the anvil that creates a sudden stop and sends a shock t h r o u g h o u t the string. Mechanical mechanisms involve the following types of dynamic action: 1. Adjustable spring pressure against locking system. 2. T-slots system. A combination of upward overpull or string weight, and right-hand torque is required. W h e n torque is released, shots disengage for jarring.

816

Drilling and Well Completions

SPLINE C~P

r INSERT C.E SPLtN£

REL I

:'VILLE SPRINGS

~EL 2' .~"N~TING PISTON

Figure 4-170. Christensen's Shock Eze. (Courtesy Hughes Christensen.)

Drilling Bits and Downhole Tools

Drillpipe

~

Drillpipe ~

Drillpipe -...

817

- 600 Drillpipe CrossoverSub

t

(ft)

MasonJar

- 570

Drill Collar MasonJar

135

MasonJar m Shock-Eze

120

MasonJar Collar

90

-- Stabilizer

-Rockyback*r~'--Rockyback A

B

C

-

60

-

30

~Rockyback D

Figure 4-171. Recommended placement of the Shock Eze. (Courtesy Hughes

Christensen.)

3. J-slots system. The slots will roll out with enough overpull or string weight. Sets of springs apply lateral pressure holding mandrel in place. 4. Firing racks system. A lateral pressure is applied by adjusting racks. Angle on firing racks give it a 2:1 release factor when overpull or string weight is applied.

818

Drilling and Well Completions

Types of Drilling Jars. There are two types commonly used commercial drilling jars, combination of hydraulic (upward) and mechanical (downward) motion, and purely mechanical action. The examples of both types follow. C h r i s t e n s e n - M a s o n Jar. (See Figure 4-172 and Table 4-103 [57].) This is a combination tool, offering possibility to jar upwards hydraulically and to bump downward mechanically. The jar is equipped with a special releasing (locking) mechanism, so that the jar cannot be fired upwards until the locking system has been released. It has a 6-in. jarring stroke upwards and 30-in. for downward bumping [57].

Hevi-Hitter TM Christensen Jar. (See Figure 4-173 [57A].) This is a mechanical drilling jar with firing racks system applied. Its jar force is constant regardless of torque applied.

TOOLASSE~SLE=>(OPEN) OUTERTUBE

INNERTUBE FlexJolnt--~

BumpingNut MaleSpline

SealCap~

FemaleSpline--

CompensatingPIston~ (upper)

Bowl1

mMandre!1 Valve~ ~Mandrsl 2

CompensatingPiston(lower) Bowl2 BottomSUB--

Figure

LockingPiston--~_1~Ma~dreI 3 PackingRingBushlng.-~

4-172. Christensen's mason drilling jar. (Courtesy Hughes Christensen.)

Drilling Bits and Downhole Tools

819

Table 4-103 C h r i s t e n s e n ' s M a s o n Drilling J a r

O.D.

I.D.

Max. Jarring load

Toot Weight

Inch

Inch

Ibs

Ibs

4~I.

2

80.000

1,100

6'/,

21/,

165,0(30

1¸8oo

7'1=

2'/z

165,000

3.300

8'/,

2'/z

190.000

3.900

9'/z

21=/,,

190.000

5.000

11 '/.

2'~/~.

250,000

Z.000

Courtesy Hughes Christensen.

Bxtemion Shaft

Lower Hot~

Torque Shaft

Cam Shaft

I

Lower Conn.

] Center Housing

INNER SHAft ASSEMBLED

om~

SHAFT ASSEMBLED

Figure 4-173. Hevi-HitterTM mechanical drilling jar.

Top Box Conn.

Drive Shaft

ILl

t

~ Con~

Upper

..... t

Housi~

(Courtesy Hughes Christensen.)

Included in the drill string, the Hevi-Hitter jar can fire either upward or downward. The jarring force, which can exceed 700,000 pounds on the larger sizes, can be controlled from the surface by applying and holding right-hand torque to increase impact, and by applying and holding left-hand torque to decrease impact. Because the Hevi-Hitter jar recocks automatically, jarring operations can proceed swiftly until the stuck pipe is free. Various impact forces can be generated dependant upon weight of drill collars (or heavy weight drill pipe) above the jars and the value of surface pull, as shown in Table 4-104 [57A]. Underreamers

The term "underreaming" has been used interchangeably with "hole opening." Underreaming is the process of enlarging the hole bore beginning at some point below the surface using a tool with expanding cutters. This permits lowering the tool through the original hole to the point where enlargement of the hole is to begin.

820

Drilling and Well C o m p l e t i o n s

Table 4-104 Hevi-Hitter T M Jar Impact Forces (1,000 Ib/ft) [57A] Heavy-Weight DrillPipe or DrillCollarWeightAboveJars(Ibs. x l,000)

~" Q o c~ •,x

3 4 5 6

•~ .E ._m ¢B

7 8 9 10 11 12 13 14 15 16

~. ¢B > 0 .~ = n

4

6

8

10

12

14

16

18

20

45 60 75 90 105 120 135 150 165 180 195 210 225 240

68 90 113 135 158 180 202 225 247 270 229 315 337 359

90 120 150 180 210 240 270 300 330 359 389 419 449 479

113 150 187 225 262 300 337 374 412 449 487 524 562 599

135 180 225 270 315 359 404 449 494 539 584 629 674 719

157 210 262 315 367 419 472 524 576 629 681 733 786 838

180 240 300 359 419 479 539 599 659 719 778 838 898 958

202 270 337 404 472 539 606 674 741 808 876 943 1010 1078

225 300 374 449 524 599 674 748 823 898 973 1048 1122 1197

Courtesy Hughes Christensen.

Hole o p e n i n g is considered as o p e n i n g or enlarging the hole from the surface (or casing shoe) downward using a tool with cutter arms at a fixed diameter. Thus, the p r o p e r n a m e for the tools with e x p a n d a b l e cutting arms is underreamers. The cutting arms are collapsed in the tool body while r u n n i n g the tool in the hole. Once the required d e p t h is reached, mud circulation pressure moves the cutters o p e n i n g for drilling o p e r a t i o n . A d d i t i o n a l pressure d r o p across the u n d e r r e a m e r orifice gives the o p e r a t o r positive indication that the cutter arms are e x t e n d e d fully and the tool is u n d e r r e a m i n g at full gauge.

Underreamer D e s i g n . T h e r e are two basic types o f u n d e r r e a m e r s : (1) roller cone rock-type u n d e r r e a m e r s and (2) drag-type u n d e r r e a m e r s . T h e roller cone rock-type underreamers are designed for all types o f forma-tions d e p e n d i n g upon the type o f roller cones installed. T h e drag-type under-reamers are used in soft to m e d i u m formations. B o t h types can be e q u i p p e d with a bit to drill a n d u n d e r r e a m simultaneously. This allows for four d i f f e r e n t c o m b i n a t i o n s o f u n d e r r e a m e r s as shown in Figure 4-174 [58]. N o m e n c l a t u r e o f various underr e a m e r designs are shown in Figures 4-175, 4-176, a n d 4-177 [58]. Underreamer Specifications. Table 4-105 [58] shows example specifications for nine models o f Servco roller cone rock-type u n d e r r e a m e r s . Table 4-106 contains example data for four models o f Servco drag-type u n d e r r e a m e r s [58]. Underreamer Hydraulics. Pressure losses across the u n d e r r e a m e r nozzles (orifice) are shown in Figures 4-178 and 4-179 [58]. The shaded area represents the r e c o m m e n d e d p r e s s u r e d r o p r e q u i r e d for cutters to fully o p e n . T h e s e pressure d r o p g r a p h s can be used for pressure losses calculations (given p u m p output and nozzles) or for orifice (nozzle) selection (given p u m p output and pressure loss required).

Drilling Bits and Downhole Tools

Rock Type Und~r~m~

Roek~DrHi~ng Type Und

D~oType Und~m~

8£1

~oSt~ Und~r~m~

Figure 4-174. Types of underreamers. (Courtesy Smith Intemational, Inc.)

822

Drilling and Well Completions

9= Figure 4-175. Rock-type underreamer nomenclature. (Courtesy Smith International, Inc.)

Figure 4-176. Rock-drilling underreamer nomenclature. (Courtesy Smith International, Inc.)

Figure 4-177. Drag-type underreamer nomenclature (open arms). (Courtesy Smith International, Inc.)

Drilling Bits and Downhole Tools

823

Table 4-105 Rock-type Underreamers (Servco) [58] Through Casing, Inches

Underreamer Body Dia., Inches

¢1/2 5-112 7 7-5/8 8-5/8 9-5/8 10-3/4 13-3/8

3-518 4-1/2 5°3/4 6 7-1/4 8-1/4 9-1/2 11-3/4

18-5/8

14-3/4

Top Hole Opening Connections, Dimensions API Reg. Pin Inches 2-3/8 2-7/8 3-1/2 3-1/2 ¢1/2 ¢1/2 6-5/8 6-5/8 6-5/8

4-3/4 through 6-112 6 through 9 8 through 11 8 through 13 9 through 14 10 through 15 13 through 18 15 through 22 22 through 28

Courtesy Smith International, Inc.

Ta ble 4-106 Drag-type Underreamers (Servco) [58] Specifications Body Dia. Top Conn. Length (shoulder) Expanded Dia. (max.) Standard Orifice

57DP

Model Number 72 DP 95DP

110DP

5-3/4" 3-1/2"' Reg. Pin 66" 16"

7-1/4"' 4-112" Reg. Pin 71" 22"

9-1/2"' 6-5/8" Reg. Pin 57" 28"

11"' 6-518" Reg. Pin 57" 30"

FIo-Tel

FIo-Tel

3/4"

3/4"

Courtesy Smith International, Inc.

Stabllizers

Drill collar stabilizers are installed within the column of drill collars. Stabilizers guide the bit straight in vertical-hole drilling or help building, d r o p p i n g , or maintaining hole angle in directional drilling. T h e stabilizers are used to 1. 2. 3. 4. 5. 6.

provide equalized l o a d i n g on the bit prevent wobbling of the lower drill collar assembly minimize bit walk minimize b e n d i n g a n d vibrations that cause tool j o i n t wear prevent collar contact with the sidewall o f the hole minimize keyseating a n d differential pressure.

T h e c o n d i t i o n called "wobble" exists if the bit centerline does not rotate exactly parallel to a n d on the hole centerline so the bit is tilted.

Drilling and Well Completions

824

ORIFICE¢o ~ ~ ~ SIZE ~ ~ ,,- ~ ORIFICE AREA

~ ~

.110 .150 .196 .269 .307

¢.0 "~."-

~

¢.0 ,,-

',-

~

~

~--" .371

.442

~--" .518

~0

ao .785

.601

994

500

400

a.. 300 e~ e~

200 LLJ

100

0

100

200

300

400

500

600

700

GALLONS PER MINUTE Figure 4-178. Pressure drop across underreamer (rock-type or drag-type underreamer with one nozzle). (Courtesy Smith /ntemational, /nc.)

$1ZEOF3EQUAL 3 13 7 I s ORI~CES IN BIT. i ~ I"6 ~

.=..

1 ~

17 9 19 3"~ I"7o ~

5 •

"J1 ~

11 I-6

23 ~

3

sO0

oo

4OO

4OO

300

3oo

2OO

2OO

I00

I00

%

~oo

2

~ ~ "~ "~ GALLONS PER MINUTE

T'~

~

Figure 4-179. Pressure drop across underreamer (rock drilling underreamer with three nozzles). (Courtesy Smith /ntemational, /nc.)

~'~

Drilling Bits and Downhole Tools

825

Stabilizer Design. There are four commonly used stabilizer designs.

Solid-Type Stabilizers. (See Figure 4-180.) These stabilizers have no moving or replaceable parts, and consist of mandrel and blades that can be one piece alloy steel (integral blade stabilizer) or blades welded on the mandrel (weld-on blade stabilizer). The blades can be straight, or spiral, and their working surface is either hardfaced with tungsten carbide inserts or diamonds [57,58]. Replaceable-Blades Stabilizers. (See Figure 4-181 [58A].) These stabilizers can maintain full gauge stabilization. Their blades can be changed at the rig with hand tools; no machining or welding is required. Sleeve-Type Stabilizers. (See Figure 4-182.) These stabilizers have replaceable sleeve that can be changed in the field. There are two types o f sleeve-type stabilizers: the rotating sleeve-type stabilizer (Figure 4-182A [58]) and the n o n r o t a t i n g sleeve-type stabilizer (Figure 4-182B [59]). Rotating sleeve-type stabilizers have no moving parts and work in the same way as solid-type stabilizers. Nonrotating sleeve-type stabilizers have a nonrotating rubber sleeve sup.ported by the wall o f the borehole. The rubber sleeve stiffens the drill collar string in packed hole operations just like a bushing. Reamers. (See Figure 4-183 [59].) Reamers are stabilizers with cutting elements embedded in their fins, and are used to maintain hole gage and drill out doglegs and keyseats in hard formations. Because of the cutting ability of the reamer, the bit performs less work on maintaining hole gauge and more work on drilling

A 8 C D !ntegra~ B!ade WeldOn Blade Big Bear T M Nea~-B{t Diamond Near-Bit Stabilizer: Hardfacing StabHizer~Alloy steel Stabi~izer~Granular S~a~i~zer with tungsten carbide hardfac~n9 (Se~co) tungsten carbide (Christensen) hardfacing (Set, co) compact& (Servco)

Figure 4-180, Solid-type stabilizers. (Courtesy Smith International and Baken Hughes INTEQ)

826

Drilling and Well Completions

Figure 4-181. Replaceable-blades stabilizers. (Courtesy Smith International, Inc.)

ahead. Reamers can be used as near-bit stabilizers in the bottomhole assembly or higher up in the string. T h e r e are basically three types of reamer body: • Three-point bottom hole reamer. This type of reamer is usually r u n between the drill collars and the bit to ensure less reaming back to bottom with a new bit. • Three-point string reamer. The reamer is r u n in the drill collar string. This reamer provides stabilization of the drill collars to drill a straighter hole in crooked hole country. W h e n r u n in the string, the reamer is effective in reaming out dog-legs, keyseats and ledges in the hole. • Six-point bottom hole reamer. This type of reamer is r u n between the drill collars and the bit when more stabilization or greater reaming capacity is required. Drilling in crooked hole areas with a six-point reamer has proven to be very successful in preventing sharp changes in hole angles.

Application of Stabilizers. Figure 4-184 [16] illustrates t h r e e a p p l i c a t i o n s of stabilizers, p e n d u l u m , fulcrum, and lock-in (stiff) hook-up. T h e stiff hookup consists of three or more stabilizers placed in the bottom 50 to 60 ft of drill collar string. In mild crooked hole conditions, the stiff hookup will hold the deviation to a m i n i m u m . In most cases, deviation will be held below the m a x i m u m acceptable angle. In severe conditions, this hookup will slow the rate of angle buildup, allowing more weight to be r u n for a longer time. This m e t h o d prevents sudden increases or decreases of deviation, making dog-legs less severe and decreasing the probability of subsequent keyseats and other undesirable hole conditions. The stiff hookup is beneficial only until the m a x i m u m acceptable angle is reached. T h e p e n d u l u m p r i n c i p l e should t h e n be used.

Drilling Bits and Downhole Tools

827

Both Fit Sam

Outer Rubber C.Jshion

1

S Tu~

Diameter ~tee/ nse~

St w

Locks e@iece Mandrel

~nner Rubber Layer

A

Cushion S~bitizer 8

Figure 4-182. Sleeve-type stabilizers. (A) Rotating sleave-type stabilizer (Servco). (B) Grant cushion stabilizers (nonrotating sleave-type stabilizer). (Courtesy Smith International and Masco Tech Inc.)

To employ pendulum effect in directional drilling, usually one stabilizer is placed in the o p t i m u m position in the drill collar string. The position is determined by the hole size, drill collar size, angle of deviation and the weight on the bit. A properly placed stabilizer extends the suspended portion of the drilling string (that portion between the bit and the point of contact with the low side of the hole). The force of gravity working on this extended portion results in a stronger force directing the bit toward vertical so the well trajectory returns to vertical. To employ fulcrum effect one stabilizer is placed just above the bit and additional weight is applied to the bit. The configuration acts as a fulcrum forcing the bit to the high side of the hole. The angle of hole deviation increases (buildup) as more weight is applied. To employ a restricted fulcrum effect one stabilizer is placed just above the bit while second stabilizer is placed above the nonmagnetic drill collar. The hookup allows a gradual buildup of inclination with no abrupt changes. To prevent key-seating one stabilizer is placed directly above the top of drill collars. The configuration prevents drill collars wedging into a key seat during tripping out of the hole. To prevent differential sticking across depleted sands stabilizers are placed throughout the drill collar string. The area of contact between drill collars and hole is reduced, thus reducing the sticking force.

828

Drilling and Well Completions

Figure 4-183. Stabilizer/reamers; various cutters and schematics of cutter assembly. (Courtesy Masco Tech Inc.)

CONTROLLEDD R ~ HOLE"OR#.UNG

i

PENOULUM HOOK-UP

Figure 4-184. Applications of stabilizers in directional drilling [16].

Drilling Mud Hydraulics

829

DRILLING MUD HYDRAULICS Rheological Classification of Drilling Fluids Experiments p e r f o r m e d on various drilling muds have shown that the shear stress-shear r a t e c h a r a c t e r i s t i c can be r e p r e s e n t e d by o n e o f the f u n c t i o n s schematically d e p i c t e d in Figure 4-185. If the shear stress-shear rate d i a g r a m is a straight line passing through the origin o f the coordinates, the drilling f l u i d is classified as a Newtonian fluid, otherwise it is considered to be non-Newtonian. T h e following equations can be used to describe the shear stress-shear rate relationship: Newtonian f l u i d

1:=

\

dr)

(4-85)

$ C

j

Shoar.a,o

Figure 4-185. Shear stress-shear rate diagram. (a) Newtonian fluid. (b) Bingham plastic fluid. (c) Power law fluid. (d) HerscheI-Buckley fluid.

830

D r i l l i n g a n d Well C o m p l e t i o n s

B i n g h a m plastic f l u i d

"c = "Cy + ~tp

I_dv)° dr )

(4-86)

Power law f l u i d

,--K(dv) ° - dr )

(4-87)

H e r s c h e l a n d Buckley f l u i d

z = zr +

where

x

=

V

=

dr/dr = ~t = "Cy = ~tp = K = n =

\-~-r)

(4-88)

shear stress the velocity o f flow shear rate (velocity g r a d i e n t i n t h e d i r e c t i o n p e r p e n d i c u l a r to the flow d i r e c t i o n ) d y n a m i c viscosity yield p o i n t stress plastic viscosity consistency index flow b e h a v i o r i n d e x

T h e • ~t, z Y, ~t, K a n d n are u s u a l l y d e t e r m i n e d with t h e F a n n r o t a t i o n a l • P VlSCOSlmeter. Tile Herschel a n d Buckley m o d e l is n o t c o n s i d e r e d in this m a n u a l .

Flow Regimes T h e flow regime, i.e., w h e t h e r l a m i n a r or t u r b u l e n t , can b e d e t e r m i n e d u s i n g the c o n c e p t o f the R e y n o l d s n u m b e r • T h e R e y n o l d s n u m b e r , Re, is calculated in c o n s i s t e n t u n i t s from Re-

dvp ~t

where d = v = p = Ix =

(4-89)

d i a m e t e r o f the f l u i d c o n d u i t velocity o f the f l u i d density o f f l u i d viscosity

I n oilfield e n g i n e e r i n g u n i t s

Re = 928 dev~

(4-90)

Drilling Mud Hydraulics

831

where d e = equivalent diameter of a flow channel in in. v = average flow velocity in ft/s = drilling fluid specific weight in l b / g a l = drilling fluid dynamic viscosity in cp The equivalent diameter of the flow channel is defined as

de =

4 (flow cross-sectional area ) wetted perimeter

(4-91)

The flow changes from laminar to turbulent in the range of Reynolds numbers from 2,100 to 4,000 [60]. In l a m i n a r flow, the friction pressure losses are proportional to the average flow velocity. In turbulent flow, the losses are proportional to the velocity to a power r a n g i n g from 1.7 to 2.0. The average flow velocity is given by the following equations: • Flow in circular pipe

v = q 2.45d ~

(4-92)

• Flow in an a n n u l a r space between two circular pipes

v

q 2 2.45(d~2 - d~)

where q d d~ d~

= = = =

(4-93)

m u d flow rate in gpm inside diameter of the pipe in in. larger diameter of the a n n u l u s in in. smaller diameter of the a n n u l u s in in.

For non-Newtonian drilling fluids, the concept of an effective viscosity* can be used to replace the dynamic viscosity in Equation 4-89. For a Bingham plastic fluid flow in a circular pipe a n d a n n u l a r space, the effective viscosities are given as [61]. • Pipe flow

~e = ~p + 6.65 "Cyd

(4-94)

V

• A n n u l a r flow

~e = ~p = 4.99 "CY(dl - d ~ ) V

*Also called equivalent or apparent viscosityin some published works.

(4-95)

Drilling and Well Completions

832

For a Power law fluid flow, the following formulas can be used: • Pipe flow lie : ( l ' 6 v 3 n + l / n (J3 0~0. K ~ Jd / ~ n

(4-96)

• Annular flow ( 2.4v

lie

=td'~-d2

2 n + 1 1 " 200K(d I - d 2) 3n J v

(4-97)

The mud rheological properties I1 , ~v, n and K are typically calculated based upon the data from two (or more)-speed rotational vlscometer experiments. For these experiments, the following equations are applicable: P

,

•

•

~tp = 0600 - 03oo(Cp)

(4-98)

• y = 0300 - ~tv(lb/100 ft 2)

(4-99)

n = 3.32 log 0600 0300 K =

03°° (lb/100ft2s - ' ) (511)"

(4-100) (4-101)

where 0600 = viscometer reading at 600 r p m 0300 = viscometer reading at 300 r p m

Example Consider a well with the following geometric and operational data: Casing 9 ~ in., unit weight = 40 lb/ft, ID = 8.835 in. Drill pipe: 4-~ in., unit weight = 16.6 lb/ft, ID = 3.826 in. Drill collars: 6~ in., unit weight = 108 lb/ft, ID = 2¼ in. Hole size: 8-~ in. Drilling fluid properties: 0600 = 68, 0300 = 41, density = 10 lb/gal, circulating rate = 280 gpm. Calculate Reynolds number for the fluid (1) inside drill pipe, (2) inside drill collars, (3) in drill collar annulus, and (4) in drill pipe annulus. To p e r f o r m calculation, a Power law fluid is assumed. Flow behavior index (use Equation 4-100) is n = 3.32 log --68 = 0. 729 41 Consistency index (use Equation 4-101) is 41 K - - - 0.4331b/100ft2s ~7~0 (511) °-7~°

Drilling Mud Hydraulics

833

T h e average flow velocities are • Inside drill p i p e (use Equation 4-92)

v =

280 = 7. 807 ft/s (2.45)(3. 826) 2

• Inside drill collars 280 v = (2"45)(2"25) 2 - 22.575ft/s • In drill collar annulus, an o p e n hole (use Equation 4-93)

v =

28O = 4.282ft/s (2.45)(8.52 6.752 ) -

• In drill pipe annulus (in the cased hole) 28O v = (2"45)(8"8352_ 4.52 ) = 1.977ft/s The effective viscosities are • Inside drill p i p e (use Equation 4-96)

_-I~10 ~ 80~ ~ ~ 0 ~ ge

~,

3.826

+ 1/° ~°~ ~00~ 0 ~

(4)(0.729))

k,

8~0~/

~. 8---~

= 160.9 cp

• Inside drill collars

ge

:~, o > ~ > ~>~o~>+,)o~i~oo>~o~>~ ~>/ = 104.5 cp ~

~

(4)(0.729)

22.575

• In drill collar annulus (use Equation 4-97)

ge

= ( ( 2 . 4 ) ( 4 . 2 8 2 ) ( 2 ) ( 0 . 7 2 9 ) + 1 / 0 7 2 9 ( (200)(0. 4 3 3 ) ( 8 . 5 - - 6 . 7 5 ) ) = 140.1 cp ~ ~ . ~ (3)(0.729)) ~, ~..2--'-~"

• In drill p i p e annulus

g~

: ~ ~>~,~>~>~0 ~>+,/o~i~oo>~o ~>~8 8~_~ ~>/ = 233.6 cp ~, 8 . 8 3 5 - 4 . 5

(3)(0.729)

1.977

854

D r i l l i n g a n d Well C o m p l e t i o n s

R e y n o l d s n u m b e r (use E q u a t i o n 4-90) • I n s i d e drill p i p e Re = 928 (3. 826)(7. 807)(10) = 1723 (160.9) • Inside drill collars Re = 928 (2.25)(22.575)(10) (104.5)

= 4511

• In drill collar a n n u l u s Re = 928 (8.5 - 6 . 7 5 ) ( 4 . 2 8 2 ) ( 1 0 ) = 496 (140.1) • In drill p i p e a n n u l u s Re = 928 ( 8 . 8 3 5 - 4.5)(1.977)(10) = 340 (233.6)

Principle of Additive Pressures A p p l y i n g t h e c o n s e r v a t i o n o f m o m e n t u m to t h e c o n t r o l v o l u m e for a oned i m e n s i o n a l f l o w c o n d u i t , it is f o u n d that [62]

pA - ~ =

- A dP - P~'c~ - A p g c o s a dl

(4-102)

where p = fluid density A = flow area d v / d t = a c c e l e r a t i o n (total derivative) V = f l o w velocity "Cw = average wall s h e a r stress P~ = w e t t e d p e r i m e t e r g = gravity acceleration O~ = i n c l i n a t i o n o f a f l o w c o n d u i t to t h e vertical dP/dl = pressure gradient 1 = length of flow conduit For a steady-state flow, E q u a t i o n 4-102 is o f t e n w r i t t e n as an explicit e q u a t i o n for t h e p r e s s u r e g r a d i e n t . T h i s is dP P --~ = - ~

dv "cw - pv ~ - - P g cos a

(4-103)

T h e t h r e e t e r m s o n the right side are k n o w n as frictional, a c c e l e r a t i o n a l (local accelaration) and g r a v i t a t i o n a l c o m p o n e n t s o f t h e pressure gradient. Or, in o t h e r

Drilling M u d H y d r a u l i c s

835

words, t h e total p r e s s u r e d r o p b e t w e e n two p o i n t s o f a f l o w c o n d u i t is t h e sum o f t h e c o m p o n e n t s m e n t i o n e d above. Thus, AP = AP v + AP A + AP e

(4-104)

w h e r e AP v = f r i c t i o n a l p r e s s u r e d r o p AP A = accelerational pressure drop AP e = g r a v i t a t i o n a l p r e s s u r e d r o p (hydrostatic head) E q u a t i o n 4-104 expresses t h e p r i n c i p l e o f additive pressures. In a d d i t i o n to E q u a t i o n 4-104, t h e r e is t h e e q u a t i o n o f state for the d r i l l i n g fluid. Typically, water b a s e d m u d s are c o n s i d e r e d to b e i n c o m p r e s s i b l e or slightly c o m p r e s s i b l e . F o r t h e f l o w in d r i l l p i p e o r d r i l l c o l l a r s , t h e a c c e l e r a t i o n c o m p o n e n t (APA) o f the total p r e s s u r e d r o p is negligible, a n d E q u a t i o n 4-104 can b e r e d u c e d to AP = AP v + AP e

(4-105)

E q u a t i o n s 4-102 t h r o u g h 4-105 are valid in any consistent system o f units.

Example T h e f o l l o w i n g data are given: • • • • •

Pressure d r o p inside t h e drill string = 600 psi Pressure d r o p in a n n u l a r space = 200 psi Pressure d r o p t h r o u g h t h e bit nozzle = 600 psi H o l e d e p t h = 10,000 ft M u d density = 10 l b / g a l

Calculate • bottomhole pressure • p r e s s u r e inside t h e string at t h e bit level (above t h e nozzles) • drill p i p e p r e s s u r e B e c a u s e t h e f l u i d f l o w in a n n u l a r space is u p w a r d , t h e total b o t t o m h o l e p r e s s u r e is e q u a l to t h e hydrostatic h e a d plus t h e p r e s s u r e loss in t h e annulus. B o t t o m h o l e p r e s s u r e Pb . . . . . (psi), Pbottom =

(0.052)(10)10,000 + 200 = 5,200 psi

N o t e that w h e n t h e c i r c u l a t i o n is s t o p p e d , t h e f r i c t i o n p r e s s u r e loss in a n n u l a r space d i m i n i s h e s to zero a n d t h e b o t t o m h o l e p r e s s u r e is r e d u c e d to 5,000 psi. Pressure inside t h e string above the nozzle, Pls (psi), Pis = 5200 + 1600 = 6800 psi Drill p i p e pressure, Pdp (psi), Pap = 6800 + 600 - (0.052)(10)(10,000) = 2,200 psi N o t e t h a t t h e drill p i p e p r e s s u r e is a s u m o f all t h e p r e s s u r e losses in t h e c i r c u l a t i n g system.

836

Drilling and Well Completions Friction Pressure Loss Calculations

Laminar Flow

For pipe flow of Bingham plastic type drilling fluid, the following can be used: Ap-

~pLV 'TyL 1500d 2 + 225d

(4-106)

Corresponding equation for a Power law type drilling fluid is

Ap

=I(l'6v~(3n+l~] L\--~-)k,~)]

n KL 300d

(4-107)

For annular flow of Bingham plastic and Power law fluids, respectively, ~pLv ~yL Ap = 1000(dl _ d2) 2 + 200(dl _ d2)

(4-108)

and I ( 2.4v / ( 2 n + l ) T AP=L ~ , ( d l - d 2 ) j \ T j ]

KL

300(d~-d2)

(4-109)

Turbulent Flow

Turbulent flow occurs if the Reynolds number as calculated above exceeds a certain critical value. Instead of calculating the Reynolds number, a critical flow velocity may be calculated and compared to the actual average flow velocity [60]. The critical velocities for the Bingham plastic and Power law fluids can be calculated as follows: • Bingham plastic fluid

v¢ =

1.08/~p + 1.08~//~2p + 9.256(d, - d2)2"ryp (dl - d 2 )

(4-110)

• Power law fluid

]

/(2n+l)l n/(2-n) Lkd~-d~)\ 3n )]

v¢ = [ 3.878x10~Kp v(2-n)II 2.4

(4-111)

In the case of pipe flow, for practical purposes, the corresponding critical velocities may be calculated using Equation 4-110 and 4-111, but letting d 2 = 0.

Drilling Mud Hydraulics

837

In the above equation, the critical flow velocity is in f t / m i n a n d all o t h e r quantities are specified above. In turbulent flow the pressure losses, Ap (psi), can be calculated from the Fanning equation [60]. Ap-

fyLv~ 25.8d

(4-112)

where f = Fanning factor L = length of pipe, ft T h e friction factor d e p e n d s on the Reynolds n u m b e r and the surface conditions o f the pipe. T h e r e are n u m e r o u s charts and equations for d e t e r m i n i n g the relationship between the friction factor a n d Reynolds number. T h e friction factor can be calculated by [63] f = 0.046 Re -°'~

(4-113)

Substituting Equation 4-91 (4-92), a n d 4-113 into Equation 4-112 yields [63] • Pipe flow 7.7x10

Ap =

-5T--0.8q 1.8~tv0.2L

(4-114)

d48

• A n n u l a r flow 7.7 x 10 -5--08 T g p q02 18L Ap = ( d l _ d~)S( d, + d~) 18

(4-115)

Example T h e wellbore, drill string a n d drilling f l u i d data from the previous example are used. Casing d e p t h is 4,000 ft. Assuming a drill p i p e length of 5,000 ft a n d a drill collar length of 500 ft, f i n d the friction pressure losses. • Flow inside the drill pipe T h e critical flow velocity is

I

vc -- (3.878 x 104 )(0.433) 10

]~(2-0.729)[ 2

_-10.729](2-0.729) .~

4(2)(0.7.29) + i |

= 343.54 ft/min = 5.73 ft/s Since v < vc, the flow is laminar, and Equation 4-107 is chosen to calculate the pressure loss p,.

Drilling and Well Completions

838

Ap,

: [((1.6)(468.42) "]( (3)(0. 729)+1 tl °-
° Flow inside the drill collars It is easy to check that the flow is turbulent and thus Equation 4-114 is chosen to calculate the pressure loss Ap2. Ap 2 = (7.7 x 10 -5)(10 °8)(27) 0.2(280) ~8(500) = 243.23 psi (2.25) 4.8 ° Annulus flow around the drill collars To calculate the critical velocity, Equation 4-111 was used v = c

(3"878)(104)(0"433)] 10 J

1/(2- 0.729)

[ 2.4 [ 8.5-~.75

(2)(0. 729) + 1 ~|°72~(2-°729) (3)(0.729)

J

--- 441.79 ft/min = 7.36ft/s Since v < vc, the flow is laminar and Equation 4-109 is chosen to calculate the pressure loss Ap3. [(2.4)(25.92) (2)(0.729) + 1 0.729 (0. 433)500 AP3 = [_(--ff.-5~..7--~ (3)(0.729) (300)(8.5 - 6.75) = 32.27 psi • Annulus flow around the drill pipe in the open hole section It is found from Equation 4-111 that the flow is laminar, thus Equation 4-109 can be used [(2_.4)(131.87) (2)(0.729)+ 110.729 (0.433)1000 AP4 =[_ ( 8 . 5 - 4 . 5 ) (3)(0.729) ] (300)(8.5-4.5) --- 9.51 psi * Annulus flow around the drill pipe in a cased section It is found from Equation 4-111 that the flow is laminar, thus Equation 4-109 can be used.

Drilling Mud Hydraulics [(2.4)(118.62) Ap~ = L ~ 4 . - - ~

(2)(0.729)+

839

1] 0.729 (0.433)(4000)

(3)(0.729)

J

(300)(8.835--4.5)

= 32.0 psi T h e total frictional pressure loss is Ape = 94.32 + 243.23 + 32.27 + 9.51 + 32.0 = 411.33 psi

Pressure Loss through Bit Nozzles A s s u m i n g steady-state, frictionless (due to the short length o f the nozzles) drilling fluid flow, Equation 4-102 is written 3v 3p pv-~- = ~

(4-116)

I n t e g r a t i n g Equation 4-116 assuming incompressible drilling fluid flow (P is constant) a n d after simple r e a r r a n g e m e n t s yields the pressure loss across the bit Apb(psi ) which is Ap b = p C 2

(4-117)

Introducing the nozzle flow coefficient o f 0.95 and using field system o f units, Equation 4-117 becomes

•/v2

A p b - 1,120

(4-118)

or

APb _

~/q2 10,858A2

where v = q = ~/ = A =

(4-119)

nozzle velocity in f t / s f10w rate in gpm drilling fluid density in l b / g a l nozzle flow area in in. 2

If the bit is furnished with m o r e than one nozzle, then A = A,

+

A2 + A3 + . . . A

(4-120)

where n is the n u m b e r o f nozzles, a n d de, = ~/d~ + d~ + . . . d2 where dr, is the equivalent nozzle diameter.

(4-121)

840

Drilling and Well Completions

Example A tricone roller rock bit is furnished with three nozzles with the diameters of ~,32 ~ and ~ in. Calculate the bit pressure drop if the mud weight is 10 lb/gal and flowrate is 300 gpm. Nozzle equivalent diameter is

I(9f

(10~2+(12~ 2 =0.5643in.

and the corresponding flow area is

A = ~ | ( 18.0277"~|2 = 0.2493 in. 2 4 t 32 ) The pressure loss through bit nozzles is Apb =

(10)(300) 2 10858(0.2493) 2 = 1334psi

AIR AND GAS DRILLING Types of Operations Air and natural gas have been used as drilling fluids to drill oil and gas wells since 1953. There are basically four distinct types of drilling using these fluids: air and gas drilling with no additives (often called dusting), unstable foam drilling (also called misting), stable foam drilling and aerated mud drilling [64]. Air and natural gas have also been used as drilling fluids in slim-hole-drilling mining operations, special large-diameter boreholes for nuclear weapons tests, and, more recently, in geothermal drilling operations. Air and natural gas drilling techniques are used principally because of their ability to drill in loss-of-circulation areas where mud drilling operations are difficult or impossible. These drilling fluids have other specific advantages over mud drilling fluids when applied to oil and gas well drilling operations, which will be discussed later in this section. In general, air and gas drilling techniques are restricted to mature sedimentary basins where the rock formations are well cemented and exhibit little plastic flow characteristics. Also, to varying degrees, air and gas drilling techniques are restricted to drilling in rock formations that have limited formation water or other fluids present. In the United States, air and gas drilling techniques are used extensively in parts of the southwest in and around the San Juan Basin, in parts of the Permian Basin, in Arkansas and eastern Oklahoma, in Maryland, Virginia and parts of Tennessee. Internationally, oil and gas drilling operations are carried out with air and gas drilling techniques in parts of the Middle East, North Africa and in the Western Pacific.

Air and Gas Drilling

841

Air and Gas A i r and natural gas are often used as a drilling fluid with no additives placed in the injected stream o f c o m p r e s s e d fluid. This type o f drilling is also often r e f e r r e d to as "dusting" because great dust clouds are created a r o u n d the drill rig when no f o r m a t i o n water was present. However, m o d e r n air and gas drilling operations utilize a spray at the e n d o f the blooey line to control the dust ejected from the well. Figure 4-185 shows a typical site plan for air drilling operations. In air drilling o p e r a t i o n , large compressors and usually a booster c o m p r e s s o r are u s e d to c o m p r e s s a t m o s p h e r i c air and s u p p l y the r e q u i r e d v o l u m e t r i c f l o w r a t e to the s t a n d p i p e in much the same way that m u d pumps supply m u d for drilling. T h e volumetric flowrate o f compressed air n e e d e d (which is usually stated in SCFM o f air) d e p e n d s u p o n the drilling rate, the g e o m e t r y o f the b o r e h o l e to be d r i l l e d and the g e o m e t r y o f the drill string to be used to drill the hole [64,65]. Natural gas drilling is carried out in regions where there is significant natural gas p r o d u c t i o n , and it is e x t r e m e l y useful in d r i l l i n g into p o t e n t i a l fire or explosive zones such as coal seams, or oil and gas production formations. Instead o f utilizing atmospheric air and compressing the air for supply to the standpipe, n a t u r a l gas is taken from the nearby gas collection pipeline and supplied to the standpipe, often at pipeline pressure. If high standpipe pressures are needed, a b o o s t e r is used to raise the pressure. T h e pressure n e e d e d at the standpipe, and thus the n e e d for a b o o s t e r , d e p e n d s u p o n the v o l u m e t r i c flow r a t e required, the g e o m e t r y o f the b o r e h o l e to be drilled, and the g e o m e t r y o f the drill string to be used to drill the hole [65,66]. The volumetric flowrates required for air and natural gas drilling are basically d e t e r m i n e d by the p e n e t r a t i o n rate and the g e o m e t r y o f the b o r e h o l e and drill string. T h e r e must be sufficient c o m p r e s s e d air (or gas) circulating through the drill bit to carry the rock cuttings from the b o t t o m o f the borehole. T h e actual e n g i n e e r i n g calculations to d e t e r m i n e the r e q u i r e d volumetric flowrate and various pressure calculations will be discussed later in this section.

l

l,

_

_l!J f - I

Figure 4-186. Air drilling surface equipment site plan.

842

Drilling a n d Well C o m p l e t i o n s

Unstable Foam (Mist) In o r d e r to i n c r e a s e the f o r m a t i o n water-carrying capacity o f the air a n d natural gas drilling fluids, water is often injected at the surface j u s t after the air has b e e n c o m p r e s s e d a n d p r i o r to the s t a n d p i p e (water injector is shown in Figure 4-186). A n amount o f water is injected that will saturate the compressed air when it reaches the b o t t o m o f the hole. Thus, if the water-saturated returning airflow encounters formation water, internal energy in the airflow will not be required to change the formation water to vapor. The formation water will be carried to the surface as water particles much like the rock cuttings. If only water is injected at the surface, then the drilling fluid is called "mist." Usually a surfactant is injected with the injected water. This surfactant will cause the air and water to foam. This foam, however, is not continuous (i.e., it will have large voids in the annulus section because o f the high velocity o f the returning airflow). This is the reason why this type o f drilling operation is also denoted as unstable foam.

Stable Foam Stable foam drilling o p e r a t i o n s are used when even m o r e f o r m a t i o n waterc a r r y i n g capability is n e e d e d (relative to air a n d gas a n d unstable foam). Also, stable foam provides significant b o t t o m h o l e pressure that can counter formation p o r e pressures a n d thus p r o v i d e some well control capabilities. Stable foam drilling o p e r a t i o n s provide a continuous column o f foam in the annulus from the b o t t o m o f the b o r e h o l e annulus to the back pressure valve at the e n d o f the blooey line. A i r a n d natural gas a n d unstable foam require large compressors to p r o d u c e a fixed volumetric flowrate o f air. Stable foam drilling requires far less c o m p r e s s e d air, a n d the c o m p r e s s e d air is p r o v i d e d by a flexible system. T h e air compressors used in stable foam drilling should be capable o f supplying air at various pressures a n d volumetric flowrates. In general, the back pressure valve at the e n d o f the blooey line is adjusted to ensure that a continuous foam column exists in the annulus. However, if the back pressure is too high, the foam at the b o t t o m o f the b o r e h o l e (in the annulus) will b r e a k down into the individual phases o f liquid a n d gas. Foam quality at the b o t t o m hole in the annulus should not d r o p below about 60% [67-69]. E n g i n e e r i n g calculations for determ i n i n g the a p p r o p r i a t e p a r a m e t e r s for stable foam drilling o p e r a t i o n s are quite complicated. T h e r e are a few stable foam simulation p r o g r a m s available for well p l a n n i n g [70]. T h o s e i n t e r e s t e d in stable foam e n g i n e e r i n g calculations are advised to consult service companies specializing in stable foam drilling operations.

Aerated Mud A e r a t e d m u d drilling o p e r a t i o n s are used t h r o u g h o u t the drilling industry, o n s h o r e a n d offshore. A e r a t e d m u d drilling is usually e m p l o y e d as an initial r e m e d y to loss-of-circulation problems. To a e r a t e water-based m u d or oil-based mud, air is injected into the drilling m u d flow at the surface p r i o r to the m u d entering the standpipe (primary aeration) or in the return annulus flow through an air line set with the casing string (parasite tubing aeration) [71,72]. P r i m a r y a e r a t i o n is the most c o m m o n l y used technique for a e r a t i n g mud. But because o f the high resistance to flow o f a e r a t e d liquids, as a e r a t i o n is n e e d e d at depth, parasite tubing a e r a t i o n offers a usable alternative. T h e relative advantages a n d disadvantages o f the various types o f air a n d gas d r i l l i n g o p e r a t i o n s discussed are listed as follows:

Air and Gas Drilling

843

Air and Gas (Dusting) Advantages

Disadvantages

• • • • • •

• No ability to counter subsurface pore pressure problems • Little ability to carry formation water from hole • Hole erosion problems are possible if formations are soft • Possible drill string erosion problems • Downhole fires are possible if hydrocarbons are encountered (gas only) • Specialized equipment necessary

No loss-of-circulation problem No formation damage Very high penetration rate Low bit costs Low water requirement No mud requirement

Unstable Foam (Misting) Advantages

Disadvantages

• • • • • • • • •

• Very little ability to counter subsurface pore pressure problems • No ability to carry a great deal of formation water from hole • Hole erosion problems are possible if formations are soft • Possible drill string erosion problems • Specialized equipment necessary

No loss-of-circulation problem Ability to handle some formation water No formation damage Very high penetration rate Low bit costs Low water requirement No mud requirement Low chemical additive costs Downhole fires are normally not a problem even with air

Stable Foam Advantages

Disadvantages

• No loss-of-circulation problem • Ability to handle considerable formation water • Little or no formation damage • High penetration rate • Low bit costs • Low water requirements • No mud requirements • Some ability to counter subsurface pore pressure problems

• Considerable additive (foamer) costs • Careful and continuous adjusting of proportions necessary • Specialized equipment necessary

Aerated Mud Advantages

Disadvantages

• Loss of circulation is not a big problem • Ability to handle very high volumes of formation water

• High mud pump pressure requirements • High casing/air line costs if parasite tubing is used • Some specialized equipment

844

Drilling and Well Completions

Aerated Mud (continued) Advantages

Disadvantages

• Improved penetration rates (relative to mud drilling) • Ability to counter high subsurface pore

pressure problems The listing is basically in descending order in terms of ability to counter lossof-circulation problems (i.e., air and gas being the most useful technique) and a lack of causing formation damage (i.e., air and gas cause no formation damage). The listing is in ascending order in terms of ability to carry formation water from the hole and ability to counter subsurface pore pressure. Equipment Surface and subsurface specialized equipment are required for air and gas drilling operations. Surface Equipment Figure 4-186 shows the layout of surface equipment for a typical air drilling operation. Described below are specialized surface components unique to air drilling operations. B l o o e y Line. This special pipeline carries exhaust air and cuttings from the annulus to the flare pit. The length of the blooey line should be sufficient to keep dust exhaust from interfering with rig operations. The blooey line should have no constrictions or curved joints. B l e e d - O f f Line. This line bleeds off pressure within the standpipe, rotary base, kelly and the drill pipe to the depth of the top float valve. The bleed-off line allows air (or gas) under pressure to be fed directly to the blooey line.

Air (or Gas) J e t s . The jets are often used when there is the possibility that relatively large amounts of natural gas may enter the annulus from a producing formation as the drilling operation progresses. The air (or g a s ) j e t s pull a vacuum on the blooey line and therefore on the annulus, thereby keeping gases in the annulus moving out of the blooey line.

Compressors and Boosters. In a typical air drilling operation the compressors supply compressed air from the atmosphere for discharge to the standpipe or for the boosters. For air drilling operations, these primary compressors are usually multistage machines that compress atmospheric air to about 200-300 psig. Air drilling operations require a fixed volumetric rate of flow, thus compressors are usually rated by the capacity at sea level conditions, or the actual cubic feet per minute of higher altitude atmospheric air they will operate with. In addition, these primary compressors are also rated by the maximum output air pressure. This is somewhat confusing since some of the primary compressors used in the field are fixed ratio screw-type compressors. These primary compressors produce only their maximum or fixed output pressure.

Air and Gas Drilling

845

The booster, which can compress air coming from the primary compressors to higher levels (i.e., on the order of 1,000 psig or higher), is always a pistontype compressor capable of variable volumetric flow and variable pressure output. The volumetric rate of flow requirements for air drilling operations and unstable foam drilling operations are quite large, on the order of 1,000 actual cfm to possibly as high as 4,000 actual cfm. For stable foam drilling operations, much less volumetric rate of air flow is needed (i.e., usually less than 500 actual cfm). Also, the compressor should be capable of variable volumetric rate of flow and variable output pressure. The back pressure must be continuously adjusted to maintain a continuous column of stable foam in the annulus. This continuous adjustment of back pressure requires, therefore, continuous adjustment of input volumetric rate of airflow and output pressure (also, water and surfactant must be adjusted). For aerated mud drilling operations, the compressor should also be capable of variable volumetric rate of airflow and variable output pressure. Again, as drilling progresses, the input volume of compressed air and the output pressure are continuously adjusted.

Chemical (and Water) Tank and Pump. The pump injects water, liquid foamers and chemical corrosion inhibitors into the high-pressure air (or gas) line after compression of the air and prior to the standpipe.

Solids Injector, This is used to inject hole-drying powder into the wellbore to dry water seeping into the borehole from water-bearing formations.

Rotating Kelly Packer (Rotating Head). Figure 4-187 shows the details of a rotating head. This surface equipment is critical and is also a unique piece of

moving seal here rotates with kelly

~J

I/I].'/l/IA

~' ~ ' y / ~ / ~ / b ~ o w ' o f f ' c u t t i n g s ~

[//~'/~ a distance from fig

gas or air down thru kelly Figure 4-187. Rotating head.

846

Drilling and Well Completions

equipment to air drilling operations. The rotating head packs off the annulus return flow from the rig floor (i.e., seals against the rotating kelly) and diverts the upward flowing air (or gas) and cuttings to the blooey line. Little pressure (a few psig) exists in the annulus flow at the rotating head.

Kelly. Because o f its greater seal effectiveness within the rotating head, a hexagonal rather than a square kelly should be used in air (or gas) drilling operations. Scrubber. This removes excess water from the injected air (or gas) stream to ensure that a m i n i m u m o f moisture is circulated (if dry air for drilling is required) and to protect the booster. Sample Catchers. A small-diameter pipe (about 2 in.) is fixed to the bottom o f the blooey line to facilitate the catching and retaining o f downhole cutting samples for geologic examination.

De-Duster. This provides a spray o f water at the end o f the blooey line to wet down the dust particles exiting the blooey line. Gas Sniffer. This instrument can be hooked into the blooey line to detect very small amounts o f natural gas entering the return flow from the annulus. Pilot Light. This is a small continuously operated flame at the end o f the blooey line, and it will ignite any natural gas encountered while drilling. Burn Pit. This pit is at the end o f the blooey line and provides a location for the cutting returns, foam and for natural gas or oil products from the subsurface to be ignited by the pilot light and b u r n e d off. The burn pit should be located away from the standard mud drilling reserve pit. Meter for Measuring Air (or Gas) Volume. A standard orifice meter is generally used to measure air (or gas) injection volume rates. Downhole Equipment Special pieces o f downhole equipment and special concerns must be considered during downhole air (or g a s ) d r i l l i n g operations.

Float-valve Subs. These subs are at the bottom and near the top o f the drill string. The bottom float-valve sub prevents the backflow o f cuttings into the drill string during connections or other air (or gas) flow shutdowns that would otherwise plug the bit. The b o t t o m float-valve sub also aids in preventing extensive damage to the drill string in the event o f a downhole fire. The top (or upper) float-valve subs aid in retaining high pressure air (or gas) within a long drill string while making connections or other shutdowns. Bottomhole Assemblies. In general, the drill pipe, drill collars and, in particular, bottomhole assemblies for air (or gas) drilling operations are the same as those in mud drilling. However, because the penetration rate is much greater in air (or gas) drilling operations due to the lack o f confining pressure on the bit cutting surface, care must be taken to control unwanted deviation o f the borehole. Thus, for air (or gas) drilled boreholes, a packed-hole or stiff bottomhole assembly is recommended.

Air a n d Gas Drilling

847

Drill Pipe Wear, Erosion can occur between the hard b a n d a n d the tool j o i n t metal when the box e n d is h a r d b a n d e d . This erosion is due to the high-velocity flow of cuttings in the annulus section of the borehole.

Bits, Bits that offer the best gage protection should be selected for air (or gas) drilling operations. Gage r e d u c t i o n always occurs in air (or gas) drilled boreholes, particularly near the e n d of a bit run. Returning to an air-drilled b o r e h o l e with the same gage bit is dangerous unless care is taken in r e t u r n i n g to the bottom. It is nearly always necessary to ream the last third of the borehole length (i.e., the last bit run) to get to the bottom. Most manufacturers of bits make tricone bits that are specially designed for air (or gas) drilling operations. These bits have the same cutting structures as the m u d bits. T h e differences between air bits a n d m u d bits are in the design of the internal passages for airflow a n d in the cooling of the internal bearings of the bits. It is c o m m o n practice in air a n d gas drilling o p e r a t i o n s to o p e r a t e the bits with no nozzle plates in the orifice openings. Air Hammer. This is a special d o w n h o l e d r i l l i n g tool for controlling severe deviation p r o b l e m s a n d for drilling very hard formations. T h e air h a m m e r is an air percussion h a m m e r system that operates from c o m p r e s s e d air a n d the rotary m o t i o n of the drill string.

Air (or Gas) Downhole Motors. Some positive displacement m u d motors can be o p e r a t e d on unstable foam. In general, these m u d motors must be low-torque, high-rotational-speed motors. Such motors have found limited use in air a n d gas drilling o p e r a t i o n s where directional boreholes are required. Recently a downhole t u r b i n e m o t o r has been d e v e l o p e d specifically for air a n d gas d r i l l i n g o p e r a t i o n s . This d o w n h o l e p n e u m a t i c t u r b i n e m o t o r is a high-torque, lowrotational-speed motor.

Well Completion In general, well c o m p l e t i o n p r o c e d u r e s for an air- (or gas-) drilled b o r e h o l e are nearly the same as those for a mud-drilled borehole. For mud drilling operations, the depth at which a casing is to be set is usually dictated by the pore-pressure a n d fracture-pressure gradients. In air (or gas) drilling operations, a casing is set to the d e p t h at which significant f o r m a t i o n water will occur. If at all possible, casing should be set j u s t after a significant water zone has been p e n e t r a t e d so that the air drilling difficulties e n c o u n t e r e d with all water influx to the annulus, can be minimized by sealing off the water zones p r o m p t l y after drilling t h r o u g h the zone. Thus, stand-by air compressors a n d expensive foaming additives are used only for a short time. In most air a n d gas d r i l l i n g o p e r a t i o n s , o p e n - h o l e well c o m p l e t i o n s are c o m m o n . This type of c o m p l e t i o n is consistent with low p o r e pressure a n d the desire to avoid f o r m a t i o n damage. It is often used for gas wells where nitrogen foam f r a c t u r i n g stimulation is necessary to p r o v i d e p r o d u c t i o n . In oil wells drilled with natural gas as the drilling fluid, the well is often an o p e n hole c o m p l e t e d with a screen set on a liner hanger to control sand influx to the well. Liners are used a great deal in c o m p l e t i o n of wells d r i l l e d with air (or gas) drilling techniques. The low pore-pressure subsurface limitations necessary to allow air (or gas) drilling give rise to m i n i m u m casing design requirements. Thus, liners can be used nearly t h r o u g h o u t the casing p r o g r a m .

848

Drilling and Well C o m p l e t i o n s

In many air and gas drilling o p e r a t i o n s when casing or a liner is set, the casing or liner is lowered into the dry b o r e h o l e and once the b o t t o m has b e e n reached, the casing or liner is l a n d e d (with little or no compression on the lower part of the casing or liner string). After landing the casing or liner, the borehole is then filled with water (with a p p r o p r i a t e additives), and cement is p u m p e d to the annulus around the casing or liner and the water in the borehole is displaced to the surface. T h e cement is followed by water and the cement is allowed to set. A f t e r the cement has set, there is water inside the casing (or liner) that must be removed before air (or gas) drilling can proceed. T h e following p r o c e d u r e is r e c o m m e n d e d for unloading and drying a borehole p r i o r to drilling ahead on air [73]: 1. Run the drill string c o m p l e t e with desired b o t t o m h o l e assembly and bit to bottom. 2. Start the m u d pump, r u n n i n g as slowly as possible, to p u m p f l u i d at a rate o f 1.5 to 2.0 b b l / m i n . This reduces fluid friction resistance pressures to a m i n i m u m and p u m p s at m i n i m u m standpipe pressure for circulation. T h e s t a n d p i p e p r e s s u r e (for 1.5 to 2.0 b b l / m i n ) can be f o u n d f r o m s t a n d a r d f l u i d hydraulic calculations. 3. Bring one c o m p r e s s o r and booster on line to aerate the f l u i d p u m p e d downhole; approximately 100 to 150 scfm/bbl o f fluid should be sufficient for aeration. If the air volume used is too high, standpipe pressure will exceed the p r e s s u r e r a t i n g o f the c o m p r e s s o r ( a n d / o r b o o s t e r ) . T h e r e f o r e , the c o m p r e s s o r must be slowed down until air is mixed with the f l u i d going downhole. T h e mist p u m p should inject water at a rate o f about 12 b b l / h r ; the foam injection p u m p should inject about 3 g a l / h r o f surfactant; this binds f l u i d and air together for m o r e efficient aeration. As the f l u i d c o l u m n in the annulus is aerated, standpipe pressure will drop. A d d i t i o n a l c o m p r e s s o r s (i.e., i n c r e a s e d air volume) can then be a d d e d to f u r t h e r lighten the f l u i d c o l u m n and u n l o a d the hole. C o m p a r e d to the slug m e t h o d o f u n l o a d i n g the hole, the a e r a t i o n m e t h o d is m o r e efficient. T h e slug m e t h o d consists o f alternately pumping first air (injected up to an a r b i t r a r y m a x i m u m pressure) and then water (to reduce the pressure to an a r b i t r a r y minimum); this p r o c e d u r e is r e p e a t e d until air can be injected continuously. T h e a e r a t i o n m e t h o d takes less time, causes no damage to pit walls from surges (as can h a p p e n with alternate slugs of air and water) and can generally be d o n e at lower o p e r a t i n g pressures. 5. After the hole has been unloaded, keep mist and foam injection p u m p s in o p e r a t i o n to clean the hole of sloughing formations, providing a mist o f 1.5 barrels o f water p e r h o u r p e r inch o f hole d i a m e t e r and 0.5 to 4 gal of surfactant p e r hour, respectively. 6. At this point, begin air or mist drilling. Drill 20 to 100 ft to allow any sloughing hole to be cleaned up. 7. Once the hole has been stabilized (i.e., after sloughing), stop drilling and blow the hole with air mist to eliminate cuttings. Continue this p r o c e d u r e for 15 to 20 min or until the air mist is clean (i.e., shows a fine spray and white color). 8. Replace the kelly and set the bit on bottom. Since the hole is now full o f air, surfactant and water will run to the bottom. Unless mixed with air and p u m p e d up the annulus (which cannot be d o n e if the drill bit is

Air a n d Gas Drilling

9.

10. 11.

12.

849

above the s u r f a c t a n t - w a t e r mixture), the surfactant mixture cannot be p r o p e r l y swept out o f the hole. W i t h the bit directly on bottom, start the air down the hole. Straight air should be p u m p e d at n o r m a l drilling volumes until the surfactant sweep comes to the surface, a p p e a r i n g at the e n d o f the blooey line and foaming like shave cream. Continuously blow the hole with air for about 30 min to 1 hr. Begin drilling. A f t e r 5 o r 10 ft have b e e n drilled, the hole should dust (although it is sometimes necessary to drill 60 to 90 ft before dust appears at the surface). If the hole does not dust after these steps have b e e n c a r r i e d out, p u m p a n o t h e r surfactant slug around. If dusting cannot be achieved, mist drilling may be required to c o m p l e t e the o p e r a t i o n . D e p e n d i n g on the hole depth, the entire p r o c e d u r e requires 2 to 6 hr. Holes o f over 11,000 ft have been successfully u n l o a d e d using the aeration method. A well can be dusted, mist-drilled, dried up a n d r e t u r n e d to dust drilling. To d r y a hole properly, it is i m p o r t a n t that it be kept clean. Drying agents have been tried but without much success. The best drying agent available at the present time is the f o r m a t i o n itself. It should be noted that when drilling with natural gas as the drilling fluid from a pipeline source with limited pressure, nitrogen is often used to u n l o a d the hole.

It is quite desirable to place water into an open-hole section p r i o r to r u n n i n g a casing o r liner string a n d cementing. T h e water will provide a hydraulic head to hold back any f o r m a t i o n gas in the open-hole section that could cause a fire hazard at the rig floor. However, if the o p e r a t o r feels that the open-hole section would slough badly if water were placed in the hole, t h e n the casing o r liner string may have to be run into the dry o p e n hole. This means that great care must be taken in r u n n i n g a casing o r liner string into the open-hole section if the subsurface formations are making gas. T h e r e are p r o c e d u r e s that can be followed to allow the safe placement o f casing o r liner string in a dry open-hole section that is making gas. Figures 4-188 a n d 4-189 show the typical blowout prevention (BOP) stack a r r a n g e m e n t s used for air (or gas) d r i l l e d b o r e h o l e s [74]. F i g u r e 4-188 shows t h e BOP stack a r r a n g e m e n t for rotary rigs that have r a t h e r high cellars. Such a rig would be a p p r o p r i a t e for drilling b e y o n d 8,000 ft o f depth. Figure 4-189 shows a m o r e typical BOP stack a r r a n g e m e n t for r o t a r y rigs u s e d in air a n d gas d r i l l i n g operations. These rigs typically drill boreholes o f 8,000 ft in depth o r less. These low cellar rigs cannot fit the larger BOP stack (i.e., the one shown in Figure 4-188) into the cellar. Small BOP stacks shown in F i g u r e 4-189 give rise to safety p r o b l e m s when lowering casing o r liners into the b o r e h o l e d u r i n g well completion operations. T h e safety p r o b l e m s arise when a well, which is making gas, is allowed to be o p e n e d to the surface when r u n n i n g a casing o r liner string. If p r o p e r p r o c e d u r e s are not used when the s t r i p p e r r u b b e r is c h a n g e d to a c c o m m o d a t e the o u t s i d e d i a m e t e r changes in drill p i p e o r casing o r liner, formation gas can escape to the rig f l o o r where it can be ignited. A n example o f the typical safety p r o b l e m that can occur when c o m p l e t i n g these wells is when a 6 ~ in. o p e n hole has been d r i l l e d below the last casing (or liner) shoe. T h e o p e n section o f the b o r e h o l e is usually to be cased with a 4~ in. liner. T h e liner is to be lowered into the o p e n hole o n - a liner hanger that is m a d e up to 3 ~ in. drill pipe. It is a s s u m e d t h a t p r i o r to the l i n e r operation, drilling had been u n d e r way; thus the stripper r u b b e r in the rotating

850

Drilling and Well Completions

Rotating Head

PIPE RAMS Rd . . . . BLIND RAMS

DRILLING SPOOL

i

R-PIPE RAMS £_ I ,

_

I

.

I

F i g u r e 4-188. BOP stack arrangment for high cellar rigs.

head and the pipe rams are appropriate for the 3 ~ in. drill pipe. Therefore, as the drill string is raised to the surface, the stripper rubber in the rotating head and the pipe ram are available to limit formation gas from coming to the rig floor. Usually the pipe rams are not employed, and protection of the rig and its crew from the formation gas is d e p e n d e n t u p o n stripper rubber in the rotating head. W h e n drilling a 6¼ in. b o r e h o l e with air, the drill collars employed are normally 4 ¼ in. Beginning with the removal of the drill string, the proper procedure for placing the liner in the example borehole is: 1. Use the 3-~ in. stripper rubber in the rotating head to strip over the 4 ¼ in. drill collars until the drill bit is above the blind rams (but below the stripper rubber in the rotating head).

Air and Gas Drilling

I

[

j

851

I k,~

I

PIPE RAMS

l

Rd- BLIND RAMS !

Figure

]

4-189. BOP stack arrangement for low cellar rig.

2. Close the blind rams, open the rotating head to release the 3-~ in. stripper rubber, pull the rotating table bushings and raise the last joint of drill collar, remove the bit, and lay this joint down (remove the 3-~ in. stripper rubber from this drill collar joint for later use). 3. Place the new 4-~ in. stripper rubber for the rotating head on the first joint o f 4 ~ in. liner joint. This liner joint should have the casing shoe and float valve made up to the bottom end. Lower this first joint of liner through the rotary table opening until the 4-~ in. stripper rubber can be secured in the rotating head. Once the 4~ in. stripper rubber is in place in the rotating head, secure the stripper rubber by closing the rotating head. 4. Open the blind rams, and continue to lower the 4-~ in. liner through the rotary table opening using the casing slips. 5. Make up the liner hanger to the last liner joint while holding the liner string in the casing slips. Make up the first joint of the 3-~ in. drill pipe to the liner hanger, remove the casing slips and lower the liner string on the 3 ~ in. drill pipe into the borehole until the 3-~ in. drill pipe is adjacent to the 3 ~ in. pipe rams, close the 3 12 in. pipe rams onto the 3-~ in. drill pipe and replace the rotary table bushings. Place at least three joints of

852

6.

7. 8. 9.

Drilling and Well Completions 312 in. drill pipe onto the liner string, stripping with the pipe rams and using the rotary slips as the drill pipe goes into the hole. With the 312 in. pipe rams closed on the 312 in. drill pipe, open rotating head and pull the rotary bushings. While stripping with the pipe rams, raise the liner string (with the 3 ½ in. drill pipe) until the 412 in. stripper rubber and the drill pipe joint it is on are above the rotary table. Replace the rotary table bushings and, using the rotary slips, remove this drill pipe joint with the 412 in. stripper rubber (the 4~ in. stripper rubber can be removed from this joint later). Pick up a joint of 312 in. drill pipe with a 3~ in. stripper rubber attached. Make up this 3~ in. drill pipe joint to the liner string's upper drill pipe joint being held in the rotary slips. Remove the rotary bushings and, while stripping with the pipe rams, lower the liner string until the 3~ in. stripper rubber is in the rotating head. Close the rotating head to secure the 3 ~ in. stripper rubber. Replace the rotary bushings, open the pipe rams and continue to lower the liner string with the 3 ~ in. drill pipe.

The above procedure allows for the maximum protection against formation gas escaping to the rig floor. There is basically no time at which the hole is exposed directly to the rig floor. This rather complicated procedure has been necessary because the drilling rig can only accommodate the BOP stack that has only one set of pipe rams and a blind ram (i.e., Figure 4-188). It is obvious if the rig could accommodate the taller BOP stack with two pipe rams (namely Figure 4-187), one pipe ram could be for 312 in. drill pipe and the other for the 4~ in. liner. Such an arrangement would greatly simplify the safety procedures necessary for placing the 412 in. liner into the borehole. The above example is simply one of the safety problems that must be faced with the completion of wells drilled with air (or gas) and making formation gas. The principle behind the above procedure is to eliminate or limit the exposure of the rig floor to the dangerous, potentially explosive formation gas. When a well is making (formation) gas, the rig crews must be constantly alert to safety and proper safety procedures, and rules must be followed. Nearly all drilling companies strictly forbid any smoking material, lighters or matches to be taken into the areas where air (or gas) is being used to drill a well for hydrocarbons [75]. Well Control A blowout, which is the continuous flow of oil or gas to the surface through the annulus, is the result of a lack of sufficient bottomhole pressure from the column of circulating fluid and proper well head equipment. Blowout and Bottomhole Pressure Air and Gas, In the regions where air and natural gas are used as the principal drilling fluids, the potential oil and gas production zones usually have low pore pressure, or require well stimulation techniques to yield commercial production. In these production zones, air drilling (or natural gas drilling) is continued into the production zone and the initial produced formation fluids are carried to the surface by the circulating air or natural gas. This is nearly the same situation as in mud drilling, except that in air (or gas) drilling the transit time for the initial produced formation fluids to reach the surface is much shorter. In mud

Air and Gas Drilling

853

drilling, the entry o f f o r m a t i o n fluids to the well is considered a kick. T h e well is not c o n s i d e r e d to be a blowout until the f o r m a t i o n fluids fill the annulus a n d are f l o w i n g u n c o n t r o l l e d f r o m the well. In air (or gas) drilling, o n c e f o r m a t i o n fluids enter the annulus, the well is in a blowout condition. This is due to the fact that the f o r m a t i o n fluids that enter the well can flow to the surface immediately. Unstable Foam (Mist). T h e a d d i t i o n o f water and a foaming agent into the circulating air (or gas) fluid will slightly increase the bottomhole pressure d u r i n g drilling operations. However, this slight increase in b o t t o m h o l e pressure does not alter the situation with regards to the potential well control capability o f this circulating fluid. Again, as above, once f o r m a t i o n fluids enter the well, the well is in a blowout condition. Stable Foam. W h e n a well is d r i l l e d with stable foam as the drilling fluid, there is a back pressure valve at the blooey line. T h e back pressure valve allows for a continuous c o l u m n o f foam in the annulus while drilling o p e r a t i o n s are u n d e r way. Thus, while drilling, this foam column can have significant bottomhole pressure. This b o t t o m h o l e pressure can be sufficient to counter formation p o r e pressure and thus control potential p r o d u c t i o n f l u i d flow into the well annulus.

Aerated Mud. In a e r a t e d m u d drilling o p e r a t i o n s , the drilling m u d is injected with c o m p r e s s e d air to lighten the mud. Therefore, at the b o t t o m o f the well in the annulus, the b o t t o m h o l e pressure for an a e r a t e d m u d will be less than that o f the m u d without aeration. However, an a e r a t e d m u d drilling o p e r a t i o n will have very significant bottomhole pressure capabilities and can easily be used to control potential p r o d u c t i o n f l u i d flow into the well annulus. Blowout Prevention Equipment A i r and gas, u n s t a b l e foam a n d stable foam t e c h n i q u e s are u s e d a l m o s t exclusively for o n s h o r e d r i l l i n g o p e r a t i o n s , rarely in o f f s h o r e a p p l i c a t i o n s . Aerated mud, however, is used for both onshore and offshore drilling operations. T h e minimum requirements for well blowout prevention equipment for drilling with air and gas, unstable foam and stable foam techniques are shown in Figures 4-187 and 4-188. T h e BOP stack a r r a n g e m e n t in Figure 4-187 is for a r a t h e r s t a n d a r d rotary rig that will a c c o m m o d a t e at least two sets o f p i p e rams in a d d i t i o n to the rotating head and the blind rams. Figure 4-188 shows a BOP stack a r r a n g e m e n t used for smaller rotary rigs that do not have sufficient cellar height to a c c o m m o d a t e the second set o f p i p e rams. T h e m i n i m u m r e q u i r e m e n t s for well b l o w o u t p r e v e n t i o n e q u i p m e n t for a e r a t e d m u d drilling o p e r a t i o n s are basically the same as those for n o r m a l m u d drilling operations.

Air, Gas and Unstable Foam Calculations P e r t i n e n t e n g i n e e r i n g c a l c u l a t i o n s can be m a d e for air a n d gas d r i l l i n g o p e r a t i o n s and for unstable foam drilling operations.

Volumetric Flowrate Requirements T h e r e is a m i n i m u m air (or gas) volume rate o f flow that must be maintained in o r d e r to adequately clean the b o t t o m o f the hole o f cuttings and carry these

854

Drilling and Well Completions

cuttings to the surface. This initial calculation depends principally u p o n the borehole geometry and the drilling rate. The minimum volumetric flowrate Q (actual cfm) can be obtained from [61] C1S(CT~ + ~h)Q~ = [(P~ + bT~. )e2~frav- bT~b] °5 (D~ - D2p)V2mi.

(4-122)

and

a

-

b =

where

SQ + C~KD~ 53.3Q

(4-123)

C3Q2 (D h - Dp) 1. 333 (D h2 - D~p)2

(4-124)

D h =

T = T = K = V rain = h =

inside diameter of borehole in ft outside diameter of drill pipe in ft specific gravity of gas (air is 1.0) surface atmospheric temperature in °R average temperature of flow in annulus in °R geothermal gradient in °F per ft drilling rate in f t / h r equivalent minimum velocity of standard air for removal of cuttings (Vml" = 3000 ft/min) hole depth in ft

The constants C 1, C v C 3 are

CI =

4

T~

P~

(4-125

(62.2)(2.7) C 2 =

(4-126

L53.3T,) 001

2(32.2)(3600) k.~J ~ T s )

(4-127

where Tsl = temperature at sea level standard atmospheric conditions (i.e., 520°R Psi = pressure at sea level standard atmospheric conditions (i.e., 2116.8 lb/ft ~) Thus, CI, C~ and C s are related to the actual atmospheric surface conditions where drilling is taking place. Table 4-107 gives the values of CI, C~ and C s for

855

Air and Gas Drilling

Table 4-107 Constants C1, C2 and C3 for Various Surface Locations Above Sea Level Surface Location Above See Level (tt) 0 2,000

4,000 6,000 8,000 10,000

C,

C2

6.610 5.873 5.207 4.612 4.080 3.605

28.83 30.59 32.48 34.52 36.70 39.04

C3 1.628 1.446 1.282 1.136 1.005 0.8878

x x x x x x

I0 -~' I0 -~' IO -~' I0 '~' tO -~' 106

various surface locations above sea level. Also Table 4-109 gives a t m o s p h e r i c pressure, t e m p e r a t u r e and specific weight o f air for various surface locations above sea level.

Example Find the m i n i m u m Q (actual cfm) for an air drilling o p e r a t i o n at a surface location o f 6,000 ft above sea level. Drilling is to begin at 8,500 ft o f d e p t h a n d c o n t i n u e to 10,000 ft. T h e b o r e h o l e , f r o m top to b o t t o m , has nearly a u n i f o r m inside d i a m e t e r o f slightly larger than 8 a4 in. T h e bit to be used to drill the interval is 8 a4 in. T h e outside d i a m e t e r o f drill pipe is 4 ~ in. T h e expected drilling rate is 60 ft/hr. The geothermal gradient will be taken to be 0.01 °F/ft. To obtain the g o v e r n i n g m i n i m u m Q for the interval to be drilled, Equation 4-122 must be solved at 10,000 ft o f depth. Since the drilling location is at a surface location o f 6,000 ft above sea level, f r o m Table 4-107, we have C 1 = 4.612 C 2 = 34.52 C a = 1.136 x 10 -6

Table 4-108 Atmosphere at Elevations Above Sea Level Surface ~ l o n Above See Level

fit) 0 2,000 4,000 6,000 8,000 !0,000

Preslmre (psi) 14.696 13.662 12.685 11.769 10.91 I I0.108

Temperature

Specific Weight

(*F)

(lb/ft ~)

59.00 51.87 44.74 37.60 30.47 23.36

0.0765 0.072 I O.0679 0.0639 0".0601 0.0565

856

Drilling a n d Well Completions

Equations 4-108 and 4-109 become

a

=

(1. O)Q + 34.52(60)(0.7292) 2 53.3Q

b=

1.136 x 1 0 ~ Q 2 0. 03835

The bottomhole temperature tbh(°F) is approximately (see Table 4-109) tbh = 37.60 + 0.01(10,000) = 137.6 F Thus,

T ~v =

37.6 + 137.6

+ 460 = 547.6°R

Equation 4-123 becomes 2.003 × lO-3Q2 = {[(1694.7) 2 + b(547.6) 2] e 2a(1°,°°°)/~'47.6 - b(547.6)2} o.~ where a a n d b are functions of the u n k n o w n Q a n d are given above. The above e q u a t i o n must be solved by iteration for values of Q. The value of Q that satisfies the above e q u a t i o n is Q = 2,110 actual cfm This is the upper value of the m i n i m u m air volumetric flowrates for the interval to be drilled (i.e., 8,500 to 10,000 ft).

Surface Compressor and Booster Requirements Once the governing m i n i m u m air volumetric flowrate has been found for an interval to be drilled, the compressors of fixed volumetric flowrate can be selected. A n a d d i t i o n a l compressor is usually o n site as a stand-by to have additional air available in case of unexpected downhole problems and to have a compressor available in the event one of the operational compressors needs to be shut down for maintenance. The n u m b e r of fixed volumetric flowrate compressors is selected such that the necessary m i n i m u m air volumetric flowrate is exceeded. The air volumetric flowrate that the compressors p r o d u c e is shown as the real air volumetric flowrate. This real air volumetric flowrate, Q~ (actual cfm) is used to calculate the bottomhole pressure. Bottomhole pressure, Pb (lb/ft2 abs) is d e t e r m i n e d by 2

2

05

Pb = [(P~ + bT2~ ) e2~tr"~ - bT~v ]"

where Q~ is used to find the new values of a and b.

(4-128)

Air a n d Gas Drilling

857

Knowing the b o t t o m h o l e pressure, the n u m b e r o f bit orifice o p e n i n g s and the inside d i a m e t e r o f these openings, the pressure inside the drill p i p e j u s t above the bit a n d the surface injection pressure can b e found. T h e total area o f the orifice o p e n i n g s An(ft2 ) is

An =

nX(dn~ 2 ~k.']2")

(4-129)

where n = n u m b e r o f orifices d n = d i a m e t e r o f the orifice openings in in. The weight rate o f airflow t h r o u g h the system G ( l b / s ) is G = Q't', 60

(4-130)

where "f~ = specific weight o f air at the surface location in l b / f t 3 T h e pressure above the bit P ( l b / f t 2 abs) can be found from

~ 2gk p [(p~)¢k_~)/k ]}0.5

G=A~Ik_ 1 bTbL~,pb~

--I

(4-131)

where k = ratio o f specific heat o f air (or gas) for air k = 1.4 g = acceleration o f gravity (32.2 f t / s 2) The surface injection pressure Pi(lb/ft2 abs) can be d e t e r m i n e d if knowing the pressure above the bit. The surface injection pressure is d e t e r m i n e d from p~ =

I

e2aa~/rav 10.5

P2a + b ' Tar( 2 e 2a'hfr,v - 1 )

(4-132)

and S a' = ~ 53.3

(4-133)

b ' CsQ2 D~p333

(4-134)

where D~p = inside d i a m e t e r o f the drill pipe, ft

Example 1 Using the data given below and results from the Example on p. 856, determine the real air volumetric flowrate and the expected surface injection pressure. The

858

Drilling a n d Well Completions

8 ~4 in. bit will have three o p e n orifices and each orifice has an o p e n i n g of 0.80 in. in diameter. T h e inside d i a m e t e r of drill pipe is 3.640 in. T h e surface compressors and booster available at the drilling location are Compressor (primary) Atlas Copco PN1200 Positive displacement screw-type, three stages 700 HP 1200 actual cfm Fixed m a x i m u m pressure, 300 psig Turbocharged e m -= 80% Booster (secondary) Joy WB-12 Positive displacement, piston-type, three stages 500 HP Maximum pressure, 1500 psig Naturally aspirated e m -= 80% T h e m i n i m u m volumetric flowrate has b e e n found to be Qmi, = 2,110 actual cfm. Therefore, the real air volumetric flowrate must be provided by two of the compressors given above. Thus the Q~ will be Q~ = 2(1200) = 2400 actual cfm Using the above Q~, Equations 4-123 a n d 4-124 are a = 0.0274 b = 170.62 From Equation 4-128 the bottomhole pressure is Pb =

[[(1694"7) 2

+ 170"62(547"6)2]e2(°°274)°°'°°°)/547"6

-

170"62(547"6)2}°"5

= 9789.1 l b / f t 2 abs or

Pb = 68.0

psia

T h e specific weight of the air at the bottom of the hole is Pb 9789.1 ]'b - - = 0. 3073 lb/ft ~ RT b 53.3(597.6) From Equation 4-129 the total area of the orifice openings is

Air a n d Gas Drilling

859

A . : ( 3 ) 4 ( 0 . 8 ) 2 : 0.010472ft 2 \12) From Equation 4-130 the weight rate o f flow t h r o u g h the system is G - 2400(0. 0639) _ 2.556 lb/s 6O The pressure above the bit can be found from Equation 4-131. Equation 4-131 is

•

L

Solving the above P = 13,144.9 l b / ~ 2 abs or

p, = 91.3 psia Equations 4-133 a n d 4-134 are a ' = 0.0188 b ' = 3790.7 Equation 4-132 is

Pi = I (13'144"9)2 +

3790. 2'21°'°7'°°I88'(547. ISaxI°' I'°'°°°)/547"66)2(e °°°)/~47"6-e

1)]0.5

= 25,526.4 lb/ft 2 psia or

p~ = 177.3 psia T h e above injection pressure is the expected standpipe pressure when drilling at 10,000 ft o f depth. T h e injection pressure will be somewhat less than the above when drilling the u p p e r p o r t i o n of the interval (i.e. at 8500'). Thus the p r i m a r y compressors will have sufficient pressure capability to drill the interval from 8,500 to 10,000 ft. A third p r i m a r y c o m p r e s s o r should be on site a n d h o o k e d up for i m m e d i a t e service in the event of downhole p r o b l e m s o r the necessity to shut down o n e of the o p e r a t i n g compressors. Also, the b o o s t e r should be h o o k e d up for i m m e d i a t e service in the event of downhole p r o b l e m s . For m o r e i n f o r m a t i o n a n d e n g i n e e r i n g calculations p e r t a i n i n g to compressors and boosters see reference 64.

860

Drilling a n d Well C o m p l e t i o n s

Injected Water Requirements and Formation Water If water-bearing f o r m a t i o n s are e x p e c t e d while drilling with air, then it is necessary to make sure the air entering the b o t t o m o f the annulus section o f the b o r e h o l e is s a t u r a t e d with moisture. If the circulating air is saturated then the air will not lose internal energy absorbing the f o r m a t i o n water. T h e loss o f internal energy would affect its potential to e x p a n d a n d thus reduce the kinetic energy o f air flow in the annulus. T h e loss o f kinetic energy will reduce the lifting capability o f the circulating air. Once the circulating air is saturated a n d it enters the b o r e h o l e annulus, the air will c a r r y the f o r m a t i o n water as droplets. Thus the f o r m a t i o n water will be c a r r i e d to the surface in much the same m a n n e r as the rock cuttings. To s a t u r a t e the c i r c u l a t i n g air with water so that the air c a n n o t a b s o r b f o r m a t i o n water, the water must b e injected into the c o m p r e s s e d air at the surface p r i o r to the s t a n d p i p e (see Figure 4-185). If only water is injected into the circulating air, then the drilling o p e r a t i o n is called mist drilling. Usually, however, a foaming agent (or surfactant) is injected with the water. This allows a foam to be created in the annulus, which aids in t r a n s p o r t a t i o n o f the cuttings to the surface. T h e s e f o a m i n g agents are p u m p e d t o g e t h e r with the water injected on the basis o f about 0.2% o f the injected a n d p r o j e c t e d f o r m a t i o n water. W h e n water a n d a foaming agent are injected the drilling o p e r a t i o n is called unstable foam drilling. T h e v o l u m e t r i c f l o w r a t e o f water to be i n j e c t e d into the c o m p r e s s e d air d e p e n d s u p o n the s a t u r a t i o n pressure o f the water v a p o r at the b o t t o m h o l e t e m p e r a t u r e . T h e s a t u r a t i o n p r e s s u r e Psat (psia) at the b o t t o m o f the hole d e p e n d s only on the b o t t o m h o l e t e m p e r a t u r e a n d is given by [76,77].

log,0 p,~ = 6.39416

1750. 286 217.23 + 0.555t b

(4-135)

where tb = b o t t o m h o l e t e m p e r a t u r e (°F) Knowing the saturation pressure o f the water vapor, the amount o f injected water can b e d e t e r m i n e d . T h e amount o f injected water, qi ( g a l / h r ) , to provide s a t u r a t e d air at b o t t o m h o l e c o n d i t i o n s is

qi:20917( 1o

(4-136)

where Pb = b o t t o m h o l e pressure in psia G = weight rate o f flow o f (dry) air in l b / s

Example Using the data a n d results from the Examples on pp. 856 to 859, d e t e r m i n e the a p p r o x i m a t e amount o f surface injected water a n d foaming agent n e e d e d to saturate the air at b o t t o m h o l e conditions a n d to provide an unstable foam in the annulus o f the borehole. T h e saturation pressure can be found from substitution o f the b o t t o m h o l e t e m p e r a t u r e o f 137.6°F into Equation 4-135. This yields

Air a n d Gas Drilling

861

l°gl0 Ps~ = 0.4327 Ps~t = 2.708 psia The volumetric flowrate o f injected water is d e t e r m i n e d from Equation 4-136, which yields

qi = 269.17( 2.708 "](2.556) = 2 8 . 5 g a l / h r k. 68.0 - 2. 708 ) T h e a p p r o x i m a t e volumetric rate o f foaming agent qf ( l b / h r ) injected will be qf = 0.002(28.5) = 0.06 g a l / h r However, this foaming agent injected is only a small part o f what should be injected to foam the anticipated formation water which may enter the annulus. This will be covered in the next Example. If the circulating air has b e e n saturated, then any f o r m a t i o n water e n t e r i n g the annulus will be c a r r i e d to the surface as droplets a n d will not reduce the t e m p e r a t u r e o f the air a n d thereby reduce kinetic energy o f the air as it expands in the annulus. T h e amount o f f o r m a t i o n water that can be c a r r i e d from the b o r e h o l e annulus by the real amount o f air circulating O is directly related to t h e a d d i t i o n a l air that is b e i n g c i r c u l a t e d above that m i n i m u m value Q~i, necessary to clean the hole o f rock cuttings. To calculate the amount o f water that can be c a r r i e d from the hole, O is s u b s t i t u t e d into E q u a t i o n 4-123 a n d the p o t e n t i a l d r i l l i n g rate such an air v o l u m e t r i c f l o w r a t e can s u p p o r t . T h e a d d i t i o n a l d r i l l i n g r a t e t h a t can be s u p p o r t e d by O is actually the weight o f f o r m a t i o n water (per hour) that can be removed from the borehole. Therefore, once the potential drilling rate is o b t a i n e d for O , then the f o r m a t i o n water that can be taken in the b o r e h o l e annulus p e r hour qw ( g a l / h r ) while m a i n t a i n i n g the n o r m a l drilling rate will be qw = ~n D~(Kp - K~)(62.4)(2.7)8.33

(4-137)

where Ko = potential drilling rate for O in f t / h r K" actual drilling rate in f t / h r

Example Using t h e d a t a a n d results f r o m t h e p r e v i o u s E x a m p l e s , d e t e r m i n e the approximate volumetric flowrate o f formation water into the annulus o f the well that can be removed by the actual air circulation rate o f 2,400 actual cfm. Also, d e t e r m i n e the total amount o f foaming agent which should be injected into the circulating air. Substitute into Equations 4-122, 4-123, a n d 4-124 the previous example values a n d let Q = 0

-- 2,400 actual cfm

862

Drilling a n d Well Completions

Equation 4-122 becomes 2.003 x 10-s(2400) z : {[(1694.7) z + 170.62(547.6)Z]e zal°'°°q~47.6- 170.62(547.6)z} °'~ Equation 4-123 becomes (with k = Kp) a = 0.0187617 + 0.00014349Kp From the above two equations the potential drilling rate K for a Q, = 2,400 actual cfm is found to be P Kp = 103.3 f t / h r Substitution of the above into Equation 4-137 yields

qw =

4\

lZ )

( 1 0 3 . 3 - 60)

8.33

= 365.7 gal/hr

The total volumetric flowrate of foaming agent that should be injected into the circulating air is qw = 0.06 + 0.002(365.7) -_- 0.80 g a l / h r

DOWNHOLE MOTORS Background In 1873, an American, C. G. Cross, was issued the first patent related to a downhole t u r b i n e motor for rotating the drill bit at the bottom of a drillstring with hydraulic power [78]. This drilling concept was conceived nearly 30 years before rotary drilling was i n t r o d u c e d in oil well drilling. Thus the concept of using a downhole motor to rotate or otherwise drive a drill bit at the bottom of a fluid conveying conduit in a deep borehole is not new. The first practical applications of the downhole motor concept came in 1924 when engineers in the United States and the Soviet Union began to design, fabricate and field test both single-stage and multistage downhole turbine motors [79]. Efforts continued in the United States, the Soviet Union and elsewhere in Europe to develop an industrially reliable downhole turbine motor that would operate on drilling mud. But during the decade to follow, all efforts proved unsuccessful. In 1934 in the Soviet U n i o n a renewed effort was initiated to develop a multistage downhole turbine motor [79-81]. This new effort was successful. This development effort marked the b e g i n n i n g of industrial use of the downhole t u r b i n e motor. The Soviet U n i o n c o n t i n u e d the development of the downhole t u r b i n e motor and utilized the technology to drill the majority of its oil and gas wells. By the 1950s the Soviet U n i o n was drilling nearly 80% of their wells with the d o w n h o l e t u r b i n e motors u s i n g surface p u m p e d d r i l l i n g m u d or freshwater as the activating hydraulic power.

Downhole Motors

863

In the late 1950s, with the growing need in the United States and elsewhere in the world for directional drilling capabilities, the drilling industry in the United States and elsewhere began to reconsider the downhole turbine motor technology. There are presently three service companies that offer downhole turbine motors for drilling of oil and gas wells. These motors are now used extensively throughout the world for directional drilling operations and for some straight-hole drilling operations. The d o w n h o l e t u r b i n e motors that are hydraulically o p e r a t e d have some f u n d a m e n t a l limitations. O n e of these is high rotary speed of the motor and drill bit. The high rotary speeds limit the use of downhole t u r b i n e motors when drilling with roller rock bits. The high speed of these direct drive motors shortens the life of the roller rock bit. In the 1980s in the United States an effort was initiated to develop a downhole t u r b i n e motor that was activated by compressed air. This motor was provided with a gear reducer transmission. This downhole pneumatic t u r b i n e has been successfully field tested [82]. The development of positive displacement downhole motors began in the late 1950s. The initial development was the result of a United States patent filed by W. Clark in 1957. This downhole motor was based on the original work of a French engineer, Ren6 Monineau, and is classified as a helimotor. The motor is actuated by drilling m u d p u m p e d from the surface. There are two other types of positive displacement motors that have been used, or are at present in use today: the vane motor and the reciprocating motor. However, by far the most widely used positive displacement motor is the helimotor [79,83]. The initial work in the United States led to the highly successful single-lobe helimotor. From the late 1950s until the late 1980s there have been a n u m b e r of other versions of the helimotor developed and fielded. In general, most of the recent d e v e l o p m e n t work in helimotors has c e n t e r e d a r o u n d m u l t i l o b e motors. The higher the lobe system, the lower the speed of these direct drive motors and the higher the operating torque. There have been some efforts over the past three decades to develop positive development vane motors and reciprocating motors for o p e r a t i o n with drilling m u d as the actuating fluid. These efforts have not b e e n successful. In the early 1960s efforts were made in the United States to operate vane motors and reciprocating motors with compressed air. The vane motors experienced some limited test success but were not competitive in the market of that day [84]. Out of these development efforts evolved the reciprocating (compressed) air hammers that have been quite successful and are operated extensively in the m i n i n g industry and have some limited application in the oil and gas industry [85]. The air h a m m e r is not a motor in the true sense of rotating equipment. The reciprocating action of the air h a m m e r provides a percussion effect on the drill bit, the rotation of the bit to new rock face location is carried out by the conventional rotation of the drill string. In this section the design and the operational characteristics and procedures of the most frequently used downhole motors will be discussed. These are the downhole t u r b i n e motor and the downhole positive displacement motor. Turbine Motors Figure 4-190 shows the typical rotor and stator configuration for a single stage of a multistage downhole t u r b i n e motor section. The activating drilling m u d or freshwater is p u m p e d at high velocity through the motor section, which, because of the vane angle of each rotor and stator (which is a stage), causes the rotor to rotate the shaft of the motor. The kinetic energy of the flowing drilling m u d is converted through these rotor and stator stages into mechanical rotational energy.

864

Drilling and Well Completions

Rotatio(~nI

Figure 4-190. Basic turbine motordesign principle.(Courtesy Smith International, Inc.)

Design The rotational energy provided by the flowing f l u i d is used to rotate and provide torque to the drill bit. Figure 4-191 shows the typical complete downhole t u r b i n e motor actuated with an incompressible drilling fluid. In general, the downhole t u r b i n e motor is composed of two sections: (1) the t u r b i n e motor section and; (2) the thrust-bearing and radial support bearing. These sections are shown in Figure 4-191. Sometimes a special section is used at the top of the motor to provide a filter to clean up the drilling m u d flow before it enters the motor, or to provide a by-pass valve. The t u r b i n e motor section has multistages of rotors and stators, from as few as 25 to as many as 300. For a basic motor geometry with a given flowrate, an increase in the n u m b e r of stages in the motor will result in an increase in torque capability and an increase in the peak horsepower. This performance improvement, however, is a c c o m p a n i e d by an i n c r e a s e in the differential pressure through the motor section (see Table 4-109). The t u r b i n e motor section usually has b e a r i n g groups at the u p p e r and lower ends of the rotating shaft (on which are attached the rotors). The b e a r i n g groups only radial load capabilities. The lower e n d of the rotating shaft of the t u r b i n e motor section is attached to the u p p e r e n d of the main shaft. The drilling fluid after passing through the t u r b i n e motor section is channeled into the center of the shaft through large openings in the main shaft. The drill bit is attached to the lower e n d of the main shaft. The weight on the bit is transferred to the downhole t u r b i n e motor housing via the thrust-bearing section. This bearing section provides for rotation while transferring the weight on the bit to the downhole t u r b i n e motor housing. In the thrust-bearing section is a radial support b e a r i n g section that provides a radial load-carrying group of bearings that ensures that the main shaft rotates

Downhole Motors

Figure 4-191. Downhole turbine motor design. (Courtesy EastmanChristensen Co.)

865

866

Drilling and Well C o m p l e t i o n s

Table 4-109 Turbine Motor, 63/4-in. Outside Diameter, Circulation Rate 400 gpm, Mud Weight 10 Ib/gal Number of Stages 212 318

Torque* (ft-lbs)

Optimum Bit Speed (rpm)

Differential Pressure (psi)

Horsepower*

Thrust Load (1000 Ibs)

1412 2118

807 807

1324 1924

217 326

21 30

*At optimum speed Courtesy Eastman-Christensen

about center even when a side force on the bit is present d u r i n g d i r e c t i o n a l drilling operations. T h e r e are o f course variations on the d o w n h o l e turbine m o t o r design, but the basic sections discussed above will be c o m m o n to all designs. T h e main advantages o f the d o w n h o l e t u r b i n e m o t o r are" 1. H a r d to extremely h a r d c o m p e t e n t rock formations can be d r i l l e d with turbine motors using d i a m o n d or the new polycrystalline d i a m o n d bits. 2. Rather high rates o f p e n e t r a t i o n can be achieved since bit rotation speeds are high. 3. Will allow circulation o f the b o r e h o l e regardless o f m o t o r horsepower or torque being p r o d u c e d by the motor. Circulation can even take place when the m o t o r is installed. T h e main disadvantages o f the d o w n h o l e turbine m o t o r are: 1. Motor speeds and, therefore, bit speeds are high, which limits the use o f roller rock bits. 2. T h e r e q u i r e d f l o w r a t e t h r o u g h t h e d o w n h o l e t u r b i n e m o t o r a n d t h e resulting pressure d r o p t h r o u g h the m o t o r require large surface p u m p systems, significantly larger p u m p systems than are n o r m a l l y available for most land and for some offshore drilling operations. 3. Unless a m e a s u r e while d r i l l i n g i n s t r u m e n t is used, t h e r e is no way to ascertain w h e t h e r the turbine m o t o r is o p e r a t i n g efficiently since rotation speed a n d / o r torque cannot be m e a s u r e d using n o r m a l surface data (i.e., s t a n d p i p e pressure, weight on bit, etc.). 4. Because o f the necessity to use many stages in the turbine m o t o r to obtain the n e e d e d power to drill, the downhole turbine m o t o r is often quite long. Thus the ability to use these motors for high-angle course corrections can be limited. 5. D o w n h o l e t u r b i n e m o t o r s are sensitive to fouling agents in t h e mud; therefore, when r u n n i n g a t u r b i n e m o t o r steps must be taken to provide particle-free drilling mud. 6. Downhole turbine motors can only be o p e r a t e d with drilling mud.

Operations Figure 4-192 gives the typical p e r f o r m a n c e characteristics o f a turbine motor. T h e example in this figure is a 6 ¼-in. outside d i a m e t e r turbine m o t o r having 212 stages a n d activated by a 10-1b/gal m u d flowrate o f 400 g a l / m i n .

Downhole Motors

3000~

12000 20001 0~

0

CiMud rculWei atioRate gpm gnht10400 ppg

0 ] T~ o -~

867

i 300 Pressure

1500

rsepowe t 100:~~

5001000

5~

10~ 1~0 2~0 BitSpeed(rpm) Figure 4-192. motor, 63/4-in. outside diameter, twomotorsections, (Courtesy Eastman-Christensen.) 212stages, 400Turbine gal/min, lO-Ib/gal mud weight. For this example, the stall torque o f the m o t o r is 2,824 ft-lb. T h e runaway s p e e d is 1,614 r p m and coincides with zero torque. T h e m o t o r p r o d u c e s its m a x i m u m horsepower o f 217 at a s p e e d o f 807 rpm. T h e torque at the peak h o r s e p o w e r is 1,412 ft-lb, or one-half o f the stall torque. A turbine device has the u n i q u e characteristic that it will allow circulation i n d e p e n d e n t o f what t o r q u e or h o r s e p o w e r the m o t o r is p r o d u c i n g . In the example where the turbine m o t o r has a 10-1b/gal m u d circulating at 400 g a l / min, the pressure d r o p through the m o t o r is about 1,324 psi. This pressure d r o p is approximately constant through the entire s p e e d range o f the motor. If the turbine m o t o r is lifted off the b o t t o m o f the b o r e h o l e and circulation continues, the m o t o r will s p e e d up to the runaway speed o f 1,614 rpm. In this situation the m o t o r p r o d u c e s no drilling torque or horsepower. As the t u r b i n e m o t o r is lowered a n d weight is placed on the m o t o r and thus the bit, the m o t o r begins to slow its speed and p r o d u c e torque and horsepower. W h e n sufficient weight has b e e n placed on the t u r b i n e motor, the e x a m p l e m o t o r will p r o d u c e its m a x i m u m possible horsepower o f 217. This will be at a speed o f 807 rpm. T h e torque p r o d u c e d by the m o t o r at this speed will be 1,412 ft-lb. If m o r e weight is a d d e d to the turbine m o t o r and the bit, the m o t o r speed and h o r s e p o w e r o u t p u t will continue to decrease. T h e torque, however, will continue to increase. W h e n sufficient weight has b e e n placed on the turbine m o t o r and bit, the m o t o r will cease to rotate and the m o t o r is d e s c r i b e d as being stalled. At this condition, the turbine m o t o r produces its m a x i m u m possible torque. Even when the m o t o r is stalled, the drilling m u d is still circulating and the pressure d r o p is approximately 1,324 psi.

868

Drilling and Well Completions

The stall torque Ms (ft-lb) for any turbine motor can be determined from [86] ~ q h~q m n s /~m ~ l 2 tan 13 M s = 1.38386x 10-5 O h

where

]]h =

]~m = ns= Ym = q = 13 = h =

(4-138)

hydraulic efficiency mechanical efficiency n u m b e r of stages specific weight of m u d in l b / g a l circulation flowrate in g a l / m i n exit blade angle in degrees radial width of the blades in in.

Figure 4-193 is the side view of a single-turbine stage and describes the geometry of the rotor and stator. The runaway speed N (rpm) for any t u r b i n e motor can be d e t e r m i n e d from N r = 5.85

llvq tan[3 r2mh

(4-139)

where ~v = volumetric efficiency r m = mean blade radius in in. The t u r b i n e motor instantaneous torque M (ft-lb) for any speed N (rpm) is

The t u r b i n e motor horsepower HP (hp) for any speed is

33,000

(4-141)

The m a x i m u m t u r b i n e motor horsepower is at the o p t i m u m speed, N o, which is one-half of the runaway speed. This is No = ~Nr

(4-142)

Thus the m a x i m u m horsepower HPm~x is HPm~

_

rcMsN r

2(33,000)

(4-143)

The torque at the o p t i m u m speed M0 is one-half the stall torque. Thus M 0 ~.~ M s

2

(4-144)

Downhole Motors

869

-4 Stator

Rotor

/)/)/) \\\

Figure 4-193. Turbine rotor and stator geometry of a single stage. (Courtesy Smith International, Inc.)

The pressure drop Ap (psi) through a given turbine motor design is usually obtained empirically. Once this value is known for a circulation flowrate and mud weight, the pressure drop for other circulation flowrates and mud weights can be estimated. If the above performance parameters for a turbine motor design are known for a given circulation flowrate and mud weight (denoted as 1), the performance parameters for the new circulation flowrate and mud weight (denoted as 2) can be found by the following relationships: Torque

Mz = q z \ql )

M 1

(4-145)

Speed

Nz = \(qz IN1 qI)

(4-147)

870

Drilling and Well Completions

Power

HP 2 =

HP I

(4-148)

HP2 = ('~2 ]HPI

(4-149)

Pressure drop

Ap2

= kqi (q2 ]2Apl )

(4-150)

Table 4-110 gives the performance characteristics for various circulation flowrates for the 212-stage, 6~-in. outside diameter turbine motor described briefly in Table 4-109 and shown graphically in Figure 4-192. Table 4-111 gives the performance characteristics for various circulation flowrates for the 318-stage, 6¼-in. outside diameter turbine motor described briefly in Table 4-109. Figure 4-194 shows the performance of the 318-stage turbine motor at a circulation flowrate of 400 gal/min and mud weight of 10 lb/gal. The turbine motor whose performance characteristics are given in Table 4-110 is made up of two motor sections with 106 stages in each section. The turbine motor whose performance characteristics are given in Table 4-111 is made up of three motor sections.

Table 4-110 Turbine Motor, 63,~-in. Outside Diameter, Two Motor Sections, 212 Stages, Mud Weight 10 Ib/gal Circulation Rate (gpm) 200 250 300 350 400 450 500

Torque* (ft-lbs)

Optimum Bit Speed (rpm)

Differential Pressure (psi)

Maximum Horsepower*

Thrust Load (1000 Ibs)

353 552 794 1081 1421 1787 2206

403 504 605 706 807 908 1009

331 517 745 1014 1324 1676 2069

27 53 92 145 217 309 424

5 8 12 16 21 26 32

*At optimumspeed CourtesyEastman-Christensen

Downhole Motors

871

Table 4-111 T u r b i n e Motor, 6%-in. O u t s i d e Diameter, T h r e e M o t o r Sections, 318 Stages, Mud Weight 10 Ib/gal Circulation Rate (gpm) 200 250 300 350 400 450

Torque* (ft-lbs)

Optimum Bit Speed (rpm)

Differential Pressure (psi)

Maximum Horsepower*

Thrust Load (1000 Ibs)

529 827 1191 1622 2118 2681

403 504 605 706 807 908

485 758 1092 1486 1941 2457

40 79 137 218 326 464

8 12 17 23 30 38

*At optimumpower Courtesy Eastman-Christensen

Circulation Rate 400 gpm Mud Weight 10 ppg 5OO0

2500

500

4OOO

-~

Pressure

--

400

2o0o

¢L

£

3000

300

--

1500 ~

--

lOOO~

I

" ~ Horsepower "

o

~" 2000

200

2

a

1000

Torque

500

1000

100

1500

--

500

2000

Bit Speed (rpm) Figure 4-194. Turbine motor, 6¾-in. outside diameter, three motor sections, 318 stages, 400 gal/mfn, 10-1b/gal mud weight. (Courtesy Eastman-Christensen.)

872

Drilling and Well C o m p l e t i o n s

The major reason most turbine motors are designed with various add-on motor sections is to allow flexibility when applying turbine motors to operational situations. For straight hole drilling the turbine m o t o r with the highest possible torque and the lowest possible speed is o f most use. Thus the turbine m o t o r is selected such that the m o t o r p r o d u c e s the m a x i m u m amount o f power for the lowest possible circulation flowrate (i.e., lowest speed). T h e high power increases rate o f p e n e t r a t i o n and the lower speed increases bit life particularly if roller rock bits are used. For deviation control drilling the turbine m o t o r with a lower torque and the shortest overall length is needed.

Example 1 Using the basic p e r f o r m a n c e d a t a given in Table 4-110 for the 6¼-in. outside d i a m e t e r turbine m o t o r with 212 stages, d e t e r m i n e the stall torque, m a x i m u m horsepower and pressure d r o p for this m o t o r if only one m o t o r section with 106 stages were to be used for a deviation control o p e r a t i o n . Assume the same circulation flow rate o f 400 g a l / m i n , but a mud weight o f 14 l b / g a l is to be used.

Stall Torque, From Table 4-110 the stall torque for the t u r b i n e m o t o r with 212 stages will be twice the torque value at o p t i m u m speed. Thus the stall torque for 10 l b / g a l m u d weight flow is M s = 2(1421) = 2,842 ft-lb From Equation 4-138 it is seen that stall torque is p r o p o r t i o n a l to the n u m b e r o f stages used. Thus the stall torque for a turbine m o t o r with 106 stages will be (for the circulation flowrate o f 400 g a l / m i n and m u d weight o f 10 l b / g a l )

Ms = 2,842( 106 k, 212) = 1,421 ft-lb and from Equation 4-146 for the 14-1b/gal m u d weight

1 = 1,989 ft-lb

Maximum Horsepower. From Table 4-110 the m a x i m u m horsepower for the t u r b i n e m o t o r with 212 stages is 217. From Equation 4-143 it can be seen that the m a x i m u m power is p r o p o r t i o n a l to the stall torque and the runaway speed. Since the circulation flowrate is the same, the runaway speed is the same for this case. Thus, the maximum, h o r s e p o w e r will be p r o p o r t i o n a l to the stall torque. T h e m a x i m u m power will be (for the circulation f l o w r a t e o f 400 g a l / rain and m u d weight o f 10 l b / g a l )

Downhole Motors

873

HP~,~ = 217( 1421 \ 2842 J = 108.5 and from Equation 4-149 for the 14-1b/gal m u d weight

) = 152

P r e s s u r e D r o p . Table 4-110 shows that the 212-stage t u r b i n e m o t o r has a pressure d r o p of 1,324 psi for the circulation flowrate of 400 g a l / m i n and a m u d weight of 10 l b / g a l . T h e pressure d r o p for the 106 stage turbine m o t o r should be roughly p r o p o r t i o n a l to the length of the m o t o r section (assuming the motor sections are nearly the same in design). Thus the pressure d r o p in the 106-stage t u r b i n e m o t o r s h o u l d b e p r o p o r t i o n a l to t h e n u m b e r o f stages. Therefore, the pressure d r o p should be

= 662 psi a n d from Equation 4-151 for the 14-1b/gal m u d weight

= 927 psi T h e last column in Tables 4-110 and 4-111 show the thrust l o a d associated with each circulation flowrate (i.e., pressure drop). This thrust l o a d is the result of the pressure d r o p across the t u r b i n e m o t o r rotor a n d stator blades. T h e m a g n i t u d e of this p r e s s u r e d r o p d e p e n d s on the i n d i v i d u a l internal d e s i g n details of the t u r b i n e m o t o r (i.e., blade angle, n u m b e r of stages, axial height of blades and the radial width of the blades) a n d the o p e r a t i n g conditions. T h e a d d i t i o n a l pressure d r o p results in thrust, T (lb), which is T = nr~Ap

(4-152)

Example 2 A 6 ~-in. outside diameter turbine motor (whose performance data are given in Tables 4-110 and 4.111) is to be used for a deviation control direction drilling operation. The m o t o r will use a new 8 ~-in. d i a m e t e r d i a m o n d bit for the d r i l l i n g operation. The directional run is to take place at a d e p t h of 17,552 ft (measured

874

Drilling and Well C o m p l e t i o n s

depth). The rock formation to be drilled is classified as extremely hard, and it is anticipated that 10 f t / h r will be the maximum possible drilling rate. The mud weight is to be 16.2 lb/gal. The drilling rig has a National Supply Company, triplex mud p u m p Model 10-P-130 available. The details of this pump are given in Table 4-112 (also see the section titled "Mud Pumps" for more details). Because this is a deviation control run, the shorter two motor section turbine motor will be used. D e t e r m i n e the a p p r o p r i a t e circulation flowrate to be used for the d i a m o n d bit, t u r b i n e m o t o r c o m b i n a t i o n and the a p p r o p r i a t e liner size to be used in the triplex pump. Also, prepare the turbine motor performance g r a p h for the chosen circulation flowrate. Determine the total flow area for the d i a m o n d bit.

Bit Pressure Loss. To obtain the o p t i m u m circulation flowrate for the d i a m o n d bit, turbine m o t o r c o m b i n a t i o n , it will be necessary to consider the bit and the turbine m o t o r p e r f o r m a n c e at various circulation flowrates: 200, 300, 400 and 500 g a l / m i n . Since the rock f o r m a t i o n to be d r i l l e d is classified as extremely hard, 1.5 hydraulic horsepower p e r square inch o f bit area will be used as bit cleaning and cooling requirement [87]. The projected bottomhole area of the bit A~ (in. 2) is Ab = 4 ( 8 . 5 ) 2 = 56.7 in. z For a circulation flowrate o f 200 g a l / m i n , the hydraulic horsepower for the bit HP b (hp) is HP b = 1.5 (56.7) = 85.05 T h e pressure d r o p across the bit Apb (psi) to p r o d u c e this hydraulic horsepower at a circulation flowrate of 200 g a l / m i n is Ap b _ 85.05(1,714) 200 = 729 psi

Table 4-112 Triplex Mud Pump, Model 10-P-13 National Supply Company, Example 2 Input Horsepower 1300, Maximum Strokes per Minute, 140 Length of Stroke, 10 Inches

Liner Size (inches)

Output per Stroke (gals) Maximum Pressure (psi)

51/~

51/2

5%

6

61/4

2.81 5095

3.08 4645

3.37 4250

3.67 3900

3.98 3595

Downhole Motors

875

Similarly, the pressure drop across the bit to p r o d u c e the above hydraulic horsepower at a circulation flowrate of 300 g a l / m i n is

~Pb =

85.05(1,714) 3OO

= 486 psi The pressure drop across the bit at a circulation flowrate of 400 l b / g a l is Apb = 364 psi The pressure drop across the bit at a circulation flowrate of 500 g a l / m i n Apb = 292 psi

Total Pressure Loss. Using Table 4-110 a n d Equations 4-150 a n d 4-151, the pressure loss across the t u r b i n e m o t o r can be d e t e r m i n e d for the various circulation flowrates a n d the m u d weight of 16.2 l b / g a l . These data together with the above bit pressure loss data are presented in Table 4-113. Also presented in Table 4-113 are the c o m p o n e n t pressure losses of the system for the various circulation flowrates considered. The total pressure loss tabulated in the lower row represents the surface ,standpipe pressure when o p e r a t i n g at the various circulation flowrates.

Pump Limitations. Table 4-112 shows there are five possible liner sizes that can be used on the Model 10-P-130 m u d pump. Each liner size must be considered to obtain the o p t i m u m circulation flowrate a n d a p p r o p r i a t e liner size. The maximum pressure available for each liner size will be reduced by a safety factor of 0.90.* The m a x i m u m volumetric flowrate available for each liner size will also be reduced by a volumetric efficiency factor of 0.80 a n d an additional safety factor of 0.90.** Thus, from Table 4-112, the allowable m a x i m u m pressure a n d allowable maximum volume, metric flowrates will be those shown in Figures 4-195 through 4-199, which are the liner sizes 5 ¼, 5-~, 5 ~, 6 a n d 6 ¼ in., respectively. Plotted on each of these figures are the total pressure losses for the various circulation flowrates considered. The horizontal straight line on each figure is the allowable m a x i m u m pressure for the p a r t i c u l a r l i n e r size. The vertical straight line is the allowable m a x i m u m volumetric flowrate for the particular liner size. Only circulation flowrates that are in the lower left quadrant of the figures are practical. The highest circulation flowrate (which produces the highest t u r b i n e motor horsepower) is found in Figure 4-197, the 5 ~-in. liner. This optimal circulation flowrate is 340 g a l / m i n . Turbine Motor Performance. Using the t u r b i n e motor p e r f o r m a n c e data in Table 4-110 a n d the scaling relationships in Equations 4-145 through 4-151, the performance graph for the t u r b i n e motor o p e r a t i n g with a circulation flowrate of 340 g a l / m i n a n d m u d weight of 16.2 l b / g a l can be prepared. This is given in Figure 4-200.

*This safety factor is not necessary for new, well-maintainedequipment. **The volumetric efficiency factor is about 0.95 for precharged pumps.

876

Drilling and Well Completions Table 4-113 Drill String Component Pressure Losses at Various Circulation Flowretea for Example 2 Pressure (psi)

Components

200 gpm

300 gpm

400 gpm

500 gpm

4 460 60 536 729 48 133

11 878 117 1207 486 91 248

19 1401 118 2145 364 144 391

31 2021 272 3352 292 207 561

1970

3038

4652

6736

Surface Equipment Drill Pipe Bore Drill Collar Bore Turbine Motor Drill Bit Drill Collar Annulus Drill Pipe Annulus

Total Pressure Loss

Total Flow Area for Bit. Knowing the optimal circulation flowrate, the actual pressure loss across the bit can be found as before in the above. This is

Apb =

85.05(1,714) 340

= 429 psi With the flowrate and pressure loss across the bit, the total flow area of the d i a m o n d bit Atf (in?) can be found using [88]

~Pb =

q27 m 8795 Ade -°'832 ROP Nb

(4-153)

where ROP = rate of penetration in f t / h r N b = bit speed in rpm The bit speed will be the optimum speed of the turbine motor, 685 rpm. The total flow area Atf for the d i a m o n d bit is I (340) 16.2 T/2 A~f = [ _ ~ j 0.179

= 0.713 in. 2

(text continued on page 882)

Downhole Motors P all

=

877

4586 psi

q all = 283 gpm

8000

6000 t/) t/) t/)

o, 4 t/) t/)

4000

0_

0 !--

2000

I

I

200

I

400 q (gpm)

Figure 4-195. 51/4-in.liner,total pressure loss versus flowrate, Example 2.

(Courtesy Smith International, Inc.)

t 600

878

Drilling and Well Completions Pall = 4181 psi qalt = 310 gpm

8000

6000

~3

/o 4000 P

Q.

o

2000

I

I

200

I 400

I

I 600

q (gpm) Figure 4-196. 51/2-in. liner, total pressure loss versus flowrate, Example 2.

(Courtesy Smith International, Inc.)

Downhole Motors

879

P a, = 3825 psi O alI = 340 g p m _ 8000

6000

U) U)

o,

U) U)

I

4000

n 0

I-

2000

t

I

I

I

400

200

q (gpm)

Figure 4-197. 5%-in. liner, total pressure loss versus flowrate, Example 2.

(Courtesy Smith /nternational, /nc.)

I 600

880

Drilling and Well Completions Pall = 3510 psi q all = 370 gpm

8000

6000

¢/) 0'~ 0 ...J

¢./)

I 4000

2 Q.. 0 I--

2000

I

I

i

200

I

1

400

q (gpm)

Figure 4-198. 6-in. liner, total pressure loss versus flowrate, Example 2. (Courtesy Smith /nternational, Inc.)

I 600

Downhole Motors

881

Pall = 3236 psi -Qall = 401 g p m

8000

6000

,_q l

0 _1

I 4000 D.

2000

I

I

I

I 400

200 q (gpm)

Figure 4-199. 61/4-in.liner,total pressure loss versus flowrate, Example 2.

(Courtesy Smith International,Inc.)

600

882

Drilling a n d Well C o m p l e t i o n s

4000

Circulation Rate 340 gpm Mud Weight 16.2 ppg

n

Pressure

3000

400

2000

300

1500

°~iep°w°~

2000

1000

200

1000

100

500

.= i

0 500

1000

1500

2000

Bit Speed (rpm)

Figure 4-200. Turbine motor, 63/4-in. outside diameter, two motor sections, 212 stages, 340 gal/min, 16.2-1b/gal mud weight, Example 2. (Courtesy Smith

International, Inc.)

(text continued from page 876)

Positive Displacement Motor F i g u r e 4-201 shows the typical r i g i d r o t o r a n d f l e x i b l e e l a s t o m e r s t a t o r c o n f i g u r a t i o n for a single c h a m b e r o f a m u h i c h a m b e r e d d o w n h o l e positive displacement m o t o r section. All the positive d i s p l a c e m e n t motors presently in commercial use are o f Moineau type, which uses a stator m a d e o f an elastomer. T h e rotor is m a d e o f a rigid material such as steel and is fabricated in a helical shape. T h e activating drilling mud, freshwater, a e r a t e d mud, foam or misted air is p u m p e d at r a t h e r high velocity t h r o u g h the m o t o r section, which, because o f the eccentricity o f the rotor and stator c o n f i g u r a t i o n , and the flexibility o f the stator, allows the hydraulic pressure o f the flowing f l u i d to i m p a r t a torque to the rotor. As the rotor rotates the f l u i d is passed from c h a m b e r to c h a m b e r (a c h a m b e r is a lengthwise r e p e a t o f the motor). T h e s e c h a m b e r s are s e p a r a t e entities a n d as one opens up to accept f l u i d from the preceding, the p r e c e d i n g closes up. This is the concept o f the positive displacement motor.

Deslgn T h e rotational energy o f the positive displacement m o t o r is p r o v i d e d by the flowing fluid, which rotates and i m p a r t s torque to the drill bit. Figure 4-202 shows the typical complete d o w n h o l e positive displacement motor.

Downhole Motors

883

Figure 4-201. Basic positive displacement motor design principle. (Courtesy Smith International, Inc.) In general, the d o w n h o l e positive d i s p l a c e m e n t m o t o r c o n s t r u c t e d on the Moineau principle is c o m p o s e d of four sections: (1) the d u m p valve section, (2) the multistage m o t o r section, (3) the connecting r o d section and (4) the thrust a n d radial-bearing section. These sections are shown in Figure 4-202. Usually t h e positive d i s p l a c e m e n t m o t o r has m u l t i c h a m b e r s , however, t h e n u m b e r of chambers in a positive displacement m o t o r is much less than the n u m b e r of stages in a turbine motor. A typical positive displacement m o t o r has from two to seven chambers. T h e d u m p valve is a very important feature of the positive displacement motor. T h e positive d i s p l a c e m e n t m o t o r d o e s not p e r m i t f l u i d to flow t h r o u g h the m o t o r unless the m o t o r is rotating. Therefore, a d u m p valve at the top of the m o t o r allows drilling f l u i d to be circulated to the annulus even if the m o t o r is not rotating. Most d u m p valve designs allow the f l u i d to circulate to the annulus when the pressure is below a certain threshold, say below 50 psi or so. Only when the surface p u m p is o p e r a t e d does the valve close to force all f l u i d t h r o u g h the motor. The multichambered motor section is c o m p o s e d of only two continuous parts, the r o t o r a n d the stator. A l t h o u g h they are c o n t i n u o u s parts, they usually constitute several chambers. In general, the l o n g e r the m o t o r section, the m o r e chambers. The stator is an elastomer tube f o r m e d to be the inside surface of a rigid cylinder. This elastomer tube stator is of a special material and shape. T h e material resists abrasion and damage from drilling muds containing cuttings and hydrocarbons. The inside surface of the stator is of an oblong, helical shape. T h e rotor is a rigid steel r o d s h a p e d as a helix. T h e rotor, when assembled into the stator and its outside rigid housing, provides continuous seal at contact points between the outside surface of the rotor and the inside surface of the stator (see Figure 4-201). T h e rotor or driving shaft is m a d e up of n r lodes. T h e

884

Drilling and Well Completions

~mp

Conr~tl~ R~

Th~ot ~ d P ~ a i

~ctlon

Figure 4-202. Downhole positive displacement motor design. (Courtesy Smith

International, Inc.)

Downhole Motors

885

stator is m a d e up o f n s lodes, which is equal to one lobe m o r e than the rotor. Typical cross-sections o f positive displacement motor lobe profiles are shown in Figure 4-203. As drilling f l u i d is p u m p e d t h r o u g h the cavities in each c h a m b e r that lies o p e n between the stator and rotor, the pressure o f the flowing f l u i d causes the rotor to rotate within the stator. T h e r e are several chambers in a positive displacement motor because the chambers leak fluid. If the first chamber d i d not leak when o p e r a t i n g , there would be no n e e d for additional chambers. In general, the larger lobe profile n u m b e r ratios o f a positive displacement motor, the higher the torque output and the lower the s p e e d (assuming all o t h e r design limitations remain the same). T h e rotors are eccentric in their rotation at the b o t t o m o f the m o t o r section. Thus, the connecting rod section provides a flexible coupling between the rotor and the main drive shaft located in the thrust and radial b e a r i n g section. T h e main drive shaft has the drill bit c o n n e c t e d to its b o t t o m end. T h e thrust and radial-bearing section contains the thrust bearings that transfer the weight-on-bit to the outside wall o f the positive displacement motor. T h e radial s u p p o r t bearings, usually l o c a t e d above the thrust bearings, ensure that the main drive shaft rotates about a fixed center. As in most t u r b i n e m o t o r designs, the bearings are cooled by the drilling fluid. T h e r e are some recent positive displacement m o t o r designs that are now using grease-packed, sealed b e a r i n g assemblies. T h e r e is usually a smaller u p p e r thrust b e a r i n g that allows rotation o f the m o t o r while pulling out o f the hole. This u p p e r thrust b e a r i n g is usually at the u p p e r e n d o f thrust and radial b e a r i n g section. T h e r e are, o f course, variations on the downhole positive displacement m o t o r design, but the basic sections discussed above will be c o m m o n to all designs. T h e main advantages o f the d o w n h o l e positive displacement m o t o r are: 1. Soft, m e d i u m a n d h a r d rock f o r m a t i o n s can be d r i l l e d with a positive displacement m o t o r using nearly any type o f rock bit. T h e positive displacement m o t o r is especially a d a p t a b l e to drilling with roller rock bits. 2. R a t h e r m o d e r a t e flow rates and pressures are r e q u i r e d to o p e r a t e the positive displacement motor. Thus, most surface p u m p systems can be used to o p e r a t e these d o w n h o l e motors. 3. Rotary s p e e d o f the positive displacement m o t o r is directly p r o p o r t i o n a l to flowrate. Torque is directly proportional to pressure. Thus, normal surface instruments can be used to m o n i t o r the o p e r a t i o n o f the m o t o r downhole. 4. High torques and low speeds are obtainable with certain positive displacement motor designs, particularly, the higher lobe profiles (see Figure 4-203). 5. Positive displacement motors can be o p e r a t e d with a e r a t e d muds, foam and air mist.

1,2

3,4

5,6

7,8

9,10

Figure 4-203. Typical positive displacement motor lobe profiles. (Courtesy Smith International, Inc.)

886

Drilling and Well Completions

The main disadvantages of the downhole positive displacement motors are: 1. When the rotor shaft of the positive displacement motor is not rotating, the surface pump pressure will rise sharply and little fluid will pass through the motor. 2. The elastomer of the stator can be damaged by high temperatures and some hydrocarbons.

Operations Figure 4-204 gives the typical p e r f o r m a n c e characteristics o f a positive displacement motor. The example in this figure is a 6¼-in. outside diameter positive displacement motor having five chambers activated by a 400-1b/gal flowrate of drilling mud. For this example, a pressure of about 100 psi is required to start the rotor shaft against the internal friction of the rotor moving in the elastomer stator (and the bearings). With constant flowrate, the positive displacement motor will run at or near constant speed. Thus, this 1:2 lobe profile example motor has an

Circulation Rate 4 0 0 gpm

2600

7

2400

110

2000

100

(

Bit Speed

5O0

90

1600

b

120

2200

1800

o £ !

130

400

80

Horsepower

f=

70

1400

i

1200 1000

so=~

8OO

4O

6OO

30

400

20

200

10

300

m

200

100

0 100

2~

300

400

500

600

Differential Pressure (psi)

Figure 4-204. Positive displacement motor, 6%-in. outside diameter, 1:2 lobe profile, 400 gal/min, differential pressure limit 580 psi. (Courtesy Smith

/nternational, /nc.)

Downhole Motors

887

operating speed of 408 rpm. The torque a n d the horsepower of the positive displacement motor are both linear with the pressure drop across the motor. Therefore, as more weight is placed on the drill bit (via the motor), the greater is the resisting torque of the rock. The m u d p u m p s can compensate for this increased torque by increasing the pressure on the constant flowrate through the motor. In this example the limit in pressure drop across the motor is about 580 psi. Beyond this limit there will be either extensive leakage or damage to the motor, or both. If the positive displacement motor is lifted off the bottom of the borehole and circulation continues, the motor will simply continue to rotate at 408 rpm. The differential pressure, however, will drop to the value necessary to overcome internal friction a n d rotate, about 100 psi. In this situation the motor produces no drilling torque or horsepower. As the positive displacement motor is lowered a n d weight is placed on the motor a n d thus the bit, the motor speed continues but the differential pressure increases, resulting in an increase in torque a n d horsepower. As more weight is added to the positive displacement motor a n d bit, the torque a n d horsepower will c o n t i n u e to increase with increasing differentiated pressure (i.e., standpipe pressure). The a m o u n t of torque a n d power can be d e t e r m i n e d by the pressure change at the standpipe at the surface between the u n l o a d e d condition a n d the loaded condition. If too much weight is placed on the motor, the differential pressure limit for the motor will be reached a n d there will be leakage or a mechanical failure in the motor. The rotor of the Moineau-type positive d i s p l a c e m e n t motor has a helical design. The axial wave n u m b e r of the rotor is one less than the axial wave n u m b e r for the stator for a given chamber. This allows the formation of a series of fluid cavities as the rotor rotates. The n u m b e r of stator wave lengths n a n d the n u m b e r of rotor wave lengths n per c h a m b e r are related by [79,86] n = nr + 1

(4-154)

The rotor is designed much like a screw thread. The rotor pitch is equivalent to the wavelength of the rotor. The rotor lead is the axial distance that a wave advances d u r i n g one full revolution of the rotor. The rotor pitch a n d the stator pitch are equal. The rotor lead a n d stator lead are p r o p o r t i o n a l to t h e i r respective n u m b e r of waves. Thus, the relationship between rotor pitch t (in.) a n d stator pitch, t (in.) is [86] t = t The rotor lead

(4-155) Lr

(in.) is

L r = nrt r

(4-156)

The stator lead L (in.) is L = nt

(4-157)

The specific displacement per revolution of the rotor is equal to the crosssectional area of the fluid multiplied by the distance the fluid advances. The specific displacement s (in. s) is s = nrnstrA

(4-158)

888

Drilling a n d Well Completions

where A is the fluid cross-sectional area (in2). The f l u i d cross-sectional area is approximately A -- 2ne~(n~ - 1)

(4-159)

where e is the rotor rotation eccentricity (in.). The special case of a 1:2 lobe profile motor has a f l u i d cross-sectional area of A --- 2 e d

(4-160)

where d r is the reference diameter of the motor (in.). The reference diameter is d r = 2ern s

(4-161)

For the 1:2 lobe profile motor, the reference diameter is approximately equal to the diameter of the rotor shaft. The instantaneous torque of the positive displacement motor M (ft-lb) is M = 0.0133s ApT1

(4-162)

where Ap = differential pressure loss through the motor in psi TI = total efficiency of the motor. The 1:2 lobe profile motors have efficiencies a r o u n d 0.80. T h e higher lobe profile motors have efficiencies that are lower (i.e., of the order of 0.70 or less) The instantaneous speed of the positive displacement motor N (rpm) is 231.016q N = - -

(4-163)

where q is the circulation flowrate ( g a l / m i n ) . The positive displacement motor horsepower HP (hp) for any speed is

He = qAp_ 1,714 q

(4-164)

The n u m b e r of positive displacement motor chambers n c is L n~ = 2- - (n, - 1) t,

(4-165)

where L is the length of the actual motor section (in.). The maximum torque M will be at the maximum differential pressure A p ~ , which is Mm~ = 0.133s ApmJl

(4-166)

The m a x i m u m horse power HPm~ will also be at the m a x i m u m differential pressure Apm~, which is

Downhole Motors

889

(4-167)

HP,.~, = q A p ~ T1 1,714

It should be noted that the positive displacement motor performance parameters are independent of the drilling mud weight. Thus, these performance parameters will vary with motor design values and the circulation flowrate. If the above performance parameters for a positive displacement motor design are known for a given circulation flowrate (denoted as 1), the performance parameters for the new circulation flowrate (denoted as 2) can be found by the following relationships: Torque M2 = M 1

(4-168)

Speed

N~ = (q~/N,

(4-169)

\q,)

Power

.170, Table 4-114 gives the p e r f o r m a n c e characteristics for various circulation flowrates for the 1:2 lobe profile, 6 ~-in. outside diameter positive displacement motor. Figure 4-204 shows the performance of the 1:2 lobe profile positive displacement motor at a circulation flowrate of 400 gal/min.

Table 4-114 Positive Displacement Motor, 6¾-in. Outside Diameter, 1:2 Lobe Profile, Five Motor Chambers Circulation Rats (gpm) 200 250 300 350 400 450 500

Speed (rpm)

Maximum Differential Pressure (psi)

Maximum Torque (ft-lbs)

Maximum Horsepower

205 255 306 357 408 460 510

580 580 580 580 580 580 580

1500 1500 1500 1500 1500 1500 1500

59 73 87 102 116 131 145

Courtesy Eastman-Christensen

890

Drilling a n d Well C o m p l e t i o n s

Table 4-115 gives the p e r f o r m a n c e c h a r a c t e r i s t i c s for various c i r c u l a t i o n flowrates for the 5:6 lobe profile, 6 ~-in. outside d i a m e t e r positive displacement motor. Figure 4-205 shows the p e r f o r m a n c e o f the 5:6 lobe p r o f i l e positive displacement m o t o r at a circulation flow rate o f 400 g a l / m i n . T h e positive displacement m o t o r whose p e r f o r m a n c e characteristics are given in Table 4-114 is a 1:2 lobe profile motor. This lobe p r o f i l e design is usually used for deviation control operations. The 1:2 lobe profile design yields a downhole m o t o r with high rotary speeds a n d low torque. Such a c o m b i n a t i o n is very desirable for the directional driller. T h e low torque minimizes the c o m p e n s a t i o n that must be m a d e in course p l a n n i n g which must be m a d e for the reaction torque in the lower part o f the drill string. This reactive torque when severe can create difficulties in deviation control planning. The t r a d e o f f is, however, that higher speed reduces the bit life, especially roller rock bit life. The positive displacement m o t o r whose p e r f o r m a n c e characteristics are given in Table 4-115 is a 5:6 lobe profile motor. This lobe profile design is usually used for straight hole drilling with roller rock bits, or for deviation control o p e r a t i o n s where high torque polycrystalline d i a m o n d c o m p a c t bit or d i a m o n d bits are used for deviation control operations. Example 3

A 6¼-in. outside d i a m e t e r positive displacement m o t o r o f a 1:2 lobe profile design (where p e r f o r m a n c e data are given in Table 4-114) has rotor eccentricity o f 0.60 in., a reference d i a m e t e r (rotor shaft diameter) o f 2.48 in. and a rotor pitch o f 38.0 in. If the pressure drop across the motor is determined to be 500 psi at a circulation flowrate o f 350 g a l / m i n with 12.0 l b / g a l , find the torque, rotational speed a n d the horsepower o f the motor. Torque. Equation 4-160 gives the fluid cross-sectional area o f the motor, which is

A = 2(0.6)(2.48) = 2.98 in. 2 Equation 4-159 gives the specific displacement o f the motor, which is

Table 4-115 Positive Displacement Motor, 6%-in. Outside Diameter, 5:6 Lobe Profile, Five Motor Chambers Circulation Rate (gpm) 200 250 300 350 400

Speed (rpm)

Maximum Differential Pressure (psi)

Maximum Torque (ft-lbs)

Maximum Horsepower

97 122 146 170 195

580 580 580 580 580

2540 2540 2540 2540 2540

47 59 71 82 94

CourtesyEastman-Christensen

Downhole Motors

891

Circulation Rate 400 gpm 2600

130

2400

120 110

2200 Torque 2OOO

100

1800

90

1600

80

1400

70

50O

4OO E

~ 3oo=~

Horsepower

1200

4,,

z

h-

(

1000 8OO

40

6OO

30

4OO

20

200

10

0

1~

m

5O

Bit Speed

I

J

I

I

2~

3~

400

500

I

200

100

0

600

Differential Pressure (psi)

Figure 4-205. Positive displacement motor, 6¾-in. outside diameter, 5:6 lobe profile, 400 gal/min, differential pressure limit 580 psi. (Courtesy Smith

International, Inc.)

s = (1)(2)(38.0)(2.98) = 226.5 i n ? T h e torque is obtained from Equation 4-162, assuming an efficiency o f 0.80 for the 1:2 lobe profile motor. This is M = 0.0133(226.5)(500)(0.80) = 1205 ft-lb S p e e d . T h e rotation speed is obtained from Equation 4-163. This is N = 231.016(350) 226.5 = 357 rpm

892

Drilling and Well Completions

Horsepower. T h e horsepower the m o t o r p r o d u c e s is o b t a i n e d from Equation 4-164. This is HP - 350(500)(0.80) 1714 = 82

Planning for a positive displacement m o t o r run and actually drilling with such a m o t o r is easier than with a turbine motor. This is mainly due to the fact that when a positive displacement m o t o r is being o p e r a t e d , the o p e r a t o r can know the o p e r a t i n g torque and rotation speed via surface data. T h e standpipe pressure will yield the pressure drop through the motor, thus the torque. T h e circulation flowrate will yield the rotational speed.

Example 4 A 6 ~-in. outside d i a m e t e r positive displacement m o t o r (whose p e r f o r m a n c e data are given in Tables 4-114 and 4-115) is to be used for a deviation control direction drill operation. T h e motor will use an 8 ~-in. diameter roller rock bit for the drilling operation. T h e directional run is to take place at a depth o f 10,600 ft (measured depth). The rock formation to be drilled is classified as medium, and it is anticipated that 30 f t / h r will be the maximum possible drilling rate. T h e m u d weight is to be 11.6 l b / g a l . T h e drilling rig has a National Supply Company duplex m u d p u m p Model E-700 available. T h e details o f this p u m p are given in Table 4-116 (also see the section titled "Mud Pumps"). Because this is a deviation control run, the 1:2 lobe profile positive displacement m o t o r will be used since it has the lowest torque for a given circulation flowrate (see Table 4-114). Determine the appropriate circulation flowrate to be used for the roller rock bit, positive displacement motor combination and the appropriate liner size to be used in the duplex pump. Also, p r e p a r e the positive displacement m o t o r p e r f o r m a n c e g r a p h for the chosen circulation flowrate. Determine the bit nozzle sizes.

Bit Pressure Loss. It is necessary to choose the bit pressure loss such that the thrust load created in combination with the weight on bit will yield an on-bottom load on the m o t o r thrust bearings, which is less than the maximum allowable load for the bearings. Since this is a deviation control r u n and, therefore, the m o t o r will be drilling only a relatively short time and distance, the m o t o r thrust bearings will be o p e r a t e d at their maximum rated load for on-bottom operation. Figure 4-206 shows that maximum allowable m o t o r thrust b e a r i n g load is about

Table 4-116 Duplex Mud Pump, Model E-700, National Supply Company, Example 4 Input Horsepower 825, Maximum Strokes per Minute, 65 Length of Stroke, 16 Inches

Output per Stroke (gals) Maximum Pressu re (psi)

53/4

6

61/4

61/2

63/4

7

6.14 3000

6.77 2450

7.44 2085

8.13 1780

8.85 1535

9.60 1260

Downhole Motors

OFFBOTTOMBEARINGLOAD(1000 LBS

893

MAXIMUMRECOMMENDEDBEARINGLOAD

INDICATEDWEIGHTX 1000 LBS. ~750 ~_~500

PSI RECOMMENDED BIT PSI P RESSURE DIFFERENTIAL 0 PSI ] 150 500PSI

\\,,< 5 10 ON BOTTOMBEARINGLOAD(1000 LBS)

20 15 MAXIMUMRECOMMENDEDBEARINGLOAD

Figure 4-206. Hydraulic thrust and indicated weight balance for positive displacement motor. (Courtesy Smith International, Inc.)

6,000 lb. To have the m a x i m u m weight on bit, the m a x i m u m r e c o m m e n d e d bit pressure loss of 500 psi will be used. This will give m a x i m u m weight on bit of about 12,000 lb. The higher bit pressure loss will, of course, give the higher cutting face cleaning via j e t t i n g force (relative to the lower r e c o m m e n d e d bit pressure losses).

Total Pressure Loss. Since bit life is not an issue in a short deviation control motor r u n operation, it is desirable to operate the positive displacement motor at as high a power level as possible d u r i n g the run. The motor has a m a x i m u m pressure loss with which it can operate. This is 580 psi (see Table 4-114). It will be assumed that the motor will be operated at the 580 psi pressure loss in order to maximize the torque output of the motor. To obtain the highest horsepower for the motor, the highest circulation flowrate possible while operating within the constraints of the surface mud p u m p should be obtained. To obtain this highest possible, or optimal, circulation flowrate, the total pressure losses for the circulation system must be obtained for various circulation flowrates. These total pressure losses tabulated in the lower row of Table 4-117 represent the surface standpipe pressure when operating at the various circulation flowrates. Pump Limitations. Table 4-116 shows there are six possible liner sizes that can be used on the Model E-700 m u d pump. Each liner size must be considered to obtain the o p t i m u m circulation flowrate and appropriate liner size. The maxim u m pressure available for each liner size will be reduced by a safety factor of 0.90. The m a x i m u m volumetric flowrate available for each liner size will also be reduced by a volumetric efficiency factor of 0.80 and an additional safety factor of 0.90. Thus, from Table 4-116, the allowable m a x i m u m pressures and allowable m a x i m u m volumetric flowrates will be those shown in Figures 4-207 through 4-212, which are the liner sizes 5 ~ , 6, 6¼, 6-~ and 7 in., respectively. Plotted on each of these figures are the total pressure losses for the various circulation flowrates considered. The horizontal straight line on each figure is

894

Drilling and Well Completions Table 4-117 Drillstrlng Component Pressure Losses at Various Circulation Flowmtes for Example 4 Pressure (psi)

Components

200 gpm

Surface Equipment Drill Pipe Bore Drill Collar Bore PDM Drill Bit Drill Collar Annulus Drill Pipe Annulus Total Pressure Loss

300 gpm

400 gpm

500 gpm

5 142 18 580 500 11 32

11 318 40 580 500 25 72

19 566 71 580 500 45 128

30 884 111 580 500 70 200

i288

1546

1909

2375

Pall = 2700 psi q a , = 287 g p m 3000

o~

c~ u~ o~

o _J

2000

o~ u~ L_

a.

1000

co

o p-

0

I

I

200

600

400 q (gpm)

Figure 4-207. 5¾-in. liner, total pressure loss vs. flowrate, Example 4.

(Courtesy Smith International, Inc.)

Downhole Motors

895

Pall = 2232 psi q d = 317 gpm

3000

I I I

(n

o (n (n

O 2000 -J t~ 23 (n (n t~

a.

1000

(O

O !--

, 0

!

i

200

I 400

,

! 600

q (gpm) Figure 4-208. 6-in. liner, total pressure loss vs. flowrate, Example 4.

(Courtesy Smith International, Inc.) the allowable maximum pressure for the particular liner size. The vertical straight line is the allowable maximum volumetric flowrate for the particular liner size. Only circulation flowrates that are in the lower left quadrant of the figures are practical. The highest circulation flowrate (which produces the highest positive displacement motor horsepower) is found in Figure 4-209, the 6 ¼-in. liner. The optimal circulation flow rate is 348 gal/min.

Positive Displacement Motor Performance. Using the positive displacement motor performance data in Table 4-114 and the scaling relationships in Equations 4-168 through 4-170, the performance graph for the positive displacement motor operating with a circulation flowrate of 348 gal/min can be prepared. This is given in Figure 4-213.

Bit Nozzle Sizes. The pressure loss through the bit must be 500 psi with a circulation flowrate of 348 gal/min with 11.6-1b/gal mud weight. The pressure loss through a roller rock bit with three nozzles is (see the section titled "Drilling Bits and Downholes Tools") (text continued on page 898)

896

Drilling and Well Completions p = 1877 psi qax= 348 gpm 3000 °~ U~

U~ U~

o

2000

._1 (1,1 t., U~ U~ ¢9

rt

1000

O I--

I

i

200

I

i

400

I 600

q (gpm) Figure 4-209. 61/4-in. liner, total pressure loss vs. fiowrate, Example 4.

(Courtesy Smith /ntemational, Inc.) P a, = 1602 psi q=ll = 381 gprn

3000 °~ ¢D

¢D U~

o

2000

._1 ¢9 t,.

U~ U~ a) t.,

Q.

1000

O I.--

I

i

200

I 400

i

I 600

q (gpm) Figure 4-210. 61/2-in. liner, total pressure loss vs. flowrate, Example 4.

(Courtesy Smith /nternational, /nc.)

Downhole Motors

psi q~l= 414 gpm

P all = 1382

3000 oB ¢/)

Q, ¢/) ¢/)

0 .-I ¢D

2000

¢/) ¢/)

¢D s-

Q.

1000

0 I--

I

~

200

I

i

400

I 600

q (gpm) Figure 4-211. 6%-in. liner, total pressure loss vs. flowrate, Example 4.

(Courtesy Smith International, Inc.) pal= 1134 pSi qall = 449 gpm 3000

I I I

t/)

t-. t/) t/)

0 .J

i

2000

q> L. t/) t/)

Q) b.

Q.

--L

1000

4-*

0 k-

i

i

200

i 400

i

i 600

q (gpm) Figure 4-212. 7-in. liner, total pressure loss vs. flowrate, Example 4.

(Courtesy Smith International, Inc.)

897

898

Drilling and Well Completions Circulation Rate348 gpm 2600 D

-

2400

120

2200

110 ~

2000

100

Bit Speed

1600

~

Horsepower

80

--

400 Q.

'*-. 1400

70 o~

=

1200

60

I--

1000

50

800

40

600

3O

400

20

200

10

o"

5OO

90

1800 ,~

130

L/"

I

I

1

]

100

200

300

400

500

0

o

"o

(D (D

--

300

m

200

~

0

600

Differential Pressure (psi)

Figure 4-213. Positive displacement motor, 6%-in. outside diameter, 1:2 lobe profile, 348 gal/min, differential pressure limit 580 psi, Example 4. (Courtesy Smith Internationa/, Inc.) (text continued from page 895)

q27m

APb = 7430C2d 4

where C = nozzle coefficient (usually taken to be 0.95) d e = hydraulic equivalent diameter in in. Therefore, Equation 4-171 is 500 =

(348)2(11"6) 7,430(0.98) 2de 4

which yields d e = 0.8045 in.

(4-171)

Downhole Motors

899

The hydraulic equivalent diameter is related to the actual nozzle diameters by d e = [ad~ + bd~ + cd~] I/~ where

a = b = c = dl, d~ a n d d 3 =

n u m b e r of nozzles with diameter d I n u m b e r of nozzles with diameter d~ n u m b e r of nozzles with diameter d 3 three separate nozzle diameters in in.

Nozzle diameters are usually in 32nds of an inch. Thus, if the bit has three nozzles with ~ of an inch diameter, then d e = [(3)(0.4688)~]1/~ = 0.8120 in. The above hydraulic equivalent diameter is close enough to the o n e o b t a i n e d with Equation 4-171. Therefore, the bit should have three ~ - i n . diameter nozzles.

Special Applications As it becomes necessary to infill drill the m a t u r i n g oil a n d gas reservoirs in the continental United States a n d elsewhere in the world, the need to minimize or eliminate formation damage will become an i m p o r t a n t e n g i n e e r i n g goal. To accomplish this goal, air a n d gas drilling techniques will have to be utilized (see the section titled "Air a n d Gas Drilling"). It is very likely that the future drilling in the m a t u r i n g oil a n d gas reservoirs will be characterized by extensive use of high-angle directional drilling coupled with air a n d gas drilling techniques. The downhole t u r b i n e motor designed to be activated by the flow of incompressible drilling m u d cannot operate on air, gas, unstable foam or stable foam drilling fluids. These downhole t u r b i n e motors can only be operated on drilling m u d or aerated mud. Recently, a special t u r b i n e motor has b e e n developed to operate on air, gas a n d unstable foam [82]. This is the downhole pneumatic t u r b i n e motor. This motor has been tested in the San J u a n Basin in New Mexico a n d the Geysers area in N o r t h e r n California. Figure 4-214 shows the basic design of this drilling device. The downhole pneumatic t u r b i n e motor is equipped with a gear reduction transmission. The compressed air or gas that actuates the single stage t u r b i n e motor causes the rotor of the t u r b i n e to rotate at very high speeds (i.e., -20,000 rpm). A drill bit cannot be operated at such speeds; thus it is necessary to reduce the speed with a series of planetary gears. The prototype downhole pneumatic t u r b i n e motor has a gear reduction transmission with an overall gear ratio of 168 to 1. The particular version of this motor concept that is undergoing field testing is a 9-in. outside diameter motor capable of drilling with a 10~-in.-diameter bit or larger. The d o w n h o l e p n e u m a t i c t u r b i n e motor will deliver about 40 hp for drilling with a compressed air flowrate of 3,600 scfm. The motor requires very little a d d i t i o n a l pressure at the surface to operate (relative to n o r m a l air drilling with the same volumetric rate). The positive displacement motor of the Moineau-type design can be operated with unstable foam (or mist) as the drilling fluid. Some liquid must be placed in the air or gas flow to lubricate the elastomer stator as the metal rotor rotates against the elastomer. Positive displacement motors have been operated quite

900

Drilling and Well Completions STANDARD AP~CONNECT~ON

-'°--

AIR FILTER

BYPASS VALVE

S~NGLE STAGE TURBINE HIGH SPEED COUPL NG

GEARBOX ASSEMBLY

HiGH TORQUE COUPUNG

RADIAL BEARINGS

~'~'~

THRUST BEARING

.....

STANDARD A~-SiCONNECTIO~

ROLLER CONE B}T

Figure 4-214. Downhole pneumatic turbine motor design. (Courtesy

Pneumatic Turbine Partnership.)

MWD a n d LWD

901

successfully in many air a n d gas drilling situations. T h e various manufacturers of these m o t o r s can give specific i n f o r m a t i o n c o n c e r n i n g the p e r f o r m a n c e characteristics of their respective m o t o r s o p e r a t e d with air a n d gas d r i l l i n g techniques. T h e critical o p e r a t i n g characteristic of these motors, when o p e r a t e d with unstable foam, is that these motors must be l o a d e d with weight on bit when circulation is initiated. If the positive displacement motor is allowed to be started without weight on bit, the rotor will speed up quickly to a very high speed, thus b u r n i n g out the bearings a n d severely d a m a g i n g the elastomer stator.

MWD AND LWD Most of the cost in a well is e x p a n d e d d u r i n g the drilling phase. Any amount of information gathered during drilling can be used to make decisions regarding the efficiency of the process. But the scope a n d ultimate cost to g a t h e r a n d analyze such i n f o r m a t i o n must be offset by a decrease in drilling expenditures, an increase in drilling efficiency a n d an increase in safety. As drilling technology moved the pursuit of hydrocarbon resources into highercost offshore a n d hostile environments, intentionally deviated boreholes required information such as azimuth a n d inclination that could not be derived by surface instruments. Survey instruments, either lowered on a sand line or d r o p p e d into the drill p i p e for later retrieval, to some d e g r e e satisfied the requirements but c o n s u m e d expensive rig time a n d sometimes p r o d u c e d questionable results. For many years researchers have b e e n looking for a simple, reliable measurement while drilling technique, referred to by its abbreviation MWD. As early as 1939, a logging while drilling (LWD) system, using an electric wire, was tested successfully but was not c o m m e r c i a l i z e d [89,90]. Mud pulse systems were first p r o p o s e d in 1963 [91,92]. T h e first mechanical m u d pulse system was marketed in 1964 by Teledrift for t r a n s m i t t i n g directional i n f o r m a t i o n [93]. In the early 1970s, the steering tool, an electric wire o p e r a t e d directional tool, gave the first real-time m e a s u r e m e n t s while the directional b u i l d u p was in progress. Finally, the first m o d e r n m u d pulse data transmission system was c o m m e r c i a l i z e d in 1977 by Teleco [94]. State-of-the-art surveys of the technology were made in 1978 [95], in 1988 [96-98], a n d in 1990 [99]. A p r o b l e m with the early MWD m u d pulse systems was the very slow rate of data transmission. Several minutes were n e e d e d to transmit one set of directional data. A n a d r i l l working with a Mobil patent [100] developed in the early 1980s a continuous wave system with a much faster data rate. It b e c a m e possible to transmit many m o r e drilling data, and also to transmit logging data making LWD possible. Today, as many as 16 parameters can be transmitted in 16 s. The dream of the early pioneers has b e e n m o r e than fulfilled since azimuth, inclination, tool face, downhole weight-on-bit, downhole torque, shocks, caliper, resistivity, g a m m a ray, neutron, density, Pe, sonic a n d m o r e can be t r a n s m i t t e d in realtime to the rig f l o o r a n d the main office.

MWD Technology Steering Tool Up until 1970 all d i r e c t i o n a l d r i l l i n g was c o n d u c t e d using singleshot a n d multishot data. T h e n o r m a l p r o c e d u r e was: a. drill vertically in rotary to the kick-off depth; b. kick-off towards the target using a d o w n h o l e m o t o r a n d a bent sub to an inclination of approximately 10°;

902

Drilling and Well Completions

c. resume rotary drilling with the appropriate bottomhole assembly to build angle, hold, or drop. T h e kick-off p r o c e d u r e r e q u i r e d n u m e r o u s single-shot r u n s to start the deviation in the correct direction. Since, d u r i n g this phase, the drillpipe was not rotating a steering tool was developed to be lowered on an electric wireline instead of the single shot. The m e a s u r e m e n t s were t h e n made while drilling. Measurements by electric cable are possible only when the drillstem is not rotating, hence with a t u r b i n e or downhole motor. The logging tool is r u n in the drillstring and is positioned by a mule shoe and key. The process is identical to the o n e used in the single-shot measurements. T h e magnetic o r i e n t a t i o n sensor is of the flux-gate type and measures the three c o m p o n e n t s of the earth's magnetic field vector in the reference space of the logging tool. Three accelerometers measure the three c o m p o n e n t s of the gravity vector still in the same reference space. These digitized values are multiplexed a n d transmitted by an insulated electric conductor and the cable a r m o r toward the surface. O n the surface a m i n i c o m p u t e r calculates the azimuth a n d the drift of the borehole as well as the angle of the tool face p e r m a n e n t l y d u r i n g drilling. In the steeringtool system, the c o m p u t e r can also d e t e r m i n e the azimuth a n d slant of the d o w n h o l e m o t o r u n d e r n e a t h the b e n t sub a n d thus anticipate the d i r e c t i o n that the well is going to take. It can also d e t e r m i n e the trajectory followed. Figure 4-215 shows the steering tool system.

Figure 4-215. Typical steering tool unit with surface panel and driller readout. (Courtesy of Institut Francois du Petrole.)

MWD and LWD

903

Naturally for operating the tool, the seal must be m a i n t a i n e d at the point where the cable enters the drillstring" a. either at the top of the drillpipes, in which case the logging tool is pulled out every time a new drillpipe length is added on; b. or through the drillpipe wall in a special sub placed in the drillstring as near the surface as possible, in which case new lengths are added on without pulling out the logging tool. Figure 4-216 shows the typical o p e r a t i o n of a steering tool for orienting the drill bit. T h e electric wireline goes through a circulating head located on top

Circulating Head Or, Floor near Tool Face Driller

I

Drum for Cable Slip Ring Electronics Inclination Direction

|1

Printed Results

Stranded Measuring Cable

//// /~J~i-.,--- Non-Magnetic Drill Collar

/// ,oo,n0Too, P,oo / / ~

~

l !

~'~

Mule Shoe Orienting Sleeve

i[

Bent Sub

Mud Motor

Figure 4-216. Typical operation of a steering tool for orienting the drill bit using a circulating head on the swivel. (Courtesy SPE [101].)

904

Drilling a n d Well C o m p l e t i o n s

o f the swivel. As m e n t i o n e d previously, the tool has to be p u l l e d out when a d d i n g a single. Figure 4-217 shows the same o p e r a t i o n using a side-entry sub. With this sub, the electric wireline crosses over from inside the drill p i p e to the outside. Consequently, singles may be a d d e d without pulling the steering tool out. O n the o t h e r hand, there is a risk o f d a m a g i n g the cable if it is crushed between the drillpipe tool joints and the surface casing. The wireline also goes through the rotary table a n d special care must be taken not to crush it between the rotary table a n d the slips. F u r t h e r m o r e , in case o f B H A sticking, the s t e e r i n g tool h a s to be f i s h e d o u t by b r e a k i n g a n d g r a b b i n g the electric wireline inside the drillpipes. Figure 4-218 shows the a r r a n g e m e n t o f the sensors used in a steering tool. T h r e e flux-gate-type m a g n e t o m e t e r s a n d three accelerometers are p o s i t i o n e d

anUdS~KT~l~y

Drumfor Cable

Caee oose till ~~:• , ~

to feed down

SideEntry---L.I.~I ~, sideof DrillPipe Sub i~ WireCable

.~,~~ ,:SteeringToolProbe entingSub t Sub MudMotor

Figure 4-217. Typical operation of a steering tool for orienting the drill bit

using a side-entry sub. (Courtesy

SPE

[101].)

MWD a n d LWD

905

M/t

Y

KEY C

Figure 4-218. Sketch of the principle of the sensor arrangement in a steering tool and any magnetic directional tool. (Courtesy SPE [101].) with their sensitive axis along the principal axis of the tool. O Xis oriented toward the bent sub in the bent s u b / t o o l axis plane. Oy is p e r p e n d i c u l a r to O a n d the tool axis. O z is oriented along the tool axis downward. The a r r a n g e m e n t of Figure 4-218 is c o m m o n to all directional tools based on the earth's magnetic field for orientation: MWD tools or wireline logging tools. The steering tools have practically been a b a n d o n e d and replaced by MWD systems, mostly because of the electric wireline. However, the high data rate of the electric wireline (20-30 kbits/s) compared to the low data rate of the MWD systems (1-10 bits/s) make the wireline tools still useful for scientific work.

Accelerometers. Accelerometers measure the force generated by acceleration according to Newton's law: F = ma where F = force in lb m = mass in (lb - s2)/ft (or slugs) a = acceleration in ft//sec 2

(4-172)

906

Drilling and Well Completions

If the acceleration is variable, as in sinusoidal movement, piezoelectric systems are ideal. I n case of a constant acceleration, a n d hence a force that is also constant, strain gages may be employed. For petroleum applications in boreholes, however, it is better to use servo-controlled accelerometers. Reverse p e n d u l a r accelerometers and "single-axis" accelerometers are available. Figure 4-219 shows the schematic diagram of a servo-controlled inverted pendular dual-axis accelerometer. A p e n d u l u m mounted on a flexible suspension can oscillate in the direction of the arrows. Its position is identified by two detectors acting on feedback windings used to keep the p e n d u l u m in the m e d i a n position. The current required to achieve this is proportional to the force ma x, and hence to a x. This system can operate simultaneously along two axes, such as x and y, if a n o t h e r set of detectors and feedback windings is m o u n t e d in the plane perpendicular to xO z, such as y O . The c o r r e s p o n d i n g accelerometer is called a tw0-

axis accelerometer. Figure 4-220 shows the schematic d i a g r a m of a servo-controlled single-axis accelerometer. The p e n d u l u m is a disk kept in position as in the case of the reverse pendulum. Extremely efficient accelerometers can be built according to this principle in a very limited space. The S u n s t r a n d accelerometer is seen in Figure 4-221. Every accelerometer has a response curve of the type shown schematically in Figure 4-222. Instead of having an ideal linear response, a n o n l i n e a r response is generally obtained with a "skewed" acceleration for zero current, a scale factor error and a n o n l i n e a r i t y error. In addition, the skew a n d the errors vary with temperature. If the skew a n d all the errors are small or compensated in the accelerometer's electronic circuits, the signal read is an ideal response and can be used directly to calculate the borehole inclination. If not, "modeling" must be resorted to, i.e., making a correction with a computer, generally placed at the surface, to find the ideal response. This correction takes account of the skew,

SUPPLY

H

,

l

[

LI

COIL i

L.~ ~,,,~

PROXIMITY SENSOR

lz

Figure 4-219. Sketch of principleof a servo-controlledinvertedpendular dual-axis accelerometer.

MWD and LWD

/

907

Coi~s

ServoControl

P~a×imi~ Sensors

Figure 4-220. Schematic diagram of a servo-controlled single-axis accelerometer.

{b) Figure 4-221. Servo-controlled "single-axis" Sunstrand accelerometer: (a) accelerometer photograph; (b) exploded view of the accelerometer.

(Courtesy Sunstrand [102].)

all the errors, and their variation with temperature. In this case, the accelerom e t e r t e m p e r a t u r e must be known. T h e m a x i m u m current feedback defines a m e a s u r e m e n t range beyond which the a c c e l e r o m e t e r is saturated. Vibrations must be limited in order not to disturb the accelerometer response. Assume that the accelerometer has the ideal response shown in Figure 4-223, with a m e a s u r e m e n t range of 2 g (32.2 ft/s2). We want to measure 1 g, but the ambient v i b r a t i o n level is +-3 g. In this case, the a c c e l e r o m e t e r ' s indications are shaved and the mean value obtained is not 1 g but 0.5 g. T h e m a x i m u m a c c e l e r a t i o n due to v i b r a t i o n s which are not f i l t e r e d mechanically, plus the

908

Drilling and Well Completions Holding Current I

Linearity Error

/ ..... Scale Factor Error --

Ideal Response Acceleration

4-222. Accelerometer response.

Figure

Holding Current I True A c c e l . ~ Average Read Accel. Vibrations +/- 3 G

Figure

V

Saturation at Imax (2G)

--
\

4-223. Effect of vibrations on an accelerometer response.

MWD and LWD

909

c o n t i n u o u s c o m p o n e n t to b e m e a s u r e d , m u s t b e less t h a n t h e i n s t r u m e n t ' s m e a s u r e m e n t range. T h e s e i n s t r u m e n t s s e r v e to m e a s u r e t h e e a r t h ' s g r a v i t a t i o n a l f i e l d with a m a x i m u m v a l u e o f 1 g. T h e typical values o f t h e characteristics are: • • • •

scale factor, 3 m A / g r e s o l u t i o n , 10 -6 g skew, 10 -~ g s e r v i c e t e m p e r a t u r e , - 5 5 to +150°C

F o r m e a s u r e m e n t r a n g e s f r o m 0 to 180 °, t h r e e a c c e l e r o m e t e r s m o u n t e d o r t h o g o n a l l y must b e u s e d as s h o w n in F i g u r e 4-224. T h e x and y a c c e l e r o m e t e r s are m o u n t e d w i t h t h e i r s e n s i t i v e axis p e r p e n d i c u l a r to t h e tool axis. T h e z a c c e l e r o m e t e r is m o u n t e d with its sensitive axis l i n e d u p with t h e tool axis.

o

i•l•l

Z - A C C E L E R O M E T,TER ER

HOLDING POINT

o

Y-ACCELEROMETER

Z3" ¢=~

REFERENCE PIN Figure 4-224. Mechanical drawing of the accelerometer section of a directional tool. (Courtesy $unstrand [10210

910

Drilling and Well Completions

Figure 4-225 shows the i n c l i n a t i o n m e a s u r e m e n t u s i n g a triaxial s e n s o r featuring three accelerometers. The three coordinates of the earth's gravitational acceleration vector serve to define this vector in the reference frame of the probe. The earth's acceleration is computed as G=

2

2

G2 , + G y + G z

(4-173)

It must be equal to the 32.2 ft/s2; otherwise the accelerometers are not working correctly. W h e n the readings are in g units, G must be equal to one. For the best accuracy, inclination less than 60 ° is c o m p u t e d with ~ 2G x 22 + Gy2

i = arc sin

(4-174)

G

and for i greater than 60 °

G, i = arc cos --~

(4-175)

V E R T I C A L PLANE PASSING THROUGH COLLAR

/

~

i I

,a'

I

/

,

/

iI

/,

/ s J p

s

qT S U B

PLANE NORMAL TO COLLAR

MOTOR

Figure 4-225. Vector diagram of the inclination measurement with three accelerometers.

MWD a n d LWD

911

The gravity tool face angle, or angle between the plane d e f i n e d by the borehole axis a n d the vertical a n d the plane d e f i n e d by the b o r e h o l e axis and the B H A axis below the bent sub, can also be calculated. Figure 4-226 shows the gravity tool face angle. It is readily calculated using the equation

TF = arc tan - Gx Gy

(4-176)

T h e gravity tool face angle is used to steer the well to the right, TF > 0, or to the left, TF < 0. Typical specifications for a gravity sensor are as follows: Temperature O p e r a t i n g = 0 to 200°C Storage = -40 to 200°C Scale factor = 0.01 V / ° C Power r e q u i r e m e n t 24 V n o m i n a l Less than 100 mA Output impedance 10~

VERTICAL PLANE PASSING THROUGH COLLAR

•~ - . - P L A N E N \

• \

THROUGH COLLAR,

BENT SUB AND MUD MOTOR

\

/ / / / " ~"

/ /

\

\

/

/

/

/

\

/

\

Gx

\

,\ /

\ \

\ /)

/

r-BENT SUB PLANE NORMAL

TO COLLAR

MUD MOTOR

Figure 4-226. Solid geometry representing the gravity tool face angle concept.

912

Drilling and Well Completions

Mechanical characteristics Length = 60 cm (24 in.) Diameter = 3.75 cm (1.5 in.) Mass = 2 kg (4 lb) A l i g n m e n t +0.4 ° Electrical characteristics Scale factor = 5 V / g +1% (g = 32.2 f t / s *) Bias = +0.005 g @ 25°C Linearity = +0.1% full scale E n v i r o n m e n t a l characteristics Vibrations = 1.5 cm p-p (peak-to-peak), 10 to 50 Hz 50g, 50 to 2000 Hz Shock = 2000 g, 0.5 ms, 0.5 sine

=

Magnetometers. Magnetometers used in the steering tools or MWD tools are of the flux-gate type. The basic d e f i n i t i o n of a m a g n e t o m e t e r is a device that detects magnetic fields and measures their magnitude a n d / o r direction. O n e of the simplest types o f m a g n e t o m e t e r s is the m a g n e t i c compass. However, d u e to its d a m p i n g problems more intricate designs of m a g n e t o m e t e r s have b e e n developed. The "Hall effect" m a g n e t o m e t e r is the least sensitive. The "flux-gate" m a g n e t o m e t e r concept is based on the magnetic saturation of an iron alloy core. If a strip of an iron alloy that is highly "permeable" and has sharp "saturation characteristics" is placed parallel to the earth's magnetic field, as in Figure 4-227, some of the lines of flux of the earth's field will take a short cut through the alloy strip, since it offers less resistance to their flow than does the air. If we place a coil of wire a r o u n d the strip, as in Figure 4-228 a n d pass e n o u g h electrical current through the coil to "saturate" the strip, the lines of flux due to earth's field will no longer flow through the strip, since its permeability has b e e n greater reduced. Therefore, the strip of iron alloy acts as a "flux gate" to the lines of flux of the earth's magnetic field. W h e n the strip is not saturated, the gate is open and the lines of flux b u n c h together and flow through the strip. However, when the strip is saturated by passing and electric current through a coil wound on it, the gate closes and the lines of flux pop out and resume their original paths. O n e of the basic laws of electricity, Faraday's law, tells us that when a line of magnetic flux cuts or passes through an electric conductor a voltage is produced in that conductor. If an AC current is applied to the drive winding A-A, of Figure 4-228, the flux gate will be o p e n i n g and closing at twice the frequency of the AC current and we will have lines of flux from the earth's field moving in and out of the alloy at a great rate. If these lines of flux can be made to pass through

I !

~Flux

Lines

Figure 4-227. Magnetic flux-lines representation in a highly permeable iron alloy core.

MWD a n d LWD

913

-/'f?. DRIVE W1NDING Figure 4-228. Magnetic flux-lines representation in a highly permeable iron alloy core saturated with an auxiliary magnetic field.

an electrical conductor ("sense winding"), a voltage will be i n d u c e d each time they pop in or out of the alloy strip. This induced voltage in the sense windings is p r o p o r t i o n a l to the n u m b e r of lines of flux cutting t h r o u g h it, a n d thus p r o p o r t i o n a l to the intensity of that c o m p o n e n t of the earth's magnetic field that lies parallel to the alloy strip. W h e n the alloy strip is saturated, a lot of other lines of flux are created that are not shown in Figure 4-228. The lines of flux must be sorted out from the lines of flux due to the e a r t h ' s field to e n a b l e a m e a n i n g f u l signal to be produced. A toroidal core as shown in Figure 4-229 will enable this separation of lines of flux to be accomplished. The material used for the toroidal core is usually mu metal. Each time the external lines of flux are drawn into the core, they pass through the sense windings B-B to generate a voltage pulse whose amplitude is proportional to the intensity of that c o m p o n e n t of the external field that is parallel to the centerline of the sense winding. The polarity, or direction of this pulse, will be determined by the polarity of the external field with respect to the sense windings. W h e n the flux lines are expelled from the core they cut the sense

DRIVE A~ WINDING A

/

B

SE WINOING

B

Figure 4-229. Sketch of principle of a single-axis flux-gate magnetometer.

914

Drilling a n d Well Completions

windings in the opposite direction and generate a n o t h e r voltage pulse of the same amplitude but of opposite polarity or sign. Because of this voltage pulse o c c u r r i n g at twice the driving voltage frequency, the flux gate is sometimes k n o w n as "second h a r m o n i c magnetometer." The main advantages of the flux gate magnetometers are that they are solidstate devices much less sensitive to vibration than compasses, they have uniaxial sensitivity, and they are very accurate. Typical specifications are: Temperature O p e r a t i n g = 0 to 200°C Storage = -20 to 200°C

Power requirement, output in impedance, and mechanical characteristics are similar to the acceleromete sensors. Electrical characteristics A l i g n m e n t = +0.5 ° Scale factor = 5 V / G _+5% Bias = -+0.005 G @ 25°C Linearity = _+2% full scale Note: 1 gauss = 1G = 10 -4 tesla E n v i r o n m e n t a l characteristics Vibrations = 1.5 cm p-p, 2 to 10 Hz 20 g, 10 to 200 Hz Shock = 1000 g, 0.5 ms, 0.5 sine Figure 4-230 shows the photograph of a Develco high-temperature directional sensor. For all the sensor packages, calibration data taken at 25, 75, 125, 150, 175 and 200°C are provided. C o m p u t e r m o d e l i n g coefficients provide sensor accuracy of +0.001 G a n d +0.1 ° a l i g n m e n t from 0 to 175°C. From 175 to 200°C the sensor accuracy is +0.003 G and _+0.1° alignment.

Example 1: Steering Tool MeasurementsmTool Face, Deviation Single-axis accelerometer systems are used in the steering tools and MWD tools for inclination and tool face data acquisition. Using a spreadsheet, compute the c u r r e n t values for each accelerometer in the following cases: Use a spreadsheet for a three single-axis accelerometer system m o u n t e d in a steering tool or a MWD tool a n d compute the output current values for each accelerometer in the following cases: 1. Tool-face angle: Hole deviation: 2. Hole deviation: Tool-face angle:

0° 0, 15, 30, 45, 60, 75, 90 ° 30 ° -180, -135, -90, -45, 0, 45, 90, 135, 180 °

The usual conventions as shown in Figure 4-231 are: • Axis x lines up with the mule shoe key a n d the tool face. • Axis y is p e r p e n d i c u l a r to O x a n d O . • Axis z is the same as tool axis or borehole axis, oriented downward.

MWD a n d LWD

915

Figure 4-230. Photograph of a high-temperature directional sensor with three accelerometers and three magnetometers. (Courtesy Deve/co [103].) ° T h e tool face angles are counted looking downward, clockwise positive and counterclockwise negative. • We will assume a perfect accelerometer calibration line that reads 3 mA for 1 g of acceleration.

Solution Tables 4-118 and 4-119 give answers to Example 1 in tabular form.

Example 2: Steering Tool Measurements--Tool Face, Deviation, and Azimuth The following set of data have been recorded with a MWD directional package: G x = -0.2 mA G = 0 . 1 mA G r = 2.99 mA Accelerometer sensitivity: 3 mA = 1 g z

916

Drilling and Well Completions H = 0.1 G 0.484 G Earth magnetic field amplitude: 0.52 G Earth magnetic field inclination/vertical: 32 °

II

High Side

TF

Inclinometer Vector Diagram

Xg Yg

Borehole.~ Vertical Plane

Low Side

Figure 4-231. Vector diagram for the tool-face determination.

Table 4-118 Accelerometer Output for 0 ° Tool-Face Angle and Various Tool-Face Angles Hole Deviation (°) 0 15 30 45 60 75 90

Tool Face (°)

Axis x (mA)

Axis y (mA)

Axis z (mA)

0 0 0 0 0 0 0

0.00 0.78 1.50 2.12 2.60 2.90 3.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00

3.00 2.90 2.60 2.12 1.50 0.78 0.00

MWD and LWD

917

Table 4-119 Accelerometer Output for 30 ° of Hole Deviation Angle and Various Tool-Face Angles Hole Deviation (°)

Tool Face (°)

Axis x (mA)

Axis y (mA)

-180 -135 -90 -45 0 45 90 135 180

-1.50 -1.06 0.00 1.06 1.50 1.06 0.00 -1.06 -1.50

0.00 -1.06 -1.50 -1.06 0.00 1.06 1.50 1.06 0.00

30 30 30 30 30 30 30 30 30

Axis z (mA) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60

1. C o m p u t e the inclination o f the borehole. Are the accelerometers working properly? Why? 2. C o m p u t e the tool face angle, clockwise a n d counterclockwise. If we drill a h e a d with this angle is the hole going to turn left or right? 3. C o m p u t e the field disturbance Hdc due to the drill collars. 4. C o m p u t e the inclination o f the corrected magnetic field. Does it check with the local data? W h a t could prevent this inclination from being correct? 5. Give the principle o f one o f the b o r e h o l e azimuth calculation methods.

Solution 1. T h e inclination is i = 4.27 °. Yes, the accelerometers work p r o p e r l y because 4 G ~ + G 2y+G~ = 3 m A 2. T h e tool-face angle is TF = 26.56 °. T h e b o r e h o l e is t u r n i n g right. 3. H, = 0.469 G, HDc = 0.014 G. 4. C o r r e c t e d field inclination: 25.69 ° . External disturbance: nearby casing or d r i l l collar hot spots. 5. If Z is the b o r e h o l e axis unit vector, compute A = G × Z (vector product) B=G×H and A*B c o s c t - /I'B------SIAI °

(scalar product)

Example 3: Steering Tool Measurements--Tool Face, Deviation, and Azimuth A steering tool is n o r m a l l y used d u r i n g drilling with a m u d m o t o r and is c o n n e c t e d to the surface with an electric wireline. T h e sensing devices shown in Figure 4-232 are also used in most MWD m u d pulse systems. T h e coordinates

918

Drilling a n d Well C o m p l e t i o n s

Z

M3

MAGNETOMETERS

-ly'"-.. H~x ...... L-.:,H'

Y

/ / i

Gy

ACCELEROMETERS

Y

Gx

KEY

I I / iI //

C

/

G

I /

I

/ //

Figure 4-232. Schematic view of the sensor arrangement in a steering tool. o f two vectors are p e r m a n e n t l y m e a s u r e d d u r i n g d r i l l i n g in t h e f r a m e o f reference o f the sonde• They are • Vector gravity G, which represents the vertical direction a n d is d e f i n e d by the coordinates Gx, G and G . • Vector m a g n e t i c field, which is located in the n o r t h vertical plane and is d e f i n e d by the coordinates H x, Hy a n d H z. •

•

y

•

z

MWD and LWD

919

Also needed: • Vector well direction located along the well (sonde axis) and is d e f i n e d by the coordinates Z = 0, Z = 0 and Z = 1. • O is lined up witch the n~ule shoe key and the tool face direction. For the numerical applications, we shall have: • A c c e l e r o m e t e r scale factor 3 m A / g , I X = - 2 mA, I = 1 mA, I = 2 m A a t a given depth, Y • M a g n e t o m e t e r readings: H X = -0.1077 G, H y = 0 . 2 G , H z = 0.45 G at the same depth, • M a g n i t u d e o f the magnetic field: 0.52 G, magnetic field inclination: 30 ° with respect to the vertical. 1. C o m p u t e the b o r e h o l e deviation. Show that a check o f the a c c e l e r o m e t e r readings is possible if we assume that the G vector m o d u l e is g. 2. C o m p u t e the tool face orientation. In the numerical application above, is the b o r e h o l e going to turn right, left or go straight if we keep on drilling with this orientation? 3. Show that we can check the m a g n i t u d e o f the magnetic field vector and correct for an axial field due to the drill collars. 4. C o m p u t e the dip angle o f the magnetic field vector after c o r r e c t i o n for the drill collar field, it should check with the local magnetic field data. What do you conclude if it does not? 5. C o m p u t e the o r i e n t a t i o n o f the b o r e h o l e with respect to magnetic n o r t h without axial field correction. 6. Write an interactive c o m p u t e r p r o g r a m for solving the above questions.

Solution 1. 2. 3. 4. 5.

i = 48.2°; 3 mA. TF = +26.5°; t u r n i n g right. Drill collar magnetic field = 0.0178 G; H z c o r r e c t e d = 0.468 G. ~. = 30 ° from vertical. O n e way o f making the calculation is to use the t h r e e vectors:

6 (G, G, G) H(H,H,H)

z(0, 0, f) (See Figure 4-233 a and b). a. Compute the coordinates o f vector A normal to vector G and vector H. Vector A = cross-product o f vector G by vector H. b. C o m p u t e the coordinates o f vector B n o r m a l to vector G and vector Z. Vector B = cross-product o f vector G by vector Z. c. C o m p u t e the angle between vector A and vector B. Being both normal to vector G, they are in the horizontal plane. T h e angle represents the azimuth. In some c o n f i g u r a t i o n s 180 ° must be added. T h e angle is c o m p u t e d by making the scalar p r o d u c t o f vector A by vector B. A • B = IAI • IBI cos Az = AxBX + AyBy + AzBz Care must be exercised since cos(Az) = cos(-Az). d. Numerical results: Angle between vertical planes, 31.71°; azimuth, 328.29 °.

920

Drilling and Well Completions

328.29°

VBorehole

R ~ ~L J ~ 3 1 . 7 1 °

a)

Top view of ~ Plane Normal to 0z in 0

/

/

-0.1 /

~

0

Trace of BoreholeAxis >

G ~

~

6

"

'

~

.5 °

Down

Figure 4-233. Representation of the three main vectors: (a) solid geometry view; (b) projection on plan normal to O z. Note: Another way, probably less ambiguous,to compute the azimuth is to make a rotation of coordinates around Oz to bring Ox in the vertical plane and Oy in the horizontal plane. Then, make another rotation around Oy to bring Oz vertical and Ox in the horizontal plane.The azimuth is the clockwise angle betweenthe new OHo and Ox. Example 4: Steering Tool Measurements--Trajectory Forecast An interesting problem that can be solved with the steering tool or the MWD measurements is the trajectory forecast when drilling ahead with a given bent sub (constant angle), and a given tool-face angle. 1. After drilling the mud motor length with a given tool face angle and a given bent sub angle, what is the borehole deviation and orientation likely to be at the mud motor depth?

MWD a n d LWD

921

Using the drawing Figure 4-234 f i n d the algorithm to c o m p u t e these angles. Write a short c o m p u t e r p r o g r a m a n d use the data of Example 3 for a numerical application with a 2 ° sub. 2. If we change the tool face angle to -30 ° ( t u r n i n g left), what will be the p r o b a b l e b o r e h o l e d e v i a t i o n a n d a z i m u t h after d r i l l i n g a n o t h e r m o t o r length? Use the same c o m p u t e r program. Note: We will assume that the borehole axis is the same as the drill collar axis at the steering tool depth a n d also that the borehole axis is the same as the m u d motor axis at the m u d motor depth.

Solution T h e same algorithms are used as in Example 3. The vector Z (0, 0, 1) is replaced by vector Z (sin 2 ° • cos TF, sin 2 ° • sin TF, cos 2°). This new vector Z should be used to c o m p u t e the new i n c l i n a t i o n , using the scalar p r o d u c t

-~y

,

v

G z'

Figure 4-234. Vector diagram showing the mud motor axis as well as the steering tool axis.

922

Drilling and Well C o m p l e t i o n s

between vector G and new vector Z. T h e new vector Z should also be used to c o m p u t e the new azimuth.

Vibrations and Shocks Measurements while drilling are m a d e with sensors a n d downhole electronics that must operate in an environment where vibrations and shocks are sometimes e x t r e m e l y severe. A b r i e f study of v i b r a t i o n s a n d shocks will be m a d e to u n d e r s t a n d better the m e a n i n g of the specifications m e n t i o n e d earlier. T h e vibration frequencies encountered during drilling are well known. They correspond to the rotation of the drill bit, to the passing of the bit rollers over the same hard spot on the cutting face, and to the impact of the teeth. Figure 4-235 gives the o r d e r of m a g n i t u d e for frequencies in hertz (60 r p m = 1 Hz). In each type the lowest frequencies c o r r e s p o n d to rotary drilling and the highest ones c o r r e s p o n d to turbodrilling. T h r e e vibrational modes are encountered: 1. axial vibrations due to the b o u n c i n g of the drill bit on the b o t t o m 2. transverse vibrations generally stemming from axial vibrations by buckling or mechanical resonance 3. angular vibrations due to the momentary catching of the rollers or stabilizers In vertical rotary drilling, the drillpipes are almost axially a n d angularly free. Therefore, the highest level of axial and angular v i b r a t i o n is e n c o u n t e r e d for this type of drilling. In deviated rotary drilling, the r u b b i n g of the drill string on the well wall reduces axial vibrations, but the stabilizers increase angular vibrations. In drilling with a downhole motor, the r u b b i n g of the bent sub on the well wall reduces the a m p l i t u d e of all vibrations. Vibrations are characterized by their peak-to-peak amplitude at low frequencies or by their acceleration at high frequencies. Assuming that vibration is sinusoidal, the equation for m o t i o n is A

.

x = 2 sm2nfxt

(4-177)

Rotation 30 Rollers 3

25~

Teeth 15 Frequencies Hz

10

1O0

Figure 4-235. Main vibration frequencies encountered while drilling.

300

923

MWD and LWD where x A f t

= = = =

e l o n g a t i o n in m peak-to-peak a m p l i t u d e in m f r e q u e n c y in H z t i m e in s

By d e r i v i n g twice, a c c e l e r a t i o n b e c o m e s a = - A (2~f)2 sin 2 ~ f x t

(4-178)

M a x i m u m a c c e l e r a t i o n is thus a = 2A~2F. For e x a m p l e , peak-to-peak 12 m m at 10 H z c o r r e s p o n d s to a m = 11.8 m / s 2 = 1.2 g. A c c e l e r a t i o n o f gravity is e x p r e s s e d as g. Very few v i b r a t i o n m e a s u r e m e n t s are d e s c r i b e d in t h e l i t e r a t u r e , b u t t h e f i g u r e s in F i g u r e 4-236 can b e p r o p o s e d for v e r t i c a l r o t a r y drilling. T h e lower limits c o r r e s p o n d to soft sandy f o r m a t i o n s a n d the u p p e r limits to h e t e r o g e n e o u s f o r m a t i o n s w i t h h a r d z o n e s . T a b l e 4-120 gives t h e s p e c i f i c a t i o n s t h a t t h e m a n u f a c t u r e r s p r o p o s e for several tools. T h e shocks that m e a s u r i n g devices are s u b j e c t e d to are generally c h a r a c t e r i z e d by an a c c e l e r a t i o n (or d e c e l e r a t i o n ) a n d a t i m e span. For e x a m p l e , a d e v i c e is said to withstand 500 g (5,000 m/s 2) for 10 ms. This refers to a "half-sine." S h o c k t e s t i n g m a c h i n e s p r o d u c e a d e c e l e r a t i o n i m p u l s e h a v i n g t h e f o r m s h o w n in F i g u r e 4-237. In the p r e c e d i n g example, a m = 500 g, t 2 - t, = 10 ms. T h e i m p u l s e r e p r e s e n t e d as a solid line is a p p r o x i m a t e l y e q u i v a l e n t to t h e r e c t a n g u l a r a m p l i t u d e i m p u l s e 0.66 a m. T h i s i m p u l s e c a n b e u s e d for c a l c u l a t i n g t h e d e c e l e r a t i o n d i s t a n c e , w h i c h is d = II,:adt

= 10.66amt 2 2

Axial Vibrations

30 2 -

100 MM-CC

Transverse Vibrations

1 - 50 MM-CC

Angular Vibrations

1 - 25 DE(;-CC

Frequencies Hz

10

J

250

V///////////J

P'/.3 - 300 O~l I/I/11///////~

t

I 100

300

Figure 4-236. Order of magnitude of the vibration amplitudes encountered during drilling.

924

D r i l l i n g a n d Well C o m p l e t i o n s

Table 4-120 Resistance of Some Directional Tools or Components to Vibrations Tool

Low Frequencies

Azintac (1) Drill-director (2) Q-Flex accelerometer Develco accelerometer 4-Gimbal gyroscope 2-Axis gyroscope On-shore military specifications

1 mm cm 3 (5--50 Hz) 2 g (5-45 Hz) 12.7 mm cm 3 (20-40 Hz) 2 g (10-200 Hz) 5 g (10-300 Hz)

High Frequencies 10 g (50-500 Hz) 5 g (45-400 Hz) 25 g 40 g (40-2000 Hz)

14 g (50-2000 Hz)

(1) lust. Fr. du Pet. trademark (2) HumphreyInc. trademark (The accelerationvalues correspond to maximum amplitudes.)

am

0.66 am = ae

0.1 am tl

t2

Figure 4-237. Theoretical deceleration variation during a shock or impact.

and the velocity at the beginning of the deceleration:

v = 5t:a d t = 0 . 6 6 a m t F o r 500 g, 10 ms, we w o u l d h a v e d = 0.33 x 5 0 0 0 x (0.01) 2 = 0.16 m v = 0.66 x 5000 x 0.01 = 33 m / s a s s u m i n g t h a t 1 g = 10 m / s 2. A s s u m i n g t h e d e c e l e r a t i o n c o n s t a n t , as in t h e s q u a r e a p p r o x i m a t i o n o f F i g u r e 4-237, we h a v e a c o n s t a n t b r a k i n g force, w h i c h is F = m a = 0.66 m a m

(4-179)

MWD a n d LWD

925

where m is the decelerated mass. For a 2-kg mass and a m = 500 g (5,000 m / s z) F = 2 × 0.66 × 5000 = 660 daN Note: 1 daN = 2.25 lb M e a s u r i n g devices r u n inside the d r i l l s t r i n g are mainly subject to axial impacts. These shocks come from sudden halts in the mule shoe or from an obstruction in the string. The measuring devices used while drilling are generally subjected to axial and a n g u l a r impacts caused by the b o u n c i n g of the bit on the bottom and by the catching of the rollers a n d stabilizers on the borehole walls. There is very little information in the literature about measuring impacts while drilling. Table 4-121 gives the specifications compiled by manufacturers for several measuring devices. It can thus be seen that such devices must be equipped with an axial braking system capable of having a stroke of 10 a n d even 20 cm.

Future Developments. O r i e n t a t i o n measurements while drilling are practically impossible with gimbal gyroscopes. Two-axis flexible-joint gyroscopes should be able to withstand vibrations and impacts while maintaining a sufficiently accurate heading provided that periodic recalibration is p e r f o r m e d by halting drilling and switching on the n o r t h seeking mode. In the more distant future, laser or optical-fiber gyroscopes that have been suitably miniaturized should provide a solution. Example 5: Vibration and Shock AnalysismMeasurement Package Design A n MWD sensor package has the following specifications: • package mass: 0.906 kg (weight: 2 lb) • m a x i m u m vibrations allowable (all axes)

0.5-in p-p for 2 to 10 Hz 20 g for 10 to 200 Hz • shocks: 1000 g, 0.5 ms (all axes) (g = 9.81 m / s z = 32.17 f t / s z)

Table 4-121 Resistance of Some Directional Tools or Components to Axial Shocks or Impacts Tool Azintac

Drill-director Q-Flex accelerorneter Develco accelerorneter 4-Girnbal accelerorneter 2-Axis gyroscope

Military specifications

Deceleratlon (g, G)

Time (ms)

Braking Dlstance (m)

Initial Veloclty (m/s)

60 700 250 400 50 100

11 10 11 1 10 10

0.024 0.23 0.10 0.0013 0.016 0.033

4.35 46.2 18.15 2.64 3.3 6.6

30 to 100

10

926

Drilling and Well C o m p l e t i o n s

1. Vibrations: a. C o m p u t e the m a x i m u m acceleration that the i n s t r u m e n t will accept at 2 and at 10 Hz. b. C o m p u t e the peak to peak m o t i o n which can be a p p l i e d to the instrument at 10 and 200 Hz. c. C o m p a r e the 10-Hz values. At what frequency will the peak to peak data o f the low frequency be consistent with the acceleration data o f the high frequency? d. T h e package is held in a housing with several r u b b e r rings laterally assumed to behave like perfect springs. Two different ring stiffnesses are available with total values of: • 100 l b / i n • 10,000 l b / i n C o m p u t e the resonant frequencies for lateral vibrations. In the frequency range usually e n c o u n t e r e d in drilling, which one should be used? 2. Shocks along the borehole axis (sensor package axis): Assume that the shock specification refers to the m a x i m u m d e c e l e r a t i o n (am~) o f a half sine wave impact. The mean deceleration will be taken equal to 0.66 amax. a. Assuming a d a m p e n e r in the tool housing exerting a constant force and the housing stopping abruptly, c o m p u t e according to the specifications: • the distance o f d e c e l e r a t i o n * the velocity at the b e g i n n i n g o f the d e c e l e r a t i o n • the b r a k i n g force a p p l i e d to the sensor package b. Now if the b r a k i n g force is supplied with a coil spring o f 5,000 l b / i n . compute: * the b r a k i n g length for the velocity calculated in a. * the m a x i m u m deceleration, is it acceptable? * will such a coil spring be suitable for the vertical vibrations g e n e r a t e d in rotary drilling?

Solution 1. a. b. c. d.

0.1 and 2.55 g 3.91 and 0.039 in. At 10-Hz amplitudes: 0.5 and 3.91 in.; 28 Hz 22 and 221 Hz; 10,000-1b/in. ring m o r e suitable since frequency further from drilling frequencies 2. a. d = 0.03 i n . ; v = 10.6 ft/s; F = 1320 lb b. x = 0.13 in.; a = 324 g (a m = 491 g); acceptable; f = 156 Hz; acceptable

Example 6: Vibration and Shock Analysis--Mule Shoe Engaging Shock A steering tool sensor and electronic package is m o u n t e d in a housing in F i g u r e 4-238 with a shock a b s o r b e r a n d a s p r i n g to d e c r e a s e the value o f d e c e l e r a t i o n when e n g a g i n g the mule shoe. T h e package has a mass o f 2 kg or a weight o f 4.415 lb. Assume a downward velocity o f about 10 ft/s. T h e shock a b s o r b e r develops a constant force (indep e n d e n t o f the relative velocity) o f 10 lb (44.48 N). T h e spring stiffness is 57.10 l b / i n . T h e potential energy d u e to gravity will be neglected. 1. Taking into a c c o u n t only the shock a b s o r b e r , c o m p u t e the d i s t a n c e x traveled by the i n s t r u m e n t package with respect to the housing when the

MWD and LWD

,

927

Housing

sor Package

36,000 f-t/sec (10,973 m/s)

ing

,ck Absorber

Figure 4-238. Schematic representation of a shock dampening mechanism.

928

D r i l l i n g a n d Well C o m p l e t i o n s housing stops abruptly. Compute the maximum deceleration x in g's a n d t h e d e c e l e r a t i o n t i m e t. A l l c a l c u l a t i o n s c a n b e m a d e in E n g l i s h o r metric units. 2. T a k i n g i n t o a c c o u n t t h e s p r i n g only c o m p u t e t h e d i s t a n c e t r a v e l e d x a n d t h e m a x i m u m d e c e l e r a t i o n a in g's w h e n t h e h o u s i n g s t o p s a b r u p t l y . 3. N o w if b o t h t h e s p r i n g a n d t h e s h o c k a b s o r b e r a r e a c t i n g t o g e t h e r , w h a t will b e t h e d i s t a n c e t r a v e l e d x a n d t h e m a x i m u m d e c e l e r a t i o n a in g's w h e n the housing stops abruptly? 4. W h a t is t h e a d v a n t a g e in a d d i n g a s h o c k a b s o r b e r to t h e s p r i n g i n s u c h a system?

Solution 1. N e g l e c t t h e effect o f gravity. E n e r g y b a l a n c e : Fx = ~ m v 2 (v = 3.048 m / s ) x = m v 2 / 2 F = 0.209 m a = F / m = 22.24 m / s 2 = 2.26 g x = -~at2 --+ t = ( 2 x / a ) ~/2 = 0 . 1 3 7 s x = 0.209 m = 0.685 ft = 8.23 in. = 20.9 c m a -- 2.26 g t = 0.137 s = 137 m s 2. B e f o r e t h e tool hits, g o i n g d o w n at a c o n s t a n t velocity, t h e s p r i n g is a l r e a d y c o m p r e s s e d by t h e w e i g h t o f t h e i n s t r u m e n t p a c k a g e , so t h e e f f e c t o f gravity can be neglected. Energy balance: -~mv2 = -~kx2 x = ( m v 2 / k ) ~/2 = 0.043 m = 0.141 ft = 1.69 in. F = kx = 4 3 0 N a m - 2 F / m = 215 m / s 2 = 7 0 5 . 3 8 f t / s 2 = 21.9 g x = 0.043 m = 0.141 ft = 4.3 c m = 1.69 in. a = 21.9 g 3. Still n e g l e c t i n g gravity. E n e r g y b a l a n c e : Fx + ~ k x 2 = ~ m v 2 kx 2 + 2 F x - m v 2 = 0 x = [ - F + (F 2 + k m v 2 ) l / 2 ] / k = 0 . 0 3 8 8 m = 0 . 1 2 7 ft -- 1.53 in. = 3.88 c m F~= Fs+ 1/2 kx= 432.5 N a = F / m = 216.2 m / s 2 = 709.5 f t / s 2 = 22,03 g x = 3.88 c m = 1.53 in. a = 22.03 g 4. O s c i l l a t i o n s will b e d a m p e n e d ; x slightly d e c r e a s e d : 3.88 c m v e r s u s 4.3 cm.

Teledrift and Teleorienter T h e f i r s t t r a n s m i s s i o n o f d a t a d u r i n g d r i l l i n g u s i n g m u d p u l s e s was c o m m e r c i a l i z e d b y B.J. H u g h e s I n c . i n 1965 u n d e r t h e n a m e o f teledrift a n d teleorienter. B o t h t o o l s a r e p u r e l y m e c h a n i c a l . A g e n e r a l s k e t c h o f p r i n c i p l e is g i v e n i n F i g u r e 4-239. T h e tool is n o w o p e r a t e d by T e l e d r i f t Inc. T h e t o o l g e n e r a t e s at b o t t o m p o s i t i v e p u l s e s by r e s t r i c t i n g m o m e n t a r i l y t h e f l o w o f m u d e a c h t i m e t h a t t h e m u d f l o w ( p u m p s ) is s t a r t e d . T h e p u l s e s a r e d e t e c t e d at s u r f a c e o n t h e s t a n d p i p e a n d r e c o r d e d as a f u n c t i o n o f t i m e . F i g u r e 4-240 s h o w s t h e s k e t c h o f p r i n c i p l e o f t h e t e l e d r i f t u n i t w h i c h is measuring inclination. A p e n d u l u m h a n g s i n a c o n i c a l g r o o v e d b o r e . A s p r i n g t e n d s to m o v e t h e p e n d u l u m a n d t h e p o p p e t valve u p w a r d s w h e n t h e c i r c u l a t i o n stops. I f t h e tool

MWD and LWD

929

/

/

StandPipe

RotaryHose /

~'11

~i

=|

=

u

J

Ul

,. Bottomhole Assembly

Teledrift

!U

I I

Pressure Pick-up

..

,7

Recorder

F

r7 i

Figure 4-239. Sketch of principle of the teledrift toot or teleorienter tool attached to the drillstring. (Courtesy Te/edrift, /nc. [104].)

is inclined, the p e n d u l u m catches the grooves at different levels a c c o r d i n g to the inclination and stops there. For example, for m i n i m u m inclination (Figure 4-240b) it stops the p o p p e t valve past the first restriction. In Figure 4-240d, the p o p p e t valve stops past the seventh restriction d u e to the high inclination. W h e n the circulation is started, the p o p p e t valve travels slowly down, generating one pressure pulse when passing each restriction. T h e m e a s u r e m e n t range in the standard tool is o f 2.5 ° (also 7 ° ranges, 1° increments, max. 17°). Table 4-122 gives the inclination angles c o r r e s p o n d i n g to one to seven pulses with three cones. Fifteen cones are available. T h e m a x i m u m m e a s u r a b l e angle is 10% T h e range must be selected before lowering the drillstring.

Drilling and Well Completions

930

Surface RecordingsI of PressureSignals I ~

Pul

Signalir Pulse Ri Instrument I Upper Angh Adjustin

Cod Stop RingA= Pe Orifice BlockA,, Lower Lower

(A)

(B)

(C)

DRILUNG

CODED FOR

CODEDFOR

(D) CODEDFOR

MINIMUM

MINIMUM

ANGLE

ANGLE+ 2°

MAXIMUM ANGLE

1 SIGNAL

2 SIGNALS

7 SIGNALS

Figure 4-240. Teledrift mechanism in various coding positions. (Courtesy Teledrift, Inc. [104].)

Table 4-122 Teledrift Angle Range Settings Angle Range 0.5-3.0 1.0-3.5 7.5-10.0

Deviation Angle in Degrees 1 signal

2 signals

3 signals

4 signals

5 signals

6 signals

7 signals

0.5 1.0 7,5

1.0 1.5 8,0

1.5 2.0 8.5

2.0 2.5 9.0

2.5 3.0 9.5

3,0 3.5 10,0

3+ 3,5+ 10.0+

MWD and LWD

931

T h e cone can be replaced by a mechanism that senses the angular position r a t h e r than the inclination o f the drillstring. The tool is then sensitive to the tool face a n d is called the teleorienter. Figure 2-241 shows the read-out display o f the d r i l l e r in a zero tool-face position. Four m u d pressure pulses will be r e c o r d e d each time the p u m p s are started. In Figure 4-242a, a tool-face value o f 20 ° is indicated by three pulses, turning to the right. In Figure 4-242b, a tool-face value of - 2 0 ° is indicated by five pulses, and the b o r e h o l e is t u r n i n g left.

Figure 4-241. Driller read-out display of the teleorienter in a zero tool face

angle "go straight, build angle" position. (Courtesy Teledrift, Inc. [104].)

(a)

Co)

Figure 4-242. Driller read-out display of the teleorienter: (a) +20 ° tool-face angle, turning right position; (b) - 2 0 ° tool-face angle, turning left position. (Courtesy Teledrift, Inc. [104].)

932

Drilling a n d Well C o m p l e t i o n s

These tools have been widely used in the past by the cost conscious operators. T h e tool could be rented and o p e r a t e d by the rig f l o o r personnel. However, the inclination ranges are limited, only one tool, teledrift or teleorienter, can be used during a trip, and only the tool-face angle is read by the teleorienter, not the azimuth. These tools are still available but tend to be replaced by the MWD systems.

Mud Pressure and EM Telemetry Two m e t h o d s are currently used to transmit data from downhole to surface: m u d pressure telemetry and e l e c t r o m a g n e t i c e a r t h transmission. T h e r e are three principles for t r a n s m i t t i n g data by drilling m u d pressure: 1. positive pulses o b t a i n e d by a m o m e n t a n e o u s p a r t i a l r e s t r i c t i o n o f the downhole m u d current; 2. negative pulses o b t a i n e d by creating a p a r t i a l a n d m o m e n t a n e o u s comm u n i c a t i o n between the drill string internal m u d stream a n d the annular space at the level o f the drill collars; 3. phase changes o f a low-frequency oscillation o f the drilling m u d pressure i n d u c e d downhole in the drillstring. Figure 4-243 shows sketches o f the t h r e e systems.

Transmission by Positive Pulses. This system is used by Inteq/Teleco. It is placed in a n o n m a g n e t i c drill collar containing sensors o f the flux-gate type

(a)

(b)

(c)

Figure 4-243. Telemetry systems using mud pressure waves: (a) negative pulse system; (b) positive pulse system; (c) continuous wave system.

MWD and LWD

933

for measuring the direction of the earth's magnetic field and accelerometers for measuring the gravity vector. A n electromagnetic and electronic unit, every time rotation is halted, calculates and m e m o r i z e s the azimuth, drift and tool face angles. B o t t o m h o l e electric power is supplied by an AC g e n e r a t o r coupled with a t u r b i n e situated on the m u d stream in the drill collar. In rotary drilling a rotation d e t e c t o r triggers angle m e a s u r e m e n t s when the string stops rotating with circulation maintained. With a downhole m o t o r the m e a s u r e m e n t s are r e p e a t e d as long as m u d continues to circulate. T h e transmission uses a ten-bit digital coding. Figure 4-244 gives a schematic d i a g r a m of the positive pulse generator.

Maximum Valve Travel MudValve

Turbine

Electrical Cable

Sensor and Electronics Package

Jibration solator Valve ~ctuator

Generator

Centralizer

Vibration Isolator

Figure 4-244. Schematic diagram of the positive pulse system. (Courtesy Inteq- Te/eco [105].)

934

Drilling and Well Completions

The coding principle is given in Figure 4-245. Each angular value of azimuth, drift and tool face is represented by ten bits. The practical "positive pulse" system is slightly different. The "1" bits correspond to incomplete strokes of the poppet valve as shown in Figure 4-246, making the system a slow phase-shiftkeying system. Transmission rates of 0.2 or 0.4 bit/s are commonly used.

Markerpulse

0

0

I

0

0

0

[ i i i i i l

i i i i l

i

i i l

f

i

Time

Figure 4-245. Principle of the coding of the positive pulse system. (Courtesy Inteq-Teleco [105].)

0.2 bit/second transmissionrate ~/ ~, 5 secondf.all~ , ) ~ 5 secondnse - ~

0.4 bit/second transmissionrate

"0" pulsepressure rise or fall

¢ ~,

5 secondSseconds~%.._--2.5 secondrise 2.5 ~ ""--- 2.5 secondfall

.... ~ "1" pulsepressure ~,~ 2.5 seconaTall~ ] } rise andfall ~7 2.5 secondrise~ ~ or fall andrise 2.5 secondrise ~(,~ t " over5 seconds ~.~ 2.5 secondfall ~J J ^ - s _ ~ f'~.~_._-1.25secondfall ~,/ overz.b econas . , ~ , . ~ . ~.2~SeCoOn ~ rriiSe < ~}

2.5 secondsi ~ - - ' " 1'.25secondfall 5 seconds

Figure 4-246. Pressure waves used in the practical application of the positive pulse system. (Courtesy /nteq-Te/eco [105].)

MWD and LWD

935

The calculation of the amplitude of pressure variation at bottom can be done a s s u m i n g that the restriction behaves as a choke. The pressure loss can be estimated using the relations Ap=

Q 2 • 7 •144 2ogcoc2oA~

where AP = Q = "y = c = A0 = gc =

(4-180)

pressure loss in psi flowrate in fl3/s fluid specific weight in l b / f l 3 coefficient assumed to be one cross-sectional area of the restriction in in. ~ acceleration of gravity (32.2 f t / s ~)

W h e n using a m u d motor, the Ap due to the restriction must be added to the Ap due to the motor a n d the bit nozzles. The m u d motor pressure loss is given by

Ap =

1714. W 11"Q

(4-181)

where Ap = pressure loss in psi W = motor power in HP = motor efficiency Q = m u d flowrate in g a l / m i n Formula 4-180 will apply to the bit nozzle pressure loss.

Transmission by Negative Pulses. Drilling with a nozzle bit or with a downhole motor introduces a differential pressure between the inside and the outside of drill collars. This differential pressure can be changed by o p e n i n g a valve and creating a c o m m u n i c a t i o n between the inside of the drill string and the a n n u l a r space. In this way, negative pulses are created that can be used to transmit digital data in the same way as positive pulses. H a l l i b u r t o n and other companies are marketing devices using this transmission principle. Equation 4-180 can be used to calculate the pressure change inside the drill collars by changing the cross-sectional area A 0 from bit nozzles only to bit nozzles plus the pulser nozzle.

Continuous-Wave Transmission. A n a d r i l l , a s u b s i d i a r y of Schlumberger, markets a tool which produces a 12-Hz sinusoidal wave downhole. Ten-bit words representing data are transmitted by changing or m a i n t a i n i n g the phase of the wave at regular intervals (0.66 s). A 180 ° phase change represents a 1, and phase maintenance represents a 0. Figure 4-247 shows a sketch of principle of the system a n d of the phase-shiftkeying technique. Frames of data are transmitted in a sequence. Each frame contains 16 words, a n d each word has 10 bits. Some i m p o r t a n t parameters may be repeated in the same frame, for example, in Figure 2-248, the torque Tp, the resistivity R a n d the gamma ray GR, are repeated four times. The weight on bit WOB is repeated twice, a n d the alternator voltage Va~t one time. Note that a synchronization pulse train starts the frame.

936

Drilling and Well Completions Time

D,.t

I)

Clock 2 4 HZ

n _ _ R

Clock bit .----'~

.°o~ ' I A N ~ W W W V N V ~

-.,.

Bit r.d

-..

i--

..~

./I

~0

.."

..,,J L I

."'~

I

,= *' f, I t | t (t iOIOI I tOI 111 ICIII !OltlOt 111~C)|IIt JI [0~1 I~Oltl

MI sinuso

(~

Co)

Figure 4-247. Principle of the continuous wave system: (a) sketch of the siren and electronic block diagram; (b) principle of the coding by phase shift keying. (Courtesy Anadri// [106].)

zz

•

0

!

1

0

1

0

0

0

0

!

;<-,,

0

i

1 w°rO (1o b,t"5)

\

(,o ,~l..)

/

!

/!*,"

":

1

!'

"*-- | 3to" "-,-:!

|

( ~.~ b;.,I,,,.)

/ \

! !

,'=

;

:

/

(j:j

10

11

1}

1~

IS'

16

!

( 16 worcJ$) ('1260 t,vcl¢s -

=

>,,

1 ?tame 106.7 seco,ds)

Figure 4-248. Example of a frame of data transmitted by the continuous wave system. (Courtesy Anadri// [106].)

MWD a n d LWD

937

The early system was transmitting 1.5 b i t s / s (4 sine waves to identify one bit). Later systems went to 3 bits/s. Now with a 24-Hz c a r r i e r frequency, 6 b i t s / s can be transmitted. Then, with data compression techniques (sending only changes for most o f the words in the frame and rotating the data), an effective transmission rate o f 10 b i t s / s can be achieved. T h e c o n t i n u o u s wave t e c h n i q u e has a d e f i n i t e a d v a n t a g e over the o t h e r t e c h n i q u e s : a v e r y n a r r o w b a n d o f f r e q u e n c i e s is n e e d e d to t r a n s m i t t h e information. T h e pulse techniques, on the contrary, use a large b a n d o f frequencies, a n d the various noises, p u m p noises in particular, are m o r e difficult to eliminate. In p r i n c i p l e , several channels o f i n f o r m a t i o n could be t r a n s m i t t e d simultaneously with the continuous wave technique. In particular, a downward channel to control the tool modes a n d an upward channel to b r i n g up the information.

Fluidic Pulser System. A new type o f pulser is being d e v e l o p e d at Louisiana State University. It is based on a patent by A. B. Holmes [107]. The throttling o f the m u d is o b t a i n e d by creating a turbulent flow in a c h a m b e r as shown in Figure 4-249. A vortex is generated by momentarily introducing a dissymetry in the chamber. T h e resulting change in pressure loss can be switched on and off very rapidly. T h e switching time is approximately 1 ms a n d the a m p l i t u d e o f the pressure loss change can be as high as 145 psi (10 bars). T h e prototype tool can o p e r a t e up to 20 Hz. Using a continuous wave with two cycles p e r bit could lead to a rate o f 10 bits/s. With a data compression technique, 15 effective bits p e r second could be transmitted, c o r r e s p o n d i n g to 1.5 data p e r second.

! Actuator ~. y r

Pressuresignal pulsesto the surtace

Vortex pulservalve

Borehole •j ,~

~ r~

[~ Mud flOW ! , . ~ . . , - t o surface

~ " Drill bit

Figure 4-249. Fluidic mud pulser principlet. (Courtesy Louisiana State University [107].)

938

Drilling a n d Well C o m p l e t i o n s

Surface Detection of the Mud Pressure Signals.

Thepulseorwaveamplitude

varies largely a c c o r d i n g to d e p t h , frequency, m u d type a n d pulse g e n e r a t o r device. A typical m u d surface pulse a m p l i t u d e is 1 bar (14.5 psi). In a sine wave transmission the surface a m p l i t u d e may go as low as 0.1 b a r (1.5 psi) rms. T h e p u m p noise must be l o w e r e d to m i n i m u m by the use o f p r o p e r l y a d j u s t e d d a m p e n e r s and triplex instead o f duplex pumps, the pulse amplitude being about twice as large for the d u p l e x pumps. T h e p u m p noise a m p l i t u d e varies from 0.1 to 10 or more bars (1.5 to 145 psi) with d o m i n a n t frequencies ranging from 2 to 10 Hz. T h e rotation s p e e d o f the p u m p s may have to be c h a n g e d so the noise frequency does not interfere with the measurements. T h e pressure sensors are g e n e r a l l y o f t h e AC-type, which sense only the p r e s s u r e v a r i a t i o n s . A c o m m o n sensor is o f the piezoelectric type with a crystal transducer. Generally a built-in c o n s t a n t c u r r e n t follower a m p l i f i e r c o n v e r t s t h e signal to a low i m p e d a n c e voltage. A typical sensitivity is 5 V p e r 1,000 psi (70 bars) with a m a x i m u m constant pressure o f 10,000 psi (700 bars). T h e filtering can be d o n e with digital filters or F o u r i e r t r a n s f o r m analyzers. For a F o u r i e r t r a n s f o r m processing, the signal must be p r o p e r l y analog-filtered a n d t h e n digitized. Two pressure t r a n s d u c e r s can be used at different locations on the standpipe, as shown in Figure 4-250, to take advantage o f the phase shift that is o p p o s i t e for p u m p noise and d o w n h o l e signal. Sophisticated digital cross correlation techniques can then be used.

Downhole Recording. Most MWD service c o m p a n i e s offer the possibility o f r e c o r d i n g the d a t a versus time downhole. T h e m e m o r i e s available may reach several megabytes, allowing the recording o f many p a r a m e t e r values during many hours. This i n f o r m a t i o n is particularly valuable when the m u d pulse link breaks down. T h e data can be d u m p e d in a computer, during the following drillpipe trip.

essureTransducer ]I[

MudPulsesl/IPumpN°ise ,~sure Transduce~Dampener Pump

Figure

4-250.Surfacepressure transducers location for pump noise elimination.

MWD and LWD

939

Retrievable Tools. Retrievable MWD tools similar to the steering tools are available from several service companies. They are generally battery powered a n d generate c o d e d positive pressure m u d pulses o r continuous pressure waves. T h e lower part o f the tool has a mule shoe that engages in a sub for orientation. Currently, tools are available for m e a s u r i n g directional p a r a m e t e r s a n d g a m m a rays. A typical retrievable tool is shown in Figure 4-251.

Nonretrievablelmpeller sleRotor eve Stator

Centralizer

Electronics module

GammaRay

Battery module PonyMonel UBHOsub Bottom landing assembly

Figure 4o251. Retrievable MWD tool. (Courtesy Anadrill [106].)

940

Drilling a n d Well C o m p l e t i o n s

T h e benefits o f such a tool are a p p a r e n t in the following instances: • • • • • •

kickoffs and sidetracks c o r r e c t i o n runs high stuck-pipe risk high t e m p e r a t u r e slim hole low-budget drilling

Velocity and Attenuation of the Pressure Waves. T h e velocity and attenuation o f the m u d pulses or waves have b e e n studied theoretically and experimentally. T h e velocity d e p e n d s on the m u d weight, m u d compressibility, a n d on the d r i l l p i p e characteristics, a n d varies from 4920 f t / s for a light water-base m u d to 3,940 f t / s for a heavy water-base mud. A n oil-base m u d velocity will vary from 3,940 f t / s for a light m u d to 3,280 f t / s for a heavy mud. T h e p r o p a g a t i o n velocity can be calculated using the equation

V = Jgc .144. B*M T(B + M)

V

(4-182)

and (a 2 - b 2)

M=E 4.b2( 5-

where V = gc = B = E = a = b = ~, = T=

~,]+ 2(1+ ~,)(a 2 + b 2)

(4-183)

pressure wave velocity in f t / s acceleration due to gravity: 32.17 f t / s z m u d bulk modulus in psi (inverse o f compressibility) steel Young modulus o f elasticity in psi OD o f the p i p e in in. ID o f the pipe in in. steel Poisson ratio m u d specific weight in l b / f t s

For example, in a 9 l b / g a l water-base mud, a n d a 4-~-in. steel drillpipe, the pressure wave velocity is 4,793 ft/s. The attenuation o f the pressure waves increases with d e p t h and with the m u d pressure wave velocity. More attenuation is o b s e r v e d with oil-base muds, which are mostly used in d e e p or very d e e p holes, and can be calculated with the m u d and p i p e characteristics [108] according to the equations x

e ( x ) = e ( 0 ) ( e L)

(4-184)

F

L = d i • V * ~/. 2 v 1]*o)

(4-185)

MWD a n d LWD where P(x) = P(0) = 11 = (o = with f = di = V =

941

pressure wave amplitude at distance x in psi pressure wave amplitude at distance 0 in psi kinematic viscosity in ft2/s (1 cSt x 1.075 x 10 -5 = 1 ft2/s) angular frequency in r a d / s ((o = 2~f) frequency in Hz pipe internal diameter in ft wave velocity in f t / s

Figure 4-252a a n d b gives the pressure wave amplitude versus the distance for various typical muds.

Electromagnetic Transmission Systems. O n e system uses a low-frequency a n t e n n a built in the drill collars. This system is a two-way e l e c t r o m a g n e t i c a r r a n g e m e n t allowing c o m m u n i c a t i o n from bottom to surface for data transmission and from surface to bottom to activate or modify the tool mode. At any time the sequence of the transmitted parameters, as well as the transmission rate, can be modified. The tool is battery powered and can work without m u d circulation. The principle of the system is shown in Figure 4-253. The receiver is connected between the pipe string and an electrode away from the rig for the bottom to surface mode. This system can be used on- or off-shore. Two tools are available: the directional tool, which transmits inclination, azimuth, gravity tool face or magnetic tool face, magnetic field inclination a n d intensity; a n d the formation evaluation tool, which measures g a m m a ray a n d resistivity. The f o r m a t i o n e v a l u a t i o n data are stored d o w n h o l e in a m e m o r y that can be interrogated from the surface or transferred to a c o m p u t e r when pulling out. Figure 4-254a gives the attenuation per kilometer as a f u n c t i o n of frequency for an average formation resistivity of 10 and 1 ~ • m.

PULSEAMPLITUDE,psi 5 10 20 4 1/2" drill pipe 9 Ib/gal,20-cp mud ......

Water-based mud Oil-based mud

,

PULSEAMPLITUDE,psi 50

o*~

1O0 0

#J /

:

5

10

20

4 1/2" drill pipe

50

1O0 0

18 Ib/gal,20-cp mud Water-based mud

5,000

,

......

Oil-based mud

,

5,000

10,00(

10,000 :~

15,000

:

!

20,00(

(a)

20,000

(b)

Figure 4-252. Wave amplitude variation as a function of distance in waterbase mud and in oil-base mud: (a) mud weight, 9 Ib/gal; (b) mud weight, 17.9 Ib/galt. (Courtesy Petro/eum Engineer Internationa/ [10810

942

Drilling and Well C o m p l e t i o n s

Figure

4-253. Principle of the electromagnetic MWD transmission. (Courtesy

Geoservices [109].)

E

N

40

~ ao

~

I ~m

•rillpip•

70 6O : . , ~ * " ~ J ¢._o 50

20

10

--.....~ %%~~' ,~~j ~j ~jMWD ~j 10~m

e--

Casing

~

E

l"m÷re'ay

"~ ]

l~m

10~

I

I

I

5

10

15

(a)

Frequency

I

>

0

I

I

I

5

10

15

Frequency •

(b)

Figure 4-254. Attenuation of electromagnetic signals for 1 and 0 ~ • m average earth resistivity: (a) attenuation as a function of frequency; (b) maximum depth reached versus frequency. (Courtesy Geoservices [109].)

W i t h the d o w n h o l e power available a n d the signal d e t e c t i o n t h r e s h o l d at surface, Figure 4-254b gives the m a x i m u m d e p t h that can be reached by the technique as a function of frequency. Assuming that phase-shift keying is used with two cycles p e r bit, in a 10 f~ • m area (such as the Rocky mountains) a d e p t h of 2 km (6,000 ft) could be reached while t r a n s m i t t i n g 7 b i t s / s . Coding and Decoding. Ten-bit b i n a r y codes are used to t r a n s m i t the inform a t i o n in most techniques. In one technique, the m a x i m u m r e a d i n g to be transmitted is divided ten times. In a word, each bit has the value c o r r e s p o n d i n g to its rank.

MWD and LWD

943

Demonstration. T r a n s m i t a r a n g e o f v a l u e s b e t w e e n 0 a n d 90 °. Bit Value Word Word Word

1 45

1 22.5

1 11.25

1 5.62

1 2.81

1 1.40

1 0.70

1 0.35

1 0.17

1 0.08789

1 1 1 1 1 1 1 1 1 1 = 89.91 ° 1011011001 = 64.06 ° 0 0 0 1 1 0 0 1 1 1 = 9.04 °

I n a n o t h e r t e c h n i q u e , e a c h b i t r e p r e s e n t s a p o w e r o f two i n a g i v e n w o r d . T h e h i g h e s t n u m b e r t h a t c a n b e t r a n s m i t t e d is 29 + 28 + 27 + 26 + 2 ~ + 24 + 2 s + 22 + 21 + 20 = 1023 as well as zero. T h e s m a l l e s t v a l u e t h a t c a n b e t r a n s m i t t e d for a full s c a l e o f 90 ° is 90/1024 = 0.08789 ° E a c h b i t h a s t h e f o l l o w i n g n u m e r i c a l value: Bit Value

29 512

28 256

27 128

26 64

25 32

24 16

2 s 22 21 20 8 4 2 1

F o r e x a m p l e , to t r a n s m i t 6 4 . 0 6 ° , t h e n u m e r i c a l v a l u e is 6 4 . 0 6 / 0 . 0 8 7 8 9 = 729 We will h a v e o n e one one one one one

"29" "2 TM "26" "24" "2 s'' "2 o"

bit: bit: bit: bit: bit: bit:

7 2 9 - 512 2 1 7 - 128 89 - 64 = 25 - 16 = 9 - 8 = 1 1 - 1 = 0.

= 217 = 89 25 9

T h e w o r d w o u l d b e 1 0 1 1 0 1 1 0 0 1 = 729. T h i s is t h e s a m e b i n a r y w o r d as f o u n d p r e v i o u s l y . I n e a c h t e c h n i q u e t h e a c c u r a c y is 0 . 0 8 7 8 9 ° for a r a n g e o f 0 to 90 °. T h e r o u n d i n g m u s t b e d o n e t h e s a m e way w h e n c o d i n g a n d d e c o d i n g .

Example 7: Mud Pulse Telemetry--Positive Pulse Calculations A p o s i t i v e p u l s i n g d e v i c e h a s b e e n d e s i g n e d as s h o w n i n F i g u r e 4-255. 1. C o m p u t e t h e p r e s s u r e loss w h e n t h e p u p p e t valve travels f r o m 0.2 to 0.5 in., w h e r e 0.0 in. is t h e fully c l o s e d p o s i t i o n , for e a c h 0.05 in. for a f l o w r a t e o f 400, 500 a n d 6 0 0 g a l / m i n , a n d f o r a m u d w e i g h t o f 10 l b / g a l . T h e n o z z l e e q u a t i o n is

Q = C.A.

i2I • 1 4 4 . g ¢ * U P Y V

(4-186)

944

D r i l l i n g a n d Well C o m p l e t i o n s

v

2.0" Dia

f

A

Figure 4-255. Typical positive pulse valve design. where Q = A = C = dP = "t' = gc =

f l o w r a t e in ftS/s f l o w a r e a in ft 2 f l o w factor (C = 1.0) p r e s s u r e loss in psi f l u i d specific weight in l b / f t s 32.18 f t / s 2

T r a c e t h e c u r v e r e p r e s e n t i n g dP versus t h e p u p p e t valve d i s p l a c e m e n t for t h e 5 0 0 - g a l / m i n f l o w r a t e .

MWD and LWD

945

2. What is the pulse amplitude (pressure surge) for the various flowrates when the p u p p e t valve travels from 0.2 to 0.5 in.? At what position will we have a half-height pulse? 3. We are using a m u d motor which rotates at 500 r p m and develops a useful power of 100 hp. Assuming a constant flowrate of 500 g a l / m i n , no pressure loss in the bit nozzles a n d 80% m o t o r efficiency, c o m p u t e the total bottomhole assembly AP at 0.2- a n d 0.5-in. valve opening. 4. The pulses are used to transmit deviation data from 0 ° to 90 ° with a 45, 22.5, 11.25, etc., sequence binary code of 10 bits. What is the transmission accuracy? Give the binary n u m b e r for 27.4 ° . 5. Assuming the pressure pulse travels with the sound velocity of the mud, how long will it take to reach the rig f l o o r in a 12,000-ft borehole? T h e s o u n d velocity in the m u d is given by v = (g¢

x

B

x

144/7) '/2

where v = sound velocity in ft/s B = m u d bulk modulus (3.3 x 105 psi) 7 = m u d specific weight in l b / f t 3

Solution

Table 4-123 Typical Positive Pulse Amplitude Generated at Bottomhole

400 gal/min 500 gal/min 600 gal/min

0.2 In.

0.5 in.

Amplitude

187 psi 290 psi 420 psi

35 psi 55 psi 79 psi

152 psi 235 psi 341 psi

2.

Table 4-124 Half-Height Stroke of the Valve Amplitude

Half Height

152 235 341

0.264 in. 0.264 in. 0.264 in.

400 gal/min 500 gal/min 600 gal/min

3. AP motor: Bottomhole Ap:

429 psi 0.2 in., 719 psi 0.5 in., 484 psi 4. 27.4°: 0100110111 Accuracy: 0.08789 ° Average error: 0.043945 ° 5. S o u n d velocity: 4510 f t / s Travel time: 2.67 s

946

Drilling a n d Well Completions

Example 8: Mud Pulse Telemetry--Negative Pulse Calculations The negative m u d pulse system works with a nozzle which periodically opens in the wall of the drill collar to lower the pressure in the pipe string. The following data will be used: • • • •

Bit nozzles: 3 x ~ or 3 x ~2 or 3 x ~2 in. Pulse nozzle sizes: 0.3 or 0.4 or 0.5 in. diameter Mud flowrates: 400 or 500 or 600 g a l / m i n Mud weight: 12 I b / g a l

1. Compute the pressure change inside the drillpipe at bottom when the pulse nozzle opens in each case. Give the optimal c o m b i n a t i o n s for getting 200 to 250 psi pulses. 2. A 10-bit digital system uses the sequence 180, 90, 45, 22.5, etc., to transmit the azimuth value. What is the accuracy of the transmission? Give the binary n u m b e r s for S-23-E by excess, default and nearest. 3. A positive displacement m u d motor is included in the downhole assembly between the bit and the MWD system. It develops a true power of 100 hp when the pulse nozzle is closed. What is the true power o b t a i n e d when a 200-psi pulse is created? The bit nozzle pressure loss will be neglected. Use • pulse nozzle diameter: 0.5 in. • m u d flowrate: 400, 500, 600 g a l / m i n • m u d motor efficiency: 80% 4. Same question taking into account the pressure drop in the bit nozzles with 3 x ~2 in. nozzles. Solving for AP in Equation 4-186 gives AP =

Q2 . ~ / , 144 2.gc.C2.A 2

where Q = A = C = AP = "f = gc = HP =

flowrate in ft3/s nozzle area in in. 2 nozzle factor (C = 1.0) pressure drop across the nozzles in psi m u d specific weight in I b / f t 3 32.2 f t / s 2 eft x AP x Q / 1 7 1 4

Solution 1.

Table 4-125 Optimum Nozzles Combination for Generating 200 to 250 psi Pulses Bit Nozzles 400 400 500 500 600

gal/min gal/min gal/min gal/min gal/min

15/32 16/32 15/32 16/32 16/32

in. in. in. in. in.

Pulse Nozzles 0.4 0.5 0.3 0.4 0.3

in. in. in. in. in.

MWD a n d LWD

947

2. S-23-E = 157 ° Default: 0110111110 156.796 ° Excess: 0110111111 157.148 ° Nearest: 0110111111 157.148 ° 3. Motor hp at 400 g a l / m i n : 44.8 hp Motor hp at 500 g a l / m i n : 43.3 hp Motor hp at 600 g a l / m i n : 38.3 hp 4.

Table 4-126 Typical Conditions Encountered for Various Flowrates

Pulse nozzle closed

Pulse nozzle open

400 gal/min

500 gal/min

600 gal/min

AP motor 100 hp AP bit nozzle Total AP

536 460 996

428 719 1147

1035 1392

psi psi psi

AP pulse

-200

-200

-200

psi

AP open Flow pulse nozzle Flow motor/bit New AP bit New AP motor New hp motor

796 175 225 145 651 68

947 191 309 274 673 97

1192 215 385 427 765 138

psi gal gal psi psi hp

357

Units

Example 9: Mud Pulse Telemetry--Pressure Wave Attenuation A n MWD system is lowered at the e n d of a 4.5-in. drillstring in an 8-in. borehole. Neglect the drill collar section of the string. T h e following data are available: • • • • • • • • • • • 1. 2. 3, 4. 5. 6.

total depth: 10,000 ft borehole average diameter: 8 in. drillpipe OD: 4.5 in. drillpipe ID: 3.64 in. drillpipe Young modulus: 30 × 106 psi drillpipe Poisson ratio: 0.3 m u d specific weight: 12 l b / g a l m u d compressibility: 2.8 × 10 -6 psi -1 m u d viscosity: 12 cp m u d flow rate: 400 g a l / m i n bit nozzles: 3 × ~ in.

Compute the bottomhole hydrostatic pressure with no flow. C o m p u t e the pressure drop in the drill pipe while circulating. C o m p u t e the pressure drop in the a n n u l u s while circulating. What is the pressure drop in the bit nozzles? What is the p u m p pressure at surface? Make a graph of the pressure variation with depth without circulation in the drillpipe and annulus. 7. Compute the velocity of the pressure wave in free m u d (not in a drillpipe).

948

Drilling and Well Completions

8. Compute the velocity of the pressure wave in the drillpipes. 9. Compute the amplitude of a pressure wave at surface of a wave generated at bottom with an amplitude of 200 psi at frequencies of 0.2, 6, 12 and 24 Hz. Pressure loss in pipe (turbulent flow) is dP

=

d L * ) '0.75 * v L75 * ]a, °'25

(4-187)

1800" d L25 Pressure loss in annulus (turbulent flow) is dP = dL * 2'o.7s. VLTS. BO.2S 1396. (d 2 - d~)L2S where dP = dL = 2' = v = d = d1= d~ = =

(4-188)

pressure loss in psi pipe or annulus length in ft fluid specific weight in l b / g a l fluid velocity in ft/s ID pipe diameter in in. OD pipe diameter in in. external annulus diameter in in. fluid viscosity in cp

Solution 1. 2. 3. 4. 5. 6. 7. 8. 9.

Bottomhole pressure, no flow: 6,240 psi Drillpipe pressure loss: 1,076 psi Annulus pressure loss: 113 psi Bit nozzle pressure loss: 1,055 psi Pump pressure: 2,244 psi Graph (see Figure 4-256) Wave velocity in free mud: 4,294 ft/s Wave velocity in drill pipes: 4,064 f t / s Wave amplitude at surface (Equations 4-184 and 4-185): 0.2 Hz, L = 86,744 ft, 178 psi 6 Hz, L = 15,837 ft, 106 psi 12 Hz, L = 11,198 ft, 81 psi 24 Hz, L = 7,918 ft, 56 psi

Example 10: Mud Pulse TelemetrymPulse Velocity and Attenuation Assume a well 10,000-ft deep, m u d weight o f 12 l b / g a l , m u d viscosity of 12 cp, 4~-in drillpipes (3.640 in. ID), mud flowrate of 400 gal/min, steel Young modulus o f 30 x 106 psi, and steel Poisson ratio of 0.3. 1. Compute the pressure at bottom inside the drill collars: a. with no flow and no surface pressure, b. with no flow and 2,500 psi surface pressure, c. while pumping 400 g a l / m i n with 2,500 psi at surface.

MWD and LWD Pressure 2000

0

949

(psi) 6000

4000

8OO0

10000

0

1000

f

T i I

I I

•

i

2000'

"

j

I

t

1

I

l!

Ii

3000

it

I 2500 psi st ! no flow I

4000

"0

surface

J

5000

f

i!!

A

2500 psl at surface with flow

J

6000,

,/J

7000.

i

Statll 8000'

9000"

i

i

I

1

I

10000

F i g u r e 4-256. Pressure variation with depth: grid with the solution.

Draw a pressure traverse for each case in the attached graph, use pressure loss equation given in Data Sheet below. 2. A pressure pulse is generated at bottom. Compute the pulse velocity in the pipe at bottomhole and at surface, while circulating, assuming a surface temperature of 25°C and a bottomhole temperature of 85°C. The mud compressibility is assumed equal to the water compressibility given in Figure 4-257. Compare to the free mud pressure pulse velocity.

950

D r i l l i n g a n d Well C o m p l e t i o n s

3. For t h e a v e r a g e p r e s s u r e wave velocity in t h e pipe, c o m p u t e t h e d i s t a n c e at w h i c h t h e a m p l i t u d e falls to 1 / e o f its o r i g i n a l value, t h e d i s t a n c e at w h i c h it falls at o n e - h a l f o f its o r i g i n a l v a l u e (half d e p t h ) a n d t h e attenuat i o n in d B / 1 , 0 0 0 ft. C o m p u t e also t h e a m p l i t u d e at surface. B o t t o m h o l e a m p l i t u d e p e a k to peak: 200 psi; f r e q u e n c i e s : 0.2, 12 a n d 24 Hz.

Data Sheet. P r e s s u r e loss ( E q u a t i o n 4-187) is g i v e n by dP =

dL • 7 °'7s • V~75 • ~o.z~ 1800 • d 1'~5

w h e r e dP dL 7 v

= = = = = ~t =

p r e s s u r e loss in psi p i p e o r a n n u l u s l e n g t h in ft m u d specific weight in l b / g a l m u d velocity in f t / s ID p i p e d i a m e t e r in in. m u d viscosity in cp

P r e s s u r e wave velocity is

where Vw = 7 = B = M =

p r e s s u r e wave velocity in f t / s m u d specific weight in l b / f t ~ f l u i d b u l k m o d u l u s in l b / f t 2 drill p i p e m o d u l u s in l b / f f f

B = 1/K w h e r e K = m u d c o m p r e s s i b i l i t y in ft2/lb gc = g r a v i t y a c c e l e r a t i o n 32.2 f t / s 2 and

M =

E(Do~ - D~) 2 ( 1 - v)(Do2 + D ~ ) - ( 2 " V , D~)

where E = DO = Di = v =

steel Young m o d u l u s in l b / f t 2 e x t e r n a l drill p i p e d i a m e t e r in ft i n t e r n a l drill p i p e d i a m e t e r in ft steel Poisson r a t i o

P r e s s u r e wave a t t e n u a t i o n is P(x) = P(0) • e -~/L w h e r e P(x) = wave a m p l i t u d e at d i s t a n c e x P(0) = wave a m p l i t u d e at o r i g i n

MWD and LWD

951

x = d i s t a n c e in ft L = d i s t a n c e at which t h e a m p l i t u d e falls to 1 / e o f its o r i g i n a l v a l u e T h u s , t h e l e n g t h can b e e x p r e s s e d as

L = 0.5

•

where D i = Vw = = F = 11 = Also,

Di

.12

TI~(0

• V w

i n t e r n a l p i p e d i a m e t e r in ft wave velocity in f t / s a n g u l a r f r e q u e n c y in r a d / s (co = 21tf) wave o r p u l s e f r e q u e n c y k i n e m a t i c viscosity in ft2/s

P(x) = P(0) • 2 -~D w h e r e D = distance at which the a m p l i t u d e falls to ~ of original value (half depth) and P(x) = P(0) ° 10 -~/B w h e r e B = distance at which a m p l i t u d e falls to 110 o f its original value (attenuation o f 2 bel o r 20 dB) A t t e n u a t i o n at d i s t a n c e x in dB is

x ( d B ) = 20 • log

P(x) =

(20•x)

P(0)

B

K i n e m a t i c viscosity (in consistent units) is n = II/P

(4-189)

w h e r e 11 = k i n e m a t i c viscosity IX = a b s o l u t e viscosity p = fluid density C o n v e r s i o n e q u a t i o n s are TI(~)

-- II(cp)* 2"09y x 10-~ * g"

w h e r e gc = 32.18 f t / s ~ y = m u d specific w e i g h t in l b / f t s and

952

D r i l l i n g a n d Well C o m p l e t i o n s

q I ~ - ~ ) = 1. 075 x 10-5 • q ( c s t ) .

W a t e r i s o t h e r m a l c o m p r e s s i b i l i t y is K = (A+

BT+

C T 2 ) * 10 .6

where A = 3.8546 - 0.000134 P B = - 0 . 0 1 0 5 2 + 4.77 x 10 -7 P C = 3 . 9 2 6 7 x 10 -5 - 8.8 x 10 -1° P and P T

= pressure in = temperature

psig i n °F

S e e F i g u r e 4-257 [110].

3.8

3.6

~

3"2

P" r e~s1s0u0r e0 ' p s . a .

. ~ ~ , ~ j ~ ~

o

N

2.4 2.2 50

~ / .

100

150

200

250

Temperature, °F Figure 4-257. Chart showing the variation of the coefficient of isothermal compressibility of water versus pressure and temperature [110].

270

MWD a n d LWD

953

Solution 1. a. 6,255 psia b. 8,740 psia c, 7,664 psia 2. Free f l u i d velocity: Surface: 4,168.6 f t / s Bottom: 4,356 f t / s Velocity in drillpipe: Surface: 4,044 f t / s Bottom: 4,215 f t / s Average velocity in pipe: 4,130 f t / s 3.

Table 4-127 Amplitudes at Surface for a 10,000-ft Well, 200-psi Downhole Pulses, for Various Frequencies

L D B Attenuation Pulse p-p amplitude at surface

0.2 Hz

12 Hz

24 Hz

83,357 ft 57,766 ft 191,971 ft 0.104 dB/1,000 ft 177.4 psi

10,761 ft 7,457 ft 24,782 ft 0.807 dB/1,000 ft 78.96 psi

7,609 ft 5,273 ft 17,523 ft 1.141 dB/1,000 ft 53.73 psi

Example 11: Mud Pulse Telemetry--Fluidic Pulser Calculations We have built a fluidic pulser system that can generate approximately 100 psi peak to peak with 500 g a l / m i n mud flowrate. It is to be used down to 15,000 ft. T h e surface detector needs a 5-psi p e a k to p e a k sine wave for p r o p e r phase detection. T h e following oil-base m u d is used: • • • •

density: 12 l b / g a l viscosity: 25 cp pressure wave velocity in the drill pipe: 3685 f t / s d r i l l p i p e diameter: 4.5 in. OD, 3.64 in. ID.

The system are necessary perfect pipe, the drill p i p e

transmits 5 b i t s / s with a phase-shift-keying system. Four sine waves to define the phase with a negligible chance o f error. Assume a drill collar ID same as the drill p i p e a n d no wave reflections at ends.

1. W h a t frequency(s) should be used? 2. W h a t peak-to-peak a m p l i t u d e (psi) of the pressure wave is necessary at b o t t o m to get the required peak to peak value at surface? Is our pulsing device suited for this j o b ? 3. T h e p u m p noise frequency is varying a r o u n d 8 Hz with a peak-to-peak a m p l i t u d e of 20 psi. Can the signal still be detected? Explain. 4. If we generate a 12-Hz wave at surface to transmit instructions downhole to the i n s t r u m e n t package, what a m p l i t u d e should it have at surface to reach b o t t o m with 5 psi peak to peak? 5. Can b o t h channels work simultaneously with p r o p e r filtering? Explain.

Drilling a n d Well C o m p l e t i o n s

954

6.

T h e m u d flow rate is 500 g a l / m i n a n d the fluidic p u l s e r has 4 x 2 4 / 3 2 in. d i a m e t e r nozzles in parallel. C o m p u t e the pressure loss in the fluidic p u l s e r in the m i n i m u m loss m o d e (C = 1). 7. W h a t is the equivalent d i a m e t e r o f each nozzle in the m a x i m u m loss m o d e to p r o d u c e the peak to peak wave value c o m p u t e d in question 2 (C = 1)?

Solution 1. 5 b i t / s x 4 cycles = 20 Hz (cycles/s). 2. P(x) = P(0) * e -~/D P(x)/P(0) = 0.0544, x = 4572 m P(0) = 91.9 psi 3. Yes, by filtering only the wave a m p l i t u d e c o r r e s p o n d i n g to 20 Hz can b e m e a s u r e d , thus eliminating the noise. 4. P(x)/P(0) -- 0.1049 P(0) = 47.6 psi 5. Yes, each d e t e c t o r will "see" only the wave a m p l i t u d e s c o r r e s p o n d i n g to 20 a n d 12 Hz. They will b e sensitive to "their" signal only. 6. 78.8 psi 7. 0.619 in.

Directional Drilling Parameters W i t h the m o d e r n accelerometers a n d solid-state m a g n e t o m e t e r s , a c o m p l e t e set o f d a t a is available for i n c l i n a t i o n , tool face a n d a z i m u t h c a l c u l a t i o n . Magnetic corrections can b e done. Inclination can b e calculated with Equations 4-174 a n d 4-175. T h e g r a v i t y tool face angle can b e c a l c u l a t e d with Equation 4-176. Azimuth calculation can b e d o n e by using vector analysis. In Figure 4-258 the vector Z represents the b o r e h o l e axis, vector H the e a r t h m a g n e t i c field a n d vector G the vertical o r gravity vector. T h e azimuth is the angle b e t w e e n the vertical planes VH a n d Vz counted clockwise starting at VH" This angle is the same as the angle b e t w e e n vectors A and B, respectively, p e r p e n d i c u l a r to VH a n d Vz" We know that A = G x H (vector p r o d u c t )

(4-190)

B=GxZ T h e c o m p o n e n t s o f H a n d G are m e a s u r e d in the referential o f the MWD tool, a n d Z is the vector (0, 0, 1) in the same referential. Now the azimuth tx o f the b o r e h o l e can b e c o m p u t e d with the scalar p r o d u c t B • A; thus ( A*B

_-

J

(4-191)

Some p r e c a u t i o n s must b e taken to b e sure that the correct angle is c o m p u t e d since cos(ix) = cos(-tx). T h e MWD sensors are located in a n o n m a g n e t i c p a r t o f the drill collars. T h e m a g n e t i c collars located several meters away still have an effect by creating a perturbation in the direction o f the borehole axis. This introduces an e r r o r that is

MWD a n d LWD

955

A

NB

~ G

Figure 4-258.

Z ,,

Solid geometry sketch of the planes defining the azimuth angle.

empirically corrected with the single-shot instruments. Since the three components of H are measured, the m a g n i t u d e of the error vector can be calculated if the module of the n o n p e r t u r b e d earth magnetic vector is known. The corrected dip angle vector can also be computed and compared to the non-perturbed dip angle. The c o m p u t a t i o n should match; if it does not, t h e n a nonaxial p e r t u r b a t i o n is present. This perturbation may be due to "hot spots," points in the n o n m a g n e t i c drill collar that have developed some magnetism, or to external factors such as a casing in the vicinity. Correction techniques have been introduced for the hot spots. External magnetism due to casing or steel in the well vicinity is used in passive r a n g i n g tools for blowout well detection from a relief well. The accuracy of MWD directional measurements is generally much better than the single- or multishot-type measurements since the sensors are more advanced and the measurements more numerous. The azimuth measurement is made with the three c o m p o n e n t s of the earth magnetic field vector a n d only with the horizontal c o m p o n e n t in the case of the single shot or multishot. The accelerometer measurements of the inclination are also more accurate whatever the value of the inclination. The average error in the horizontal position varies from

956

Drilling and Well C o m p l e t i o n s

6 ft per 3,000 ft drilled at no deviation to 24 ft p e r 3,000 ft drilled at 55 ° o f deviation. The reference position is given by the inertial Ferranti platform FINDS [111]. A large dispersion is noted on the 102 wells surveyed. W h e n the b o r e h o l e is vertical and a kickoff must be done, a m u d m o t o r and bent sub are generally used. To orient the bent sub in the target direction, the gravity toolface is u n d e t e r m i n e d according to Equation 4-176. Up to about 5 ° or 6 ° o f deviation the magnetic tool face is used. T h e magnetic tool face is the angle b e t w e e n the n o r t h vertical plane and the plane d e f i n e d by the b o r e h o l e (vertical) and the m u d m o t o r or lower part o f the bent sub if the bent sub is located below the m u d motor. A f t e r reaching 5 ° or 6 ° o f inclination the surface c o m p u t e r is switched to the gravity tool face mode.

Drilling Parameters T h e main drilling parameters m e a s u r e d downhole are:

• weight-on-bit • torque bending moment • m u d pressure • mud temperature •

Strain gages are usually used for the first four measurements.

Strain Gages. Strain gages are used to measure the strain or elongation caused by the stress on a material. They are usually m a d e o f a thin foil grid laid on a plastic s u p p o r t as shown in Figure 4-259. They are the size o f a small postal stamp and are glued to the structure to be stressed. T h e sensitive axis is along the straight part o f the c o n d u c t i n g foil. W h e n elongated, this c o n d u c t i n g foil increases in resistance. T h e change in resistance is very low. Two gages are usually used and m o u n t e d in a W h e a t s t o n e bridge. Two m o r e gages not submitted to the strain are also used to compensate for t e m p e r a t u r e variation. T h e change in resistance for o n e gage is given by F*R*~ &R - - E where AR F R E

= = = = =

(4-192)

resistance change in 1) gage factor gage resistance in 1) Young modulus in psi or Pa stress in psi or Pa

Demonstration. T h e gage is a platinum gage with F = 4, R = 50 1). T h e structure m e a s u r e d is steel with E = 30 x 106 psi. If the stress is 1000 psi, the resistance change is AR -- 0.0067 1) For constantan, the gage constants are usually F = 2, R = 100 1). Weight-on-bit is usually m e a s u r e d with strain gages attached to a sub subjected to axial load. T h e axial load is c o m p o s e d o f three parts:

Weight-on-Bit.

MWD a n d LWD

957

FOIl. GRID PATTERN

/

TERMINAL WIRE;

o

f~.

)

',"

t INSULATING LAYER / AND BONDING CEMENT ri

,

:~,

,

"

NI[UTRAL AXIS Figure

S T R U C T U IRI[ UNDER BENDING

4-259. Sketch of principle of glued foil strain gage transducers.

1. weight on bit proper 2. e n d effect due to the differential internal pressure in the drill collar 3. hydrostatic pressure effects Hydraulic lift must also be taken into account when using d i a m o n d bits a n d PDC bits. The weight-on-bit varies between 0 a n d 100,000 lb or 0 a n d 50 tonforce. T h e e n d effect is due to the differential pressure between the drill collar internal pressure and the external hydrostatic pressure. This differential pressure acts on the sub internal cross-sectional area.

Demonstration. T h e WOB sub i n t e r n a l d i a m e t e r is 3.5 in.; the differential pressure is 1,000 psi; the downward force acting to elongate the sub is F a = 4 ( 3 . 5 ) ~ x 1,000 = 9.621 lb The hydrostatic pressure has two effects: an upward force acting on the wall cross-section of the sub, a n d a downward stress due to the lateral compression of the subwall.

Demonstration. The sub has an ID of 3.5 in. a n d OD of 6 in. The area of the wall is 18.65 in. * For a 10,000-ft well with a 10-1b/gal m u d

D r i l l i n g a n d Well C o m p l e t i o n s

958

P . = 0.052 × 10,000 × 10 = 5 , 2 0 0 psi T h e u p w a r d f o r c e a c t i n g o n t h e s u b is F u = 9 6 , 9 8 0 lb T h e d o w n w a r d stress d u e to t h e m u d p r e s s u r e ( n e g l e c t i n g t h e d i f f e r e n t i a l p r e s s u r e ) is 6 = 2 x v x PH

(4-193)

w h e r e 6 = stress d o w n w a r d ( t r y i n g to e l o n g a t e t h e sub) v = Poisson ratio of the sub PH = h y d r o s t a t i c p r e s s u r e

Demonstration. For steel, v = 0.3 a n d PH = 5,200 psi a n d 6 = 2 x 0.3 x 5,200 = 3 , 1 2 0 psi. T h i s stress is to b e a c c o u n t e d f o r w h e n c o m p u t i n g t h e t o t a l stress i n t h e s u b wall. T h e c a l c u l a t i o n c a n b e d o n e easily i n real t i m e w i t h a c o m p u t e r ; h o w e v e r , it is e a s i e r a n d p r o b a b l y m o r e a c c u r a t e to m e a s u r e a d i f f e r e n c e i n s t r a i n ( o r stress) i n t h e s u b b e t w e e n t h e o f f - b o t t o m p o s i t i o n a n d w h i l e d r i l l i n g . T h i s v a l u e s h o u l d b e r e l a t e d closely to t h e t r u e w e i g h t - o n - b i t .

Torque. T h e

t o r q u e is m e a s u r e d b y p l a c i n g two s t r a i n g a g e s at 45 ° o n t h e s u b as s h o w n i n F i g u r e 4-260. Stress at 45 ° d u e to t o r q u e is

G -

T-R o ~(R4o - R~ )

where a R° Ri T

= = = =

4-194)

stress i n psi o u t e r r a d i u s i n in. i n n e r r a d i u s i n in. t o r q u e i n in. • lb

S t r a i n is

8 = -I-T x R° G ~(R4o- R~)

4-195)

w h e r e G is s h e a r m o d u l u s ( u s u a l l y 12 x 106 psi) a n d

AR = _ + T x G

R o

xFxR

n(R4o - R4o)

Demonstration. P l a t i n u m g a g e s o n steel collar: T = 2,000 ft * l b

F = 2

R ° = 2.5 in.

R = 100

4-196)

MWD a n d LWD

959

Wob Gages

Bending Gages

Torque Gages

Figure 4-260. Sketch of theoretical strain gage position in a sub to read

WOB, torque, and bending moment.

R i = 1.5 in. AR = 9.36 × 10 -s f~ Using two gages in opposite legs of the bridge will double the sensitivity. The axial load (compression) gives a u n i f o r m stress and strain in the absence of a b e n d i n g m o m e n t . If a b e n d i n g m o m e n t exists, then one side is extended while the other is compressed. During the rotation an alternative signal for the axial load is s u p e r i m p o s e d o n the DC signal. By filtering, both the axial load a n d the b e n d i n g m o m e n t can be measured. In practice, the strain gages are placed in holes drilled in the m e a s u r i n g sub as shown in Figure 4-261.

Mud Pressure. Internal and external m u d pressures are usually measured with strain gages mounted on a steel diaphragm. Figure 4-262 shows a sketch of principle.

960 DrillingandWellCompletions

DWOBj ~ gauge

h

o

Uphole

~

-1:©+~ ' - ~

- ~,7~N

-;&+

3

~

Torque gauge hole

Figure 4-261. Practical design of a drilling parameter sub.

--

(Courtesy Anadri//[106].)

I

i

i

INTERNAL PRESSUFIE STRAIN GAGES

II II

ANNULUS P ~ STRAIN GAC~$

-,,,,j -,,,,j "H

Figure 4-262. Sketch of principle of downhole pressure measurements.

MWD and LWD

961

O n e steel diaphragm is exposed to the internal pressure, the other is exposed to the external pressure. Four gages are normally used. Two of them are sensitive to pressure and t e m p e r a t u r e , a n d two are sensitive to the t e m p e r a t u r e . A Wheatstone bridge is used for detection of the pressure.

Downhole Shocks Measurements. A n accelerometer in the MWD telemetry tool measures transverse accelerations, or shocks, that may be damaging for the bottomhole assemblies. W h e n acceleration exceeds a certain threshold, the event is signaled to the surface as being a shock. These events versus time or depth are displayed as shock count. This i n f o r m a t i o n is used as a w a r n i n g against excessive downhole vibrations and to alert the driller to change the r p m or weight on the bit [106]. A simple circuit has b e e n designed to count the n u m b e r of shocks that the tool experiences above a preset "g" level. The transverse shocks are measured in the range of 2 to 1,000 Hz in excess of the preset level. The level is adjustable and defaults at 25 g's (when no preset level is specified). Downhole shock m e a s u r e m e n t s are used to" • send alarms of excessive downhole vibration in real-time so that action can be taken to reduce damage to the MWD tools, drill bits, and bottomhole assemblies; • reduce costly trips to replace damaged equipment; • improve drilfing rate by eliminating counter-productive BHA vibration motion.

Downhole Flowrate Measurement. Anadrill's basic MWD tool can be set up to m o n i t o r the alternator voltage being produced by the m u d flowing across the MWD turbine downhole. By comparing this voltage to the standpipe pressure and the p u m p stroke rate, the surface system shows that a washout in the drill string is occurring much quicker than with conventional methods [106]. The downhole flowrate m o n i t o r i n g and washout detection system is used to • avoid potential twist-offs from extensive drill string washouts; • determine if the washout is above or below the MWD tool, thus saving rig time when searching for the failure.

Safety Parameters O n e area where MWD would be most useful is drilling safety and, particularly, early gas kick detection and monitoring. Conventional kick m o n i t o r i n g is based on pit gain m e a s u r e m e n t s and all other available surface indication such as drilling rate break, injection pressure variation, etc. Using the p r o b a b l e detection threshold achievable a n d a gas kick model applied to a typical 10,000-ft drill hole, an early alarm provided by MWD systems decreases significantly the amount of gas to be circulated as compared to using conventional methods of kick detection.

Dissolved G a s . Gas which enters the borehole when penetrating a high pressure zone may not dissolve immediately in the mud. The free gas considered here is the gas entering the borehole minus the dissolved gas. Table 4-128 indicates the m a x i m u m volume of dissolved gas at b o t t o m h o l e conditions expressed in percent of annulus m u d volume. Thus, when entering a high pressure permeable formation this much gas will dissolve first before free gas appears in the mud.

962

Drilling and Well C o m p l e t i o n s

Table 4-128 Maximum Dissolved Gas Content of Drilling Muds Mud Water base Water base Oil base Oil base

Density (Ib/gal)

Pressure (psi)

Gas Volume* (scf/STB)

% of Injected Mud Volume*

9 18 9 18

4,680 9,360 4,680 9,360

16 13.7 760 7,200

0.9 0.6 38 77

Conditions: Depth = 10,000 ft Temperature = 150°F Filtrate salinity = 20 kppm Gas density (air = 1.0) = 0.7

Oil S.G. = 0.83 (39°API) Brine density = 1.175 g/cm 3 Brine-oil ratio = 16:84

*At bubble point in the mixture

Note that from Table 4-128 the very large volumes that can dissolve in oilbase muds. For the water-base muds, 0.6 to 0.9% o f gas will dissolve and not appreciably change the density or compressibility o f the mud. It will be difficult to detect these low concentrations with downhole physical measurements. Free gas will be easily detected as shown hereafter. For the oil-base muds we will assume no free gas is present at b o t t o m h o l e and the m u d properties are changed only due to the dissolved gas. The detection will be more difficult than with free gas.

Bottomhole Gas Detection. Many techniques could be used for b o t t o m h o l e gas detection: • • • • • •

m u d acoustic velocity m u d acoustic attenuation m u d specific weight m u d resistivity mud temperature annulus noise-level

Figure 4-263 shows the various sensors that could, schematically, be installed in the annulus. Cuttings, turbulent flow, v i b r a t i o n and shock may r e n d e r some measurements difficult. We shall study those that can be related easily to gas content.

Mud Acoustic Velocity. Acoustic velocity can be accurately p r e d i c t e d . T h e m e a s u r e m e n t s could be made over a short distance in the annulus o f the o r d e r o f 1 to 2 ft. T h e "free" m u d formula can be used. This is

v = J144gc K~/

where V = acoustic wave velocity in ft K = gas cut m u d compressibility in psi -1 = gas cut m u d specific weight in l b / f t 3

(4-197)

MWD a n d LWD

963

<,. Temperature sensor

sensor

"• Pressuremud weightsensors

Noiselevel sensor

Drillcollar

Resistivity

i

'~

[ " Acoustic velocity I attenuation /~ sensors

Annulus

/ Bit

Formation Figure 4-263. Schematic representation of bottomhole kick detection

(Courtesy Petroleum Engineer International [96].)

sensorst.

with

f~

K = ( 1 - fb )Kin + pL4

(4-198)

where Km = gas free m u d compressibility in psi -1 P = m u d pressure in psi f = free gas content (fraction) and = ( 1 - fg)Tm + f g

0. 7637g Bg

(4-199)

where 7 = gas cut m u d specific weight in l b / f t 3 7m = gas free m u d specific weight in l b / f t 3 = gas specific gravity (air = 1.0) gas volume factor

For oil-base muds Equation 4-197 can be applied, b u t K a n d p must be calculated for an average natural gas using tables or the c o r r e s p o n d i n g algorithms.

964

Drilling a n d Well C o m p l e t i o n s

Table 4-128 shows m a x i m u m dissolved gas concentrations in drilling muds at the bottom of the hole. Figure 4-264 shows the variation of the acoustic velocity for two water-base muds a n d two oil-base m u d s of 9 a n d 18 l b / g a l at pressures of 5,000 a n d 10,000 psi. A s h a r p velocity d e c r e a s e is seen for t h e water-base m u d s . A s s u m i n g a t h r e s h o l d d e t e c t i o n of 500 i f / s , the alarm could be given for 0.5% of free gas or 1.1 to 1.4% of total gas (dissolved a n d free). T h e oil-base m u d s having no free gas behave differently a n d the 500-ft/s t h r e s h o l d is not reached before approximately 5% of gas is dissolved. T h e n the velocity decrease is almost as fast as with the water-base mud. M u d Specific Weight. The water-base mud specific weight can be calculated readily using Equation 4-199. T h e oil-base m u d specific weight requires the use of tables. T h e variations are shown in Figure 4-265 for the same 9- a n d 18-1b/gal muds. Specific weight-wise, the m u d s behave in a similar manner. Assuming that a density m e a s u r e m e n t with the g r a d i o m a n o m e t e r can be m a d e accurately, the specific weight threshold would be 0.15 lb/gal. The gas content of the mud would be 2 to 5% according mainly to the density, the greater sensitivity being for the heavier mud. M u d Resistivity. T h e m u d resistivity can be m e a s u r e d only with the water-base muds. It is m e a s u r e d easily with a small microlog-type sensor e m b e d d e d in the outer wall of the drill collar. Assuming the free gas is dispersed in small bubbles in the mud, the resistivity of the gas cut m u d is

5.000 ~

4,000

J

i

I

I

|

9-1b/gal,5,OOO-pslwaler-basemud 18-1b/gal,lO,O00-pslwaler basemud 9-1b/gal,5,000-psi oil-basemud 18-1b/gal,lO,OOO-psloil-basemud |

3,000

e

\X.

i 2,000

1.000 0 0.5 I 2

5

tO

20

50

70

Gas In mud, % of volume F i g u r e 4-264. Acoustic velocity in the annulus as a function of the gas content in the mud. (Courtesy Petroleum Engineer Intemationa/ [96].)

965

MWD a n d LWD Rgcra -

Rm

fg)2

(1 -

(4-200)

where R~m = gas cut m u d resistivity in ~2 • m gas free m u d resistivity in ~2 • m f~ volumetric gas content (fraction) T h e variation is i n d e p e n d e n t of the m u d weight, pressure, or temperature, b u t is sensitive to fluids other than gas, such as oil or saltwater. Figure 4-266 shows the resistivity variations for a 142 • m mud. If we assume that a change of 10% can be detected, then the alarm could be given again for a free gas or oil volumetric c o n c e n t r a t i o n of 2 to 5%.

Mud Temperature, O n e can attempt to calculate the variation of the temperature of the m u d when it mixes with a gas stream cooled by expansion. Calculations were made with a 500-gal/min m u d flowrate, an expansion from 10,500 to 10,000 psi with an 18-1b/gal m u d a n d also an expansion from 5,500 to 5,000 psi with a 9-1b/gal mud. T h e t e m p e r a t u r e decrease of the m u d was a few °F up to 50% gas by volume in the mud. T e m p e r a t u r e m e a s u r e m e n t s do not seem to be good gas indicators. Mud acoustic attenuation a n d a n n u l u s noise level are b e i n g investigated. It is expected that a t t e n u a t i o n would be very sensitive to free gas concentration.

18

16 m

.~ 14

:~ 10

Eii Ziii0!: / e?:0 ~0i000-psi

oil-basemud

6 0 O5 1 2

5

10

2O

50

70

Gas in mud, % of Volume

Figure 4-265. Bottomhole mud density in the annulus as a function of the gas content of the mud (Courtesy Petroleum Engineer International [96])

966

Drilling a n d Well C o m p l e t i o n s 4

ohm-m mud E E3 tO

.m

•~

2

0

0 0.5

2

5

10

20

50

70

Gas in mud, % of Volume

Figure 4-266. Bottomhole mud resistivity in the annulus as a function of the gas content of the mud. (Courtesy Petroleum Engineer International [108].) Example 12: Drilling ParametersmDownhole Weight-on-Bit and Torque We want to measure the b o t t o m h o l e weight on bit a n d torque with a sensing collar sub 5-in. OD and 3-in. ID. The differential pressure across the three ~-in. bit nozzles is 1,000 psi. We want to use platinum strain gages with a resistance of 50 fl and a gage factor o f 4. The Young modulus of the steel sub is 30 x 106 psi, the shear m o d u l u s is 12 x 106 psi. 1. C o m p u t e the e n d effect d u e to the internal differential m u d pressure. Should we correct for this effect? 2. C o m p u t e the force acting on the drill collar for a weight-on-bit o f 0, 30,000 and 100,000 lb. 3. T h e gages are stuck on the sub and c o n n e c t e d to a W h e a t s t o n e bridge. W h a t is the change in resistance from no load and no pressure for a weighton-bit o f 0, 30,000 and 100,000 lb? 4. Show that with two gages conveniently placed on the sub the b e n d i n g strain compensates. 5. The bridge is supplied with 10 V, balanced for 0 lb. W h a t is the u n b a l a n c e for 100,000 lb? 6. Trace the response versus the weight-on-bit with (a) no differential pressure, (b) 1,000 psi differential pressure. 7. T h e m a x i m u m torque to be m e a s u r e d is 20,000 ft-lb. Using the same type of gages, properly placed on the sub, show that with two gages conveniently o r i e n t e d the differential pressure strain a n d weight-on-bit strain do not register on the bridge. 8. C o m p u t e the resistance variation for each gage d u e to torque. 9. C o m p u t e the m a x i m u m signal using a 10-V supply.

MWD and LWD

967

G a g e r e s p o n s e to axial l o a d is AR= (F'R'L) (E'A)

(4-201)

where R = gage resistance in AR = r e s i s t a n c e v a r i a t i o n i n F = gage factor L=loadin lb E = Young modulus A = s u b c r o s s - s e c t i o n o r a r e a i n in. 2 G a g e r e s p o n s e to t o r q u e is

(T'F'R'R°)

AR=±

G , 5 , ( R 4 - R~) where T F R R° R~ G

= = = = = =

(4-202)

t o r q u e i n i n * lb gage factor gage resistance in s u b i n t e r n a l r a d i u s i n in. s u b e x t e r n a l r a d i u s i n in. shear modulus

Solution 1. 2. 3. 4.

7.070 lb; yes, we s h o u l d c o r r e c t for t h i s effect. 7,070 lb d o w n w a r d , 2 2 , 9 3 0 lb u p w a r d , 9 2 , 9 3 0 lb u p w a r d . - 0 . 0 0 4 , 0.012 a n d 0.049 ft. T y p i c a l W h e a t s t o n e b r i d g e as s h o w n i n F i g u r e 4-267. C o n n e c t t h e s e n s i t i v e g a g e s (1) a n d (4) o n o p p o s i t e sides o f t h e sub. 5. C u r r e n t i n e a c h leg: 0.1 A. F o r 100,000 lb (92,930 lb effective), AR = 0.049 f l / g a g e . F o r t w o gages: AR = 0.098 ft. AV = 0.0098 V = 9.8 mV. 6. R e s p o n s e e q u a t i o n : AV = 10.6 × 10 -5 L V. 7. Place t h e sensitive gages o n o p p o s i t e sides a n d o p p o s i t e d i r e c t i o n s as s h o w n i n F i g u r e 4-268. C o n n e c t t h e g a g e s i n (1) a n d (2), b r i d g e will n o t b e s e n s i t i v e to axial l o a d a n d AP.

IOV.

Figure 4-267. Sketch of a Wheatstone bridge for small resistance variations.

968

Drilling a n d Well C o m p l e t i o n s

Figure 4-268. Sketch showing the theoretical position of strain gages for torque measurement. 8. AR torque = 0.01 ~ / g a g e . 9. Signal due to torque: AV = 0.002 V = 2 mV.

Example 13: Drilling ParametersmAnnular Temperature Bottomhole annulus mud temperature is recorded during drilling for mechanical p r o b l e m s and for fluid entry diagnosis. Borehole depth: 10,000 ft, deviated hole Drill p i p e rotation rate: 10 r p m Mud heat capacity: 0.77 c a l / g Hole diameter: 12 ¼ in. Drainage radius: 660 ft Mud specific weight: 12 l b / g a l Mud flowrate: 500 g a l / m i n Gas gravity: 0.7 z: 0.9 1. The surface measured torque is 2 kft-lb and the downhole torque is 1 kft-lb. Assuming the heat g e n e r a t e d is entirely transferred to the descending m u d stream, what is the t e m p e r a t u r e rise due to the pipe friction? 2. A water inflow occurs suddenly at the rate o f 1,000 b b l / d a y . Water heat capacity is 1 cal/g; water density is 1,00 k g / m 3. The formation t e m p e r a t u r e is 200°F and the m u d reaches the drill collars at a t e m p e r a t u r e of 160°F. C o m p u t e the annular t e m p e r a t u r e rise. 3. A gas inflow occurs suddenly when entering an a b n o r m a l pressure zone. Compute the flowrate of gas if the formation pressure is 7,000 psi, 1 ft has been penetrated in a 50-ft zone with 500 md, gas viscosity is 0.035 cp. Assume no annulus pressure drop, no cutting. Compute the annular temperature drop.

MWD and LWD

Q b = 19.88 *

969

k*f'h(P:- P:) F + 7cos[f, x ~ r ~ - - - ] g , pw , ln(r~_] ~1

2 ) ~ *-'-~-~* 2 h J

Qs = Pw*Ts*Qb z • Ps • Tw

(4-203)

(4-204)

Solution 1. Dissipated energy: 852,000 J / m i n Massic mud flow: 2721 k g / m i n Calories required to raise temperature by 1°C: 2,095,170 cal/min Calories available: 203,828 c a l / m i n Temperature rise: AT = 0.1°C = 0.17°F 2. Heat given up by the inflowing water equals heat received by the mud. AT = 2.5°F 3. Bottomhole pressure: 6240 psi Gas flow at downhole conditions: 286,000 ft3/d = 8,099 m3/d = 5.62 m3/min Gas pressure decrease: 760 psi = 5,239,440 Pa a. Energy absorbed by the gas if E = VdP = 29,468,211 J / m i n = 7,049,811 cal/min Temperature decrease o f the mud: 3.36°C = 6°F b. Energy absorbed by the gas in isentropic process = 600 Btu/lb mole (See [113], p. 96) When converted and for massic flowrate of 443.6 l b m / m i n = 2,501,393 cal/min Temperature decrease o f the mud: 1.19°C = 2.15°F (second calculation is probably more correct)

Example 14: Drilling Parameters--Drill Collar Pressure Drop The following data characterize a well during drilling: depth: 10,000 ft 4 {-in. drillpipes (ID = 3.64 in.) mud specific weight: 12 lb/gal flowrate: 500 g a l / m i n three-bit nozzles: ~-in. diameter mud viscosity: 12 cp nozzle factor: C = 1.0 hole diameter: 8.5 in. 1. Assuming no cutting in the annulus, compute the pressure recorded inside the drill collars downhole and the pressure in the standpipe at surface using the formula given hereafter. 2. A leak develops in the pipe string. The standpipe pressure reading drops to 1,896 psi with the same mud flowrate and the downhole drill collar inside pressure drops to 6,700 psi. What is the flowrate of the leak? What is the area of the leaking hole assuming it is located at 3,000 or 5,000 or 7,000 ft? (Assume that AP annulus does not change.)

970

D r i l l i n g a n d Well C o m p l e t i o n s

Equations 1. Hydrostatic p r e s s u r e is PH = 0.052

• y"

z

(4-205)

where PH = hydrostatic p r e s s u r e in psi 7 = m u d specific weight in l b / g a l z = d e p t h in ft 2. T u r b u l e n t flow p r e s s u r e loss in pipe ( E q u a t i o n 4-187) is AP = AL * 7 0.75 • V1"75* ~.[0.25 1800 • d L25 where AP = AL = ~/= v = m = d =

p r e s s u r e loss i n psi pipe l e n g t h in ft f l u i d specific weight in l b / g a l average f l u i d velocity in f t / s f l u i d viscosity in cp pipe ID in in.

with v = Q / ( 2 . 4 4 8 x d 2) where Q = f l o w r a t e in g a l / m i n d = pipe ID in in. 3. T u r b u l e n t flow pressure loss in a n n u l u s ( E q u a t i o n 4-188) is AL AP =

•

~/0.75• vl.75 • B0.25

1396(d 2 _ d l )1.25

where ( n o t a t i o n s same as above) d 2 = b o r e h o l e or casing d i a m e t e r in in. d~ = pipe O D i n in. 4. Flowrate t h r o u g h a choke, or nozzle, or leak ( E q u a t i o n 4-186) is

Q=CoAo

where Q = C = gc = AP = ~/= A =

oAP 2t° g o [ 144o ~/ V f l o w r a t e in ft3/s coefficient (0.95 to 1.0) a c c e l e r a t i o n o f gravity (32.17 f t / s 2) p r e s s u r e loss in psi f l u i d specific weight in l b / f t 3 area in ft 2

Solution 1. AP drillpipes: 1,590 psi AP bit nozzles: 718 psi AP a n n u l u s : 74 psi

MWD a n d LWD

971

Hydrostatic pressure: 6,240 psi P inside DC: 7,032 psi P standpipe: 2,382 psi 2. Total DP in pipe (friction plus leak): 1,436 psi Pressure d r o p in DC due to leak: 332 psi New AP across nozzles: 386 psi Q t h r o u g h nozzles: 366.5 g a l / m i n Q through drillpipes below leak: 366.5 g a l / m i n Q through leak: 133.5 g a l / m i n If leak at 3000 ft: Pipe AP above leak: 477 psi Pipe AP below leak: 646.5 psi AP across leak: 312.5 psi Leak cross-section: 0.24 in. 2 If leak at 5000 ft: Pipe AP above leak: 745 psi Pipe AP below leak: 462 psi AP across leak: 229 psi Leak cross-section: 0.28 in. 2 If leak at 7,000 ft: Pipe Pipe Sum The

AP above leak: 1,272 psi AP below leak: 277 psi is m o r e than total AP leak must be above 7,000 ft

LWD Technology Logging while drilling has been a t t e m p t e d as early as 1939. The first commercial logs were r u n in the early 1980s. First g a m m a ray logs were r e c o r d e d d o w n h o l e a n d t r a n s m i t t e d to the surface by m u d pulses. T h e n came the resistivity logs of various types that were also r e c o r d e d downhole a n d / o r transmitted to the surface. Now, neutron-density and Pe logs are also available. Soon, sonic logs will be offered commercially.

Gamma Ray Logs G a m m a rays o f various energy are emitted by potassium-40, thorium, uranium, a n d the d a u g h t e r p r o d u c t s o f these two last elements c o n t a i n e d in the e a r t h formations s u r r o u n d i n g the borehole. These elements occur primarily in shales. T h e g a m m a rays reaching the b o r e h o l e form a spectrum typical o f each formation e x t e n d i n g from a few keV to several MeV. T h e g a m m a rays are d e t e c t e d today with sodium i o d i d e crystals scintillation counters. The counters, 6 to 12 in. long (15 to 30 cm) are shock m o u n t e d and housed in the drill collars. Several types o f m e a s u r e m e n t s can be made: total g a m m a rays, direction-focused g a m m a rays, spectral g a m m a rays.

Total Gamma Rays. Total g a m m a ray logs have been run on electric wireline since 1940. The sondes are rather small in diameter (1.5 to 4 in. or 37 to 100 mm).

972

Drilling and Well C o m p l e t i o n s

The steel housing rarely exceeds 0.5 in. (12 mm) and a calibration is d o n e in terms o f API units, a r b i t r a r y units d e f i n e d in a s t a n d a r d calibration pit located at the University o f Houston. The MWD total g a m m a ray tools cannot be calibrated in the standard pit, since they are too large. Their calibration in API units is difficult because it varies with the spectral content o f the radiation. By spectral matching the MWD logs can be made to closely resemble the wireline logs. The logs which were recorded by the MWD companies in counts p e r second (cps) are now recorded in API units. A n o t h e r difference between the wireline logs and the MWD logs is the logging speed. With a wireline, the sonde is pulled out at a speed o f 500 to 2,000 f t / m i n (150 to 600 m / r a i n ) . The time constant used to optimize the effect o f the statistical variations o f the radioactivity emission, varied from 2 to 6 s. Consequently, the log values are somewhat distorted and inaccurate. In MWD, the r e c o r d i n g s p e e d is the rate o f p e n e t r a t i o n which rarely exceeds 120 to 150 f t / h r or 2 to 2.5 f t / m i n , two o r d e r s o f m a g n i t u d e less than the logging speed. Counters can be m a d e s h o r t e r and time constant l o n g e r (up to 30 s or more). This results in a b e t t e r accuracy and a b e t t e r b e d definition. Figure 4-269 shows an example o f c o m p a r i s o n between an MWD g a m m a ray log and the wireline log ran later. To summarize, the total g a m m a ray m e a s u r e m e n t s are u s e d for real-time correlation, lithology identification, d e p t h marker and kick-off point selection.

Directlon-Focused Gamma Rays. It is i m p o r t a n t to keep the t r a j e c t o r y o f horizontal or nearly horizontal wells in the pay zone. By focusing the provenance o f the g a m m a rays it is possible to d e t e r m i n e if a shale b o u n d a r y is a p p r o a c h e d from above or from below. The tool shown in Figure 4-270 has its scintillation d e t e c t o r inserted in a b e r y l l i u m - c o p p e r housing, fairly t r a n s p a r e n t to g a m m a rays. A tungsten sleeve surrounds the b e r y l l i u m - c o p p e r housing, with a 90 ° slot or window running from top to bottom. Figure 4-270 is a sketch o f the tool cross-section. The center o f the window is keyed to the reference axis o f the directional sensor. Consequently the directional sensor indicates if the window is pointing up or down. By rotating the tool, one can differentiate between the level o f g a m m a rays entering from the top and the lower part o f the borehole. A sinusoidal response is r e c o r d e d which d e p e n d s on the following: • • • •

distance from the b e d boundary. g a m m a ray intensity o f the b e d in which the tool is in. the contrast o f radioactivity at the boundary. the shielding efficiency o f the tungsten sleeve.

An example o f the log ran is a horizontal borehole as shown in Figure 4-271. The d e p t h s on the log are along the hole depths. Vertical depths are shown in the higher part o f the log with a representation o f the true radioactivity o f each bed. The following observations can be made: • Approaching formation b e d boundaries are detected by concurrent separation and displacement o f the high and low g a m m a counts. These are shown in Figure 4-271 at measured depth intervals (7970-7980 ft) and (8010-8020 ft). • Radioactive events occur in the m e a s u r e d d e p t h interval (8,100-8,200 ft) with no displacement o f the l o w / h i g h side g a m m a ray logs. The radioactive events must be p e r p e n d i c u l a r to the g a m m a detector and could be indications o f vertical n a t u r a l fractures in the formation.

MWD a n d LWD

~Jm

~

kJ~l

973

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IW ~ l U

BAmi"MII111~

1

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

" ~--- Wireline Io!

I ,~.,~

,'

I

Figure 4-269. Example of good similarity displayed between the MWD gamma ray log and the wireline log. Spectral Gamma Ray Log. This log makes use o f a very efficient tool that records the i n d i v i d u a l r e s p o n s e to the different radioactive minerals. T h e s e minerals include potassium-40 and the elements in the u r a n i u m family as well as those in the t h o r i u m family. T h e GR s p e c t r u m emitted by each element is m a d e up o f easily identifiable lines. As the result o f the C o m p t o n effect, the counter records a continuous spectrum. T h e presence o f potassium, u r a n i u m and t h o r i u m can be quantitatively evaluated only with the help o f a c o m p u t e r that calculates in real time the amounts present. The counter consists of a crystal optically coupled to a photomultiplier. The radiation level is measured in several energy windows.

974

Drilling a n d Well C o m p l e t i o n s

Figure 4-270. Cross-section of an MWD focused gamma ray tool. (Courtesy SPWLA [11210 Figure 4-272 shows an example o f a MWD spectral GR log. O n the left track, SGR is the total GR count, and CGR is this total count minus the uranium count. O n the right side o f Figure 4-272 the wireline spectral g a m m a ray in the same interval is displayed. T h e curves are similar but some differences occur in the a m p l i t u d e o f the t h r e e curves. The main field applications o f this log are: 1. Clay content evaluation: Some formations may contain nonclayey radioactive materials. Then the curve GR-U or GR-K may give a better clay content estimate. 2. Clay type identification: A plot o f t h o r i u m versus potassium will indicate what type o f clay is present. T h e t h o r i u m / p o t a s s i u m ratio can also be used. 3. Source rock potential o f shale: A relation exists between the uranium-topotassium ratio and the organic carbon content. The source rock potential o f shale can thus be evaluated.

Resistivity Logs Four types o f resistivity logs are currently r u n while drilling: 1. short n o r m a l resistivity 2. focused current resistivity

MWD a n d LWD 0 HI orAAPI 0 LOorAAPI

100 30 100

orAAPI

130 7

7

o~

'~'~

785O

7900

,

~, ~-~r..:.

3~.

A

F

I

7" ~

!~,P. ° i,p° °°*.l

7950

8000

:~ i-'q

8050 .(,.~ G3

8200

~ ~-~

"

[~..,.

~

8250

.~, ~ ,~\ I~:1X i

8300

;,

84oo

.!

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:~ ~.:,-

k~o

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./.t

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"~. N ,.~, .... t;, =:,,;"

":~i" ~:,1 i.;I

•, 8350

'~,."'~

; ,IV~"

::,I \ '~) \ : ' : -

:"

i"* ~'X

7-

~ ~' '- '~'~'

F i g u r e 4-271. MWD focused gamma ray composite log in a horizontal borehole. (Courtesy SPWLA [112].)

975

i..o _C~(APJ~- do -I 0

I

SGR(API) 150/

,'1

2200

0

2300

Figure 4-272. Example of natural gamma ray spectral logs recorded while drilling and with a wireline.

MWD and LWD

977

3. electromagnetic resistivity 4. toroidal system resistivity

Short Normal Resistivity (after Anadrill). The short normal (SN) resistivity sub provides a real-time measurement of formation resistivity using a 16-in. electrode device suitable for formations drilled with water-base muds having a moderate salinity. A total gamma ray measurement is included with the resistivity measurement; an a n n u l a r bottomhole m u d t e m p e r a t u r e sensor is optional. The short normal resistivity sub schematically shown in Figure 4-273 must be attached to the MWD telemetry tools and operates in the same conditions as the other sensors. Due to the small invasion and the large diameter of the sonde body, a resistivity near the true resistivity of the formation is generally measured. This is particularly true in shale where no invasion takes place. The main applications are: • • • •

real-time correlation and hydrocarbon identification lithology identification for casing point and kick-off point selection real-time pore pressure analysis based on resistivity trend in shales resistivity range: 0.2 to 100 ~ • m

Coverplate Temperature sensor

A electrode Gammaray measurepoint

16 in. M electrode

Standoffsfor resistivityelectrode protection

] I I

J

Figure 4-273. Short normal resistivity sub. (Courtesy Anadrill [113].)

978

Drilling and Well Completions

Focused Current Reslstlvlty. Focused resistivity devices are particularly suited for wells where highly conductive drilling muds are used, where relatively high formation resitivities are encountered and where large resistivity contrasts are expected. The focused current system employs the guarded electrode design shown in Figure 4-274.

RCl~JIIN

I1¢11~11N

[] Figure 4-274. Block diagram of an LWD focused current system. (Courtesy SPE [114].)

MWD and LWD

979

T h e system is similar to the laterolog 3 used in wireline logging. A constant 1-k Hz AC voltage is m a i n t a i n e d for all electrodes. T h e current flowing t h r o u g h the center electrode is measured. T h e resistivity range is 0.1 to 1000 ~ * m. Beds as thin as 6 in. (15 cm) can be adequately delineated.

Electromagnetic Resistivity. T h e m e a s u r e m e n t in electromagnetic resistivity systems is similar to the wireline induction sonde resistivity. T h e frequency used is 2 MHz instead of 20 kHz. This is due to the drill collars steel that would completely destroy a 20-kHz signal. Early systems had one transmitter coil and two receiver coils. Systems presently in use have two to four transmitters allowing the recording of many curves with different depths of investigation. Figure 4-275a shows the CDR, c o m p e n s a t e d dual resistivity tool of Anadrill. Figure 4-275b is a schematic of the o p e r a t i n g p r i n c i p l e . Two signals are measured: the wave a m p l i t u d e reduction and the wave phase shift. Two values of the resistivity can be calculated. T h e wave a m p l i t u d e resistivity (Rad) a p p e a r s to have a deep investigation radius: 35 to 65 in. a c c o r d i n g to the f o r m a t i o n resistivity. T h e p h a s e shift resistivity ( R ) a p p e a r s to have a shallow investigation radius: 20 to 45 in. A n example of tool response is given in Figure 4-276. T h e d e e p p e n e t r a t i o n curve reads a value close to the n o n i n v a d e d zone resistivity and the shallow p e n e t r a t i o n curve reads a value much lower than the invaded zone resistivity. T h e resistivity ranges for an acceptable accuracy are 0.15 to 50 ~ • m for the deep investigation radius (Rd) and 0.15 to 200 ~ " m for the shallow investigation radius (Rps). T h e vertical resolution is 6 in. (15 cm). ps

Toroidal System Resistivity (after Gearhart-Halliburton).

.

.

T h e system uses one

toroidal t r a n s m i t t e r o p e r a t i n g at 1 kHz and a pair of toroidal receiver coils m o u n t e d on the drill collars. Figure 4-277 shows a sketch of a toroid. T h e winding of the toroid acts as a t r a n s f o r m e r p r i m a r y and the drill collar as the secondary. T h e current lines i n d u c e d by the drill collar are shown in Figure 4-278. T h e drill collar acts as a series of e l o n g a t e d electrodes in a way similar to the laterolog 3 wireline sonde. T h e lower electrode, which is the drill bit, is used to get the "forward" resistivity curve. A lateral resistivity m e a s u r e m e n t is m a d e between the two toroid receivers. A n example of toroid logs is shown in Figure 4-279. T h e readings of both toroid curves seem to follow closely the ILd and ILm curves.

Example 15: Gamma Ray and Resistivity Interpretation A typical set of logs r e c o r d e d while drilling is shown in Figure 4-280. T h e wireline caliper is shown in the g a m m a ray track. Displayed on this a t t a c h m e n t are g a m m a ray, R,~ curve, Pe curve, n e u t r o n and density curve. T h e delta-rho curve is the quality curve check for the density log. 1. 2. 3. 4. 5.

Draw a lithology d e s c r i p t i o n in the d e p t h column. Is the clean f o r m a t i o n permeable? Why? Does the porous zone contain hydrocarbons? What type? Give the boundaries. D e t e r m i n e R,. Compute the hydrocarbon saturation at 8400 ft assuming a = 1 and m = 2. (text continued on

page 982)

980

D r i l l i n g and Well C o m p l e t i o n s

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MWD and LWD

981

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20.0 0.0

0.2 0.2

CDRTIMESINCEDRILLING(HRS.) 1.0

200.0 SONIOTRANSffTIME 100.0

Rps

0.2

,

20.0 WL R~

FROMDITE 20.0

WL R t FROMDITE

20.0

Figure 4-276. Comparison of the compensated dual-resistivity log resistivities run while drilling to the invaded and noninvaded resistMties calculated with wireline phasor induction data. The spurt loss is the ratio RJRaa. (Courtesy Anadrill [113].) !

~k ~ A

Figure 4-277. Toroid mounted on a drill collar. (Courtesy SPWLA [115].)

982

D r i l l i n g a n d Well C o m p l e t i o n s

LATERAL CURRENT

BIT CURRENT

Figure 4-278. Computed current pattern in a homogeneous formation for the

MWD toroid system. (Courtesy SPWLA [115].) (text continued from page 979)

Solution 1. 8,450 to 8,434 ft d o l o m i t e 8,434 to 8,430 fl shale 8,430 to 8,426 ft d o l o m i t e 8,426 to 8,423 ft shale 8,423 to 8,374 ft d o l o m i t e 8,374 to 8,350 ft shale R o c k n a t u r e is r e a d o n t h e Pe log. 2. Yes, a m u d cake is seen o n t h e c a l i p e r log. 3. Yes, t h e Rwa curve increases sharply in t h e m a i n z o n e at 8425 ft. Oil f r o m 8425 to 8400 ft. Gas a b o v e 8,400 ft. Gas is i n d i c a t e d by a density p o r o s i t y larger t h a n t h e n e u t r o n porosity. 4. R = 0.05 ~ o m; r e a d on R,~ c u r v e in t h e lower p o r o u s zone. 5. A~ 8400 ft, p o r o s i t y = 20%, Rwa = 0.45, F = 25, R t = 11.25 ~ o m = ~ 2 5 - 0.05

Sw v ~ . ~ Sac = 67%

=°33=33%

MWD and LWD

DUALINDUCTION-LL3 I

983

MWDRESISTIVITY

I0

I ....

I L d - * l ~ ILm

I

I0 ~

.....

!

"

'

B I T . ~ LATERAL X550

X600

J

X650

Figure 4-279. Comparison of toroid logs with dual induction logs. (Courtesy SPWLA [115] .)

'

984

Drilling and Well Completions

WL DCAL 6,5

(in.)

WLPEF 16.5 0

10

LWD DCAL -2

20

(in,)

8

LWD Density Porosity 60

LWD

LWD Gamma Ray PEF (GAPI) 12o 0 lO o

(p.u.)

-30

LWD Neutron Porosity 60

(ohm-m)

-30

(p.u.)

LWD RWA

LWD Delta-Rho 0.5

-0.8

(g/crn 3)

8350

8400

!?

8450

Figure 4-280. LWD logs recorded while drilling [113].

0.2

MWD and LWD

985

Neutron-Density Logs T h e physics o f the m e a s u r e m e n t s m a d e by the MWD neutron-density tools are similar to those of c o r r e s p o n d i n g wireline sondes. A sketch of principle of the A n a d r i l l tool is shown in Figure 4-281.

:h Drill Collar an Detectors

Irle AmBe Neutron Source

le Steel Cable

de Cesium 137 y Source Window Spacing

3 Ray Detectors pacing

h Clamp on Stabilizer

Figure 4-281. Neutron-density sub. (Courtesy Anadrill [113].)

986

Drilling a n d Well Completions

For the n e u t r o n porosity measurement, fast n e u t r o n s are emitted from a 7.5curie (Ci) a m e r i c i u m - b e r y l l i u m (Am-Be) source. The quantities of hydrogen in the formation, in the form of water or oil-filled porosity as well as crystallization water in the rock if any, primarily control the rate at which the n e u t r o n s slow down to epithermal a n d thermal energies. Neutrons are detected in near- a n d far-spacing detectors, located laterally above the source. Ratio processing is used for borehole compensation. The energy of the detected n e u t r o n s has an epithermal c o m p o n e n t because a high percentage of the i n c o m i n g thermal n e u t r o n flux is absorbed as it passes through a 1 in. of drill collar steel. Furthermore, a wrap of c a d m i u m u n d e r the detector banks shields them from the thermal n e u t r o n arriving from the i n n e r m u d channel. This mainly e p i t h e r m a l detection practically eliminates adverse effects caused by thermal n e u t r o n absorbers in the borehole or in the formation, such as boron. Figure 4-282 shows a typical comparison of wireline a n d MWD gamma ray a n d n e u t r o n logs in a borehole in excellent hole conditions. The M W D / L W D log matches the wireline log almost perfectly. The density section of the tool, also seen in Figure 4-281, uses a 1.7 curie (Ci) of 137-cesium (Ce) gamma ray source in conjunction with two gain-stabilized scintillation detectors to provide a high-quality, borehole compensated density measurement. The tool also measures the photoelectric effect Pe for lithology identification. T h e density source a n d detectors are positioned close to the borehole wall in the fin of a full-gage clamp-on stabilizer as seen in Figure 4-281. This geometry excludes mud from the path of the gamma rays, greatly reducing borehole effect. In deviated a n d horizontal wells, the stabilizer may be r u n u n d e r gage for directional drilling purposes. Rotational processing provides a correction in oval holes a n d yields a differential caliper. Figure 4-283 shows a schematic of the tool positions in a borehole. In the top part of Figure 4-283 the stand-off is constant d u r i n g the rotation. In the oval borehole represented in the lower part of the figure, the stand-off is excessive when the density system is oriented up and the n o r m a l Ap correction is not enough. Statistical m e t h o d s are used to measure the density variation as the tool rotates, the stand-off can be estimated a n d the density corrected. A density caliper can be c o m p u t e d that works for cavings of 2 in. (5 cm) or less when the tool rotates at a speed r a n g i n g from 6 to 150 rpm. Figure 4-284 shows a typical MWD density log compared to a wireline density log. The calipers are also shown. At 1620 ft, the wireline caliper detects a much larger caving because it was r u n several days later.

Photoelectric (Pe) Curve. The C o m p t o n effect (change in g a m m a ray energy by interaction with the formation electrons) is used for measuring the density of the formation. The energy range is 200 to 450 keV. The photoelectric effect (absorption of a low-energy g a m m a due to ejection of a low orbital electron from its orbit) is seen for gamma in an energy range of 35 to 100 keV. By counting the g a m m a of low energy reaching the first counter a Pe curve sensitive to the nature of the formation can be recorded. A special counter protection fairly transparent to low-energy g a m m a ray (beryllium) is used. Table 4-129 shows the value of Pe for various lithologies. Two systems are presently used by the MWD service companies c o n c e r n i n g the radioactive source installation. O n e way is to lock the sources in holes in the drill collars. Thus, if the BHA is lost, the sources are left in the formation.

MWD

e io

+':

I

oi

ill

I I//1/il [ILIIJ LI I11111111UI[I U I11TII II I I I III II liITITPEITITITITI~ [llll~lllilIlilIIIIIIilUJJlIII1HIIHIIIIIIIII HIIIIIIIIII|IIILL!J 11 III i I I lillllfll [ITII ill'il Ill I1~ I III III III III II IIJlLIIIJlIIIIIIIJlIIIIIII lllllllllillllt II'il lilll lilT[] lil[lillllllllllliliLlllHIlil Ili[lllllllilll Lllllqllillllllllllllllllllll|lllllllllllllilllllUllillllllll rLI41'l~ .LI-t.U.~ I'I,L'L,i.I LI,I.LLI 1 I.L I I I I I-I.U, I-iJJ, LILP]LI.E IILP]LI.ELU+I.II J IILIIJ.I.LIJ.IILIILI l LI.III.LJ, LLLLIJ, LI/,LI,LILLII I LI II IIIIJlillllilllllll|Ul:lllll ••••••i•••••••••••••L••:••••••••••i•••••••••••••i••••••[•]••••]••]•]••]•••i•••i•• ILLIllll il III|H |llllilll~lllll llLIl|llillll|Hlllllilll~llllilllililllll[illlllllU IIIlllIIIIIIIIIIIIIIIIIIIIILU I~ IA IJ~H I L),tJ L),[J P+I III Ill MA]d'tld,H 1, ilII I I I I I h['l I I11111 t I11111111 [llil] [JL~J[I I1 i [I I lJWfi ~J'fN I l~l t'~ ~11l lI/I~ H P,LIIVIIIIIIIIItlIIIIIIIIJUI[IIJLI LI I I/T ~ff'NILVlt'~IYII|II/i~HP, U /5 |[llJIJ,~Ull r~l~ 11111~ IIII I ~]3 ~t+]3LII II111~11 I I1~ 11Y~I~ LII I I I I 111111d41~ff1,1L4~ U~JJJ{I I fl'~lU~fPIJl~llfl I i I l I J1L4H~ IIllI l-J1 [+H~ ILU III I I I III I I I IIJ I I J I ~,lll~: hll IJ~H I I I lllJ~llJ LIJJ ILIU~I ~I~ILL~I~ IJ 11 ttffl/J ,i'H H~ I I111 Ill I lJ PLU II[]H ll[]lq I HITI FIITI I I}111111+111HTrl'll~4 IlXl Ill [ I II I ITI |1LI lf]iTlLlll] UI I[III|IIIIlilIIIH'YHIlIklI|II Ill I111111 II IIII H'YHIlIklI|IIIPPU, UXIFIIIIII illlllllll IIIIIU UII] I I I IJJJ.]~ IIlIlillIIIIIIIIIIIIIIIIUIIII lllll ill II II II IIIII IIIIU[IIIIIIIIIIIIIlI[IIII I11|111 jJ|ll III II IIIIIIIIIIJ II IJ.LI'.LLI ]lllllllll IIIIllllll llllHllllllllHIIlli IIlII[IlIIIIIIHIIIIIJ.IIIIIIIIIIIIIIIIIIIIIIUIIIIIIIIIIIIIlILIUIII]III /IIIIIIIIIIIIIIUlllIIIII, I]IIII /IIIIIIIIIIIIIIUIUIIIIHIlIIIIIIIIIIIII] UIIIIIIIIIIIIIIIIIIIIIIIHIIIIIIIIIIIII I,II'llllll [Lll.lillll II1F[IUIUI]IIIIIIIIIIIIIII|I II lll-J I III U I II I IIII U I,li'llllill llllll~J~ 111rl]'[ rlTIITTI rT rLlJ rLl] I]1[I l]lil ITH~ ITH~I+I Ill ITTI rT ITI rlI I |il I i ]A-I.U-L4-LUJ. t,l-I l-~l +Jel~L~I,I~I~ LLI H-I't-EJJ U UUJlLtlIII lltIIIIIIIl.lltllTilllll[lllilllllllllllllllllllllllilllllllllllllllllll I lllllt.ll H ITII I llilllllllllllllllll-ll,H HIIIII IIIlll-JI,HllllilllllllllllillH Ill111111]lllllllillllililllllllllllll

G

,qP| , ~

|

i r

L,

cu~l

I

I [

987

1111111[I] i|ll 11111 ~ Illillllltll[[Irl Illil

t

01+I

and LWD

i ~i

•

"

:."-;+ ~+i

!

ilUJ+UI J.L I IlIIlIi~.i]ILIIII.~~J_L~L[LL[LtI[LIJIULIJJIIII[ LL]].LLt I m t llrn tn n~r.l~-HTITn1"rlm Hell I~iH,.FHfl, m i ~ i T [ ~ ~ UIU l Uli[li t I I|llllll~llll I II I i I fll [lllil I II I It lilTI rlfTI I I]I]]T[BEE]]E[f.I]" |il],I~LI [I.1 [I I111111 II H ~.LLIJJJJ_LI,I-I-PI I I I I I I I IIll|ll I| IIIII LllilllltU LiJll III I]$L LLIM~I UU I I I IJ44TII1TlI+III II11 nlil I III il IlIiIIIIU[IUIU i/lillll lilll II I I [ III Ill

[L

"I

Figure 4-282. Comparison of wireline and LWD gamma ray and neutron logs in a borehole in good conditions,

988

Drilling and Well C o m p l e t i o n s

CIRCULAR 80REHOLE COLLAR

DETECTOR

i ................................. ENLARGED BOREHOLE

1

WlNOOW IN COLLAR AND STABILIZER

STANDOFF

6RAVITY

Figure 4-283. Schematic of the density tool position in a borehole. (Courtesy

Anaclrill [113].)

A n o t h e r way (Anadrill) is to use removable sources. Figure 4-285 shows the sources being installed in the tool at surface. T h e two sources, neutrons and gammas, are m o u n t e d on the same flexible shaft. They are moved from the shield to the sub without b e i n g exposed. F u r t h e r m o r e , if the B H A b e c o m e s stuck, they can be fished out with an overshot that connects to the fishing head on top of the n e u t r o n source.

MWD and LWD L0¢J • SJM • |J~

CJJ,JmMA I A Y ~ ~

~l~ ~AL

|.N

~

~utA~

989

O(d~I~TT

8-04 LO4I

,ll

Figure 4-284. Density comparison in a deviated well. (Courtesy Anadrill [113].)

990

Drilling and Well Completions Table 4-129 Pe a n d R o c k Matrix D e n s i t i e s for V a r i o u s L l t h o l o g i e s Lithologles

Pe

Rock Density (g/cm 3)

Sandstone Limestone Dolomite Illite Kaolinite Smectite

1.81 5.08 3.14 3.45 1.83 2.04

2.65 2.71 2.85 2.45-2.65 2.35-2.50 2.05-2.30

Shield

and slips Rig floor

Radioactive source handling toot

Pon,

~

Neutron sensors 7.5-Ci Am-Be neutron source 1.8-Ci ~37cesium density source Density source CDN tool

I1~

Data port

Power ,' Batteries Real-time _ _ connector Figure 4-285. Radioactive sources being installed in the neutron-density sub.

(Courtesy Anadri// [113].)

MWD and LWD

991

Example 16: Neutron-Density Logs Interpretation T h e set of logs in Figure 4-286 have all been recorded while drilling in a Gulf Coast s a n d - s h a l e sequence. 1. Give the b o u n d a r i e s o f the clean sand. Are some zones shaly? 2. Give the p r o b a b l e h y d r o c a r b o n / w a t e r contact. Give the p r o b a b l e nature o f the hydrocarbons and the g a s / o i l contact. 3. C o m p u t e the gas saturation at 9692 ft. 4. Can the oil saturation be computed at 9720 ft using the basic formula given in this chapter?

)

-!lllttii} lltlrl[l (i

Gamin= Ray

Oel= CauW~"

~

~

0.S

~N,,,~,~o,.o~

0.2 mnm-m) 20 ~===vqy ~ S.'~.SNu~ow

--

- 0 40

j tl0

o~.~,o

|D~r~=) 0,erm~ Po~mt*y

(l=.u.}

_

0.t0

0

Figure 4-286. LWD logs recorded while drilling in a development well. (Courtesy Anadri// [113].)

992

Drilling and Well C o m p l e t i o n s

Solution 1. Shaly sand. Cleanest parts: 9679 to 9696 and 9803 to 9808 ft. 2. H y d r o c a r b o n / w a t e r contact at 9750 ft with Rw~ curve. Oil to 9696 ft. Gas above with n e u t r o n density. 3. At 9692 ft, • = 30%, R = 8 ~ o m , R = 0.1 ~ o m , S = 3.3%, Sg= 6.7%. 4. No, shaly sand formula must be used.

Example 17: Neutron-Density Logs Interpretation The Gulf Coast logs shown in Figure 4-287 have been run in the same interval with M W D / L W D sondes and wireline sondes.

0

] 20

i

LWO RWA (anm-m]

(O~U"I)

02

lento-m)

21

02

(ohm-m)

Z

O~

02

~ . . SJ'mJImw,~L (o~m.,m)

lao

0.2

(oen..m)

20O

ZOI

,

; f t

. . . . . . . . . . . . .

,

. ,,,,,,,

Figure 4-287. Wireline and LWD logs showing the effect of invasion.

(Courtesy Anadri// [113].)

MWD and LWD

993

1. 2. 3. 4.

Draw the lithology description in the depth column. Looking at the R curve, where is the h y d r o c a r b o n / w a t e r contact? Do we have enough i n f o r m a t i o n to know if we have oil or gas? What is the invasion diameter at 8397 ft using the wireline logs? What is the invasion diameter using the M W D / L W D logs? 5. What is needed to compute the hydrocarbon saturation? Solution

1. Shale-sand sequence: Top to 8,374 ft shale 8,374 to 8,425 ft sand 8,425 to 8,429 ft shale break 8,429 to bottom sand 2. H y d r o c a r b o n / w a t e r contact: 8,413 ft. 3. No, we need the n e u t r o n and density curves. 4. According to chart in Figure 4-304, d i = 40 in. with the wireline logs. T h e d~ cannot be calculated with the M W D / L W D logs since we have only two resistivity curves. 5. We need the porosity. Rw is given by R a in the lower sand. We also need R t. U l t r a s o n i c C a l i p e r a n d S o n i c Log w h i l e D r i l l i n g

In the ultrasonic caliper sub, two ultrasonic sensors are m o u n t e d 180 ° apart o n stabilizer blades as shown in Figure 4-288.

'

•;: Pulse Ultrasonic / Sensor

~lil'illl ~ll~i i

LWD tool sonic sensor stabilizer

~

~ Rring ~"~ / ,., I pulse ~

(~

~r

I I

/ L -

(a)

"

• / / / l ~ ~ -- ~Formation] Wind-'-'-'- - -- ~.Echo ,~:'~..'.-'..."~:~ ' echoW7A . . . .

/1111/I,,.

with .Itra-

2"

,,,,,,,,,.- -

,' X " Mud /~ interface

.:ki '":' ": ""'"

~.~e~o'ati°n ~ ~,.~.~

Ltech°

Timeafterfiring Cleanmud, no gas Mudw{thgas (b)

F i g u r e 4 - 2 8 8 . M W D ultrasonic caliper: (a) sensor in the stabilizer blades; (b) schematic of the echoes. (Courtesy Anadrill [113].)

994

Drilling and Well C o m p l e t i o n s

The sensors function in a pulse-echo m o d e that allows the direct measurement o f stand-off, from which s h o r t a n d l o n g axes o f the b o r e h o l e d i a m e t e r are computed. The vertical resolution is 1 in. (25 mm) and accuracy o f the d i a m e t e r m e a s u r e m e n t is +0.1 in. (2.5 mm). The caliper is used to correct the density and neutron porosity measurements for b o r e h o l e effects and also can be used as a borehole stability indicator. Figure 4-289 shows an e x a m p l e o f c o m p a r i s o n between the MWD ultrasonic caliper and the four-arm wireline caliper run five days later. The MWD caliper sub can also be used for d o w n h o l e d e t e c t i o n o f free gas in the a n n u l u s (gas b u b b l e s , not dissolved gas) t h r o u g h a c o m b i n a t i o n o f f o r m a t i o n and "faceplate" echo signals. In Figure 4-288b a schematic o f the system is represented. The faceplate is the interface between the window and the mud. The faceplate echo signal is the echo d u e to the i m p e d a n c e mismatch between the window and the mud. This echo is affected by the gas content o f the mud, with echo a m p l i t u d e increasing with the gas content. It can be seen in Figure 4-288b that concurrently the f o r m a t i o n echo decreases. The smallest amount o f gas detectable is about 3% o f free gas in volume. Real-time transmission o f this information can shorten the time n e e d e d to detect gas influxes while drilling. It can help and simplify the kill operations. Figure 4-290 shows an example o f drilling in u n d e r b a l a n c e conditions. Gas influxes are very well outlined.

MWD Sonic. A new LWD tool d e v e l o p e d by A n a d r i l l p r o v i d e s sonic compressional At measurements in real time and r e c o r d e d modes. The tool operates on the same general principles as m o d e r n wireline sonic tools. As the drilling o p e r a t i o n progresses, the transmitter is actuated and acoustic waves p r o p a g a t i n g t h r o u g h the m u d a n d f o r m a t i o n are d e t e c t e d by the receiver array. Using a d o w n h o l e p r o c e s s i n g a l g o r i t h m , t h e c o m p r e s s i o n a l At o f the f o r m a t i o n is e x t r a c t e d from the waveforms and t r a n s m i t t e d u p h o l e in real time via m u d telemetry. The compressional At and porosity logs are generated, providing an i n p u t for lithology identification and overpressure d e t e r m i n a t i o n . A successful sonic-while-drilling tool must overcome four major problems: • • • •

suppressing collar arrivals t r a n s m i t t e r and receiver mounting on drill collars interference o f drilling noise processing sonic waveforms d o w n h o l e

A diagram o f the tool is shown in Figure 4-291. The array length and the use o f four receivers give a g o o d c o m p r o m i s e for compatibility with wireline measurements and spatial aliasing properties. The choice o f four receivers also minimizes m e m o r y and power requirements, which are both proportional to the n u m b e r o f receivers. The separation between transmitter and receivers is a compromise between a long distance for good signal amplltude and minimum tool cost. This distance is also similar to that used in wireline array tools. The receivers are small, wideband piezoceramic stacks, which have responses similar to wireline receivers. The battery-powered electronics acquire and store sonic waveforms. U n d e r the control o f a downhole microprocessor, the transmitter is fired, and four receiver waveforms are simultaneously digitized at 12 bits and a d d e d to a signal stack. The t r a n s m i t t e r firing is d o n e in bursts at the rate o f 10 Hz, which allows m i n i m u m movement while stacking. The d a t a acquisition rate is generally set so that the sample spacing o f the sonic log (the distance between two acquired d a t a points) ranges from 6 in. to 1 ft based on the anticipated drilling rate o f p e n e t r a t i o n (ROP).

MWD and LWD

Smmll

large

Axis

Axls

MWO Ultrasonic Caliper While Ddlling

WirelineFour-Arm Caliper 5 Days After Drilling

12 w L 1712 w L 17 SmaRAx~

SmallAxis

U-sonlc U - s o n l c MWD MWD 12 17 12 17

¢-

.:12

Large Axis . . .in. . .

L~rge Axis 22,12 . . . . . . . .in ....

~t~.

X

A

~

p

w x,oo

). Figure 4-289. Comparison of MWD ultrasonic caliper logs with the 4-arm wireline caliper logs run five days later, (Courtesy Anadrill [113].)

995

DrillingandWellCompletions

996

LWD Ultrasonic

Catper

While Drilling ~= ~.~

ROP

Large Axis in

8

.~

o

~

o

J J 181

Gas Indicator

I

=ow,o ,~o

I

I

I

g=,~

,~ol o

u..,

~;

I ,/

2~

Baselineno gas

prOducing fracture

-~;oe ~

X4~

~

~

i

[

C

XS~

) producing

- ~ _

#"

i

,rW~re

x600"~

x,oo I

Figure 4-290. MWD ultrasonic caliper and gas influx log. (Courtesy Anadrill [113].)

MWD and LWD

997

6 5/8-in. FH o o l joint

Standa m~dr~ ~ewer array Electro Readou poG 23.08 ft

TransR

~-h. FH oint

Figure 4-291. Schematic of the LWD sonic tool. (Courtesy SPWLA [116].) For LWD/wireline sonic log comparison, we highlight the zone from 600 to 1000 ft in Figure 4-292. However, the two sonic measurements in the 840-860-ft interval show a major disagreement. This disagreement probably results from the deteriorated hole condition (two large washouts shown on the caliper logs) when the wireline logs were acquired (10 days after drilling).

998

Drilling and Well Completions

1 SO.00

D T - W L (US/F)

SO.00

•~SO.00

01" o L W O ( U S / F )

';0.00

60O

700

800

900

lOOO Figure 4-292. Comparison of a wireiine sonic log with an LWD sonic log. (Courtesy SPWLA [116].)

MWD and LWD

999

O f p a r t i c u l a r interest in Figure 4-292 is the shaly sandstone in the 690-720ft interval. In this zone, the LWD sonic m e a s u r e m e n t s are consistently faster than the wireline measurements. Since the wireline logs were acquired 10 days after drilling, it is likely that shale swelling in the shaly sandstone has taken place. This p h e n o m e n o n , known as f o r m a t i o n alteration, causes the wireline sonic measurements to be slower. In this type of zone, LWD sonic yields a m o r e correct At, which will better match surface seismic sections.

Measuring while Tripping: Wiper Logs When the MWD systems are battery powered and have a downhole recording capability or use an electromagnetic telemetry, logging measurements can be repeated each time the bit is pulled out or run into the borehole. This new capability provides a way to map the progression of the filtrate front in the permeable formations.

Downhoie Recording. W h e n the logging m e a s u r e m e n t s are battery powered the logging p a r a m e t e r s can be r e c o r d e d versus time while t r i p p i n g the drill string. If the d e p t h is simultaneously r e c o r d e d versus time, the data can be plotted versus depth. C o m m o n m e m o r y capabilities are of the o r d e r of 2 to 10 megabytes. T h e recording rate is adjusted to obtain about two data sets p e r foot.

Electromagnetic Telemetry, The electromagnetic telemetry is usually powered d o w n h o l e with batteries. Parameters such as g a m m a ray, resistivity and temp e r a t u r e , can be t r a n s m i t t e d while t r i p p i n g u p or down. Since a two-way c o m m u n i c a t i o n is possible, the system can be switched to a "logging only" m o d e to transmit only the logging information.

Invasion Diameter Versus Time. Many p a r a m e t e r s d e t e r m i n e the invasion diameter: • • • • • •

f o r m a t i o n porosity formation permeability mudcake p e r m e a b i l i t y mudcake thickness differential pressure m u d filtrate and f o r m a t i o n fluid viscosity

Figure 4-293 shows two typical cases for a 1-~td, 0.25-in. (6-mm) mudcake, 500 psi (3450 kPa) differential pressure, 20% porosity (a), and 30% porosity (b). T h e factor p e r m e a b i l i t y is i m p o r t a n t only for the low permeabilities, below 1 md. T h e invasion d i a m e t e r increases rapidly in the first few days, making the m e a s u r e m e n t s d u r i n g t r i p p i n g particularly significant.

Example 18: Example of Wiper Logs Figure 4-294 shows a set of resistivity logs run in a s a n d - s h a l e sequence of the Gulf Coast. We have one wireline dual i n d u c t i o n log, one MWD resistivity log, a wiper-MWD resistivity log and one g a m m a ray log. 1. 2. 3. 4.

Describe the lithology of this zone. How do we know that the cleaner zones marked A and B are permeable? C o m p a r e the invasion for the various logs. W h a t is the true resistivity of Zone A and Zone B?

1000

Drilling and Well Completions 120 ¸

I

~ M C

lp.d,

I

1 d, 1 rnd

PHi=20%

I

100"

==

0.1 md

J

¢l

Ca)

= •~ 4o 0.01

//I

imq

md

20

0

0

20

Invasnon Time (days) 100

! ! i

~ M C

lp.d,

PHI=30%

z

i

"-

~

ii d 1 md

0.1 rnd

~ (b)

~ so

~ , ~

- - 0.01 rnd

i

0 0

10

20

Invasion Time (days) Figure 4-293. Invasion diameter versus invasion time for various formation permeabilities. (a) Filtrate invaded porosity: 20%; mudcake permeability: 1 p,d; mudcake thickness: 0.25"; differential pressure: 500 psi. (b) Filtrate invaded porosity: 30%; mudcake permeability: 1 tad; mudcake thickness: 0.25"; differential pressure: 500 psi. (Courtesy Louisiana State University [99].)

MWD and LWD

1001

Solution:

l. L a m i n a t e d shaly zone; two fairly clean intervals marked A and B. 2. Invasion causes curve s e p a r a t i o n for wiper and wireline logs. 3. No invasion in the M W D / L W D log. In the wireline log, using the chart in Figure 4-304. Sand A: d i = 32 in. Sand B: d i = 30 in. U s i n g the w i p e r log, we have i n v a s i o n b u t it can n o t b e d e t e r m i n e d quantitatively. CDR-Ddlling Attenuation.Deep

CDR-Wiper Attenuation.Deep

PhaseShiR.Shallow 0.20

ol~m-rn

20 0.20

PhaseShift.ShaJlow ohm-m 20

Wireline Induction

Deep Medium

Gamma Ray

Shallow 0

API

0.20

150

ohm.m

20

i

U

:"

F i g u r e 4-294. Comparison of compensated dual-resistivity logs run while drilling and in a wiper pass with the wireline induction logs, (Courtesy

Anadri// [113].)

1002

Drilling a n d Well Completions

4. In the wireline log (Rzd), Sand A: R t = 3.0 f l ° m Sand B: R t = 1.8 ~ ° m Using the wiper log ( R ) Sand A: R = 3.0 fl ° m Sand B: R = 1.5 f l ° m

Example 19: Example of Wiper Logs Figure 4-295 shows a set of MWD/LWD logs recorded in a Gulf Coast well. 1. 2. 3. 4. 5.

What are the boundaries of the main sand? What curve is used for lithology? Is there a h y d r o c a r b o n / w a t e r contact? Where? Which curve(s) will tell us? Is the u p p e r part gas or oil saturated? Determine the porosity at 400 ft. Determine the hydrocarbon saturation at 400 ft.

Solution: 1. 2. 3. 4. 5.

Top of sand at 383 ft. Bottom of sand at 486 ft. G a m m a ray indicates shales a n d clean formations. Yes, h y d r o c a r b o n / w a t e r contact at 410 ft. Resistivity a n d Rwa. With chart in Figure 4-303, • = 28%. Slighdy above sandstone line, probably gas. Saturations: Rwa= 0.01; R = 6 fl • m ; ~ = 28%; S = 12%; Sg= 88%.

Measurements at the Bit A typical MWD bottomhole assembly used in rotary drilling is as follows from b o t t o m to top: drill bit, stabilizer, resistivity, WOB torque, d i r e c t i o n a l a n d telemetry system, neutron-density Pe. T h e typical distances are seen in Figure 4-296a. W h e n a m u d motor is inserted between the lower stabilizer and the drill bit, the distances are increased as shown in Figure 4-296b. The time elapsed between drilling and recording the data at a given depth can be read in Table 4-131 for various rates of penetration. To meet the challenges posed by horizontal drilling in particular, a system has been developed to make the measurements at or near the bit a n d transmit them to the m u d telemetry section of the MWD b o t t o m h o l e assembly. T h e resistivity at the bit tool is similar to the toroidal resistivity tool described in the section titled "Resistivity Logs." As shown in Figure 4-297, the A n a d r i l l geosteering package includes below the Power Pack m u d motor: • a surface adjustable bent housing • a sub for m e a s u r e m e n t of the bit resistivity, azimuthal g a m m a ray, inclination, a n d bit r p m (the same sub contains an electromagnetic transmission system that sends the data to the m u d telemetry above the m u d motor) • a _~o 4 fixed bent-housing section equipped with the bit resistivity toroid a n d the azimuthal resistivity b u t t o n • a stabilizer a n d b e a r i n g section, just above the drill bit Figure 4-298a shows the sketch of principle of the resistivity m e a s u r e m e n t in water-base mud. The drill bit resistivity is measured below toroid T v A n average resistivity is measured between toroid T 1 a n d T 2. T h e azimuthal resistivity is measured with

MWD and LWD

1003

0,,~ C,m w 20

{GN~ PEF

1~ I .....ReMm~y A . ~ ,,H • 0.2o (~m-m) 30 -0.40 (=~=) o.lo ~ J=m==m/ P~m,ly I=~u=St~.Sa~low ~.~)

RWA

0

0.f,O

~L

60

~u.)

,¢:

,>

400

<

i

,,} SO0 i t'

.X F i g u r e 4-295. LWD resistivity logs recorded during a wiper pass. [113].)

Anadrill

(Courtesy

1004

Drilling and Well Completions

N-D-Pe

Incl/Az

NoD-Pe

WOB/T 105'

Incl/Az

R-GR

80' I

WOB/T

I 1

R-GR

5

! !

! I I

I

I

1

I i

I

Mud Motor

28'

Bent

HousingBit ~

Bit (a)

(b)

Figure 4-296. Typical MWD bottomhole assemblies: (a) rotary drilling; (b) mud motor drilling. button R. In normal buildup drilling, the azimuthal resistivity measures the high side of the borehole and the gamma ray window sees the low side of the borehole. Measurements in other orientations are made by rotating the bottomhole assembly. In the geosteering configuration, the resolution of resistivity at

MWD and LWD

1005

Table 4-130 "Time Since Drilling" for Various MWD/LWD Logs with Typical Spacings (a) Rotary Drilling PJGR (hr/min)

WOB/T (hr/min)

INCIJAZ (hr/min)

ND Pe (hr/min)

13-0 2-36

32-0 6-24

10

1-18

3-12

20 50 1O0

0-39 0-15 0-8

1-36 0-38 0-19 32

50-0 10-0 5-0 2-30 1-0 0-30 50

80-0 16-0 8-0 4-0 1-36 0-48 80

ROP (ft/hr) 1 5

13

(b) Mud Motor Drilling ROP (ft/hr) 1 5 10 20 50 1O0

PJGR (hr/min)

WOB/T (hr/min)

INCIJAZ (hr/min)

ND Pe (hr/min)

28-0 5-36 2-48 1-24 0-34 0-17 28

57-0 11-24 5-42 2-51 1-8 0-34 57

75-0 15-0 7-30 3-45 1-30 0-45 75

105-0 21-0 10-30 5-15 2--6 1-3 105

the bit is 6 ft (1.8 m). W h e n drilling in rotary, the resistivity at the bit (RAB) is also m e a s u r e d with a similar toroidal system as shown in Figure 4-298b. T h e RAB tool has three b u t t o n electrodes spaced to give azimuthal resistivities with three depths of investigation: 3, 6 and 9 in. (7.6, 15 and 23 cm). A ring electrode is also p r o v i d e d to yield an axial focused resistivity 5 ft above the drill bit. Focusing is improved by a near-bit transmitter. T h e radius of investigation of the ring electrode is about 12 in. (30 cm) and the vertical resolution about 2 in. (5 cm). Figure 4-299 is a sketch o f the ring electrode measurement. T h e b u t t o n electrode m e a s u r e m e n t is similar with a b u t t o n instead o f the ring. Both rotary and m u d motor systems use an electromagnetic wireline telemetry to relay the d a t a from the near-bit sub to the m u d t e l e m e t r y sub.

Basic Log Interpretation T h e log i n t e r p r e t a t i o n using logging while drilling logs is very similar to the interpretation m a d e with wireline logs. O n e major difference is that the invasion is u s u a l l y less i m p o r t a n t d u e to t h e s h o r t t i m e e l a p s e d b e t w e e n d r i l l i n g a n d logging.

L|thology. G a m m a ray is used to differentiate between shales a n d clean formations. Pe is used to d e t e r m i n e the nature of the clean formations: sandstone, limestone, o r dolomite.

1006

Drilling and Well Completions

PowerPak PDM

Surface Adjustable Bent-housing

Gamma Ray Azimuthal Resisti~

NBS with Bit Resistivity, Azimuthal Resistivity, Gamma Ray, Inclination, RPM 3/4 ° Fixed Bent-housing Stabilizer + Bearings

Figure 4-297. Anadrill geosteering tool. (Courtesy Anadrill [113].) Porosity. Two porosity logs are run today (1994); namely, neutron and density. Soon the sonic will also be available. With the lithology matching the log scale, and assuming the formation fully invaded by m u d filtrate, a n e u t r o n porosity and a density porosity can be determined. • If the two porosities match, the formation is saturated with a liquid, water or oil, and the porosities are true porosities. • If the neutron porosity is low and the density porosity is high, the formation contains gas and the true porosity can be determined with charts.

MWD a n d LWD

1007

PowerPak motor

(a)

(b)

F i g u r e 4-298. Measurement at the drill bit.

(Courtesy Anadrill [113].)

Side view

Top view

•

\

1

I

I

\

i=

Drill collar

9

J Insulation

/

T

Figure 4-299. Principle of the ring resistivity measurement in the resistivityat-the-bit tool. (Courtesy Anadrill [113].)

1008

D r i l l i n g a n d Well C o m p l e t i o n s

Saturation. Resistivity logs are u s e d for s a t u r a t i o n estimates. O n e , two o r m o r e resistivity logs with d i f f e r e n t i n v e s t i g a t i o n d e p t h s are usually available. T h e t r u e resistivity o f t h e f o r m a t i o n can b e e s t i m a t e d . I f a w a t e r s a n d has b e e n d r i l l e d n e a r t h e i n t e r v a l o f interest, t h e f o r m a t i o n w a t e r R can b e d e t e r m i n e d by

R.

R°

4-206)

F w h e r e R 0 = t r u e resistivity o f t h e w a t e r s a n d F = f o r m a t i o n factor and

F=--

1

4-207)

02

or

0.62 F = -(I)2.I5 -

4-208)

w h e r e • = p o r o s i t y in f r a c t i o n E q u a t i o n 4-207 is u s e d in c a r b o n a t e s ( l i m e s t o n e a n d d o l o m i t e ) a n d E q u a t i o n 4-208 is u s e d in u n c o n s o l i d a t e d to m e d i u m c o n s o l i d a t e d sandstones. A t h i r d E q u a t i o n 4-209 can b e u s e d in highly c o n s o l i d a t e d sandstones. T h i s is

F-

0.81 02

(4-209)

If n o w a t e r s a n d exists, t h e n an e s t i m a t e o f R m u s t b e m a d e b a s e d o n regional knowledge. Since t h e t r u e p o r o s i t y has b e e n d e t e r m i n e d , f o r m a t i o n w a t e r s a t u r a t i o n can b e d e t e r m i n e d by

S.

= jV-Rw ~ R~

where S = 1~ = Rw = Rt =

(4-210)

f o r m a t i o n water s a t u r a t i o n f o r m a t i o n factor f o r m a t i o n water resistivity t r u e resistivity o f t h e f o r m a t i o n

T h e oil o r gas s a t u r a t i o n is Shc = 1 - S w h e r e Shc = h y d r o c a r b o n s a t u r a t i o n

(4-211)

MWD and LWD

1009

T h e volume o f h y d r o c a r b o n s in place at reservoir c o n d i t i o n s is O~p= 7 7 5 8 " 4 ) ' S h c * where Q~p 4) She h

= = = =

h

(4-212)

volume o f h y d r o c a r b o n s in b b l / a c r e porosity in fraction h y d r o c a r b o n s a t u r a t i o n in fraction f o r m a t i o n thickness in ft

Apparent Water Resistivity Rw.. S o m e

M W D / L W D log sets display a curve labeled R . R is c o m p u t e d using Equation 4-210 assuming that S w = 1 (100%). Consequently we have R Rw = R . = ---~' F

(4-213)

Since a

F = 4)---g-

(4-214)

where F = f o r m a t i o n factor a = constant d e p e n d i n g on the formation, generally 1 or 0.81 or 0.62 m = c e m e n t a t i o n factor, generally 2 or 2.15 Finally, R.

-

R, • 4)" a

(4-215)

T h e t r u e porosity 4) is d e t e r m i n e d with the neutron-density Pe logs. R t is generally given by the d e e p investigation resistivity curve. Rwa equals R in the water formations. It increases rapidly in h y d r o c a r b o n s a t u r a t e d formati~ons. Permeability. Permeable zones can be i d e n t i f i e d with the resistivity measurem e n t s m a d e with different r a d i u s o f investigation. A d e p a r t u r e b e t w e e n the curves o f deep and shallow investigation is a qualitative indication o f permeability. T h e charts m e n t i o n e d in the section titled "Measuring While Tripping: W i p e r Logs" can be used to estimate quantitatively the p e r m e a b i l i t y if several measurements d u r i n g t r i p p i n g are m a d e with resistivity devices that can give the invasion diameter. Surface m e a s u r e m e n t s on the m u d can be used to estimate the m u d c a k e characteristics. If the f o r m a t i o n pressure is known, the differential pressure can be calculated, a n d a chart similar to Figures 4-293a a n d b can be plotted. T h e invasion diameters at various times should follow one o f the permeability curves. Note that the p e r m e a b i l i t y effect is seen only for formations with 1 m d or less permeability. Above 1 md, the invasion d i a m e t e r is d e p e n d e n t mostly on porosity.

Log Samples. Figure

4-300 shows samples o f g a m m a ray and spectral g a m m a ray logs. T h e b o u n d a r i e s o f the clean (not shaly) zone can be seen very clearly:

1010

Drilling and Well C o m p l e t i o n s MWD LWD hogs

Figure 4-300. Sample of MWD/LWD logs. 2,256-2,274 ft 2,274-2,356 ft 2,356-2,388 ft

shale clean zone shale

Shale streaks are visible in most of the lower part of the clean section. A high radioactivity peak can be seen at 2388 ft. Looking at the spectral log it can be seen that this peak is due to a high u r a n i u m content. O t h e r radioactive elements' concentration is normal. Figure 4-301 shows sample neutron-density Pe log over the same interval. Figure 4-302 shows sample MWD resistivity (left) and wireline dual induction (right) for the same interval. A high neutron porosity a n d low density porosity occur in the shale zones: 2256-2274 a n d 2356-2388 ft. In the clean zone, a r o u n d 2280-2290 ft, the cleanest part reads @n = 18% and @d = 13%. Plotting the point in the CNL chart o f Figure 4-303, the rock matrix appears to be a d o l o m i t i z e d limestone and the true porosity is 17%. Since the d e e p and shallow curve o f the MWD log a n d the deep, shallow and g u a r d (laterolog) o f the wireline log shows a d e p a r t u r e , the zone 2274-2356 ft is invaded, consequently p e r m e a b l e . Using the dual induction chart of Figure 4-304, we can plot the point at 2290 ft:

MWD and LWD

1011

MWD/LWD logs

Figure 4-301.

Sample of MWD/LWD logs.

RIM/R m = 1.2/1 = 1.2 RLJR,D = 7 / 1 = 7 T h e i n v a s i o n d i a m e t e r is 36 in. where Rxo/R ~ = 11 R t / R m = 0.98 (text continued on page 1014)

1012

Drilling and Well Completions

o

il

,]!' t it

I =,,i, II

'illllllllllllllllllllllllllllllllllllllliil Illlllll~llltllllllllli .l~lllllllllll II lllllllt111111111III111]IIIF1111 I#111111111111It / I I I I ! H Itt I III lJ 11111 lllllllllll Ill II'I, LI.I,HITTFli'rIH II111111111 Iltlt11111111 IIIIIIIIIIIIIIIit 711111FIT131"flIIIIIIIIIIIIIII I I I I 1/11 li|ll I 11111111111 Lll lllll'lTIll~l|llIJrlllllllllrlJIlJllllll IIIIIIit tHeir,Ill II Ili'lPll I ll'lfllll I/I IIII I I I I Iit111111,li LILN I II ~-HfFli-I-#l I I N 11] FIl-rll~lll II#'W I 1%111111111 t I I I II I III I li,IJi N41 [111|11111kl~ IIt1111111,~trllll IJ I I I I I~11111111 ii ii1 i1111111 iii itllllU,IIIII ~I q I111111 [llG I,t.H4114.121111 f'l I'f N.I,#I I I I I~Udd !,/I I II II I I I I I I I I I I I I I II 111111 I I I I II tlltll~lllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllllll

Figure 4-302. Sample of MWD/LWD logs.

MWD and LWD

1013

Porosity and Lithology Determinationfrom Litho-Density* Log and CNL* Compensated Neutron Log L i q u i d - F i l l e d Holes pf = 1.000 g/cc, Cf = 0 p p m

For CNL Curves that have been EnvironmentallyCorrected 1.9 2.0 2.1 ¥ 2.2 II

2.3 >I-

2.4

>I--

Z

0 n,0 n

2.5 3¢: .J

==

2.6

.5 o..

Z LU ,...,

2.7

&

2.8 )

2.9

t

3.0 0

10

20

30

40

~CNLcor, NEUTRON POROSITYINDEX (pu) (Apparent Limestone Porosity)

• M=~ of sc~ur.~fg=r

CP-le

Figure 4-303. Porosity and lithology determination from the Litho-Density* logs and the CNL* Compensated neutron log. (Courtesy Sch/umberger.) (*trade mark of Schlumberger.)

1014

Drilling a n d Well C o m p l e t i o n s

DIL* Dual Induction - Laterolog 8 ID--IM--LL8

I Rxo/Rm= 100 [

Thick Beds, 8-in. (203-mm) Hole, Skin-Effect Corrected, DIS-DB or Equivalent

',!

20

,ool II

I I

10 9 8 7 n-

6

iI 4

!

1.0

1.1

1.2

1.3

1.4 1.5

1.7

1.9

RIM/RID

Figure 4-304.

Resistivities and invasion determination with the Dual Induction log (DIL*) and the laterolog-8. (Courtesy Sch/umberger.) (*trade mark of Schlumberger.) (text continued from page 1011)

Consequently: R t = 0.98 g~ ° m_= 1 f l ° m R o = 11

~

* m

MWD a n d LWD

1015

The formation factor is F = 1/4) 2 = 1/0.172 = 34.6 If we assume a 100% water saturation, the water resistivity is Rw = R / F =

0.029 t l .

m

If an oil or gas zone is present above this water sand, R, should be c o m p u t e d the same way a n d Sw calculated.

MWD/LWD Applications The progresses that have b e e n made in the last few years in MWD a n d LWD have b e e n described in the first part of this section. These progresses could not have b e e n accomplished without a strong support from the oil industry. The support is motivated by the numerous, i m p o r t a n t a n d sometimes indispensable applications of the new technologies. In this chapter we will review drilling mechanics, properties d e t e r m i n a t i o n , a b n o r m a l pressure detection, horizontal well steering a n d geosteering, a n d short radius well technology.

Drilling Mechanics We will discuss four main topics: stuck pipe prevention, drillstring failure prevention, ROP optimization a n d real-time use of drilling mechanics.

Stuck Pipe Prevention. Drillpipes get stuck for many reasons. Differential sticking occurs when the pipe is standing still a n d is pressed against the m u d cake of a highly overbalanced formation. The formation may cave into the wellbore if the pressure exceeds the hydrostatic m u d pressure in shale. The f o r m a t i o n may be reactive a n d swell. It may be u n c o n s o l i d a t e d a n d collapse on the tool j o i n t s or drill collars. We may have "mobile" formations such as "gumbo" shales or salt beds in a plastic condition. Key seats occur in dog legs of the borehole. The drill pipes cut a groove in the wall at their d i m e n s i o n a n d when tool j o i n t s or drill collars are pulled up, the drillstring gets stuck. Wellbore geometry is another reason. In kick-off or well curvature, the drillstring has more flexibility when tripping in than when tripping out a n d the friction may increase to the point of getting stuck. Undergage hole, due to the wearing out of the previous bit, may cause the new bit to get j a m m e d a n d stuck. Finally, inadequate hole cleaning results in an overloading of the a n n u l u s with cuttings, especially in very high p e n e t r a t i o n rate, poor m u d properties, a n d insufficient a n n u l a r velocity or circulation time. Inadequate hole cleaning can also be experienced in deviated wells with the formation of cutting beds on the low side m i g r a t i n g in a "sand d u n e " fashion. The most i m p o r t a n t factor to avoid pipe sticking is the friction factor computed both when sliding a n d rotating. The rotating friction factor is usually called "friction" or FRIC; the sliding friction factor is called "drag" or DRAG. Referring to Figure 4-305a a n d b, the buoyant weight of an element of pipe resting on a curved b o r e h o l e exerts a side force that generates weight loss

1016

D r i l l i n g a n d Well C o m p l e t i o n s

Tension

Weight loss Torque loss

Tension

Side force

Side force

Buoyant weight of element (b)

(a)

Figure 4-305. Forces acting on a drill pipe element: (a) side force; (b) weight and torque loss. t r i p p i n g in o r over-pull t r i p p i n g out. Also, a t o r q u e loss is g e n e r a t e d by t h e side force d u r i n g r o t a t i o n . For o n e e l e m e n t , the D R A G a n d F R I C are given by D R A G --

FRIC -

FI - F2 Wpm . sin i

(4-216)

TI - T2 Wpm * r * sin i

(4-217)

w h e r e F~, F 2 = forces acting o n e l e m e n t e n d s T 1, T 2 = t o r q u e a c t i n g o n e l e m e n t e n d s W pm = weight o f the e l e m e n t in m u d r = radius o f t h e d r i l l p i p e i = average inclination of the element T h e F I, F2, T a, T 2 a r e n o t k n o w n for e a c h e l e m e n t o f t h e drillstring. A v e r a g e f r i c t i o n factors are calculated for t h e w h o l e string u s i n g t h e s u r f a c e m e a s u r e ments o f W O B a n d t o r q u e a n d the d o w n h o l e m e a s u r e m e n t s o f W O B and torque. C o n s e q u e n t l y , D R A G a n d F R I C are c a l c u l a t e d u s i n g t h e following e q u a t i o n s :

D R A G ( % ) = 100 x

FRIC(%) = 100 ×

AWOB Wp~ * sin i ATOR

Wpm . r * sin i

where AWOB = surface WOB minus downhole WOB ATOR = surface torque minus downhole torque Wpm = weight o f d r i l l s t r i n g in t h e m u d

(4-218)

(4-219)

MWD and LWD

1017

r = d r i l l p i p e radius i = average inclination o f the b o r e h o l e The sliding d r a g (DRAG) and rotary friction (FRIC) vary between 5 and 40%. According to Anadrill, the values listed in Table 4-131 are normally encountered in the field. A n example o f a DRAG and FRIC log is given in Figure 4-306. Figure 4-307 shows the raw data collected d u r i n g drilling the interval shown in Figure 4-306. By m o n i t o r i n g the weight loss between the MWD and the rotary table (surface weight - downhole weight) and the torque loss between the MWD tool and rotary table (surface torque - downhole torque), one can effectively look at the sticking forces on the drill string s e p a r a t e d from the forces acting on t h e bit. T h e following c o m m e n t s can be m a d e c o n c e r n i n g Figure 4-306. m: Drag a n d r o t a r y f r i c t i o n i n c r e a s e due to t h e t h i r d and f o u r t h stabilizers hanging and digging in sand at X310. ROP decreases from 50 to 10 f t / h r . Work and ream pipe, d r a g decreases, ROP increases to 70 f t / h r . Rotary friction does not go down until stabilizers are out o f the sand. X 5 2 0 m: Drag and rotary friction increase as the third stabilizer enters sand at )(480. ROP decreases from 80 to 15 f t / h r . Work and ream p i p e with no success. Five-stand wiper trip. Drag and rotary friction decrease to n o r m a l levels, ROP increases to 50 f t / h r . X 7 3 0 m: Rotary friction increases sharply at X710 as top stabilizer enters sand at X570. Drag starts to increase as stabilizer begins to h a n d in the sand. This decreases the ROP from 60 to 10 ft/hr. Three-stand wiper trip decreases both d r a g and rotary friction and increases ROP from 10 to 80 f t / h r . X 1 5 0 m: C o n n e c t i o n , work a n d r e a m pipe. Stabilizers now out o f sandy sections. Rotary friction factor decreases. X 2 3 0 m: Drag friction increases due to top stabilizer hanging in sand at X080. Three-stand wiper trip. Drag decreases back to normal.

At X380

At

At

At At

T h e DRAG-FRIC technique can be used to: * detect the onset o f sticking p r o b l e m s and avoid stuck pipe; • optimize bit p e r f o r m a n c e and avoid unnecessary trips; • optimize hole c o n d i t i o n i n g techniques. (text continued on page 1020)

Table 4-131 Common Friction Factor Values 0.0 Water Base Mud

Plain Treated Additives

OilBase Mud

Plain Treated Additives

CourtesyAnadrill [113]

0.2

0.4

0.6

0.8

1018

Drilling and Well Completions

GFl (c/see) FlOP

lo

io

-

so l o o

il II

(ft/hr) ~

o

DRAG (%) o

_-

FFllC lo zo

qp so

(%)

I

s~ ,,M

2 i

x~

~f

i I

i j

Figure 4-306. Example of sticking pipe indicators. (Courtesy Petroleum Engineer International [117].)

MWD and LWD J$

I

loGR

t

(c/$ec) ROP

,o,Eoo .7_

URF.W.(KIb,)I $ URF.TOR(;(It.lbl)

(ft/hr) ~.~D. H. W.(Klbs)(D.H.TOR(Kft.lbe)

oj

~_

,~,

,~

Figure 4-307. Raw data used for computing the log represented in Figure 4-306. (Courtesy Petroleum Engineer International [117].)

1019

1020

Drilling and Well Completions

(text continued from page 1017)

Drillstring Failure Prevention.

Drillstring failures are mainly due to vibrations, shocks and neutral point positioned too close to the drill pipes. They result in drillstring washouts a n d twist-offs. Axial vibrations usually occur in vertical boreholes and hard rock drilling with tricone bits. They can cause top drive shaking, Kelly b o u n c i n g , a n d i n d u c e downhole shocks. Axial vibrations can be minimized by changing the WOB and rotary RPM after rotation comes to a complete stop. Change the bit type may also help. Lateral vibrations result from the c o u p l i n g with axial mode of buckling. The lateral vibrations may also result from a coupling with the torsional vibrations. Torsional vibrations are due to the "stick-slip" effect of the stabilizers in deviated boreholes. They can be seen at surface as large torque oscillations with a period of 3 to 10 s. Figure 4-308 shows a near-bit stabilizer in a deviated borehole. The stick-slip effect increases with WOB and RPM. A torque feedback system has been developed to d a m p e n the surface torque oscillations and consequently the stick-slip motion at the bit. The system consists of (see Figure 4-309) • • • •

motor current sensor shaft e n c o d e r coupled to the rotary drive motor microprocessor o n / o f f switch for the driller to activate the feedback system

The system of Figure 4-300 reduces drillstring vibrations by 00%. Note that when deactivating the system, several minutes elapse before the vibrations start again. Similarly, when the system is t u r n e d on, several minutes will elapse before the vibrations are dampened. The lateral shocks, the most damaging for the MWD/LWD equipment, are more severe in vertical holes than in horizontal holes. In a vertical hole, the collars or stabilizers hit the borehole wall hard because the gravity does not pull the collar on the low side as in deviated or horizontal boreholes.

DB

HHM

OB

Figure 4-308. Stick-slip effect due to near-bit fraction in a deviated borehole. (Courtesy Anadrill [113].)

MWD and LWD

Current Sensor

1021

Shaft Encoder

Drlilstdn9

13)

(a)

13

,,i ~-.I

I I

I 1

i it

! !

I

!

I

I

II ,,,

!

~10

I ,.LH, il I . 1, ' I ! ,I, INguH|III .9.o8 ~, .~.1 .,IHI~H,LA, II,j~IILdnLi,.,IL]],,BIIINi 9

C~7

5

1'I '[ " 'r ! I"IIIR

3 16.2

i/

I I I Time (Hours) (b)

Figure 4-309. Torque feedback system: (a) block diagram; (b) effect on drill string torque. (CourtesyAnadrill [113].)

Bottomhole assembly whirling is also a cause of lateral shocks. Whirling is the rotation of a bent or buckled BHA or drillpipes. It results in extreme damage to the drillstring a n d bit. One-sided wear appears on the tool joints. Whirling can be minimized by stopping the rotation and t h e n r e s u m i n g it with a lower RPM a n d higher WOB. Twist-offs, a r u p t u r e of the drillstring, mainly occur at tool j o i n t s or connections between drillpipe a n d drill collar. T h e m a i n causes for twist-offs are • b e n d i n g fatigue due to lateral vibrations • torsional vibrations overstress the tool joints • neutral point cycling up and down the connection drill collar/drillpipe due to axial vibrations • drill pipe washouts

Drillpipe washouts are cracks in the drill pipes, causing a m u d leak. T h e detection of drillpipe washouts is d o n e by recording in n o r m a l drilling:

1022

Drilling and Well Completions

• the standpipe pressure (SPP) • the p u m p stroke n u m b e r per minute (SPM) • the MWD generator t u r b i n e speed in r p m (TRPM) These parameters are related by the following relations: SPP = k × SPM 2

(4-220)

SPM = m × T R P M

(4-221)

where k and m are proportionality constants d e p e n d i n g on the units. If a drillstring washout occurs then SPP SPM-'---7 = k (decreases)

(4-222)

and TRPM SPM

m (decreases)

(4-223)

A n example of drill pipe washout is shown in Figure 4-310. In the interval XX800 to XX980 ft the n o r m a l correlation between the total flowrate (strokes per minute) and the MWD flowrate (alternator voltage) can be seen. At the depth XX060, a sharp drop in MWD flowrate indicates that a leak is occurring somewhere in the drillstring. The string was pulled out and a washout was found in the second heavyweight above the MWD tool. Note that in the example the torque friction was above 4% a n d the pipe drag about 10%, which is fairly low for a borehole deviation of 28 °.

Rate of Penetration Optimization. O n e i m p o r t a n t p r o c e d u r e for the ROP optimization is the

drill-off

test. A drill-off test is conducted as follows:

A. Choose a starting weight-on-bit and an RPM. (The RPM will be maintained constant d u r i n g the test.) B. Drill at starting weight for a few m i n u t e s to establish the b o t t o m h o l e conditions. C. Lock the brake a n d let the bit "drill-off" the weight. D. Record the time (AT) to drill a p r e d e t e r m i n e d a m o u n t of weight (AWOB), usually 2,000 to 4,000 lb. E. Calculate the average ROP over the WOB change using ROP = L × where ROP L E A

= = = =

1 AWOB ×~ E•A AT

(4-224)

rate of p e n e t r a t i o n in f t / m i n drillpipe length in ft Young modules of the drillpipes in psi cross-sectional area of the drillpipe in in. 2

F. Repeat steps D and E as the drill bit continues to drill-off weight and graph. G. Repeat drill-off test with different RPM.

MWD and LWD

1023

COt~£LATOR 5~

ROPe5 #~
.............

-oi

Q-

~pt5 ....o I ~±6

t:L

....

w 8jvq%

O?OR

F~C

i

DRAG %

¢om

_

i

i i< i ?

?

e~a:

~

r

Washou~ la seeo~g heviwe ght above MWD

Figure 4-310. Example of drill pipe washout. (Courtesy Anadrill.)

Drill-off tests are tedious to perform by hand. Computerized drill-off tests are now available. ROP is directly calculated as a function o f WOB. Figure 4-311 is an example o f computer generated drill-off curves. T h e driller uses the curves by selecting the WOB and RPM corresponding to the highest ROE T h e curves can also be used to quantify the advantages o f r u n n i n g unconventional weights-on-bit and rotary speeds. The weight transfer is also an important parameter that can decrease the rate o f penetration. In deviated wells, up to 20,000 lb o f weight and 25,000 ft-lb o f torque can be lost to drag and friction. Figure 4-312 shows the improvement that can be caused by an l l - s t a n d short trip and circulating a m u d pill o f 15 l b / b b l o f Barafiber.

1024

Drilling and Well Completions

t5

\ x

~

H

60

Weight ea 8R {Klbs)

Figure 4-311. Drill-off test curves generated by a computerized system. (Courtesy Anadrill.)

HYCALOG DS-39-H PDC B~T

Figure 4-312. Example of poor weight transfer caused probably by cutting buildup. (Courtesy Anadrill.)

1025

MWD and LWD

Bit Wear and Rock Type. Using downhole weight-on-bit and torque the roller cone bit w e a r can be estimated while drilling. T h e well site c o m p u t e r can be used to c o m p u t e in real-time a dimensionless t o r q u e (TD) and a dimensionless rate of p e n e t r a t i o n (RD) using the following equation:

TD=

RD =

DTOR x 12 DWOB * BD

(4-225)

ROP x 12 RPM * BD 60

where D T O R DWOB ROP RPM BD

= = = = =

(4-226)

downhole t o r q u e in klb-ft downhole weight-on-bit in klb rate of p e n e t r a t i o n f t / h r bit r p m bit diameter in in.

For a sharp bit drilling in shale [118] the following expression is used: T D = AI+E d+A=x~

(4-227)

where E d = bit efficiency (one for sharp bit; zero for worn out bit) A~ = dimensionless gouging coefficient (A~ = 0.07 to 0.12 for milled tooth bit; A I = 0.2 to 0.35 for PDC bits) A s = crushing coefficient (A~ = 0.07 to 0.15 for milled tooth bit) Figure 4-313 shows schematically the variation of T D versus (RD)°5 in shales, as well as other zones in the diagrams such as porous zones and tight zones.

Excess torque below the 1 MWD due to stabilizers digging or locked cones

Td

IPorous type formations

I

New bi~ in shole~-~ Gradual trend of tooth wear in shale Tight low porosity'] ype formations ) Rdl/2

Figure 4-313. Variation of the dimensionless torque versus the dimensionless ROP.

1026

Drilling and Well C o m p l e t i o n s

Assuming that A t does not change, E D can be calculated in real-time as shown in the example o f Figure 4-314. T h e effect o f a locked cone can be seen clearly at XX610 ft. W h e n the bit was pulled out and examined, o n e cone was hanging, o n e was locked, and o n e was okay (T4).

Downhole Mud Motor Optimization. Downhole mud motors in use today are practically all o f the positive displacement type (sometimes called the " m o v i n g cavity"). A d e s c r i p t i o n o f these motors has b e e n given in section 4.10. T h e theoretical characteristics curves o f the motors are shown in Figure 4-315 in arbitrary units. If AP is the differential pressure across the motor, due to leakage b e t w e e n the rotor and stator, the RPM decreases as follows: New Motors RPM = 4.0 - 1.0 x AP

REED HP51AJ (inse£) 12,25"

Figure 4-314. Bit efficiency curve. (Courtesy Anadrill.)

(4-228)

MWD a n d LWD

1027

Worn OUt motors RPM = 4.0 - 2.0 x Ap

(4-229)

The torque (T) increases with Ap as follows: T = 2.0 x Ap

(4-230)

The horse power (MHP) goes through a m a x i m u m according to the formula: New motors M H P = 8.0 x A p - 2.0 x AW

(4-231)

Worn OUt motors M H P = 8.0 x A p - 4.0 x AW

(4-232)

Figure 4-316 shows the characteristic curves for a new 8-in. OD, 7:8 lobe, a n d three stages. The r e c o m m e n d e d full load AP is 490 psi. W h e n the pressure is measured inside the drill collars and below the motor, AP can be determined. The flowrate is also k n o w n a n d the hydraulic power can be calculated in real time:

HHP-

~°0.

171-----~

(4-233)

where H H P = motor hydraulic power in hp Ap = motor pressure drop psi Q = flowrate in g a l / m i n

10 ~ 8

E

24

New Motor

10

Worn Motor

--T°ique=2"0y

if o

T°riue=2"( U

~8

//

P-2.01 ~_ E

~4, MHP=8.0P-4.0P^2

0

. PM--4. 1 2

0~ 3

4

Differential Pressure

5

0

f/ -,,/' ",,. \1 "qi

"' I

I

RPM~'O-ZOPI

1 2 3 4 Differential Pressure

Figure 4-315. Characteristics of new and worn out positive displacement

mud motors. (Courtesy Anadrill.)

1028

D r i l l i n g a n d Well C o m p l e t i o n s

8-in. OD 7:8 Lobe 3 Stage 300 ~" 250

'q"

"10

12

/ /

300 g~n ~ 525 gpm j 7.50 g~om ~lI .,~ /t

10

. - . 2OO

e-.

e/:/2/"

E EL

A

X

v

"o Q) 4)

150

o.

I

100 5O

525 gpm

/

=L i

J

/ / . "/ /"

f

6

/ /

/

RPM =1= 750 gpm

/

o o o

/ 4

o"

/

S

v

ill

100

200

300

400

500

600

700

800

Pressure drop across power section (psi) F i g u r e 4-316. Characteristic curves for a positive displacement mud motor with 8-in. OD, 7:8 lobe, and three stages. (CourtesyAnadri//.)

F o r t h e m o t o r o f F i g u r e 4-316 at Ap = 4 9 0 psi a n d Q = 525 g a l / m i n , we h a v e H H P = (490 × 5 2 5 ) / 1 7 1 4 = 150 h p H H P = 3 , 3 7 8 , 0 6 0 × 0.03312 = 111,877 W = 150 h p ( m e t r i c u n i t s ) The mechanical power can be calculated with the formula when the RPM and t o r q u e a r e k n o w n . B o t h a r e m e a s u r e d d o w n h o l e in A n a d r i l l g e o s t e e r i n g system:

MHP-

T- RPM 526-""--~

M H P = 2_._~.~× T × R P M 60

(4-234)

(4-235)

where MHP = motor mechanical power in HP T = m o t o r t o r q u e i n ft-lb RPM = motor rotation speed in rpm F o r t h e m o t o r o f F i g u r e 4-316 at Ap = 490 psi, we r e a d 6,000 ft-lb a n d 74 r p m : M H P = ( 6 0 0 0 x 7 4 ) / 5 , 2 4 7 = 85 H P = ( 2 ~ / 6 0 ) x 8,134.8 x 74 = 6 3 , 0 6 7 W = 85 H P ( m e t r i c u n i t s )

MWD a n d LWD

1029

T h e efficiency o f the m o t o r o f Figure 4-316 is

1] .

MHP . . . HHP

85 . 150

56%

To m o n i t o r the motors p e r f o r m a n c e , a plot can be m a d e in real time o f the mechanical horsepower versus the hydraulic horsepower. T h e curve should be similar to the MHP curve o f Figure 4-315 since, according to equation 4-233, at constant ~ the hydraulic power is p r o p o r t i o n a l to Ap. A n example is shown in Figure 4-317 where m e a s u r e m e n t s have b e e n m a d e at various RPM. Motorwise, the o p t i m a l setting is marked on the screen with a large X.

Rock Mechanical Properties. In the previous section (Figure 4-313), the wear o f the bit teeth can be d e t e r m i n e d in shales by plotting the dimensionless bit torque (TD) versus the dimensionless ROP (RD). By introducing a new parameter, namely the a p p a r e n t f o r m a t i o n strength, the bit effects can be s e p a r a t e d from the lithology effects.

Figure 4-317. Power drilling monitor example. (Courtesy Anadrill [113].)

1030

Drilling and Well C o m p l e t i o n s

T h e a p p a r e n t f o r m a t i o n strength (FORS) is calculated with the following equation: FORS = 40 x DWOB x RPM x A 1 x E d ROP x BD where FORS DWOB RPM A~

(4-236)

= = = =

apparent f o r m a t i o n strength in psi d o w n h o l e weight-on-bit in lb bit rotation p e r m i n u t e dimensionless g o u g i n g coefficient (A 1 -- 0.07 to 0.12 for milled tooth bit, A I = 0.2 to 0.35 for PDC bits) E d -- bit efficiency (one for a sharp bit, zero for a worn bit) ROP = rate of p e n e t r a t i o n in f t / h r BD = bit d i a m e t e r in in.

This e q u a t i o n produces a f o r m a t i o n strength that is i n d e p e n d e n t of the wear state o f t h e bit a n d o t h e r m e a s u r a b l e d r i l l i n g variables. F i g u r e 4-318 is a schematic plot o f the dimensionless t o r q u e (TD) versus the apparent f o r m a t i o n strength (FORS). O n c e the shale line has been established for a certain drill bit, the porous and tight zones can be d e t e r m i n e d regardless of bit condition.

1.0 ¸

•.-.

0.8

S

Excess torque below MWD

0.6 ~

"~ ,,//

o -~

0.4

shales

I-0.2

tight

)

0.0 0

50

100 FORS

150

(kpsi)

Figure 4-318. Schematic plot of the dimensionless torque T D versus the apparent formation strength.

Z00

M W D and L W D

1031

Demonstration. If D W O B = 14,000 lb, RPM = 100, A I = 0.1, E d = 1 (new bit), R O P = 80 f t / h r , BD = 8.5 in. F O R S = 8,235 psi. Typical shallow G u l f C o a s t f o r m a t i o n s . T h e t e c h n i q u e s d e s c r i b e d p r o v i d e t h e f o l l o w i n g answers at t h e rig site, in real-time: • • • •

rock strength wear state o f t h e bit t e e t h in shales lithological correlations excess t o r q u e o r c o n e l o c k i n g

T h i s last p o i n t is i l l u s t r a t e d in F i g u r e 4-314 w h e r e F O R S = 190 kpsi, w h e n the c o n e s lock.

Example 20: Drag and Friction Coefficients F i g u r e 4-319 shows t h e f r i c t i o n ( d u e to r o t a t i o n ) a n d t h e d r a g r e c o r d e d in a slanted b o r e h o l e . B o r e h o l e data: • A v e r a g e inclination: 24 ° • K O P at 3,000 ft • M u d weight: 16 l b / g a l D r i l l s t r i n g data: • D r i l l p i p e OD: weight: metal displacement: length: • Drill collars OD: weight: metal displacement:

4½ in. 22 l b / f t 0.2855 g a l / f t 1,000 ft 8 in. 223 l b / f t 2.2882 g a l / f t

1. C o m p u t e the d r a g c o e f f i c i e n t at 16,200 ft. 2. C o m p u t e the f r i c t i o n c o e f f i c i e n t at 16,200 ft. 3. C o m p a r e with the d a t a c o m p u t e d and r e c o r d e d at 16,200 ft.

Solution 1. L e n g t h o f i n c l i n e d drillpipes: 16,200 - 3,000 - 1,000 = 12,200 ft. Weight o f d r i l l p i p e s in air: 12,200 x 22 = 268.4 klb. W e i g h t o f d i s p l a c e d m u d : 0.2855 x 12,200 x 16 = 55.73 klb. W e i g h t o f d r i l l p i p e s in m u d : 268.4 - 55.73 = 212.67 klb. W e i g h t o f drill collars in air: 223 x 1,000 = 223 klb. W e i g h t o f d i s p l a c e d m u d : 2.2882 x 1,000 x 16 = 36 klb. W e i g h t o f drill collars in m u d : 223 - 36 = 187 klb. Total weight o f i n c l i n e d p i p e and drill collars: 212.67 + 187 = 399.67 klb ( - 4 0 0 klb). S u r f a c e weight-on-bit: 23 klb D o w n h o l e weight-on-bit: 5 klb U s i n g E q u a t i o n 4-218

WEIGHT TRANSFER

OORREL&TOR ROP'5

2 .............

0

o m 0

50

N 0 ° ~- ,';:~

50

o

TORQUE TRANSFER S TORQUE

WASHOUT INDICATOR 0

DTOR 0

KfHbs

15

0 ......

% DRAG.

" ........

%

50

pSI 0~

5

0 eL,

V-ALT 50 ............. ~............... i 50 volts O

i

o !il

0

Figure 4-319. Friction (due to rotation) and drag recorded in a slanted borehole. (Courtesy Anadri/l.)

O

MWD a n d LWD

DRAG -

1033

23 - 5 - 0.11 = 11% 400 x sin 24

2. Surface torque: 11.1 kft • lb Downhole torque: 1.5 kft • lb Using Equation 4-219 FRIC =

(11.1- 1.5) x 12 = 0.23 = 23% sin 24 x (212.67 x 2.25 + 187 x 4)

3. T h e values read on Figure 4-319 DRAG = 11% FRIC = 22% T h e algorithms used for c o m p u t i n g the values of Figure 4-319 are identical to those used in questions 1 and 2.

Example 21: Drag and Friction Coefficients Figure 4-320 shows the data recorded in a highly deviated well. Borehole data: • Mud weight: 12 l b / g a l (water-base) • KOP: 2,000 ft • Average inclination: 46 °. Drillstring data: • Drillpipe OD: weight: metal displacement: • Drill collar OD: length: weight: metal displacement:

4 ½ in. 22 l b / f t 0.2855 g a l / f t 8 in. 1,000 ft 223 l b / f t 2.28 g a l / f t

1. 2. 3. 4.

C o m p u t e the drag and friction coefficients at 11,000 ft. What was the effect of the " p u m p pill" a n d short trip at 11,020 ft? Was the short trip at 11,350 ft necessary? If the p u m p pills decrease the drag, what is the probable reason for drag increase? 5. If the short trips decrease the drag, what is the probable reason for drag increase?

Solution 1. Drag: 0.05 (5%) Friction: 0.18 (18%) Same values c o m p u t e d on the log.

1034

Drilling and Well Completions

20.~0GRC(CPS) 70.00

0.00 SWO~(KLBS) 30.00 0.00 STOR(KFT-LBS)20.00 0.~

DRAG% 10.00

0.00 DWOB(KLBS) 30.00 0.00 DTOR(KFT-LBS)20.00 10.00 FRIC% 20.00 5@100

0.00

q

~!i iooo i! )

;![

•

J

,~ I J t i

i

,,~

•

t t

%1 120

;(

~.t

]

,.~,~ Pumppill "Shorttrip 11stands i Circulate ..,~:~,~ , bottomsup ~;*'~---'~ Pumppill

t t

,,°

-...

•

"%

",-

,t..

'~

Shorttrip 15stands

l" ,.''"

f

.:

:4.::

•

.z'

i"

%

t'f

! e

I r

'

,o

,)'1 ~

i. i

I

~.~. ,,;'~"

"F'

Shorttrip ~".... ~ 19stands ~!i~'Pump ~ ,,~,.~ problems Pumppill

Figure 4-320. Example of drilling data recorded in a highly slanted

(CourtesyAnadril .)

Shorttrip 17stands

borehole.

2. It decreased the drag from 5 to 0.5% for the next 200 ft of drilling. Cutting buildup may be the problem. 3. Probably not. 4. Probably cutting buildup. 5. Probably stabilizers hanging.

Example 22: Shocks Recording Figure 4-321 shows the data r e c o r d e d in a borehole. Shocks have b e e n monitored. The curve at the right shows the number of shocks per second with an amplitude greater than 25 g.

MWD and LWD

500 0

R O ~ | o RPM 200 | o

SWOB kFos: ~TOR Ikft-lbs~

:so 5 o

1035

DOWNHOLE looo SHOCK (see-l)

11400

ROP 11600

11800 DOWNHOLE SHOCKS

12000 , Change ~"~,

RPM

~

===,,,,,,,. Change: WOB :

12200

Figure 4-321. Example of drilling data including shocks recorded in a slanted borehole. (Courtesy Anadrill.)

1036

Drilling and Well C o m p l e t i o n s

Only surface WOB and torque are available. Borehole inclination is 40 °. 1. Is there a correlation between the shock number, surface weight-on-bit, rate o f p e n e t r a t i o n , and RPM? Explain. 2. W h a t is the p r o b a b l e reason for the shocks? 3. At 12,040 ft, would you have increased or decreased RPM for reducing the shock number? 4. How can the weight-on-bit i n c r e a s e / d e c r e a s e the shock number? 5. Could something else have been tried?

Solution 1. Yes; with the shock number, RPM increases, ROP decreases and SWOB increases. 2. Probably stabilizer digging in a stick-slip fashion. 3. In theory, an increase in RPM decreases stabilizer digging due to increase in the B H A m o m e n t u m . However, here it did not help. We may have tried the RPM value used a r o u n d 11,400 ft where no shocks were registered. 4. A g a i n in theory, a decrease in the weight-on-bit improves the stabilizer digging by reducing the side forces. H e r e weight-on-bit was increased. 5. A short trip of 20 stands may have helped.

Example 23: Weight-On-Bit and Torque Interpretation T h e data given in the first four columns of Table 4-132 were r e c o r d e d d u r i n g drilling with an MWD downhole W O B / T O R sub. 1. Compute the normalized torque (TOR), the normalized ROP, and plot T O R versus ROP. 2. C o m p u t e the drilling f o r m a t i o n strength (FORS) and plot versus depth. 3. Plot T O R versus FORS. 4. C o m m e n t on the results.

Solution 1. Table 4-133b gives calculated values o f n o r m a l i z e d TOR, n o r m a l i z e d ROP and FORS. 2. Figure 4-322 gives n o r m a l i z e d T O R versus n o r m a l i z e d R O E 3. Figures 4-323 gives FORS versus depth. 4. Figure 4-324 gives n o r m a l i z e d T O R versus FORS. 5. S o m e tight f o r m a t i o n s can be seen at 9,250 and 9,400 in. T h e representative point at 8,900-ftplots in the porous area of the graph. T h e o t h e r points seem to be mostly shale points. C o n f i r m a t i o n should be sought with logging data.

Abnormal Pressure Detection Definition of Concepts. T h e hydrostatic pressure in a b o r e h o l e is the pressure exerted by a column o f fluid that height is the true vertical depth. This is PH = 0.052 ° W~ ° Zv

(4-237)

MWD and LWD

1037

T a b l e 4-132 I n t e r p r e t i n g D o w n h o l e D r i l l i n g Data R e c o r d e d in a V e r t i c a l Well FORS Calculation DIA = RPM =

12.25 inches 1 60 rpm

I

Norm. TOR ' Jl 2°To R/(WoB'DIA) Norm. ROP I(12"ROPI(RPM*DIA))A0.5 FORS= 40"0.0563*WOB*RPM/(60"ROP'DIA) Deptll ft WOBKIbs ROP ftlmin TOR kft.lbs Norm TOR Norm. ROP FORS (kpsl) 23.21 39.29 8900 0.089[ 0.071 0.83 3.57 39.29 8950 0.71 3.33 0.083 0.066 27.13 9000 39.29 0.59 3.33 0.083 0.060 32.65 9050 46.43 0.71i 3.8 0.080 0.066 32.06 44.64 0.078 21.88 9100 0.083i 1I 3.8 9150 37.09 44.64 0.060 0.078 0.59! 3.57 9200 46.43 0.77 3.81 0.080 0.069 29.56 9250 46.43 0.59 3.33 0.070 0.060 38.58 9300 53.57 1.07 4.52 0.083 0.081 24.54 9350 50 0.47 4.05 0.079 0.054 52.15 44.51 9400 53.57 0.060 0.59 3.81 0.070

y = 0.0563 + 0.3598x

R = 0.53

0 . 0 8 5

"El

A

0 v

nO I--

0.075

~r

0.065 0.05

/

/ ,

0.06

0.07

,

,,

,.

0.08

0.09

(ROP/(N*D))^0.5 F i g u r e 4-322. D i m e n s i o n l e s s torque versus d i m e n s i o n l e s s ROP: (a) grid; (b) plot of calculated values.

1038

Drilling and Well Completions

FORM. STR. (kpsi) 30

2O

40

50

60

8800'

8900

9000

9100

DEPTH (ft)9200

-

~

9300

9400 9500 Figure 4-323. Formation strength versus depth: (a) grid; (b) plot of calculated values.

0 0.065"1 20

•

I

30

-

•

•

40 F O R S (kpsi)

50

60

Figure 4-324. Dimensionless torque versus formation strength: (a) grid; (b) plot of calculated values.

MWD a n d LWD

1039

where P . = hydrostatic pressure in psi W M = fluid density in l b / g a l Z v = true vertical d e p t h in ft The mud equivalent circulation specific weight includes the pressure d r o p in the annulus. Thus,

ECW =

P . + PD 0. 052 * Z v

(4-238)

where ECW = m u d equivalent circulation density in l b / g a l Note that P . must b e calculated using the true m u d specific weight l o a d e d with cuttings. The gradient (G) is the specific weight of the fluid in a column of height Zv. Thus, G =

P" O. 052 • Z v

(4-239)

T h e g r a d i e n t c o n c e p t here is different from the m a t h e m a t i c a l gradient. This concept of g r a d i e n t is also applicable to a column of a solid.

Demonstration. If W M = 12 l b / g a l Z v = 10,000 fl PD = 200 psi P . = 6,240 psi ECW = 12.38 l b / g a l We shall say that the g r a d i e n t is 12 l b / g a l without circulation and 12.38 l b / g a l with circulation (no cuttings). The geostatic or overburden gradient is the average density of a column of sediments of height Z v. The o v e r b u r d e n pressure is calculated with the Equation 4-237 by replacing W M with the average s e d i m e n t density. Since the density of sediments generally increases with d e p t h , the o v e r b u r d e n g r a d i e n t a n d Poisson's ratio increase with depth, b u t not linearly (see Figure 4-325). The following e q u a t i o n may be used to c o m p u t e the o v e r b u r d e n g r a d i e n t Gov: Gov = a(ln Zv)2 + b(ln Zv) + c

(4-240)

Gov = d(ln Zv)2 + e(ln Zv) + f

(4-241)

T h e coefficients a, b, c, d, e, f are given in Table 4-133. Figure 4-325a shows a plot of o v e r b u r d e n pressure g r a d i e n t versus d e p t h for typical soft (1) a n d h a r d (2) provinces. Figure 4-325b gives similar data for Poisson's ratio.

1040

Drilling and Well Completions

I

\/

100(:

200¢

\

\\ \ \\

II

3OO6

, o.Ts 0.80 o . s s l:s

"

,:,

"

0.90 o.gs 2:0

"

O.4 0.5

*.o 1.os p , i / ,

2:2

" 2:4k#,,~

0.5

o.~s 0::3 o.~s

(a)

~K

0.7

0:4

0.~s

0:,

V

(b)

Figure 4-325. Overburden gradient and Poisson ratio: (a) variation of the overburden gradient with depth; (b) variation of the Poisson ratio with depth.

(Courtesy Editions Technip.) Table 4-133 Values of Coefficients a, b, c, d, e, f in Equations 4-241 and 4-242 Gulf Coast (Southern Texas)

Santa Barbara (California)

Soft (1)

Hard (2)

-0.00312 0.11715 0.18241 0.01264 --0.04670 1.66734

0.02176 --0.31307 2.06162 --0.04998 0.85514 -1.34235

Formation a b c d e f

The fracture gradient is an important parameter that must be taken into account while increasing the mud weight and during well control operations. Several equations have been proposed for calculating the fracture gradient. The best results seem to be obtained with the one suggested by Mathews and Kelly [101]: GFRAC =

where

(GoB - Gp)

*

Kp

+

Gp

fracture gradient in psi/ft GoB = overburden gradient in psi/ft Gp = pore pressure gradient in psi/ft coefficient related to Poisson ratio p

GFRAC =

(4-242)

MWD a n d LWD

1041

with v Kp = ] - v where v = static Poisson ratio The static Poisson ratio is d e t e r m i n e d in a triaxial cell. T h e dynamic Poisson ratio is calculated with the sonic compressional and shear wave velocities. They usually are different. W h e n c o n t r o l l i n g a well, be careful not to exceed the fracture pressure anywhere in the open-hole section. A n intermediate casing may have to be set to avoid the fracture condition. The normal formation pressure gradient is the density of a c o l u m n of saltwater of length Zv is expressed in psi-ft in customary units. Table 4-134 gives n o r m a l gradient values for areas a r o u n d the world. Note that for freshwater or quasifreshwater G r = 0.433 p s i / f t = 8.345 l b / g a l . The formation pressure is said "normal" when it corresponds to the hydrostatic pressure of a column of water of length Zv; the water having the densities stated in Table 4-134. A n abnormalformation pressure is a formation pressure greater than the n o r m a l f o r m a t i o n pressure. S u b n o r m a l f o r m a t i o n pressures are also e n c o u n t e r e d in drilling; they are generally due to depleted reservoirs. Abnormal Formation Pressures Origin. F o u r m a i n causes a r e a t t r i b u t e d t o abnormal formation pressures: compaction effects, diagenetic effects, differential density effects a n d fluid migration. The compaction effects are the most c o m m o n . According to Terzaghi's work in soil mechanics, the overburden pressure m e n t i o n e d earlier, is equal to [119] PoB = ~v + [3Pr where POB = ~v = Pr = [3 =

(4-243)

overburden pressure in psi vertical stress in psi formation pressure in psi poroelasticity constant (0.75 to 1.0)

Table 4-134 Normal Formation Pressure Gradients in Various Areas [101] Area West Texas Gulf of Mexico coastline North Sea Malaysia Mackenzie Delta West Africa Anadarko Basin Rocky Mountains California

Pressure Gradient (psi/if)

Equivalent Water Specific Weight (Ibs/gal)

0.433 0.465 0.452 0.442 0.442 0.442 0.433 0.436 0.439

8.345 8.963 8.712 8.520 8.520 8.520 8.345 8.403 8.462

1042

Drilling a n d Well Completions

During compaction, if the fluid can escape, the formation pressure stays equal to the n o r m a l formation pressure. If the fluid cannot escape due to permeability barriers, for example, then the fluid supports part or most of the overburden load. U n d e r these conditions the formation pressure can be up to twice the n o r m a l formation pressure. The diagenetic effects are related to the alteration of rock mineral, shales in particular. U n d e r certain conditions, m o n t m o r i l l o n i t e clays change to illites, chlorites a n d kaolinites. The water of hydration that desorbs in the form of free water occupies a larger volume. This volume increase will cause a b n o r m a l pressures if the water cannot escape. The differential density effects are especially related to thick gas reservoirs or highly d i p p i n g reservoirs. If we assume that at the gas/water contact a n o r m a l pressure exists, as we come up the reservoir or updip, the n o r m a l pressure due to the water c o l u m n decreases more rapidly than the gas pressure.

Demonstration. For example, assume a gas reservoir with a gas/water contact located at 10,000 ft. The reservoir thickness, or change in d e p t h due to dip, is 2,000 ft. The normal gradient is 0.433 psi/ft. The normal pressure at 10,000 ft is Pn(10,000 ft) = 4,330 psi The n o r m a l pressure at 8,000 ft is P n ( 8 , 0 0 0 ft) = 3,464 psi Assuming the gas causes a local gradient of 0.0866 psi/ft, the pressure due to a 2,000-ft gas c o l u m n is APG = 173.2 psi Consequently, the gas pressure at 8,000 ft will be PG(8,000 ft) = 4,330 -- 173.2 -- 4,155 psi The overpressure will then be

Pop

=

4,155 - 3,464 = 691 psi

The increase in m u d specific weight to balance this overpressure at 8,000 ft should be A W , = 1.66 I b / g a l The pressure variation with depth is shown on the lower part of Figure 4-326. The fluid migration effects occur when c o m m u n i c a t i o n t h r o u g h a c e m e n t channel along the casing lets the fluids migrate from one zone to another. The u p p e r zone is being "charged" by the lower zone. The overpressure in the u p p e r zone may be very large.

Demonstration. A gas sand with n o r m a l pressure at 6,000 is charging a sand at 3,000 ft. The n o r m a l pressure at 5,000 ft is 2,603 psi. Assuming that the gas has caused an overburden gradient of 0.0433 psi/ft, then the pressure due to 3,000 ft of gas c o l u m n is

MWD and LWD

0

Pressure

(psi)

2000

3O00

1000

0

1043

4000

5000

i

1000 ~ 2000

OP 1171 psi

'~

3ooo

\ Por~)us

Gas Pressure I

4000

Depth (ft)

5000 '

8ooo, ~,,, Normal~!

Pressure,

7000

~ressure-

I 8000

/

9000 10000

OP 691 psi \

4330

psi

Figure 4-326. Schematic of pressure versus depth for a thick gas formation and for a channel communication behind casing.

APc = 130 psi T h e p r e s s u r e at 3,000 ft will be Pc(3,000 ft) = 2,603 - 130 = 2,473 psi T h e n o r m a l p r e s s u r e at 3,000 ft: PH = 1,302 psi

1044

Drilling and Well Completions

The overpressure at 3,000 ft will then be Pop

=

2,473 - 1,302 = 1,171 psi

The increase in m u d weight to balance this overpressure at 3,000 ft should be AWM = 7.51 l b / g a l This large increase at a shallow depth would probably fracture the f o r m a t i o n such c o m m u n i c a t i o n charging would pose very grave problems when drilling new wells.

Abnormal Formation Pressure Detection with Drilling Parameters. There are four groups of parameters that can be used for a b n o r m a l formation pressure detection: • • • *

Drilling parameters for detection "at the bit" Logging parameters for detection 30 to 50 ft later Mud logging parameters for delayed detection Kicks

In 1966, J o r d e n a n d Shirley [120] i n t r o d u c e d the d-exponent method designed to allow real-time pressure estimation while drilling by analyzing the drilling data, mainly: ROP, RPM and WOB. The equation is as follows:

ROP = K x RPM x

where ROP RPM WOB D K d

= = = = = =

(4-244)

rate of p e n e t r a t i o n in f t / h r rotary speed in r p m weight-on-bit in klb bit diameter in in. rock drillability factor weight-on-bit e x p o n e n t

Assuming a drillability of one,

In( ROP ) d -

~,60 RPM ) l n ( 12wOB ) 1000D )

where ROP RPM WOB D

= = = =

(4-245)

rate of p e n e t r a t i o n in f t / h r rotary rotation per minute weight-on-bit in klb bit diameter in in.

The d-exponent method provided a qualitative overpressure detection, because other parameters did not appear in the equation.

MWD a n d LWD In 1971, Rehm a n d M c C l e n d o n [121] i n t r o d u c e d the for m u d weight. G d= = ECW x d

1045

corrected d-exponent, d ,

(4-246)

where G = n o r m a l g r a d i e n t ECW = equivalent weight with the m u d used d = d-exponent T h e d e x p o n e n t is mostly used in Eaton's equation for a quantitative estimation o f the p o r e pressure using the following equation [122]:

z,

z,

L-/7, [kzvJnJ [dc,n J

(4-247)

where P = Z~= Pob = (Pp/Zv) n =

f o r m a t i o n p o r e pressure in psi true vertical d e p t h in ft o v e r b u r d e n pressure in psi n o r m a l g r a d i e n t in p s i / f t d e s n = e x t r a p o l a t e d n o r m a l c o r r e c t e d d-exponent, in n o r m a l l y c o m p a c t e d shales, not o v e r p r e s s u r e d d¢, = o b s e r v e d c o r r e c t e d d-exponent

Eaton's equation is the most c o m m o n l y used relationship in the industry. It has provided good results in many areas of the world, even though the basic theory remains questionable. Bit wear c o r r e c t i o n s were attempted, b u t since bit wear could not be quantified p r i o r to A n a d r i l l TD/'RD technique (see Equations 4-225 and 4-226), the bit wear c o r r e c t i o n in the d technique is rarely used. A n o t h e r technique used for i n t e r p r e t i n g the d ¢ s curve is the equivalent depth method. T h e c o n c e p t is as follows. T h e p o r o s i t y , thus d , o b s e r v e d in t h e overpressure section at a given d e p t h , Zv is the same as would be expected at a shallower d e p t h , Z~, in a n o r m a l pressure environment. Terzaghi's relation (Equation 4-243) can be written at b o t h d e p t h s with ~ = 1. Pobl = O,1 + Pn at d e p t h Z 1 Pob2 = ~v2 + Pn at d e p t h Z 2 Since an equal de, implies equal t~ we have Pn = Pn + (Pob~ - Pob,)

(4-248)

A n example will be worked out later. O t h e r attempts to develop a p o r e pressure evaluation m e t h o d f r o m different drilling equations were made by Combs, by Bourgoyne and Young and by Bellotti and Giacca [101]. T h e three models follow the same general approach: a drilling equation is d e v e l o p e d assuming that all variables are i n d e p e n d e n t . T h e ROP is then n o r m a l i z e d to eliminate the effect o f each variable b u t the p o r e pressure. These equations a t t e m p t to take m o r e variables into account.

1046

Drilling and Well Completions

Demonstration. Using the example in Figure 4-327, we will plot the corrected d-exponent data, expressed in d-units, in a linear scale, and a logarithmic scale [101]. Both scales give the same results; however, the correlations in normally pressure shales may be easier in the logarithmic scale. Applying Eaton's equation (Equation 4-247) at 13,000 ft, with a n o r m a l gradient o f 0.465 psi/ft, an overburden gradient of 1 psi/ft, dc," = 1.64 and d = 1.17, we find P----~P= 0. 643 psi/ft Zv Pp = 8,362 psi (Pp, = 6,045 psi) At 16,000 ft, where des" = 1.8 and des = 0.8, PP = 0. 797 psi/ft Zv

MODIFIED d - EXPONENT (d-UNITCJ) 0.Z G4 G6 GII t,0 2.0

MODIFIED d - EXPONENT(d-UNITS) O 0,5 I.O 1.5 2.0

Illl,

1

2,000

ZOOO 4000

4.0(~ I

•

NORMAL PRESSURE TRE

d,,mt• 1.15÷O.OO(X)3eO\ ,.ooo

-

z

D

o.

0

,ooo

x o. ~ ~0,000

a 12,000

1300

ft,

tfg HI

'

18,0OO

(a)

(b)

Figure 4-327. de, plots for a U.S. Gulf Coast well in shales: (a) linear scale; (b) logarithmic scale. (Courtesy SPE [101].)

MWD a n d LWD

1047

Pp = 10,371 psi (Ppn = 7,440 psi) Applying the equivalent d e p t h technique at 13,000 ft, the same d s is read on the e x t r a p o l a t e d n o r m a l t r e n d at 4,000 ft. This gives Pvl = 1,860 psi Pob~ = 13,000 psi Pobl = 4,000 psi Pv2 = 10,860 psi This technique is probably less accurate than the technique using Eaton's equation. This equation has been established statistically in the Gulf Coast. No i n d e p e n d e n t pressure m e a s u r e m e n t s are available for this d e m o n s t r a t i o n calculation. W h e n downhole drilling measurements are available, the techniques based on weight-on-bit, can be i m p l e m e n t e d with a better accuracy since the d r a g is eliminated. However, they are still based on a trend line determined in non-overpressured shales. Sometimes, such shales do not exist. Changes in lithology may affect the trend line determination. Early or real-time pressure detection can be made using the f o r m a t i o n strength p a r a m e t e r FORS discussed previously (Equation 4-236). FORS is first n o r m a l i z e d to a 9-1b/gal m u d a n d 0 psi pressure using 1

FORSo, 9 = FORS x

2WM

where FORS09 = FORg WM= PM =

x 1.0

1

0.002PM + 1 . 0

(4-249)

FORS with 9 l b / g a l and 0 psi m e a s u r e d f o r m a t i o n strength m u d weight in l b / g a l m u d pressure in psi

FORS0, 9 is used to d e t e r m i n e the excess effective porosity in the f o r m a t i o n using an e q u a t i o n greatly simplified here: @or, = A - (B • FORSo,9) A and B are functions of many p a r a m e t e r s such as non-shale-rock strength, volume o f shale, shale rock strength, effective porosity, a n d overpressured shale rock strength. T h e s e p a r a m e t e r s are first initialized with local knowledge, for example, the volume of shale, Vc~, o f 65% sandstone FORS, etc. T h e calculated pore pressure is referred to as the "bit pore pressure." Petrophysical data coming later d u r i n g drilling ( g a m m a ray, resistivity, n e u t r o n density) are used to refine the p a r a m e t e r values for a m o r e accurate pressure evaluation. T h e technique will be d e s c r i b e d in m o r e detail later on. T h e total p o r e pressure is derived with the following equation:

Pp = P n + k • o v - l o g

1+ ~ . )

(4-250)

1048

Drilling a n d Well C o m p l e t i o n s

where P = Pnp k = = = ~Pn =

p o r e pressure in the overpressured zone n o r m a l f o r m a t i o n pressure constant vertical stress excess effective porosity n o r m a l shale porosity at the d e p t h o f burial (well depth)

No t r e n d line is n e e d e d to d e t e r m i n e the f o r m a t i o n pressure. However, petrophysical data are required to refine the results. A c o m p u t e r is m a n d a t o r y to i m p l e m e n t the technique.

Abnormal Formation Pressure Detection with Logging Parameters. The first logging p a r a m e t e r used for d e t e c t i n g overpressure zones is the shale resistivity. T h e first observation o f the shale resistivity decrease in overpressured zone was made by Hottman and Johnson [123]. A normal resistivity increase trend exists in normally pressured shales. In overpressured shales the resistivity decreases sharply as shown in Figure 4-328. T h e shale resistivity, as seen in the a m p l i f i e d short normal, decreases from approximately 1 ~ • m at 9,000 ft to about 0.5 ~ • m at 10,000 ft. After setting casing at 10,150 ft, the m u d weight h a d to be raised progressively to 18 l b / g a l to keep the well u n d e r control. H o t t m a n a n d J o h n s o n d e v e l o p e d an empirical correlation to relate the ratio o f resisitivities to the p o r e pressure g r a d i e n t . In 1972, Eaton d e v e l o p e d an empirical relationship that he m o d i f i e d in 1975 to the following [122]:

P Pob IPob/ /lx/Rsh/1

F Z

Z-z,o

(4-251)

where P = f o r m a t i o n pressure in psi Z~= true vertical d e p t h in ft Pob = overburden pressure in psi ( P p / Z ) n = n o r m a l g r a d i e n t in p s i / f t R h = observed shale resistivity in ~ * m R hn = e x t r a p o l a t e d shale resistivity in n o r m a l l y c o m p a c t e d shales in ~ • m In a n o t h e r e x a m p l e f r o m B o u r g o y n e , t h e shale c o n d u c t i v i t y (inverse o f resistivity) was plotted as shown in Figure 4-329 [101].

Demonstration. Both resistivity and conductivity scales have been used with a p p r o x i m a t e l y the same success. At 13,000 ft, Csh = 1,700 m S / m a n d C hn -369 m S / m . A s s u m i n g a n o r m a l g r a d i e n t o f 0.465 p s i / f t a n d an o v e r b u r d e n g r a d i e n t o f 1 p s i / i f , we get P--~P= 0.92 psi/ft Zv Pp = 11,960 psi Using the Matthews and Kelly (1967) correlation [101] (shown in Figure 4-330) for South Texas, we get Pp = 10,660 psi using the Frio correlation, a n d Pp = 11,960 psi using the Vicksburg correlation.

MWD and LWD

MUD WEIGHTS

-11.0#

--11.7m

-12.01

"12.0# 12.5m ,GAS CUT WITH 12.0# MUD "IS.S; KICKED 13.5= MUD I¢ 17.71 NELL STARTED FLOWING. KILLED NELL w/|7.71 ~UD -18.0a

11

F i g u r e 4-328. E x a m p l e of resistivity d e c r e a s e in o v e r p r e s s u r e d shales.

1049

1050

Drilling and Well Completions

SHALE CONDUCTIVITY, Co, (lO'3m/tim 2 )

200

40o

=,oooz,ooo ~ c o

0

2000

4000

6000 ~m

-r ~- 8 0 0 0 a. uJ

I0000

12000

14000

16O0O Figure 4-329. Example of shale conductivity plot in the Frio sand in South Texas. (Courtesy SPE [101].)

MWD a n d LWD

1051

0.4

0.5

,~

,

-

o.6

,

I 2

1.0

1.0

1.25

1.5

1.75 2.0

2.5

3.0

4.0

5.0

6.0

SHALE RESISTIVITY or CONDUCTIVITY RATIO (Ron/Ro)sh or (Co/Con) sh Figure 4-338. Matthews and Kelly relationship between formation pore pressure and shale resistivity for the South Texas Gulf Coast. (Courtesy SPE [101].)

A large difference in pressure prediction will occur if the formation is not well known. Several e x p o n e n t s m i g h t have to be used in Eaton's equation. Exponent 1.2 seems to match the Vicksburg formation as was seen in the preceding example. A n o t h e r technique based o n shale resistivity was proposed by Alixant [124]. This technique does not use a n o r m a l trend line or empirical correlations and is based solely on the shale resistivity. The procedure is as follows: • Select a shale interval. Using MWD data, g a m m a ray, a n d resistivity, determine R w • Estimate the f o r m a t i o n t e m p e r a t u r e at the c o r r e s p o n d i n g d e p t h a n d d e t e r m i n e b o u n d water resistivity using the equation [124] R b = ]] * T-V where

= R[~w~ T = T=

h o u n d water resistivity in ~ * m coefficient equal to 297.6 formation t e m p e r a t u r e in °F coefficient equal to -1.76

(4-252)

1052

Drilling and Well Completions

• Calculate the formation factor using F -

Rsh

Rwb

(4-253)

• Calculate the shale porosity using the Perez-Rosales equation [124] F=I+M*--

(4-254)

~--~r

where F = formation factor M = geometrical factor, usually 1.85 = porosity in fraction = residual porosity in fraction, usually 0.1 • Determirne the vertical effective stress, using the void ratio [e = ~ / ( 1 - ~)] with the equation (iv = 10(¢-¢~)/¢" where (iv = e = ei = cc =

(4-255)

vertical stress void ratio void ratio for (iv = 1 psi average constant compression index

Numerically: (I v =

10 le-3'84)/-t'l

(4-256)

• Apply the Terzaghi relationship (Equation 4-243) to determine the formation pressure. The procedure is summarized in Figure 4-331. The technique has been tried in various areas of the world with good results provided that the shales are very clayey. Silt, sand or carbonates will lead to erroneous results. Figure 4-332 is an example of calculation in a North Sea well. A good formation pressure agreement is seen at 9,500 ft with the wireline formation tester data. T h e sonic log can also be used to detect overpressured zones. The sonic measurements until recently were available only on wireline. Now, MWD sonic tools have been developed adding one more parameter for overpressure detection while drilling. Two equations relating the formation porosity to the transit time are used: The Wyllie equation (simplified form) [125] At

= Vsh •

Atsh • Vma • A t

+ ~ • Atmf

(4-257)

The Hunt-Raymer-Gardner equation [126] 1

1

A-'-~= Atm,

0 . 6 2 5 . At~

(4-258)

MWD a n d LWD

1053

I E

Rws = 297.6 T -1.76]

1-d~

L

I

E

C T

F= P~h

C A L

Ov = 10 . 1.1

RWB

R I

M

E C H A N !

[ O=1,75+0.1 F 0.85 + F

Pp = Pob " O'v

C A L

Figure 4-331. Summary of useful numerical equations in the Alixant's method. (Courtesy Louisiana State University [124].)

At n~ = V , h * At,h + V n~ * A t V~h + Vm~ where At = Vh= At~h = Vma = At = = Atmf =

ma

(4-259)

transit time of the sonic wave in Ils/ft volume of shale in fraction transit time in the shale in m s / f t volume of rock matrix in fraction transit time in the rock matrix Ils/ft porosity in fraction transit time in the m u d filtrate in Ils/ft

Equation 4-258 gives better results in most formations, particularly in unconsolidated formations. Both of these equations show a variation of the transit time with the porosity. Since the porosity increases in overpressured zones, the transit time increases. Figure 4-333 shows a typical plot for the shale formations of a well in Jefferson County, Texas.

Demonstration. A normal compaction trend can be seen down to 9,000 ft, then the overpressured zone is clearly outlined. At 12,000 ft the difference between the extrapolated normal trend transit time Ath" and the measured transit time At h is At h - Atsh" = 39 g s / f t The empirical correlation of H o t t m a n a n d J o h n s o n of Figure 4-334 can be used [101].

1054

Drilling and Well Completions

-3000

,I M W

il

-4000'

l LL.

KICI(

-5000'

-6000'

"1

w

i

'-n

1

¢1)

-7000'

-8000

-9000

WFT'S

4-

+

-10000 8

10

12

14

16

Pore Pressure Gradient, PPG

Figure 4-332. Pore pressure evaluation in a North Sea well. (Courtesy Louisiana State University [124].) The formation pressure gradient corresponding to the difference of transit times is 0.93 psi/ft. The formation pressure is 0.93 x 12,000 = 11,160 psi With the availability of the MWD/LWD drilling parameters, gamma ray resistivity, neutron-density Pe, a global approach of interpretation has been implemented by Anadrill when all measurements have been made in a given strata. A particular strata is first analyzed with the drilling data for a "pressure at the bit" estimate. Then, it is reanalyzed later when gamma ray resistivity data

MWD a n d LWD

1055

SHALE INTERNAL TRANSIT TIME (10-6S/FT.', 70 80 90 100 120 140 160 180 200 0

~o=0.33 ~ .

2,000

~

/

":'. 6,000 ub-

-rI-13. LU a 8,000

10,000

1 2 , 0 0 0 ft.

12,000

/[

) 05

.t

14,000

Figure 4-333. Example of sonic log data collected in the shale formations of a well in Jefferson County, Texas. (Courtesy SPE [101].) b e c o m e available. The full global p r o g r a m is i m p l e m e n t e d still later when the neutron-density Pe d a t a also b e c o m e available. The global technique used for pressure d e t e r m i n a t i o n is similar to that used for wireline log interpretation. The various volumes o f rock matrix, shale, porosity, overpressure porosity and hydrocarbons are used to c o m p u t e the various tool responses according to a model. T h e r e s p o n s e s are c o m p a r e d to the m e a s u r e d values a n d a v o l u m e optimization is made to minimize the errors g r o u p e d in an incoherence function. T h e value o f the i n c o h e r e n c e function for the best fit d e t e r m i n e s the quality o f the answer. Figure 4-335 is an example o f formation pressure calculation as well as f o r m a t i o n evaluation for lithology and fluid content.

1056

Drilling and Well C o m p l e t i o n s

0.450 0.500

m

\

0.600

W

v

I..Z ILl c~ 0.700 m

\

\

laJ oc ¢/3 0 . 8 0 0 oo I,U n,.

LU nO 0.900

1.000 0

20

40

60

SHALE INTERVAL TRANSIT TIME DIFFERENTIAL

(tsh -tsh n )

, (IO'6S/FT)

Figure 4-334. Empirical correlations between shale transit time and the pore pressure in the Gulf Coast. (Courtesy SPE [101].)

A standard e r r o r on the f o r m a t i o n pressure of_+1.8 l b / g a l (_+216 k g / m s) can be seen clearly on the figure for the lower 55 ft when only f o r m a t i o n strength data are available. For the next 38 ft, when resistivity and g a m m a ray b e c o m e available, the standard e r r o r is _+0.9 I b / g a l (_+108 kg,/m3), to reach _+0.35 I b / g a l (_+43 k g / m s) when all m e a s u r e m e n t s are available.

Abnormal Formation Pressure Detection with Mud Logging Parameters. The main p a r a m e t e r used in m u d logging for a b n o r m a l pressure detection is the shale cutting bulk density. Four techniques are commonly used:

MWD a n d LWD

1057

<== N,Dens, Pe

<== Gr, R

<== ROP, RPM WOB, TOR

Figure 4-335. Computations of the formation pressure, lithology, and fluid content made with MWD formation-strength, LWD resistivity, gamma ray, neutron, and density measurements. (Courtesy Anadri//[113].)

1058 • • • •

Drilling and Well C o m p l e t i o n s m e r c u r y p u m p technique m u d balance variable density column microsol scale

In the mercury pump technique, the volume o f a 25-g sample o f shale is obtained by pressuring a chamber to 24 psig with and without the shale sample. In the mud balance technique, shale cuttings are a d d e d in the mud balance cup until they weigh the equivalent o f a cup o f water. The volume o f shale can be expressed as

V h : P__.z_~.V~ P~h where V h = pw = P~h = V :

(4-260)

volume o f shale density o f water density o f shale cup volume

A d d i n g water to fill the cup and m e a s u r i n g the density o f the mixture gives V sh

Pm= Psh " - ~ f ' + Pw "

(Vc - V sh )

V¢

(4-261)

Substituting Equation 4-260 into 4-261 gives

Psh = 20 w _ Pm

(4-262)

A third technique used a variable density column. The variable density column is obtained by mixing gently a dense liquid, generally bromoform (density = 2.85 g / cm ~) with a light solvent, for example trichlorethane in a g r a d u a t e d cylinder. Calibration density beads are placed in the column for calibration. Shale cuttings are i n t r o d u c e d carefully. They float at a level c o r r e s p o n d i n g to their density. T h e microsol scale technique is used to weigh a shale sample out o f and in water, thus giving weight a n d volume. T h e results are plotted versus depth. Low shale d e n s i t i e s (high p o r o s i t y f i l l e d with water) i n d i c a t e o v e r p r e s s u r e d zone. A d e m o n s t r a t i o n example is shown in Figure 4-336.

Demonstration. T h e transition zone is clearly indicated at 12,000 ft. T h e t r e n d line is d e t e r m i n e d as an exponential function. T h e difference between the trend line value (2.48 g / c m 3) and the m e a s u r e d value (2.28 g / c m 3) at 13,000 ft can be c o r r e l a t e d to the formation pressure g r a d i e n t using the empirical correlation curve established by Boatman a n d shown in Figure 4-337 [101]. T h e f o r m a t i o n pressure g r a d i e n t c o r r e s p o n d i n g to the density difference o f 0.2 g / c m 3 is 0.86. The f o r m a t i o n pressure is Pp = 0.86 × 13,000 = 11,180 psi T h e shape of the shale cuttings also gives a q u a l i t a t i v e e v a l u a t i o n o f the formation pressure. The cuttings are larger and m o r e angular than normal. They

MWD and LWD

1.8

0

SHALEDENSITY,Psh,(g/cm3) 2.0 2.2 2.4

2000

2.6

1059

2.8

5_.O.52e-O.OOOOSSD m

4000 6000 "t-

8000

,

10,000 12,000 13,000ft. 14,000

~ C ~ "28 . i TransitiOnzone 2.48

16,000 Figure 4-336. Example of shale cutting density plot. (Courtesy SPE [101].)

appear to be "exploded" into the borehole. Less crushing by the bit occurs as they rapidly leave the bit region. The gas content of the mud is also an overpressure indicator. The background gas level (liberated and recycled gas) increases when drilling shales in underbalanced conditions. The connection gas (produced during connection when the bottomhole pressure decreases due to stopping the mud circulation, and working the drillstring) increases in underbalanced conditions. Finally, the trip gas (gas entering the mud column when the drillstring is out of the hole) also increases in underbalanced conditions. Bit swabbing may accentuate the increase. Background, connection, and trip gas increase are indications that previously drilled zones are underbalanced and absolute control should be established before a trip is attempted.

1060

Drilling a n d Well Completions

0.5 ,..->. 0,3 v

I-Z LI,J

LI,J t't"

0.6

0.7

O3 O3 " ' t't"

0.8

Z 0

.~ 0.9 L~

1.0

0

0.1

0.2

0.3

0.4

0.5

0.6

SHALE DENSITY DIFFERENCE(Pshn-Psh),(g/cm 3) Figure 4-337. Boatman correlation between formation pressure gradient and bulk density of shale cuttings. (Courtesy SPE [101].) Flowline temperature is also an overpressure indicator. In overpressured zones the formation temperature increases. The flow line temperature gradient (increase in temperature per 100 ft) can increase by 2 ° to 10° over the normal gradient. However, other effects (salt domes, lithology changes) may also cause gradient changes. Salinity reversals or decrease of the formation b r i n e salinity with depth are generally associated with overpressured formations. The m u d salinity or chloride content reflects the formation water salinity if there is a close control over the m u d properties a n d analyses. Abnormal Formation Pressure Detection from Kicks. T h e kicks, or flow of formation fluids into the borehole, are the ultimate indication that the well has e n c o u n t e r e d an overpressured zone. Kick detection d u r i n g drilling usually is achieved by use of a pit-volume indicator a n d / o r a flow indicator. The usual pitvolume alert is 10 barrels drilling fluid volume increase. A differential mud flow indicator can also be used to detect kicks more quickly. Kick detection while tripping is done by monitoring the volume of m u d added to keep the hole full. If the volume required to fill the hole is less than the volume of pipe removed, a kick may be in progress. When a kick is detected while drilling or while tripping, well control operations should be started immediately.

Example 24: Overpreasure Detection with Rate of Penetration T h e m u d l o g g i n g log r e c o r d e d in a well of the G u l f Coast is shown in Figure 4-338.

MWD a n d LWD

1061

~ Y l k l C : A L. P~NIItUATtO~ |. . . coo~JmY.

.

.

.

. NOUt sa~

!

f..,~

milcalo

t

~L~.,~'-,.TO~,, .

'

0

U

N

T

/

'

~

S'rAT!

t

d

.,--,.-o.,..~f - - T o - . . ~ - ~ , ~

• ~

TO J m °

'

TO - . ~

N

s'rAmrlo ~

AT.

Imm

Pmlr

i..."~,"r I ~ p's'.~

s,OOaato ..,t

k,.'WqILLFOtll"r'~

~ T~

~

mint ~ o . ~ . ~ 'It'.

Figure 4-338. Example of mud log for interpreting ROP in terms of formation pressure. (Courtesy The Analysts, now Anadrill.)

1062

Drilling a n d Well C o m p l e t i o n s

T h e hole has b e e n d r i l l e d with a 12 ¼-in. bit and approximately 25,000 lb weight down to 8,685 ft. T h e n a 8½-in. bit was used with 17,000 lb weight to TD. Bit r p m was approximately constant a n d equal to 100 r p m for the whole section. T h e n o r m a l hydrostatic g r a d i e n t for the area, G H, is 8.4 l b / g a l . T h e m u d weight MW is shown on the log. T h e o v e r b u r d e n g r a d i e n t for the area Gob is 1 psi/ft. [Note: 1 g / c m ~ = 62.4 l b / f t ~ = 8.345 l b / g a l = 0.433 psi/ft] 1. C o m p u t e the d-exponent c o r r e c t e d for m u d weight assuming that ECD = MW + 0.5 l b / g a l

2. 3.

4. 5. 6. 7.

for the d e p t h s listed in the first column o f Table 4-135 (average ROP for + 10 ft at each depth). Plot the d values versus d e p t h on the g r a p h as in Figure 4-339. Mark the slow shale points with a dot (°) and the fast sand points with a cross (x). Plot the n o r m a l shale t r e n d a n d d e t e r m i n e the top o f the high pressure zone if any. Is the sand at 8850 ft high pressured? Will it p r o d u c e hydrocarbons? Why? Compute the formation pressure gradient and formation pressure at 8,460 ft using the d - e x p o n e n t technique. C o m p u t e the f r a c t u r a t i o n pressure g r a d i e n t and f r a c t u r a t i o n pressure at 8,460 ft assuming a Poisson ratio o f 0.4. C o m p u t e the formation pressure gradient and fracturation pressure at 8,800 ft using the d - e x p o n e n t technique. Why was a casing set at 8,680 ft? C o m p u t e the formation pressure o f the formation at 8,400 to 8,450 ft. Will it b e a h y d r o c a r b o n p r o d u c e r ? Do we have enough i n f o r m a t i o n to know if it will p r o d u c e oil or gas?

Solution 1. See Table 4-135: in / dc

ROP 60 • RPM J

=

ln(

1 2 - WOB

GH ECD *

2. See g r a p h in Figure 4-339. 3. Top o f high pressure zone at 8,500 ft; dc decreases, yes sand is high pressured; no, because no gas and no fluorescence. 4. d c = d c a ; Gfp = 8.4 l b / g a l ; FP = 3,695 psig 5. K Is = 0.667; GOB = 19.27 l b / g a l ; G FRAC = 15.65 l b / g a l ; Pci r a c = 6,885 psig. . 6. d c = 0.673; d n = 1.00; G.. I p = 11.9 lb/gal; FP =. 5,445 psig. To avoid fracturing . . . o p e n h o l e above when increasing m u d weight m high pressure zone. 7. dc = dcn; above and below zone, no overpressure. FP = 3,680 psig at 8,425 ft. Yes, it will produce HC because gas show in mud. Oil because oil in cuttings, fluorescence.

Example 25: Overpressure Detection with Rate of Penetration T h e data in the first six columns o f Table 4-136 were taken in a m u d logging log o f a South Louisiana well.

MWD and LWD

1063

Table 4-135 d= Exponent Calculation Table FlOP

Z ft 8020 8060 8220 8260 8330 8420 8500 8600] 8680

rpm 70 600 65 900 6O 800 50 70

872~i

120 120

8800 8850

110 500

100 100 100 100 100 100 100 100 100 100 100 100

WOB D 250001 25000! 25000 25000 25000 25000 250001

250001 25000 17000 17000 17000

ECD

GH

11 11 11 11 11 11 11.2 11.8 12.8 13 13.3 13.3

8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4

12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 8.5 8.5 8.5

)dc 0.9163 0.474 0.9315 0.3905 0.948 0.4148 0.968 0.8542 0.6921 0.8777 0.6772 0.4208

dc exp

8000

0.3

0.5

0.7

0.9

.4-

8200

8400 Z

/

ft

8600

J 8800

I

Jl

-•

I

sandstone

shale

9000 Figure 4-339. D - e x p o n e n t g r a p h : ( a ) g r i d ; ( b ) p l o t o f t h e r e s u l t s .

1064

Drilling and Well Completions

Table 4-136 d-Exponent and de-Exponent Corrected Calculation Table Depth Hole size ROP WCO (ft) (in) (ft/hr) (1000 4000 12 126.1 5000 9.875 49.4 6000 9.875 53.7 7000 9.875 16.7 8000 9.875 60.1 9000 9.875 77.6 1OOOO 9.875 15.7 11000 9.875 27.6 12000 6.5 15.9 13000 8.5 33.1 14000 6.5 54.6 15000 6.5 5.3

]Mud W. {(Ib/gal)

~RPM Ibs I (rprn) 120 110 100 70

5O 4O 4O 3O 55

d-exp

9.5

9.5

60

140 150

9.5 9.5 9.5 9.7

5O 5O 3O 35 3O 15

100 80 80 100 100 50

9.7 10 12 12.2 12.3 12.3

Id-exp.cor 1.35 1.62 1.56 1.87

1.18 1.41

1.s3 1.82

1.36 1.46 1.s9 1.s5

2.12 1.84 1.97 1.90 1.82 1.77

1.82 1.53 1.38 1.30 1,:11 1.21

1. Compute the d-exponent and d-exponent corrected in the last two columns of Table 4-136. 2. Plot the penetration rate, d-exponent, and d-exponent corrected versus depth. 3. C o m p u t e the pore pressure at 15,000 ft using Eaton's equation, a n o r m a l gradient of 0.453 psi/ft, a n d an overburden gradient of 1 psi/ft assuming the well vertical. 4. Should the m u d weight be increased? Solution

1. 2. 3. 4.

The d-exponent and d-exponent corrected have been computed in Table 4-136. T h e plot of the results are shown in Figure 4-340. At 15,000 ft: d = 2.08; d c = 1.2; Po/Z v = 0.729 psi/ft; P = 10,937 psi. should be Equivalent m u dc" weight: 14 l b / g a l : The m u d specific weight P" increased to 14.5 l b / g a l to avoid a kick in the next permeable zone.

Example

26: Overpressure

Detection

with Shale

Resistivity

T h e data of Figure 4-341 was taken from the log of a H u m b l e Oil a n d Refining Co. well in Pecan Island, Louisiana. 1. Compute the formation pressure at 15,000 and 18,000 ft assuming a normal gradient of 0.465 psi/ft, an overburden gradient of 1 p s i / f t and a vertical well. (Use Eaton's equation). 2. What m u d weight should be used for drilling at 15,000 a n d 18,000 ft? 3. What will be the danger uphole if casing is not set a r o u n d 12,000 ft? Solution

1. The top of the overpressure zone is a r o u n d 13,000 ft. 15,000 ft: Rshn = 1.35; Rsh = 0.6 fl ° m Pp/Z v = 0.797 psi/ft; Pp = 11,955 psi

MWD and LWD

\

4000

1065

\

P \

[]

\ 6000

8000

I

k'~

~

.\

[] d-exp • d-expcorr ,.E:

•'-'

~, ,\

10000

/ 12000

14000

I"1

/

[]

\

/

-"

/

I

v' /

,

/ k ¢ • / []•

/

/ m I

•

I

'

• []

,

•

I 16000 1.0

1.2

1.4

I 1.6

1.8

2.0

2.2

d-exp Figure 4-340. D-exponent graph: (a) grid; (b) plot of the d-exponent and of the d-exponent corrected.

18,000 ft: Rsh n = 1 . 6 7 ;

R h = 0.6 ~"

m

P p / Z = 0.842 psi/ft; Pp = 15,180 psi 2. 15,000 ft: 0.797 psi/ft = 15.36 lb/gal. Recommended mud weight = 15.86 lb/gal. 18,000 ft: 0.842 psi/ft = 16.23 lb/gal. Recommended mud weight = 17.73 lb/gal. 3. The formation may fracture uphole.

1066

Drilling and Well Completions

I ,11 I

HUMBLE OIL & REFINING COMPANY PECAN ISLAND VERMILION PARISH, LOUISIANA EQUATIONOFTHE NORMALTREND RSH = AxEXP(BxDEPTH) A = 0.475854 B=O.O00070

10

12

TOPOFGEOPRESSI.

I--, 14

16

18

20

22

10-1

2

3

4

5 6 7 8 9 100

2

3

4

5 6 7 8 910

SHALE RESISTIVITY(RSH)OHM-METER Figure 4-341. Plot of the resistivity of shales versus depth in a Gulf C o a s t land well (Louisiana).

Example 27: Overpressure Detection with Shale Resistivity A shale resistivity plot versus depth is shown in Figure 4-342 has been prepared with electric log data for a well drilled in south Louisiana.

MWD a n d LWD

1067

1. Estimate the depth of the top of the overpressured zone. 2. C o m p u t e the pore pressure using Eaton's equations, assuming a n o r m a l gradient of 0.465 psi/ft, an overburden gradient of 1 psi/ft at 14,000 ft a n d a vertical well.

Solution 1. Probable top of overpressure: 12,800 ft. 2. Rshn = 1; R h = 0.7; Pp/Z v = 0.651 psi/ft; Pp = 9.114 psi.

Drilling Safety, Kick Alert The safety priority at the well site must be given to personnel safety. The utmost care must be given to avoid casualties a n d injuries. The second priority is e q u i p m e n t safety. Breakdowns, fishing, a n d lost hole must be avoided or at least minimized.

Personnel Safety The greatest danger is u n c o n t r o l l e d kick or blowout. W h e n m u d logging, MWD a n d LWD can play a major role to improve safety by p r e v e n t i n g or minimizing the danger of kicks a n d blowouts. The conventional kick detection is done with the mud pit level measurement. The alert is generally given for a pit gain of 5 or 10 barrels. A n o t h e r system is the differential mud flowrate measurement. If the difference outflow rate minus inflow rate increases, fluid is entering the borehole. These techniques will work for gas, oil, or water inflow with any types of mud, water-base or oil-base. For gas inflow in oil-base mud, large amounts of gas go into solution at high pressures a n d reduce the flowrate increase. The change is less important, if detectable, with oil or water entry. The gas in solution in oilbase m u d cannot be detected easily. The latest a n d most promising e q u i p m e n t is the kick alert (AnadriU). Figure 4-343 shows a schematic of "Kick Alert." The kick alert detects the free gas over the whole a n n u l u s length by comparing the p u m p noise in the standpipe to the p u m p noise picked up a few feet below the flowline. The phase shift is correlated to the a n n u l u s sonic velocity, itself a function of the free gas. The operational constraints are • • • • •

p u m p s must be operating; m u d level must cover the a n n u l u s transducer; only gas influxes are detected; it works in water-base or oil-base muds; gas may be entering anywhere.

A n o t h e r i m p o r t a n t feature of m u d logging a n d MWD/LWD, is the capability of overpressure zone detection. As was discussed previously in this section, overpressure estimates can be d o n e d u r i n g d r i l l i n g with many t e c h n i q u e s a n d accuracy increases with the n u m b e r of parameters available. Drilling operations will never be 100% safe for the personnel but the various techniques available in mud logging, MWD a n d LWD greatly improve the safety on the drill site. (text continued on page 1070)

1068

Drilling and Well Completions

~I:~ 10

I---

~-12

14

16

18

20

10-1

2

3

4

5

6 78910o

2

3

4

5

6 78910

SHALERESISTIVITY(RSH) OHM-METER Figure 4-342. Plot of the resistivity of shales versus depth in a Gulf Coast land well (Louisiana).

MWD and LWD

How the Kic~eR Service Detects Gas Influxes

T~

SWna~ ~,e~ure

(SP~ ~

m ~ ~ m p ~ec~r~ wave ~ e Annulus presSUt~~ n ~

at $ ~

(AP~ ~s~

be~w ~ w ~ne de~ec~ wave p h ~

a~

end o~ round-~.

wave

Lf)is ~ e ~ n ~

~ ga$4~e~ mud~~ e n

~om

~ n ~ ~ve| ~me

Figure 4-343. Schematic of the "Kick Alert" system of Anadrill. (Courtesy

Anadrill [113].)

1069

1070

Drilling and Well C o m p l e t i o n s

(text continued from page 1067)

Equipment Safety. The greatest risk for the equipment is sticking the drillstring. Before MWD, the drilling p e r s o n n e l had to rely on surface m e a s u r e m e n t s only. The drilling p a r a m e t e r s can now be m e a s u r e d practically "at the bit." Calculations of drag and friction can be c a r r i e d out in real-time alerting the driller of any danger of p i p e sticking. Downhole flowrate m e a s u r e m e n t s indicate drillstring washouts before the drillstring breaks and, consequently, avoiding expensive and dangerous fishing. Bit efficiency calculated in real time gives an indication that the drill bit is d a m a g e d and that cones may be lost. Downhole v i b r a t i o n and shock measurements are also valuable indicators used to avoid d a m a g i n g the drillstring. All of these MWD measurements are definitively improving safety, minimizing breakdowns and making drilling m o r e efficient. Horizontal Drilling, Geosteering To attain higher performances, the oil and gas companies are demanding greater drilfing efficiency in conditions such as extended reach and horizontal drilling. The improved production and return on investment can be achieved from fewer wells, but better quality wells. Figures 4-344 and 4-345 show the theoretical vertical profile for a buildup to horizontal with respectively 1°/10 m (3°/100 ft) and 2°/10 m (6°/ 100 ft). In the first case, the distance below kick-off point (KOP) to reach horizontal is 570 m (2,870 ft) TVD, with a measured depth of 900 m (2,952 ft). In the second case, the corresponding lengths are 290 m (951 ft) and 450 m (1,476 ft). To follow accurately the theoretical trajectory, MWD techniques must be used. W h e n the borehole is near horizontal, logging or surveying tools cannot be lowered by gravity anymore. T h e y must be p u m p e d down the drillpipes for directional measurements. Conventional logging has to be carried out by conveying the logging sondes downhole at the tip of the drillstring. The logging operation becomes long, expensive and dangerous. A much more efficient way is to survey the trajectory and record the logs while drilling. The logging data can be used to ascertain that the borehole is being drilled in the anticipated pay zone. If not, immediate remedial action is taken to "steer" the well towards the pay zone. The most advanced technique in use today is the "geosteering" technique. G e o s t e e r i n g is usually d o n e with a m u d motor. A m u d m o t o r with bent sub allows changing of orientation and inclination without pulling the drillstring out. Steering is done by rotating it a small angle. In classical geosteering the sensors for inclination, azimuth, drilling parameters, and logging are located above the m u d m o t o r and the distances may be in the o r d e r of those shown in Figure 4-296 that is 30 ft or m o r e above the drill bit. A l t h o u g h radial m e a s u r e m e n t s can be p e r f o r m e d to verify that the borehole is being drilled in the pay zone, it is often too late to make a correction and the borehole leaves the pay zone. The new geosteering system offers measurements "at the bit" (below the m u d motor) of inclination, rpm, azimuthal g a m m a ray, azimuthal resistivity, and bit resistivity as seen in Figure 4-298. The signals are transmitted electromagnetically to the MWD sub located above the mud motor, then relayed to surface with the s t a n d a r d m u d pressure transmission system. To summarize, the following is r e c o r d e d just above the drill bit: • inclination • revolution p e r minute

MWD a n d LWD

1071

• azimuthal g a m m a ray • azimuthal resistivity • bit resistivity Above the m u d motor, the following is recorded:

• • • • • •

weight-on-bit torque inclination azimuth~ tool face neutron density

•

Pe

•

O t h e r parameters, such as alternator voltage (for flowrate), temperature and pressure, can also be monitored. A frame of 16 words of i n f o r m a t i o n can be u p d a t e d in 27 s at a rate of 6 bits/s. Even at 100 f t / h r of drilling rate (never reached in horizontal drilling), u p d a t i n g would occur every 0.75 ft. A n example of three horizontal wells drilled in a 2 m (6 ft) in the North Sea is shown in Figure 4-346. Well No. 1 was drilled with inclination and azimuth data only. The sensors were located above the m u d motor. Only a short section (63 m; 207 ft) was drilled in the reservoir. Well No. 2 was "geologically" steered by adding g a m m a ray a n d resistivity capability. Only a short section is out of the reservoir, making a total of 168 m (552 ft) in the reservoir. Well No. 3 was steered with the new geosteering system. A smooth trajectory was o b t a i n e d with the whole interval in the reservoir. T h e last section was dipped intentionally to investigate the lower reservoir. We see that horizontal drilling can be carried out satisfactorily if the following is available: • sophisticated M W D / L W D technology • c o m p u t e r capability • positive displacement motor Suggestions have b e e n made recently to drill horizontal branches in the horizontal p o r t i o n of the h o r i z o n t a l wells. If this t e c h n i q u e is developed, the drainage capacity of horizontal wells will be even better.

Types of Directional Drilling Horizontal drilling is performed using "long radius" of curvature to reach horizontal: 1 to 2 ° / 1 0 m (3 to 6 ° / 1 0 0 ft). Attempts have b e e n made for years to improve p r o d u c t i o n with medium, short and ultrashort radius of curvature. The sketch of Figure 4-347 shows the four types of curvatures [127]. Table 4-137 gives the range of values of radius, angle change with depth, and usual horizontal lengths drilled in each case. Ultrashort radius wells are usually called "drainholes." They are drilled with special e q u i p m e n t a n d c o m p l e t e d with 1 1 to 2 ~-in. t u b i n g . T h e t u b i n g is

1072

Drilling and Well C o m p l e t i o n s

Displacement 1000

2000

Rate

of

(ft)

3000

Buildup:

4000

3°/100

!

!

1000

~°

o

i

o

°I

(2°/m)

I

,.Measured • Depth

i o

it

i

i

¢:

5000

oi

i o

°~,

6000

!

(ft)

I

o

i

'

o

°

............. ~.......~...j ........... ~ o....?.....~..~.............. ~........~..

2000

,.-

/ i

80°.,,,'~

~,o,: ;

3000

i

~

,

i/

Depth

(ft) 4000 p"

i i

I

I

/

5000 Oa

.i

s

• /

6000

/ i1 i

t

l [ i

2;2: 7000

"=:

i

.! i I

Figure 4-344. Theoretical vertical profile for a buildup rate of 1°/10 m (3°/100 ft) for a well reaching horizontal. (Courtesy Inst. Fr. du Petr.)

p e r f o r a t e d and severed where it reached the main vertical hole. No MWD or LWD o p e r a t i o n s are carried out in these drainholes. Short radius wells are usually drilled f r o m a cased or uncased vertical well. Articulated drill collars are used to drill to 90 ° or beyond. A second stabilized assembly is used to drill the rest o f the hole, usually in 4 ~ or 6 ~-in. diameter.

MWD and LWD Displacement 0

1000

0

2000

i

(ft)

3000

4000

5000

!

•

I

1 0 0 0 ...... " I ~ , ~ ~ , . ~ . . . . ~ . ~ _ i i ! ~ ~ 2 " ' ~ • •i..................... • ~ .........

2000 ..... :"~"i ~ .............' ~ ........"~ ~ ' " " ~ ,

3000

t

i

6000

Meaaured • ~Depth~ (ft) i~

..L

.........I.................T'"'-"I..............

s

" /

• i!

"

.\-\ \.NI

.,'N i\,'

"

)~"i•'""90i°'"'•~•"l"

................~ i

/"

1073

70 "

I

I ;

i~0o,

Depth (ft)

4000 .............. @

5ooo,

6000

7000

.................. ~.......~.....-....'..~......-.~-,'oo..:.+

. -

~._-~ ..... \ ~ .... ; I

---=~i ';/

\o

.

el

+

............... ...N

~

.~\~ ,i

~3° i \ i I, ":" i

..X,

iI

......

\

'

~ o ,o,: +...~ ~ ...!......X..~ .....,n~,.....,,o ................... ~=;~ IV1 ....... i...........~ __.~---~: I\ .! i \I. ~

!

I

i 1 l-L2i, "

Rate

i

~ I

i

of Buildup:

f

i

~ \1

!

6°1100

I

I

It (2°110

i

i ..........

I

! .........

"

!

m)

I

Figure 4-345. Theoretical vertical profile for a buildup rate of 2°/10 m (6°/100 ft) for a well reaching horizontal. (Courtesy Inst. Fr. du Petr.)

N o M W D or LWD e q u i p m e n t exist to date to log these wells• However, service c o m p a n i e s are d e v e l o p i n g e q u i p m e n t for M W D p u r p o s e in 40-ft (12-m) curvature r a d i u s or 1.S°/ft (4.6O/m). T h e e q u i p m e n t consists of a r t i c u l a t e d m u d m o t o r s a n d i n c l i n a t i o n a n d a z i m u t h sensors.

Well deliberately dipped e

1.5

1

0.5 ©

o

©

(D -0.5

"(3

-1

-1.5

-2 0

0

0 CM

0 ~

0 '~r

0 ~

0 (,0

0 r...

0 co

0 o')

0 o

0 ~

0 C~I

0 c,~

0 ,~-

0 L.")

0 co

0 r...

0 co

Horizontal Section MD,m Figure 4-346. North Sea geosteering example. (Courtesy Anadrill [113].)

0 o'~

0 o

MWD a n d LWD

1075

\~,,\\

h

I ~ ~ " ' ~ -

°

',c

'

Figure 4-347. Schematics of different types of wells or drains: (a) ultrashort radius; (b) short radius; (c) medium radius; (d) long radius. (From Ref. [127].)

Table 4-137 Characteristics of Horizontal Wells (a) Metric Units Radius Ultrashort Short Medium Long

R (m)

°/10 m

L (m)

0.3-0.6 6-12 90-240 >300

-91-46 6-2.3 <2

30-60 30-240 300-1,200 300-1,200

R (ft)

°/10 ft

L (ft)

1-2 20-40 300-800 >1,000

-280-140 19-7 <6

100-200 100-800 1,000-4,000 1,000-4,000

(b) English Units Radius Ultrashort Short Medium Long

Medium radius and long radius wells are drilled with conventional oilfield tools. Both MWD a n d LWD are usable in these wells. Downhole motors are mostly used in m e d i u m radius wells to avoid fatigue o f the BHA. L o n g radius wells have b e e n d r i l l e d with b o t h m u d motors a n d rotary techniques. Air drilling operations can also be utilized for directional drilling a n d M W D / LWD technologies. Due to the absence of reliable d o w n h o l e p n e u m a t i c motors, this technology is not yet fully developed.

1076

Drilling and Well Completions

Example 28: Overpull Estimation Figure 4-348 shows the proposed trajectory of a horizontal well. The p l a n n e d m u d weight is 12 l b / g a l water base. The drillstring will be as follows: • 200 ft of drill collars: 6 ¼-in OD 2.81-in. ID weight 149 l b / f t displacement 1.537 g a l / f t • 4,000 ft of heavy drillpipes: 3.5-in. OD weight 37.7 l b / f t displacement 0.387 g a l / f t • 4,904 ft of regular drillpipes: 3.5-in. OD weight 16.57 l b / f t displacement 0.2236 g a l / f t The drag coefficient is 0.3. 1. Compute the overpull with a straight trajectory in the horizontal plan at TD. 2. Compute the overpull with the horizontal trajectory shown in Figure 4-348 at TD. Assuming that the direction change of 40 ° is at the j u n c t i o n of the regular drill pipes and heavy drill pipes. (The capstan effect will be neglected.)

Solution 1. Drill collar drag: Weight in air: 200 x 149 = 29.8 klb Displaced m u d weight: 200 x 1.537 x 12 = 3.689 klb Weight in mud: 29.8 - 3.689 = 26.11 klb Drag: 26.11 x 0.3 x sin 90 ° = 7 klb Heavy drillpipe drag: 1,804 ft horizontal Weight in air: 1,804 x 37.7 = 68 klb Displaced m u d weight: 1,804 x 0.387 x 12 = 8.378 klb Weight in mud: 59.622 klb Drag: 59.622 x 0.3 x sin 90 ° = 17.887 klb 2,196 ft at 62 ° inclination Weight in air: 2196 x 37.7 = 82.789 klb Displaced m u d weight: 2196 x 0.387 x 12 = 10.198 klb Weight in mud: 72.591 klb Drag: 72.591 x 0.3 x sin 62 ° = 19.228 klb Drillpipe drag: 3,904 ft at 62 ° (includes buildup) Weight in air: 3904 x 16.37 = 63.908 klb Displaced m u d weight: 3904 x 0.2236 x 12 = 10.475 klb Weight in mud: 53.433 klb Drag: 53.433 x 0.3 x sin 62 ° = 14.153 klb Total drag (overpull) = 7 + 17.887 + 19.228 + 14.153 = 58.268 klb 2. Forces due to drag below the direction change: 7 + 17.887 + 19.228 = 44.115 klb

MWD and LWD

)tOPJZ~T~C_~L~ Scale 1" = 1000' 1000 0 ~ 0

TESTER OIL COMPANY Double Build wlth Turn Example

2000

1077

N 1000

500 1000 -

PLANE OF PROPOSAL 197.3"

1500

- 2000

VERTICAL SECTION Scale 1" = 1000' 0 -

- 2500 - 3000

818 1000

/

0'818 M.D. Start build 1 at 2.5"/100ft

~

k 2000

\

2841 300C

~'~

-

- 4000 . i 4500

i

3298 M.D. Hold

0

3965 4000 -

3500

5500

-

" " ~ 62' 5691 M,D. Start Turn at 4,11"/100ft DLS

~2"

4388 4510

4386'

6592 M.D. Staff build ~ 5.5"/100ff DIS 90" 7100 M.D. Horizontal 9104 M.D. 200Oft dralnhole

500C

0

I 1000

I 2000

I 3000

I 4000

I 5000

I 6000

I 7000

F i g u r e 4 - 3 4 8 . P r o p o s e d t r a j e c t o r y of a h o r i z o n t a l well.

Force acting on the dog leg (approx.) = 2 x 44.115 x cos ((180 - 4 0 ) / 2 ) = 30.176 klb Drag due to dog leg force: 30.176 x 0.3 = 9.052 klb Total d r a g (overpull): 58.268 + 9.052 = 67.32 klb Comparison

of LWD Logs with Wirellne

Logs

T h e best scientific study c o m p a r i n g the LWD logs with the wireline logs has b e e n d o n e in the f r a m e w o r k o f a p r o j e c t s p o n s o r e d by the oil a n d service companies in C o n o c o test facility, Kay County, O k l a h o m a in 1990. Five service companies have field tested b o t h their commercial and prototype M W D / L W D petrophysical sensors in oil-base m u d and freshwater-base m u d test

1078

Drilling and Well C o m p l e t i o n s

wells. The data recorded were compared to equivalent wireline measurements. The effect o f the rate o f penetration (ROP) on some devices was investigated. The waterbase mud well was drilled to 3.035 ft with 7 ~-in. bit. The oil-base m u d well was drilled to 2,400 ft with an 8 ¼-in. bit. Each MWD company ran a full suite o f M W D / L W D logs that were c o m p a r e d to "benchmark" wireline logs o b t a i n e d by averaging the wireline logs with the least s t a n d a r d d e v i a t i o n errors. The data have b e e n analyzed in the oil and service c o m p a n i e s [128] and at Louisiana State University (LSU) where two master o f science theses were completed utilizing this data [129,130]. The general conclusions o f the LSU studies are as follows:

Gamma Ray. A linear relationship is generally established when c o m p a r i n g LWD and wireline g a m m a ray logs. Therefore, the LWD g a m m a ray data can be used with c o n f i d e n c e as a replacement o f wireline g a m m a ray for f o r m a t i o n evaluation. F u r t h e r m o r e , LWD g a m m a ray logs generally have a b e t t e r b e d resolution than their wireline equivalent.

Resistivity. The 2-MHz LWD a m p l i t u d e and phase-shift resistivity logs match the wireline deep and m e d i u m induction very well. Excellent results are obtained when the invasion is not severe (less than 40 in. in diameter) and in formations 20 ~ ' m or less. The focused resistivity log offered by one o f the service companies is very sensitive to b o r e h o l e d i a m e t e r and can be used only in a qualitative m a n n e r in its present form. Neutron. The n e u t r o n porosity values r e c o r d e d with most tools match closely the wireline thermal neutron logs in the lower porosity ranges (under 25 porosity units). In high porosity zones, the LWD n e u t r o n porosities lie between t h e r m a l and e p i t h e r m a l wireline values. In all zones the discrepancies between LWD and wireline porosity d a t a are in the range o f one to five porosity units. Thus, the LWD n e u t r o n data are suitable for f o r m a t i o n evaluation.

Density. The best data are o b t a i n e d with stabilizer-type tools. In g o o d b o r e h o l e sections, a close match between the LWD data and the wireline data was found. Discrepancies o f less than 0.05 g / c m 3 were generally noticed. Washouts, rugosity, and drillstring wobbling (or vibration) will affect the LWD density readings. However, the LWD density d a t a are generally suitable for f o r m a t i o n evaluation. Photoelectric Effect (Pe). Only one service company was offering a commercial Pe log. The readings o f the LWD tool were very sensitive to washouts. For a qualitative lithology identification o f the strata, the LWD Pe curve is satisfactory. In conclusion, the logs available now with LWD are perfectly suitable for a g o o d basic f o r m a t i o n evaluation in all types o f formations. It should be possible to complete a well successfully with LWD data alone in most instances. Comparison of MWD Data with Other Drilling Data Before MWD, most drilling data were r e c o r d e d at the surface. Mud logging data, the only downhole data, were available with a time delay c o r r e s p o n d i n g to the time required by the m u d to reach the surface.

Directional Drilling

1079

D r i l l i n g surface data such as weight-on-bit a n d t o r q u e were difficult to interpret because they were loosely related to downhole values. MWD for the first time in the history of drilling gives values of parameters measured at the bit or close by. Rock strength, bit wear, drag and friction can be calculated in real time. Shocks, temperature and pressure can also be measured. Sophisticated programs and codes are now available to interpret all these data in real time. The result is a more efficient and safer drilling process.

DIRECTIONAL DRILLING Glossary of Terms Used in Directional Drilling The glossary of terms used in directional drilling [131] has been developed by the API Subcommittee on Controlled Deviation Drilling u n d e r the jurisdiction of the American Petroleum Institute Production Department's Executive Committee on Drilling and Production Practice. The most frequently used terms are listed below. Angle of b u i l d u p Rate of change (°//100 ft) of the inclination angle in the section of the hole where the inclination from the vertical is increasing. Angle drop-off Rate of change (°/100 ft) of the inclination angle in the section of the wellbore that is decreasing toward vertical. Angle of i n c l i n a t i o n (angle of drift) The angle, in degrees, taken at one or at several points of variation from the vertical as revealed by a deviation survey; sometimes called the inclination or angle of deviation. A n g l e of twist The azimuth change through which the drillstring must be turned to offset the twist caused by the reactive torque of the downhole motor. Anisotropic formation t h e o r y Stratified or anisotropic formations are assumed to possess different drillabilities parallel and n o r m a l to the b e d d i n g planes with the result that the bit does not drill in the direction of the resultant force. A z i m u t h Direction of a course measured in a clockwise direction from 0 ° to 360 ° as North; also bearing. Back-torque Torque on a drillstring causing a twisting of the string. Bent sub Sub used on top of a downhole motor to give a nonstraight bottom assembly. O n e of the c o n n e c t i n g threads is machined at an angle to the axis of the body of the sub. Big-eyed bit Drill bit with one large-sized j e t nozzle, used for j e t deflection. Bit stabilization Refers to stabilization of the downhole assembly near the bit; a stabilized bit is forced to rotate a r o u n d its own axis. Borehole direction Refers to the azimuth in which the borehole is heading. Borehole d i r e c t i o n a l survey Refers to the m e a s u r e m e n t s of the inclinations, azimuths and specified depths of the stations through a section of borehole. Bottom-hole assembly (BHA) Assembly composed of the rock bit, stabilizers, reamers, drill collars, subs, etc., used at the bottom of the drillstring. Bottomhole location Position of the bottom of the hole with respect to some k n o w n surface location. Bottomhole o r i e n t a t i o n sub (BHO) A sub in which a free-floating ball rolls to the low side and opens a port indicating an orientation position. B u i l d - a n d - h o l d wellbore A wellbore c o n f i g u r a t i o n where the i n c l i n a t i o n is increased to some terminal angle of inclination and m a i n t a i n e d at that angle to the specified target. B u i l d u p That p o r t i o n of the hole in which the inclination angle is increased.

1080

Drilling a n d Well Completions

Clearance

Space between the outer diameter of the tool in question a n d the side of the drilled hole; the difference in the d i a m e t e r of the hole a n d the tool. C l i n o g r a p h A n i n s t r u m e n t to measure a n d record inclination. Closed traverse Term used to indicate the closeness of two surveys; one survey going in the hole a n d the second survey coming out of the hole. Corrective jetting runs Action taken with a directional j e t bit to change the direction or inclination of the borehole. Course The axis of the borehole over an interval length. Course bearing The azimuth of the course. Crooked hole Wellbore that has been inadvertently deviated from a straight hole. Crooked-hole area A n area where subsurface formations are so composed or a r r a n g e d that it is difficult to drill a straight hole. Cumulative fatigue d a m a g e The total of fatigue damage caused by repeated cyclic stresses. Deflection tools Drilling tools a n d e q u i p m e n t used to change the inclination a n d direction of the drilled wellbore. Departure Horizontal displacement of one station from a n o t h e r in an east or west direction. Deviation angle See "Angle of inclination."

Deviation Control Techniques Fulcrum technique Utilizes a b e n d i n g movement principle to create a force on the bit to counteract reaction forces that are t e n d i n g to push the bit in a given direction. Mechanical technique Utilizes bottomhole equipment which is not normally a part of the c o n v e n t i o n a l d r i l l s t r i n g to aid deviation control. This e q u i p m e n t acts to force the bit to t u r n the hole i n d i r e c t i o n a n d inclination. Packed-hole technique Utilizes the hole wall to minimize b e n d i n g of the bottomhole assembly. P e n d u l u m technique The basic principle involved is gravity or the "plumbbob effect." Directional drilling contractor A service company that supplies the special deflecting tools, BHA, survey i n s t r u m e n t s a n d a technical representative to p e r f o r m the directional drilling aspects of the operation. Direction of inclination Direction of the course. Dogleg Total curvature in the wellbore consisting of a change of inclination a n d / o r direction between two points. Dogleg severity A measure of the a m o u n t of change in the inclination a n d / or direction of a borehole; usually expressed in degrees per 100 ft of course length. Drift angle The angle between the axis of the wellbore a n d the vertical (see "Inclination"). Drainholes Several high-angle holes drilled laterally from a single wellbore into the producing zone. Drag T h e extra force n e e d e d to move the d r i l l s t r i n g r e s u l t i n g from the drillstring being in contact with the wall of the hole. Drop off The p o r t i o n of the hole in which the inclination is reduced. Goniometer A n i n s t r u m e n t for measuring angles, as in surveying. Gyroscopic survey A d i r e c t i o n a l survey c o n d u c t e d using a gyroscope for directional control, usually used where magnetic directional control cannot be obtained.

Directional Drilling

1081

.Hole c u r v a t u r e Refers to changes in inclination a n d direction of the borehote. H y d r a u l i c orienting sub Used in directional holes, with inclination greater than 6 °, to f i n d the low side of the hole. A ball falls to the low side of the sub a n d restricts an orifice, causing an increase in the circulating pressure. T h e position of the toot is then known with relation to the low side of the hole. H y d r a u l i c a l l y operated bent sub A d e f l e c t i o n sub that is activated by hydraulic pressure of the d r i l l i n g fluid. Inclination angle T h e angle of the wellbore from the vertical. Inclinometer A n i n s t r u m e n t that measures a p o s i t i o n angle of deviation from the vertical. Jet bit deflection A m e t h o d of changing the inclination angle a n d direction of the wellbore by using the washing action of a j e t nozzle at one side of the bit. Keyseat A c o n d i t i o n wherein the b o r e h o l e is a b r a d e d a n d e x t e n d e d sideways, a n d with a d i a m e t e r smaller t h a n the drill collars a n d the bit; usually caused by the tool j o i n t s on the drillpipe. K i c k o f f p o i n t (kickoff d e p t h ) T h e position in the wellbore where the inclinat i o n of the hole is first p u r p o s e l y i n c r e a s e d (KOP). Lead angle A m e t h o d of setting the direction of the wellbore in anticipation of the bit walking. Magnetic declination A n g u l a r difference, east or west, at any g e o g r a p h i c a l location, between true n o r t h or g r i d n o r t h a n d magnetic north. Magnetic survey A directional survey in which the direction is d e t e r m i n e d by a magnetic compass d e f l e c t i n g the earth's magnetic field. Measured depth Actual length of the wellbore from its surface location to any specified station. Mechanical orienting tool A device to orient d e f l e c t i n g tools without the use of subsurface surveying instruments.

Methods of orientation Direct method Magnets e m b e d d e d in the n o n m a g n e t i c drill collar are used to indicate the position of the toot face with respect to magnetic north. A picture of a n e e d l e compass p o i n t i n g to the m a g n e t s is superi m p o s e d on the picture of a compass p o i n t i n g to m a g n e t i c north. By knowing the position of the m a g n e t s in the tool, the toot can be posit i o n e d with respect to north. Indirect method A m e t h o d of o r i e n t i n g d e f l e c t i n g tools in which two survey runs are n e e d e d , o n e showing the direction of the hole a n d the o t h e r showing the position of the tool. Surface readout A device on the rig f l o o r to i n d i c a t e the subsurface position of the tool. Stoking M e t h o d of o r i e n t i n g a tool using two p i p e d a m p s , a telescope with a hair line, a n d an aligning b a r to d e t e r m i n e the orientation at each section of p i p e run in the hole. Monet (K monet) A p e r m a n e n t l y n o n m a g n e t i c alloy used in making p o r t i o n s of d o w n h o l e tools in the b o t t o m h o l e assembly (BHA) where the m a g n e t i c survey tools are placed for o b t a i n i n g magnetic direction information. Monel refers to a family of n i c k e l - c o p p e r alloys. Mud motor Usually a positive displacement or turbine-type motor. Mule s h o e A s h a p e d form used on the b o t t o m of o r i e n t i n g tools to position the t o o l T h e shape resembles a mule shoe or the end of a p i p e that has b e e n cut b o t h diagonally a n d concave. T h e s h a p e d e n d forms a wedge to rotate the toot when lowered into a m a t i n g seat for the mute shoe.

1082

Drilling a n d Well C o m p l e t i o n s

Multishot survey A d i r e c t i o n a l survey in which m u l t i p l e d a t a p o i n t s are r e c o r d e d with one trip into the wellbore. Data are usually r e c o r d e d on rolls o f film. Near-bit stabilizer A stabilizer placed in the b o t t o m h o l e assembly j u s t above the bit. O u i j a b o a r d ® (registered t r a d e m a r k o f Eastern Whipstock) A n i n s t r u m e n t c o m p o s e d o f two protractors a n d a straight scale that is used to d e t e r m i n e the p o s i t i o n i n g for a d e f l e c t i n g tool in an inclined wellbore. Permissible dogleg A dogleg through which e q u i p m e n t a n d / o r tubulars can be o p e r a t e d without failure. Pendulum effect Refers to t h e pull o f g r a v i t y on a body; t e n d e n c y o f a p e n d u l u m to r e t u r n to a vertical position. Pendulum hookup A bit a n d drill collar with a stabilizer to attain the maximum effect o f the p e n d u l u m . Rat hole A hole that is d r i l l e d ahead o f the main wellbore a n d which is o f a smaller d i a m e t e r than the bit in the main borehole. Reamer A tool employed to smooth the wall of a wellbore, enlarge the hole, stabilize the bit a n d straighten the wellbore where kinks a n d a b r u p t doglegs are encountered. Rebel tool® (registered t r a d e m a r k o f Eastman Whipstock) A tool d e s i g n e d to prevent a n d c o r r e c t lateral drift (walk) o f the bit tool. It consists o f two paddles on a c o m m o n shaft that are d e s i g n e d to push the bit in the desired direction. Roll off A c o r r e c t i o n in the facing of the d e f l e c t i o n tool, usually d e t e r m i n e d by experience, a n d which must be taken into consideration to give the p r o p e r facing to the tool. Setting off course A m e t h o d o f s e t t i n g t h e d i r e c t i o n o f t h e w e l l b o r e in anticipation o f the bit walking. Side t r a c k A n o p e r a t i o n p e r f o r m e d to redirect the wellbore by starting a new hole at a position above the b o t t o m o f the original hole. Slant hole A nonvertical hole; usually refers to a wellbore purposely inclined in a specific direction; also used to d e f i n e a wellbore that is nonvertical at the surface. Slant rig Drilling rig specifically designed to drill a wellbore that is nonvertical at the surface. The mast is slanted and special pipe-handling equipment is needed. Spiraled wellbore A wellbore that has attained a changing c o n f i g u r a t i o n such as a spiral o r helical form. Spud bit In directional drilling, a special bit used to change the direction a n d inclination o f the wellbore. S t a b i l i z e r A tool placed in the drilling assembly to: (1) change o r maintain the inclination angle in a wellbore by controlling the location o f the contact point between the hole a n d drill collars; (2) center the drill collars near the bit to improve drilling performance; and/or (3) prevent wear a n d differential sticking o f the drill collars. Surveying frequency Refers to the n u m b e r o f feet b e t w e e n survey records. T a r g e t a r e a A d e f i n e d area, at a p r e s c r i b e d vertical depth, that is p l a n n e d to be intersected by the wellbore. Tool azimuth angle T h e angle between n o r t h a n d the p r o j e c t i o n o f the tool reference axis onto a horizontal plane. Tool high-side angle T h e angle b e t w e e n the tool reference axis a n d a line p e r p e n d i c u l a r to the hole axis a n d lying in the vertical plane. Total curvature Implies three-dimensional curvature.

Directional Drilling

1083

T r u e n o r t h The direction from any geographical location on the earth's surface to the n o r t h geometric pole. T r u e vertical d e p t h (TVD) The actual vertical depth of an inclined wellbore. T u r b o d r i l l A downhole motor that utilizes a turbine for power to rotate the bk. T u r n A change in b e a r i n g of the hole; usually spoken of as the right or left t u r n with the orientation that of an observer who views the well course from the surface site. Walk (of hole) The t e n d e n c y of a wellbore to deviate in the horizontal plane. Wellbore survey calculation m e t h o d s Refers to the mathematical methods and assumptions used in reconstructing the path of the wellbore and in generating the space curve path of the wellbore from inclination and direction angle measurements taken along the wellbore. These m e a s u r e m e n t s are obtained from gyroscopic or magnetic i n s t r u m e n t s of either the single-shot or multishot type. Whipstock A long wedge and channel-shaped piece of steel with a collar at its top through which the subs and drillstring may pass. The face of the whipstock sets an angle to deflect the bit. Woodpecker drill collar ( i n d e n t e d drill collar) Round drill collar with a series of i n d e n t a t i o n s o n one side to form an eccentrically weighted collar.

Dogleg Severity (Hole Curvature) Calculations Currently there are several analytical methods available for calculating dogleg severity. These methods include: • • • • •

tangential radius of curvature average angle trapezoidal (average tangential) m i n i m u m curvature

Here the tangential a n d radius of curvature methods are outlined.

Tangential Method [171] The overall angle change is calculated from aa = 2 arc sin(sin 2Av + sin 2Ah sin V o sin V, h|o.~ ) 2 2 where Aa Ah Av V0, V,

= = = =

(4-263)

overall angle change change of horizontal angle (in horizontal plane) change of vertical angle (in vertical plane) hole inclination angle in two successive surveying stations

The hole curvature is

(4-264) where L = course length between the surveying stations

1084

D r i l l i n g a n d Well C o m p l e t i o n s

Example

1

Two s u r v e y i n g m e a s u r e m e n t s were t a k e n 30 ft apart. T h e r e a d i n g s are as below: S t a t i o n 1: H o l e i n c l i n a t i o n , 3°30" Hole direction, Nll°E S t a t i o n 2: H o l e i n c l i n a t i o n , 4°30" H o l e d i r e c t i o n , N23°E F i n d the d o g l e g severity.

Solution C h a n g e in h o r i z o n t a l angle is Ah = 23 - 1 1 = 12 ° C h a n g e in vertical angle is Av=4.5-

3.5 = 1 °

T h e overall angle c h a n g e is Aa = 2 arc sin[sin2(0.5) = sin2(6) sin(3.5) sin(4.5)] °s = 1.3 ° H o l e c u r v a t u r e is

C =

1.3 100 = 4 . 3 3 ° / 1 0 0 f t -_- 4° 20'/100ft 3O

Radius of Curvature Method [133] T h e d o g l e g severity is calculated from: C = 100[a ~ sin4~ + b~]°.5

(4-265)

where a = rate o f c h a n g e in d i r e c t i o n angle in ° / f t b = rate o f c h a n g e in i n c l i n a t i o n angle i n ° / f t = i n c l i n a t i o n angle in o T h e s e q u e n c e o f c o m p u t a t i o n s involved is e x p l a i n e d in the following example.

Example 2 F r o m two successive d i r e c t i o n a l survey stations is o b t a i n e d :

Hole inclination angle: Hole direction angle:

Station 1

Station 2

30 ° (d)~) Nll°E (0~)

40° (¢2) N18°E (e2)

Directional Drilling

1085

T h e d i s t a n c e b e t w e e n t h e s t a t i o n s is 60 ft. D e t e r m i n e t h e d o g l e g severity.

Solution R a t e o f c h a n g e in i n c l i n a t i o n a n g l e is 40 - 30 b---=0.1667~ 6O R a d i u s o f c u r v a t u r e in v e r t i c a l p l a n e is 180 Rv = . . b~

180 . . 0.1667~

363~

H o r i z o n t a l d e p a r t u r e (arc l e n g t h o f p r o j e c t i o n o f w e l l b o r e in h o r i z o n t a l p l a n e ) is H d = R v (cos ~Pl - cos ~P2) = 363 (cos 30 ° - cos 40 ° ) = 3 4 . 2 8 ft R a t e o f c h a n g e in h o l e d i r e c t i o n is

a =

02 - 0 ~

18-11 - - 34.28

Hd

= 0. 2042 °/ft

H o l e c u r v a t u r e at t h e f i r s t s t a t i o n is c t = 100 [(0.2042) 2 sin 4 30 ° + (0.1667)2] 0.~ = 7 . 4 3 ° / 1 0 0 ft H o l e c u r v a t u r e at t h e s e c o n d s t a t i o n is c 2 = 100 [(0.2042) 2 sin 4 40 ° + (0.1667)2] 0.~ = 1 8 . 6 8 ° / 1 0 0 ft T h e a v e r a g e v a l u e is

c =

17.43+18.68

= 18.05°/100ft

2

Deflection Tool Orientation A p p l i c a t i o n o f a d e f l e c t i n g t o o l (e.g., d o w n h o l e m o t o r w i t h a b e n t s u b ) r e q u i r e s d e t e r m i n i n g t h e o r i e n t a t i o n o f t h e tool so t h a t t h e h o l e takes t h e desired course. T h e r e are t h r e e effects to c o n s i d e r w h e n s e t t i n g a d e f l e c t i o n tool: 1. t h e e x i s t i n g b o r e h o l e i n c l i n a t i o n a n g l e 2. t h e e x i s t i n g b o r e h o l e d i r e c t i o n a n g l e 3. t h e b e n t s u b a n g l e o f t h e d e f l e c t i o n tool i t s e l f T h e s e t h r e e e f f e c t s in c o m b i n a t i o n will r e s u l t in a n e w d o g l e g o f a w e l l b o r e . T h e d e f l e c t i o n tool o r i e n t a t i o n p a r a m e t e r s c a n b e o b t a i n e d u s i n g t h e v e c t o r i a l m e t h o d o f D. R a g l a n d , t h e O u i j a B o a r d ®, o r t h e t h r e e - d i m e n s i o n a l m a t h e m a t i c a l deflecting model.

1086

Drilling and Well Completions

Vectorial Method of D. Ragland [134] This m e t h o d is explained by solving two example problems.

Example 3 Determine the deflection tool-face orientation, tool deflection angle and tool facing change from original course line angle if the data are as follows: Existing hole inclination angle: 10 ° Existing hole direction: N30°W Desired change of azimuth: 25 ° (to the left) Desired hole inclination: 8 °

Solution The solution to this problem is shown in Figure 4-349. The following steps are involved in p r e p a r i n g a Ragland diagram. 1. 2. 3. 4. 5. 6. 7.

Lay a q u a d r a n t N-S-W-E. Select a scale for the angles. With a protractor lay off an angle 30 ° from N. Using the selected angle scale find p.B (10 ° from p.A). With a protractor lay off an angle 25 ° to the left of line AB. Find p.C using the angle scale (8 ° from p.A). Describe a circle about p.B with a radius of CB = 4°6 ' (read off from the diagram). This is the desired tool d e f l e c t i o n angle. 8. Read off required tool-face orientation: $22°W 9. Read off required tool facing change from original course line: 131%

Example 4 T h e o r i g i n a l hole d i r e c t i o n a n d i n c l i n a t i o n were m e a s u r e d to be S60°W a n d 6 °, respectively. To obtain a new hole direction of $75°W with an inclination angle of 7 °, a whipstock with the d e f l e c t i o n angle of 2 ° was used and oriented correctly. After drilling 90 ft, a checkup measurement was performed that revealed that the hole direction is $72°W and the inclination is 6°30 '. Determine the magn i t u d e of roll-off for this system and the real deflection angle of the whipstock. How should the whipstock be oriented to drill a hole with a direction of $37°W and inclination of 5.5°?

Solution The solution to this problem is shown in Figure 4-350. Steps 1 and 2 are the same as in Example 3. 3. Lay off an angle 60 ° from S. 4. Draw a line 00'. 5. Draw a line OA that will r e p r e s e n t the d e s i r e d new hole d i r e c t i o n ($72°W). Point A is found at a distance of 7 ° from point O. 6. Read off the original whipstock o r i e n t a t i o n N64°W. 7. Draw a line OB (direction, $72°W; inclination, 6°30').

1087

Directional Drilling

I

1°

I

N

T

W

-

A

-

E

Figure 4-349. Graphic solution of Example 3.

8. Describe a circle about p.A" with a radius of OB = l°36 ' which is the whipstock true deflection angle. 9. T h e angle AO "B is the roll-off angle. Read off the roll-off angle = 9 ° to the right. 10. Draw a line OC ($37°W and inclination 5.5°). 11. If the roll-off effect is not considered, the whipstock direction is $71°E. Including the roll-off effect, the whipstock direction is S80°E.

1088

D r i l l i n g a n d Well C o m p l e t i o n s

Note: W i t h a D y n a - D r i l l d o w n h o l e m o t o r t h e r e will b e a l e f t - h a n d r e a c t i o n torque; therefore, the tool should be turned counterclockwise from the ideal position.

Three-Dimensional Deflecting Model R e c e n t l y a m a t h e m a t i c a l m o d e l h a s b e e n p r e s e n t e d [135] t h a t e n a b l e s o n e to a n a l y z e a n d p l a n d e f l e c t i o n tool r u n s . T h e m o d e l is a set o f e q u a t i o n s t h a t r e l a t e t h e o r i g i n a l h o l e i n c l i n a t i o n a n g l e (c~), n e w h o l e i n c l i n a t i o n a n g l e (C~N), o v e r a l l a n g l e c h a n g e ([3), c h a n g e o f d i r e c t i o n (A¢), a n d tool-face r o t a t i o n f r o m o r i g i n a l c o u r s e d i r e c t i o n (Y). T h e s e e q u a t i o n s a r e g i v e n below: [3 = arc c o s ( c o s cx cos cxN + sin cx sin cxN cos A¢)

(4-266)

cxN = arc c o s ( c o s cx cos [3 - s i n [3 sin cx cos Y)

(4-267)

( t a n [3 sin y A~ = arc t a n g ! . - - - --g - - -\ s m c~ + t a n p cos c~ cos y

(@268)

-

)

T h e a b o v e e q u a t i o n s c a n b e r e a r r a n g e d to t h e f o r m s u i t a b l e for a s o l u t i o n o f a p a r t i c u l a r p r o b l e m . A h a n d - h e l d c a l c u l a t o r m a y b e u s e d to p e r f o r m r e q u i r e d c a l c u l a t i o n s [136]. P r a c t i c a l u s e f u l n e s s o f this m o d e l is p r e s e n t e d below.

Example 5 O r i g i n a l h o l e d i r e c t i o n a n d i n c l i n a t i o n is N 2 0 ° E a n d 10 °, respectively. It is d e s i r e d to d e v i a t e t h e b o r e h o l e so t h a t t h e n e w h o l e i n c l i n a t i o n is 13 ° a n d d i r e c t i o n N30°E. W h a t is t h e tool o r i e n t a t i o n a n d d e f l e c t i n g a n g l e (dogleg) n e c e s s a r y to a c h i e v e this turn and build?

Solution F r o m E q u a t i o n 4-266, [3 = arc c o s ( c o s 10 (cos [3) + sin 10 (sin [3) cos 10) = 3.59 ° T h e d e s i r e d t o o l d e f l e c t i o n a n g l e (e.g., b e n t s u b ) is 3.59 ° . S o l v i n g E q u a t i o n 4-267 f o r y yields

y = arc cos

cos ~ cos [3 - cos a N ( cos 10(cos 3 . 5 9 ) - cos 13 ") sin [3 sin ~ = arc c o s Jk. ~sin 3 . 5 9 sin -10 -

= 38.53 ° C o n s e q u e n t l y t h e tool-face o r i e n t a t i o n is 20 + 38.53 = N 5 8 . 5 3 ° N

)

1089

Directional Drilling

~N 0

W

E

\

Figure 4-350. Graphical solution of Example 4. Example 6 S u r v e y i n g s h o w s t h a t t h e h o l e d r i f t a n g l e is 22 ° a n d d i r e c t i o n $36°W. It is d e s i r e d to t u r n t h e h o l e o f 6 ° to t h e r i g h t a n d b u i l d a n g l e . F o r t h i s p u r p o s e a d e f l e c t i o n t o o l w i t h a d o g l e g o f 3 ° is u s e d . W h a t is t h e e x p e c t e d n e w h o l e i n c l i n a t i o n a n g l e ? W h a t is t h e r e q u i r e d t o o l d i r e c t i o n ?

Solution E q u a t i o n 4-266 c a n b e solved for CXy by a p p l y i n g t h e f o l l o w i n g r e a r r a n g e m e n t s : cos 13 = cos cx cos ecN + s i n cx cos Ae s i n CXy Denote a = s i n cx cos Ae b = cos ct

1090

Drilling a n d Well C o m p l e t i o n s

Then cos ~ = (a 2 + b2) °'5 c o s ( a N - ~) where a

¢ = arc t a n b SO

aN

-arccos

cosl~ ) + ¢

(a2+b2)0.5

cos3 ) arc cos (c°s 2 22 + sin 2 22cos 2 6) 0.5 = 1.99 °

¢ = arc

tan ( sin 22 cos 6 ~ = ~, cos22 ) 21"89°

and a N = 23.88 ° Using Equation 4-267, the tool-face rotation is found to be 54.02 ° . Consequently the r e q u i r e d tool direction is N90°W.

SELECTION OF DRILLING PRACTICES Factors Affecting Drilling Rates T h e factors that influence the rate o f p e n e t r a t i o n d u r i n g a conventional rotary drilling process are numerous. In general these factors can be classified into five groups. 1. Formation mechanical and physical properties (strength, hardness, abrasiveness, porosity, permeability, etc.) 2. Rock bit type (tooth shape, j o u r n a l angle, cone offset, f l u i d circulation system) 3. Drilling f l u i d type a n d p r o p e r t i e s (density, viscosity, f l u i d loss, etc., solids content, differential pressure, etc.) 4. Drilling p a r a m e t e r s (weight on bit, rotary speed, nozzle size, flowrate) 5. Rig type a n d p e r f o r m a n c e o f drilling p e r s o n n e l (rig size, d e g r e e o f automation, power equipment, etc.) T h e d e t a i l e d a n d rigorous analysis o f the relationship between the drilling rate a n d the a f o r e m e n t i o n e d factors is not available as o f today.

Selection of Drilling Practices

1091

Selection of Weight on Bit, Rotary Speed and Drilling Time (Bit Rotating Time) To select p r o p e r l y the weight on bit W (lb), rotary speed N (rpm) a n d bit rotating time T b (hr), a drilling e n g i n e e r should choose a criterion for selection a n d a drilling model. As criteria for the drilling process evaluation a n d the drilling p a r a m e t e r s selection the following functions are generally used. Drilling cost p e r foot Cf ($/ft) is Cf = (Tb + Tt)Cr +Cb F

(4-269)

Run cycle speed RCS ( f t / h r ) is F RCS - - T b + T,

(4-270)

Footage F (ft) is F = ROP x T b

(4-271)

where

C r = hourly rig cost in $ / h r C b = bit cost in $ T t = trip time ( n o n r o t a t i n g time) in h r ROP = an average rate of p e n e t r a t i o n in f t / h r

The drilling model presented here is a simplified and m o d i f i e d model developed by Bourgoyne a n d Young [137]. T h e m o d e l includes three equations. Instantaneous drilling rate equation dF dt

1 K I 1 1 + Ch

where

II

~4Db)

\100)

Rate of bit tooth wear equation dh

d-t = where

1

I21+PI~h

(4-272)

1092

Drilling and Well Completions

I~)m --~ 1+-~-]

(4-273)

Rate of bit b e a r i n g wear equation is d._~B= 1 I3 dt S

(4-274)

where

N Wb where

F = footage in ft t = bit rotating time in hr W = weight on bit in 103 lb N = bit rotary speed in r p m D b = bit diameter in in. h = rock bit tooth dullness (fraction of original height worn away), 0 < h <1 B = b e a r i n g wear (fraction of a b e a r i n g life expected), 0 <_ B<_I C = constant d e p e n d e n t u p o n bit and formation type Af = formation abrasiveness parameter in hr K = formation drillability parameter in f t / h r S = bit b e a r i n g parameter in hr al,a 2 = bit weight a n d rotary speed exponents H v H v H 3 or (W/Db) m = constants which d e p e n d u p o n bit type (see Table 4-138) b = constant d e p e n d i n g u p o n bearing and drilling fluid type (see Table 4-139) 4 = normalized weight on bit in 4 x 103 lb 100 = normalized rotary speed in r p m Although the presented model is not a perfect simulation of the real system, it provides a possibility of d e t e r m i n i n g the optimal WOB, RPM a n d T b. The formation abrasiveness, drillability and bit-bearing parameters are calculated from the following formulas based on data available from previous drilling experience. Af =

K =

I2Tb H2 h 2 hf + --~- f

(4-275)

FI 2

I A E hf+ ,n/Chf+l

]

4 70,

Selection o f Drilling Practices

1093

Table 4-138 Recommended Tooth Wear Parameters (After Bourgoyne and Young [137])

Bit C l a s s

H l

1.9 i. 84 1.80 l . 76 70 1. 65 1. 6 0 1. 50

1-1 to 1-2 1-3 tO 1-4 2-1 tO 2-2 2-3 3-1 3-2 3-3 4-1

H 2

7 6 5 4 3 2 2 2

H 3

1.0 0.8 0.6 0.48 0.36 0.26 0.20 0.18

(W/Db) max

7.0 8.0 8.5 9.0

l'O.O 10.0 10.0 10.0

Table 4-139 Recommended Value of Exponent "b" (After Maratier [137])

Bearing

type

Nonsealed

[ S e a l e d ....

S = I3Tb B

Drilling

fluid

B a r i t e mud -Sulfide m u d L Water C l a y mud Oil b a s e m u d

b 1.00

5.25

i

1.30 2.04 2'.'55 2.8"

(4-277)

Taking the m i n i m u m drilling cost as a c r i t e r i o n for d e t e r m i n i n g the o p t i m u m m a g n i t u d e o f WOB, RPM a n d T b, the following equations are applicable:

W(opt ) =

\ b Jm Ob a~H~ + a~

(4-278)

1094

Drilling a n d Well C o m p l e t i o n s

N(opt)

= 100 ~ - - - ~ - - ) _2_ _ . . . ~LDb )______~ Db___.__J ) Tb(o,,H3[( --~w]

"

LtD

L

-4.0](1+H2~ _It 2 ) J

(4-280)

Equations 4-278, 4-279 and 4-280 are valid only if the bit life is limited by tooth wear or economical drilling rate.

Example 1 The following data are available from an offset well: Weight on bit, W = 45 × l 0 s lb; Rotary speed, N = 130 rpm; Footage, F = 580 ft; Bit rotating time, T b = 16 hr; Trip time, T t = 9 hr; Bit diameter, D b = 12 ¼ in.; Bit type: SDS; From Table 4-138: H~ = 1.9, H 2 = 7, H s = 1.0, (W/Db) m = 7; Bearing type: nonsealed, clay mud; From Table 4-139: b = 2.06; Tooth wear, hf = ~; Bearing wear, B = ~; Exponents: a x = 1.0, a 2 = 0.8; Constant: C = 6.5. Find the f o r m a t i o n abrasiveness a n d drillability p a r a m e t e r s and the bit-bearing constant.

Solution Calculate the dimensionless functions:

Iz

~4Db)

~,100)

4×12.25)

~,100)

= 6.68

Selection o f Drilling Practices

1095

and

(N ]( W )b =(130)( I,=

~

~

45 )2.O4

(1--~)(4×T2.25

=1.09

Applying Equations 4-275, 4-276 and 4-277 yields the following: F o r m a t i o n abrasiveness p a r a m e t e r is 6 . 6 8 x 16

Af =

= 30.07 hr

0. 875 + 7 0. 8752 2 F o r m a t i o n drillability p a r a m e t e r is

K=

580 × 6.68

= 133.66 ft/hr

1.323×30.07/67.5 0 . 7 8 5 + 6 ~ .; S ( 6 . 5 ×. 0 . 7 8 5 + 1 ) a n d the b e a r i n g constant is 1.09 × 16 S= - -23.31hr 0.75 Note: Using the above o b t a i n e d values for K, Af a n d S, o n e may a t t e m p t to

optimize drilling p a r a m e t e r s from Equations 4-278, 4-279 and 4-280; however, in the case considered, the bit life is limited by bearings wear. Consequently Equations 4-278, 4-279 and 4-280 are not applicable. Nevertheless a simple triala n d - e r r o r calculation can be used to find the d e s i r e d parameters.

Example 2 Find the o p t i m a l weight on bit a n d rotary speed for m i n i m u m drilling cost p e r foot if the data are as follows: F o r m a t i o n drillability parameter, K = 28.5 f t / h r ; F o r m a t i o n abrasiveness parameter, Af = 24.7 hr; Bit bearings constant, S = 45 hr; Bit diameter, D b = 9.875 in.; Bit constants: H I = 1.84, H 2 = 6, H~ = 0.8, ( W / d b ) Exponents: a 1 = 1.2; a 2 = 0.6, b = 2.04; Trip time, T t = 7 hr; Bit cost, C b = $900; Rig cost, C = 600 $ / h r ; Bit f o r m a t i o n constant, C = 2.5.

Solution O p t i m a l weight on bit is Wop, = 9 . 8 7 5

1.2xl.84x8 = 6 2 . 1 x 1 0 3 lb 1.2 x 1.84+ 0.6

m = 8;

Drilling and Well Completions

1096

Optimal bit rotating time is = (900 + 7~(1"84 - 1) : 17.5 hr T~°vt ~,600 )~, 0.6 Optimal rotary speed is

= 100[ 24" 7[h f + ~ h~)[8__~-; 2 8 ~ ] ] VI86 N°P~

17.5×0.8×(8-4)(1+3)

/

= 40.4(hf +3 x h~) °'54347 Take hf = 1.0: Nchf-1.o) = 85.8 -_- 86 rpm Expected bearings wear is

B = 13 ~ - =

4 x--9.875 )

4--'5--

Conclusion: Bit life is limited by tooth wear or economical drilling rate. Expected magnitude of footage at W = 62.1 x l0 s lb, N = 86 rpm, and hf = 1.0. Calculate 11 and I2: I1

= ( 62.1 f'2(86~°6 ~,4 x---~.875) ~,1-'~) = 1.572

12 = 0.8

87"0-'6.-'~8 (1+3)--- 5.665

The expected footage is F=28"5x24"71"572( = 3 326.54 1 +f ~ (t2 " 5 x 1. + 16) ) 6 5 and the expected cost per foot is Cf = (7+17.5)900+600 = 67.8 $/ft 334

Selection o f Drilling Practices

1097

F u r t h e r c a l c u l a t i o n s can be p e r f o r m e d for h e = 0.9; however, in t h e case considered, the expected cost p e r foot is higher. Consequently, the bit life is limited by tooth wear, and the c o m p u t a t i o n s are completed.

Selection of Optimal Nozzle Size and Mud Flowrate O p t i m a l hydraulics is the p r o p e r balance o f hydraulic p a r a m e t e r s (flowrate and equivalent nozzle size) that satisfy chosen criteria o f optimization. Hydraulic quantities used to characterize j e t bit p e r f o r m a n c e include hydraulic horsepower, j e t impact force, j e t velocity, Reynolds n u m b e r at the nozzle, generalized drilling rate or cost p e r foot d r i l l e d . W h i l e d e s i g n i n g t h e h y d r a u l i c p r o g r a m t h e l i m i t a t i o n s due to cuttings t r a n s p o r t in t h e annulus a n d p u m p p e r f o r m a n c e characteristics must be included. A n estimate o f the m i n i m u m required m u d flow velocity in annular space to assure adequate cuttings t r a n s p o r t can be estimated from 196 Van = mTDh=--

(4-281)

where V art = annular velocity in f t / s D h = bore-hole d i a m e t e r in in. 7m = m u d weight in l b / g a l T h e m u d p u m p p e r f o r m a n c e characteristic can be thought o f as being c o m p o s e d o f two o p e r a t i n g ranges. Range 1 is Pp = Pb + Pd = const

(4-282)

Range 2 is HPp = HP b + HP d = const where pp Pb Pd HP HP~ HP d

(4-283)

= = = =

p u m p pressure in psi bit pressure drop in psi pressure d r o p through r e m a i n i n g circulating system in psi p u m p hydraulic h o r s e p o w e r hydraulic horsepower developed at the bit = hydraulic horsepower dissipated t h r o u g h the r e m a i n i n g circulating system

Range 1 o f t h e m u d p u m p p e r f o r m a n c e c h a r a c t e r i s t i c is d e f i n e d by t h e p e r f o r m a n c e o f t h e smallest liner, a n d range 2 is d e f i n e d by the r e m a i n i n g liners. T h e pressure loss in a circulating system, except for bit (Pd), can be e s t i m a t e d from n u m e r o u s theoretical formulas or from a f l o w r a t e test. Data o b t a i n e d from a flowrate test can be a p p r o x i m a t e d using a curve-fitting technique by the following function: Pd = Kq m

(4-284)

1098

Drilling and Well Completions

The quantities K and m may also be found by plotting Pd VS. Q (flowrate) on loglog graph paper. Here, an outline of a hydraulic program design for the maximum jet impact force is presented. The jet impact force E (lb) is calculated from Fj = 1.73 × 10-2Q(Pb) °.~

(4-285)

where q is the flowrate (gal/min). For the first p u m p operating range (pp = const = Pp_m) (0 < Q < Q~), where Ppm is maximum desirable p u m p pressure. The optimal flow rate qopt is

qop~(l)

~ K(m + 2)

(4-286)

The pressure drop across the bit is m

Pb = m + 2 Pore

(4-287)

For the second p u.m p operating range (HP p = const = HPm) (q m <. q < qml), where . . . . HP m is maximum desirable pump hydrauhc horsepower. The opnmal flowrate is 1,714 × HPpm )~/m+~ K × (m + 2)

qoot(2) =

(4-288)

and the corresponding pressure change across the bit is m+l Pb = m + 2 PpIop0

(4-289)

where 1,714HPpm Pp(opt)

--

qopt(~)

(4-290)

O n determining the optimal flowrate q o p t (gal/min) and pressure drop across the bit nozzles Pb, the total flow area is calculated from

=( Y.q~op0 ) 0.5 An

~ 1-~,8 - ~ p b

(4-291)

Example 3 Calculate the optimal hydraulic parameters for the hole depth of 8,555 ft if the available data are as given below: Type of pump: Continental Emsco F-1600 with 97% p u m p volumetric efficiency. To prevent rapid p u m p wear, the p u m p pressure should not exceed about 80% of the maximum p u m p pressure at any liner size. The hole size is 12 ¼ in. and the mud weight is 9.7 lb/gal. Upon completing a drilling run at the depth of 8,555 ft, the flowrate test was performed and the following measurements were obtained:

Selection of Drilling Practices q (gaVmln) 375 400 425 450

1099

pp (psi) 1,950 2,125 2,400 2,725

Nozzle size at flowrate test is 3 × ~ . The minimum required flowrate is 350 gal/min. Solution

Applying the least-squares technique, the equation for pressure loss Pd is Pd = 0"0522q 1"623 Based on a nominal pump performance characteristic, the following table is prepared.

Liner size (in.) 5% 53A 6 61/4 61/2 63/4 7 71A 71/2

Pump output at 130 strokes/mln gal/min

Max pump pressure (psi)

hydr. hrspwr.

481 526 573 621 671 724 778 836 894

5,558 5,078 4,665 4,299 4,012 3,688 3,423 3,197 2,988

1,560 1,558 1,560 1,558 1,570 1,557 1,554 1,560 1,558

Pump

Introducing the volumetric efficiency (97%) and the limitations for p u m p pressure (80%) we obtain

Liner size (in.) 51/2 53/4 6 61/4 61/2 63/4 7 71/4 71/2

Pump output at 120 strokes/min gal/min

Max pump pressure (psi)

hydr. hrspwr.

430 470 513 556 600 648 696 720 800

4,446 4,062 3,732 3,439 3,209 2,950 2,738 2,557 2,390

1,115 1,114 1,117 1,112 1,123 1,115 1,112 1,074 1,115

Pump

1100

Drilling and Well Completions

For further calculations the maximum p u m p pressure of 4,446 psi and maximum hydraulic horsepower of 1,110 hp is accepted. Also, qm = 430 g a l / m i n and q" = 800 g a l / m i n . Since qm > qr' we calculate qop,(2) from Equation 4-288: ( 1,716x 1,100 t I/I"623+1 qopt(2) = ~ (1. 623 + 2)0. 0522 ) = 466 gal/min then, applying Equation 4-290,

Ppop, =

1,716 x 1,100 = 4,045 psi 466

The liner size is 5 ~ in. The n u m b e r of strokes per minute is 119. Pressure drop across the bit from Equation 4-289 is

Pb -

2.623 4,045 = 2,928 psi 3.623

Calculate the total nozzle area from Equation 4-291: /

a,

2

,,0.5

=[ 9.7 x 466 / "\ i ~u , 2-;2-"~" ~x Z,UZ 2-~8)"

= 0.2574 in. 2

The nozzles sizes are ~ , ~ a n d ~ in. For the selected set of nozzles, the total flow area is 0.2554 in3, which will result in slightly higher p u m p pressure than 4,446 psi; however, this seems to be acceptable.

WELL PRESSURE CONTROL Introduction Basically all formations penetrated during drilling are porous and permeable to some degree. Fluids contained in pore spaces are under pressure that is overbalanced by the drilling fluid pressure in the well bore. The bore-hole pressure is equal to the hydrostatic pressure plus the friction pressure loss in the annulus. If for some reason the borehole pressure falls below the formation fluid pressure, the formation fluids can enter the well. Such an event is known as a kick. This name is associated with a rather sudden flowrate increase observed at the surface. A formation fluid influx (a kick) may result from one of the following reasons: • • • • • •

abnormally high formation pressure is e n c o u n t e r e d lost circulation m u d weight too low swabbing in d u r i n g tripping operations not filling up the hole while pulling out the drillstring recirculating gas or oil cut mud.

If a kick is not controlled properly, a blowout will occur. A blowout may develop for one or more of the following causes:

Well Pressure Control

1101

• lack of analysis of d a t a o b t a i n e d from offset wells • lack o r m i s u n d e r s t a n d i n g of d a t a d u r i n g drilling • malfunction o r even lack of adequate well control e q u i p m e n t

Surface Equipment A f o r m a t i o n f l u i d kick can be efficiently a n d safely controlled if the p r o p e r e q u i p m e n t is installed at the surface. O n e of several possible a r r a n g e m e n t s of pressure control e q u i p m e n t is shown in Figure 4-351. T h e blowout preventer (BOP) consists of a spherical preventer (Hydril), b l i n d a n d pipe rams, a n d the drilling spool. A spherical preventer contains a packing element that seals the space a r o u n d a drillpipe. This preventer is not designed to shut off the well when the drillpipe is out of the hole, a l t h o u g h it allows s t r i p p i n g o p e r a t i o n s a n d s o m e p i p e rotation. Hydril C o r p o r a t i o n , Shaffer a n d o t h e r manufacturers provide several models with different packing system designs for specific types of service. T h e ram-type preventer seals the annulus a r o u n d the drillpipe; however, each size of ram is designated for only one size of drillpipe. In other words, the preventer with 5-in. pipe rams can provide a seal only on 5-in. drillpipe. T h e preventer with b l i n d rams is used to shut in the well if the p i p e is not in the hole. If this type of preventer is activated with the pipe in the hole, the pipe can be cut. T h e r e are also specially d e s i g n e d preventers with shear-blind rams. This type of ram will certainly cut the pipe a n d seal the o p e n hole. Special precautions should be taken to ensure that the b l i n d rams cannot be mistakenly closed. A drilling spool is the element of the BOP stack to which m u d a n d kill lines are attached. T h e pressure rating of the drilling spool a n d its outlets must be consistent with the BOP stack. T h e kill line serves to p u m p drilling fluid directly into the annulus in case of need. T h e choke lines are attached to the BOP to enable controlled circulation of the drilling a n d f o r m a t i o n fluids out of the hole. A degasser is installed on the m u d line to remove gas from drilling fluid while p e n e t r a t i n g gas b e a r i n g formations. Samples of gas are analyzed using the gas chromatograph. If the well cannot be shut in (for some reason) to i m p l e m e n t regular kick killing procedures, a diverter stack is used r a t h e r than a regular BOP stack. A diverter is f u r n i s h e d with a b l o w - d o w n line to allow the well to blow out away from the rig.

When and How to Close the Well T h e r e are certain warning signals while drilling which, if analyzed properly, can lead to early d e t e c t i o n of f o r m a t i o n f l u i d entry into the wellbore.

1. Drilling break. A relatively sudden increase in the instantaneous drilling rate is called the drilling break. T h e drilling break may occur due to a decrease in the d i f f e r e n c e b e t w e e n the b o r e h o l e p r e s s u r e a n d f o r m a t i o n p o r e pressure. W h e n a drilling break is observed, the p u m p s should be s t o p p e d a n d the well watched for flow at the m u d line. If the well does not flow, it means that the overbalance is not lost o r simply that a softer f o r m a t i o n has b e e n encountered. 2. Decrease in pump pressure. W h e n less dense f o r m a t i o n f l u i d enters the borehole, the hydrostatic h e a d in the annulus is decreased; thus, the pressure supplied by mud pumps is decreased. Although reduction in p u m p pressure

0

Row line O~

fill line

C~

Choke line Blind rams

5" Kill line

Degasser |

Pipe rams

Choke line

valve g valve Adjustable choke Presswe gauge

i•udmulic

Figure 4-351. Pressure control equipment. (From Ref. [144].) Source: Preston Moore's "Drilling Practices Manual, 2nd Edition" Copyright PennWell Books, 1986.

Well Pressure Control

1103

may be caused by several other factors, drilling personnel should consider formation fluid influx in the wellbore as one possible cause. Again, the pumps should be stopped and the flow line watched carefully. 3. Increase in pit level. This is a definite signal of formation fluid invasion into the hole. The well must be closed as soon as possible. 4. Gas-cut mud. When drilling through gas-bearing formations, small quantities of gas occur in the cuttings. As these cuttings are circulated up the annulus, the gas expands. Consequently a reduction in mud weight is observed at the surface. Here again stopping the pumps and watching the flow line return helps to find out whether or not the overbalance is lost. If the kick is gained while tripping, the only warning signal we have is an increase in fluid volume at the surface (pit gain). Once it is determined that the pressure overbalance is lost, the well must be closed as quickly as possible. The sequence of operations involved in closing the well is as follows: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Shut off the mud pumps. Raise kelly above the BOP stack. Open the choke line. Close the spherical preventer. Close choke slowly. Record the pit level increase. Record the stabilized pressure on drillpipe and annulus pressure gages. Notify the company personnel. Prepare the kill procedure.

If the well kicks while tripping, the sequence of necessary steps can be as given below: 1. 2. 3. 4. 5. 6. 7. 8.

Close the safety valve (kelly cock) on the drillpipe. Pick up and install the kelly. O p e n safety valve (kelly cock). Open the choke line. Close the annular preventer. Record the pit gain and the shut-in drillpipe and casing pressure. Notify the company personnel. Prepare the kill procedure.

Depending u p o n the drilling rig type and company policy, the sequence of operations described above may be changed. Gas-Cut Mud

A gas-cut mud is a warning signal of possible formation fluid influx, although it is not necessarily a serious problem. Due to gas expandibility, it usually gives the appearance of being a more serious problem than it actually is. The bottomhole hydrostatic head of gas-cut mud and the expected pit gain can be calculated from the following equations:

Ph =P'+(1-a,------T

Psas ln( /

(1-a~-------T ~ P~J

(4-292)

1104

D r i l l i n g a n d Well C o m p l e t i o n s

Vp= AnP~a~ln(Ph]_ 7,

CP,)

(4-293)

where

7s =

PsMas + T m ( 1 - - a~) zRTav

(4-294)

where Ph = hydrostatic pressure o f gas-cut m u d in l b / f t 2, abs P = casing p r e s s u r e at the s u r f a c e in l b / f t 2, abs = vertical hole d e p t h with the gas-cut m u d in ft = gas c o n c e n t r a t i o n in m u d (ratio o f gas to total f l u i d v o l u m e ) as ~s = gas-cut m u d specific weight at surface in l b / f t 3 An = cross-sectional area o f a n n u l u s in ft 2 Vm= o r i g i n a l m u d specific weight in l b / f t 3 Z = the average gas c o m p r e s s i b i l i t y factor M = gas m o l e c u l a r mass T = t h e average f l u i d t e m p e r a t u r e in °R = u n i v e r s a l gas c o n s t a n t in lb ° f t

Example 1 Calculate the e x p e c t e d r e d u c t i o n in b o t t o m h o l e pressure a n d pit gain for the data as given below: H o l e size = 9 ~ in. H o l e d e p t h = 10,000 ft D r i l l i n g rate = 60 f t / h r O r i g i n a l m u d d e n s i t y = 10 l b / g a l M u d f l o w r a t e = 350 g a l / m i n F o r m a t i o n pore p r e s s u r e g r a d i e n t = 0.47 p s i / f t Porosity = 30% W a t e r s a t u r a t i o n = 25% Gas s a t u r a t i o n = 75% Gas specific gravity = 0.6 (air specific gravity is 1.0) Surface t e m p e r a t u r e = 540°R Temperature gradient = 0.01°F/ft

Solution Gas v o l u m e t r i c rate e n t e r i n g the a n n u l u s

~. = n ( 9 . 6 2 5 ) 2 x 60 x 1 x 0 . 3 x 0.75 = 0.1136 ft3/min = 0.85 g a l / m i n 4 × 144 60 Gas v o l u m e t r i c f l o w r a t e at surface (at c o n s t a n t t e m p e r a t u r e ) is .Q = 0.85 x 4700 = 272.6 g a l / m i n 14.7

Well Pressure Control

1105

T h e surface pressure is assumed to be 14.7 psia. Gas concentration at surface is 272.6 = 0.4378 as = 272.6 + 350 Mud weight at surface (assume z = 1.0) is 14.7 x 144 x 0.6 x 29 x 0.4378 "/s =

10 x 7.48(1 - O. 4378)

1,544 x 540

= 42.07 lb/ft s, or 5.62 lb/gal Hydrostatic pressure of gas-cut m u d is

Ph = 14.7 +

O.052x5.62x9,038 (1 - O. 4378)

1 4 . 7 x O . 4 3 7 8 1 n ( Ph 1 ----'0.4---~ ~.1--~. 7)

Solving the above yields Ph = 4646 psia Hydrostatic head at the b o t t o m of the hole is Pb~ = 0.052 x 10(10,000 - 9,038) + 4,646 = 5,146 psia Since the hydrostatic pressure of the original m u d is 5,214.7 psia, the reduction in the hydrostatic pressure is about 69 psi. Because the pore pressure at the vertical d e p t h of 10,000 ft is 4,700 psi, the hydrostatic pressure of the gas-cut m u d is sufficient to prevent any f o r m a t i o n f l u i d kick into the hole.

The Closed Well U p o n shutting in the well, the pressure builds up both on the d r i l l p i p e and casing sides. T h e rate of pressure b u i l d u p a n d time r e q u i r e d for stabilization d e p e n d u p o n f o r m a t i o n f l u i d type, f o r m a t i o n p r o p e r t i e s , initial d i f f e r e n t i a l pressure a n d drilling f l u i d properties. In Ref. [143] technique is p r o v i d e d for d e t e r m i n i n g the shut-in pressures if the d r i l l p i p e p r e s s u r e is r e c o r d e d as a function of time. Here we assume that after a relatively short time the conditions are stabilized. At this time we r e c o r d the shut-in d r i l l p i p e pressure (SIDPP) a n d the shut-in casing pressure (SICP). A small difference between their pressures indicates liquid kick (oil, saltwater) while a large difference is evidence of gas influx. This is true for the same kick size (pit gain). Assuming the f o r m a t i o n f l u i d does not enter the drillpipe, we know that the SIDPP plus the hydrostatic h e a d of the drilling f l u i d inside the p i p e equals the pressure of the kick f l u i d (formation pressure). T h e f o r m a t i o n pressure is also equal to the SICP plus the h y d r o s t a t i c h e a d of the o r i g i n a l mud, plus the hydrostatic head of the kick f l u i d in the annulus.

1106

Drilling and Well C o m p l e t i o n s

Thus pp = 0.052~mH + SIDPP

(4-295)

= 0.052~m (H - L) + 0.052~fL + SICP

(4-296)

where H = vertical hole d e p t h in fl ~m = original m u d specific weight in l b / g a l ~f = f o r m a t i o n f l u i d specific weight in l b / g a l L = vertical length o f the kick in ft p p = f o r m a t i o n p o r e pressure in psi If the hole is vertical the kick length can be calculated as V

L-

(4-297)

VC dc or

L = Ld~+

where V VCdc Ldc VCdv

= = = =

V - LdcVCdc

VCdv

(4-298)

pit gain in bbl annulus volume capacity opposite the drill collars in b b l / f t length o f drill collar in ft annulus volume capacity opposite the d r i l l p i p e in b b l / f t

E q u a t i o n 4-297 is a p p l i c a b l e if t h e kick l e n g t h is s h o r t e r than t h e drill collars while Equation 4-298 is used if the kick fluid column is longer than the drill collars. From Equations 4-295 and 4-296 it is found that the required m u d weight increase can be calculated from

A'~m -

19.23 x SIDPP H

(4-299)

T h e f o r m a t i o n f l u i d density can be o b t a i n e d from

~f ~---~m

S I C P - SIDPP 0. 052 H

(4-300)

Kick Control Procedures There are several techniques available for kick control (kick-killing procedures). In this section only three m e t h o d s will be addressed. 1. Driller's method. First the kick fluid is circulated out o f the hole a n d then

the d r i l l i n g f l u i d density is raised up to the p r o p e r density (kill m u d

Well Pressure Control

1107

density) to replace the original mud. A n alternate n a m e for this p r o c e d u r e is the two circulation m e t h o d . 2. Engineer's method. T h e drilling fluid is weighted up to kill density while the f o r m a t i o n f l u i d is being circulated out o f the hole. S o m e t i m e s this technique is known as the one circulation method. 3. Volumetric method. This m e t h o d is a p p l i e d if the d r i l l s t r i n g is o f f the bottom. The g u i d i n g principle o f all these techniques is that b o t t o m h o l e pressure is held constant a n d slightly above the f o r m a t i o n pressure at any stage o f the process. To choose the most suitable technique one ought to consider (a) complexity o f the m e t h o d , (b) drilling crew experience and training, (c) m a x i m u m e x p e c t e d surface a n d b o r e h o l e pressures a n d (d) time n e e d e d to reestablish pressure overbalance and resume n o r m a l drilling operations.

Driller's Method T h e driller's m e t h o d o f controlling a kick is accomplished in two main steps:

Step 1. T h e well is circulated at half the n o r m a l p u m p speed while keeping the d r i l l p i p e p r e s s u r e constant (see Figure 4-352a). This is a c c o m p l i s h e d by adjusting the choke on the m u d line so that the b o t t o m h o l e pressure is constant a n d above the f o r m a t i o n f l u i d pressure. To maintain a constant b o t t o m h o l e pressure the f o r m a t i o n f l u i d is allowed to expand, which usually results in a noticeable increase in casing pressure. This step is c o m p l e t e d when the formation f l u i d is out o f the hole. At this time casing pressure should b e equal to the initial SIDPP if the well could be shut in.

Step 2. W h e n the f o r m a t i o n f l u i d is out o f the hole, a kill m u d is circulated down the drillpipe. To obtain constant b o t t o m h o l e pressure, the casing pressure is kept constant (see Figure 4-352b) while the d r i l l p i p e pressure drops. O n c e the kill m u d reaches the b o t t o m o f the hole the control moves back to the d r i l l p i p e side. The d r i l l p i p e pressure is m a i n t a i n e d constant (almost constant) while the new m u d fills the annulus.

Example 2 C o n s i d e r the following data: Vertical hole d e p t h = 10,000 ft Hole d i a m e t e r = 8¼ in. Drillpipe d i a m e t e r = 4 ~ in. Mud density = 12 l b / g a l Yield point = 12 l b / 1 0 0 ft 2 Circulating pressure at r e d u c e d speed = 800 psi Shut-in d r i l l p i p e pressure = 300 psi Calculate the following: 1. 2. 3. 4.

required m u d weight to restore the safe overbalance initial circulating pressure (ICP) final circulating pressure (FCP) specific weight o f f o r m a t i o n f l u i d

1108

P

Drilling and Well Completions

dp O.t-

Q. ~n "~._ 1,Oil-

SIDPP( tB

tc

Step 1

tD

Step 2

TIME

~-I

Figure 4-352a. Driller's method--Schematic diagram of drillpipe pressure vs. time.

Pept

SIC~ L r

tA Step 1

tB _I_

tc

to Step 2

TIME

_I

Figure 4-352b. Driller's method--Schematic diagram of casing pressure vs. time. t A = kick fluid out the top of the hole; t 8 = kick fluid out of the hole; t c = kill mud at the bottom of the hole; t o = killing procedure completed.

Solution Mud weight increase to balance formation pressure is 20 x 300 A?~ -= uuuu1% ""-----------~ = 0.6 lb/gal Trip margin A~t is

Well Pressure Control =

A~,

yp

_

6(D h - Dp)

1109

12 = O. 47 lb/gal 6 ( 8 . 7 5 - 4.5)

Consequently the required m u d weight is Ym = 1 2 + 0 . 6 + 0 . 4 7

_-- 13.1 lb/gal

Initial circulating pressure is ICP = 800 + 300 = 1,100 psi Final circulating pressure is the system pressure loss c o r r e c t e d for new m u d weight. This is

F C P - - - 8 0 0 ( 1 1 - ~ ) = 873 psi

Engineer's Method This m e t h o d consists of four phases. Phase I. During this phase the drilling fluid, weighted to the desired density, is placed in the drillpipe. W h e n the d r i l l p i p e is filled with heavier mud, the s t a n d p i p e pressure is gradually reduced. T h e expected d r i l l p i p e pressure versus the n u m b e r of p u m p strokes (or time) must b e p r e p a r e d in advance. Only by p u m p i n g with a constant n u m b e r of strokes and simultaneously maintaining the standpipe pressure in accordance with the schedule can one keep the b o t t o m h o l e pressure constant and above the f o r m a t i o n pressure. T h e annulus pressure at the surface generally rises due to f o r m a t i o n f l u i d expansion, although for some f o r m a t i o n f l u i d the casing p r e s s u r e may d e c r e a s e . This d e p e n d s on p h a s e b e h a v i o r of the f o r m a t i o n f l u i d and irregularities in the hole geometry. Phase 2. This phase is initiated when the kill m u d begins filling the annulus and is f i n i s h e d when the f o r m a t i o n f l u i d reaches the choke. T h e s t a n d p i p e pressure remains essentially constant by p r o p e r adjustment of the choke. Phase 3. T h e f o r m a t i o n f l u i d is circulated out of the hole while heavier m u d fills the annulus. Again the choke o p e r a t o r maintains the d r i l l p i p e pressure constant and constant p u m p i n g speed. Phase 4. During this phase the original m u d that follows the kick fluid is circulated out of the hole and a kill m u d fills up the annulus. T h e choke is o p e n e d m o r e and more to keep the drillpipe pressure constant. A t the e n d of this phase the safe pressure overbalance is restored. A qualitative relationship between the d r i l l p i p e pressure, casing pressure and circulating time is shown in Figures 4-353a and 4-353b, respectively.

Volumetric Method This m e t h o d can b e used if the kick is taken d u r i n g t r i p p i n g up the hole with the bit far from the b o t t o m of the hole. Again the constant b o t t o m h o l e pressure principle is used to control the situation. T h e f u n d a m e n t a l principle of this m e t h o d is equating the pit volume change with the c o r r e s p o n d i n g change in annulus pressure. We write

l ll0

Drilling and Well Completions

P -dp

I I I

Q.

E

t I

CI

t1

t2

I t3

t4

TIME

F i g u r e 4 - 3 5 3 a . Engineer's m e t h o d - - D r i l l p i p e pressure v. time.

Pcp

Y

n

I I I I I I

°c-

I

1

tz t3

tl

t4

TIME

I

PHASE 1

_L -ii

PHASE 2

J_~ 2 "F

PHASE 4

"T"

.J "7

F i g u r e 4 - 3 5 3 b . Engineer's m e t h o d - - C a s i n g pressure vs. time. t I = kill mud at the bottom of the hole; t 2 = formation fluid reaches the choke; t 3 = kick fluid out of the hole; t 4 = pressure overbalance is restored.

Ap~ = AVp 0.0527m AV where ~p~ ~Vp Ym AV

= = = =

(4-301)

change in surface pressure at casing side in psi change in pit volume (volume gained) in bbl mud specific weight in lb/gal volume capacity of annulus in bbl/ft

Note that the term (0.052 y J A V ) expresses the expected increase of casing pressure when 1 bbl of pit gain is recorded. The magnitude of the casing pressure during kick control is

P = SICP + ~Vp 0.0527m AV

(4-302)

Well Pressure Control

1111

W h e n the pit volume stabilizes, there is equilibrium in the a n n u l u s and the kick fluid is out of the hole.

Maximum Casing Pressure D e t e r m i n a t i o n of the m a x i m u m expected casing pressure is r e q u i r e d for selection of the kick control technique. If the driller's m e t h o d is used for kick control, the maximum casing pressure Pc m= (psi) is calculated assuming gas influx into the hole. This is

SIDPP + Pc~ = --~

+ 0.052~t m ppAVpT2z2 zlTIAV

10.

(4-303)

where SIDPP = shut-in drillpipe pressure in psi Ym = original m u d density specific weight in l b / g a l P = formation pressure = pit gain in bbl AVT" 2 gas t e m p e r a t u r e at surface in °R T 1 = gas t e m p e r a t u r e at the b o t t o m of the hole in °R zl = gas compressibility factor at surface conditions z2 = gas compressibility factor at the b o t t o m of the hole AV = volume capacity of a n n u l u s in b b l / f t For the e n g i n e e r ' s m e t h o d the m a x i m u m expected casing pressure can be calculated from

Pcmax ----0"026(yk -- ~tm )Era + ([0"026(yk - Ym )Era ]2

_ ppAVpZ2T2 ]0.5 + 0.052Yk

(4-304)

where ~tk = kill m u d density L m = length of original m u d in the a n n u l u s at the m o m e n t the b u b b l e reaches the top of the hole

Example 3 Calculate the maximum expected casing pressure for the driller's and engineer's techniques of kick control for the data as below: Vertical hole depth = 12,500 ft Original m u d weight = 12.0 l b / g a l Shut-in drillpipe pressure = 260 psi Pit gain --- 30 bbl Volume of m u d inside the drillstring = 175 bbl A n n u l a r volume capacity = 0.13 b b l / f t Gas compressibility ratio zl/z 2 = 1.35 Gas temperature at the surface = 120°F

1112

Drilling and Well C o m p l e t i o n s

Well-bore t e m p e r a t u r e g r a d i e n t = 1.2°F/100 ft Surface t e m p e r a t u r e = 80°F

Solution Required m u d weight for killing the well is ~k = 12 +

260 + 0.5 = 12.9 lb/gal 0.052 ×12,500

For trip margin, a 0.5 l b / g a l was a d d e d arbitrarily. Bottomhole t e m p e r a t u r e is T 1 = 80 + 1.2 × 125 = 230°F F o r m a t i o n p o r e pressure is pp = 260 + 0.052 x 12 x 12,500 = 8,060 psi For the driller's m e t h o d

P~m= -- 260 + 2

+ 0. 052 × 12

8000 0 1 8010 690×0.13

= 1,285 psi

For the e n g i n e e r ' s m e t h o d 175 Petal, = 0.026(12.9 - 12.0) 0-~-3

+ [ ' | ( 0 . 0 2 6 × 0 . 9 × 1,346.1) 2 + 0 . 0 5 2 × 1 2 . 9 8 , 0 6 0 × 3 0 × 1 . 3 5 × 5 8 0 |°51 69"-0x-0-~1"3 _1 L = 1,222 psi The engineer's method normally results in lower maximum surface pressure than the driller's method. For fast field-type calculations, the following equation for the engineer's method can be used:

Pcm~ = 200(PpAVp~k] °SAV

(4-305)

All symbols in Equation 4-305 are the same as those used above.

Maximum Borehole Pressure W h e n the top of the gas b u b b l e j u s t reaches the casing setting depth, the o p e n part of the hole is e x p o s e d to the highest pressure. If this pressure is less

Fishing Operations and E q u i p m e n t

1113

than the formation fraction pressure, the kick can be circulated out of the hole safely without danger of an u n d e r g r o u n d blowout. If the driller's m e t h o d is used, this m a x i m u m pressure Pbm can be obtained from

2

Pbm - (Pp - 0.052 × Ym × H + 0.052~mD1)pbm - 0.052~m AVppp - 0 AV

(4-306)

Example 4 The data for this example are the same as the data used in Example 3. Casing setting depth = 9,200 ft Formation fracturing pressure at casing shoe = 7,550 psi It is required to determine whether or not the formation at the casing shoe will break down while circulating the kick out of the hole. The a n n u l u s volume capacity in an o p e n hole is 0.046 b b l / f t .

Solution Using Equation 4-306 we write Pb~m -

(8,060

- 0. 052 x 12 x 12,500 + 0. 052 x 12 x 7,550)Pbm

-0.052×12× 30×8,060 =0 0.046 Solving the above equation yields Pbm = 5,561 psi. Since the maximum expected pressure in an open hole is less than the formation fracture pressure, the kick can be safely circulated out of the hole.

FISHING OPERATIONS AND EQUIPMENT Fishing Operations A fish is a part of the drillstring that separates from the u p p e r r e m a i n i n g p o r t i o n of the drillstring. This can result from the drillstring failing mechanically, or from the lower p o r t i o n of the drillstring b e c o m i n g stuck a n d having to be disconnected from the lower p o r t i o n to instigate an operation to free and retrieve the lower portion with a strengthened, specialized string. J u n k are small items that fall into the borehole, or are left b e h i n d in the b o r e h o l e d u r i n g drilling operations. These are nondrillable items that must be retrieved before drilling operations can continue [146-148]. Whenever there is a fish or j u n k in the hole, it must be removed from the borehole. The technique of removing the fish or j u n k from the borehole is called

fzshing.

It is i m p o r t a n t to remove the fish or j u n k from the borehole as quickly as possible. The longer these items remain in a borehole, the more difficult they

1114

Drilling and Well C o m p l e t i o n s

will be to retrieve. Further, if the fish or j u n k is in an open-hole section o f a borehole, the l o n g e r such a b o r e h o l e remains open, the m o r e likely b o r e h o l e stability p r o b l e m s are to occur. T h e r e is an i m p o r t a n t t r a d e o f f that must be m a d e d u r i n g any fishing operation. Although the actual cost o f a fishing o p e r a t i o n is normally small c o m p a r e d to the cost o f the drilling rig and o t h e r investments in the borehole, if a fish or j u n k cannot be removed from the b o r e h o l e in a timely fashion, it may be necessary to s i d e t r a c k ( d i r e c t i o n a l l y drill) a r o u n d the fish or j u n k , or drill a n o t h e r borehole. Thus, the e c o n o m i e s o f the fishing o p e r a t i o n and the o t h e r i n c u r r e d costs at the well site must be carefully and continuously c o n s i d e r e d while the fishing o p e r a t i o n is u n d e r way. It is very i m p o r t a n t to know when to terminate the fishing o p e r a t i o n and get on with the p r i m a r y objective o f drilling the borehole.

Causes and Prevention T h e r e are a n u m b e r o f causes for fishing operations. Many o f the causes are preventable by careful planning o f the drilling o p e r a t i o n and being very watchful for the indication o f possible future trouble [149]. T h e major causes are: 1. M e c h a n i c a l f a t i g u e a n d overstress o f d r i l l s t r i n g c o m p o n e n t s p r o b a b l y accounts for a large p o r t i o n o f the fish and j u n k left in a borehole. T h e most c o m m o n location o f a drillstring failure is in the d r i l l p i p e j u s t above the drill collars, usually in a tool j o i n t at the base o f the t h r e a d e d pin. Also, drill collar tool j o i n t s are notorious failure locations. Again, the base o f the t h r e a d e d pin is the most likely location. Such possible failures can be prevented by conducting nondestructive testing on these drillstring comp o n e n t s p r i o r to placing t h e m back in the borehole. Such nondestructive testing p r o g r a m s have been responsible for reducing fishing operations over the past two decades. 2. Stuck drillstring is responsible for many fishing operations. A drillstring can b e c o m e stuck because o f a n u m b e r o f problems. Pressure differential sticking, caving o f the borehole wall, cuttings accumulations and key-seating o f drill collars are a few o f these problems. Often when the drillstring b e c o m e s stuck it is n e c e s s a r y to unscrew the u n s t u c k p o r t i o n s o f the drillstring, remove this portion, and return to the fish with a strengthened, specialized string for removing the fish. Usually there are signs that the drillstring is in d a n g e r o f being stuck p r i o r to the actual sticking o f the string. T h e drilling crew must be constantly alert for these signs and react to t h e m quickly. If these signs are not i g n o r e d , fishing o p e r a t i o n s can be avoided. 3. Broken bit c o m p o n e n t s left b e h i n d in a b o r e h o l e when the drillstring is removed and h a n d tools and o t h e r foreign objects falling in the b o r e h o l e constitute j u n k ,that must be retrieved. These c o m p o n e n t s cannot be drilled up d u r i n g n o r m a l d r i l l i n g o p e r a t i o n s . T h e y may be m i l l e d with metal drilling bits and o t h e r special a p p a r a t u s that can eventually remove these items in pieces. Such j u n k items can be very difficult to remove. 4. L o g g i n g cable and wireline can p a r t d u e to the logging tool b e c o m i n g stuck. Such cable and wireline can be removed by special fishing tools. 5. Production tubulars after long p e r i o d s o f service in a b o r e h o l e can c o r r o d e and b e c o m e weakened. W h e n such tubulars are removed d u r i n g well workovers, these tubulars may fail mechanically. P r o g r a m s that have m i n i m i z e d

Fishing O p e r a t i o n s a n d E q u i p m e n t

1115

corrosion in production wells have decreased the necessity for fishing operations in p r o d u c t i o n wells.

Fishing Tools T h e r e are basically t h r e e categories of fishing tools. These are (1) those used to d e f i n e the g e o m e t r y and orientations of the fish or j u n k in the borehole, (2) those used to recover tubular items (fish), a n d (3) those used to recover miscellaneous items (junk).

Geometry and Orientation Tools T h e tools used to d e f i n e the g e o m e t r y a n d o r i e n t a t i o n of the fish or j u n k in the b o r e h o l e vary f r o m s o p h i s t i c a t e d d o w n h o l e televiewers to very s i m p l e impression blocks such as that shown in Figure 4-354. T h e impression block has a soft lead insert in the lower e n d of its steel housing. T h e impression block is made up to the end of the fishing drillstring and is lowered to the top of the fish (or junk). A small amount of weight is placed on the impression block, which

Figure 4-354. Impression block. (Courtesy Bowen Tools, Inc.)

1116

Drilling and Well C o m p l e t i o n s

places an i m p r i n t o f the top o f the f ~ h on the lead insert. This i m p r i n t when recovered enables the o p e r a t o r to assess the c o n f i g u r a t i o n o f the fish and its location in the borehole. The o p e r a t o r is then in a b e t t e r position to select the p r o p e r tool n e e d e d to successfully complete the fishing operation. Sophisticated televiewers are r u n in the b o r e h o l e much like any o t h e r logging tool. These services are o b t a i n e d from c o m p a n i e s that specialize in such equipment.

Tubular Fishing Tools T h e r e are two subcategories o f tubular fishing tools: those that can attach to the inside o f the tubular fish and those that can attach to the outside o f the tubular fish.

Inside Fishing T o o l s . Most o f the fishing tools designed to catch tubular items from the inside are variations on the tap or spear concept. Figure 4-355 shows an example o f a simple tap. A tapered tap is a tool with case-hardened lead. T h e tap when lowered on a d r i l l p i p e string can engage a fish when the u p p e r part o f the fish consists o f an inside open element (box). The taper o f the fishing tool p e r m i t s easy entry into the u p p e r p a r t o f the fish. T h e coarse lead allows for positive e n g a g e m e n t with the box end o f the u p p e r p a r t o f the fish. A box tap uses a specific t h r e a d e d spear to screw into a specific o p e n box element. Figure 4-356 shows an example o f a c o m p l e x spear fishing tool. O n c e the spear is inside the fish, rotation to the left will place the g r a p p l e in the engaging position. Upward pull will wedge the g r a p p l e in the fish. T h e fishing tool can be released if it b e c o m e s necessary to come out o f the hole. Bump downward

Figure 4-355. Inside fishing tool, tap. (Courtesy Bowen Too~s, Inc.)

Fishing Operations a n d E q u i p m e n t

1117

to break the hold of the grapple and t u r n to the right a few turns and the fish should release.

Outside Fishing Tools. Outside fishing tools must pass over the outside of the fish before attaching themselves. The simplest of the outside fishing tools is the die collar, which is shown in Figure 4-357 with lipped guide. This is a short tubular that has case-hardened coarse threads cut in the i n n e r surface of the tool. Such a tool is used to recover tubular items. The overshot is a n o t h e r outside fishing tool. This tool consists of a tapered bowl in which slips are free to move up and down. Figure 4-358 shows a release type of overshot. The entire tool is designed to fit over the u p p e r part of a fish. In the example the overshot is lowered on a drillpipe string a n d rotated slowly to the right until the fish is inside the overshot. Lifting the string allows the slips (or basket grapple) to wedge the u p p e r part of the fish in the overshot. If it is necessary to release the grip of the overshot, the weight of the fish is d r o p p e d and simultaneously rotates to the right. This should release the fish when the string is slowly lifted.

Figure 4-356. Inside fishing tool, spear. (Courtesy Bowen Tools, Inc.)

1118

Drilling and Well C o m p l e t i o n s

Figure 4-357. Outside fishing tool, die collar with lipped guide. (Courtesy Bowen Too~s, Inc.)

Auxiliary Equipment. T h e r e are a n u m b e r o f special tools that are used that allow the fishing tools to attach themselves to the fish. A n i m p o r t a n t auxiliary tool is the knuckle joint. Figure 4-359 shows the typical knuckle j o i n t in the knuckled position and in the straight position. Such a device used in conjunction with an overshot (see Figure 4-358) and a wall-hook guide (see Figure 4-360) can be used effectively to engage a fish in a washed-out p o r t i o n o f the borehole. Figure 4-361 shows the useful action o f the knuckle joint and the wall-hook guide in retrieving the fish from its position in the washout. In some cases a stuck d r i l l p i p e or drill collar cannot b e recovered by simple grappling o f the pipe and pulling out o f the hole. Often if circulation has ceased, i n c o m p l e t e formations will cave a r o u n d the fish. In such situations, wash-over equipment must be used to expose the u p p e r part o f the fish so that the fishing tool can effectively engage it. In such situations a wash-over shoe is placed on the bottom o f the fishing string. Above the wash-over shoe is about 200 to 500 ft o f wash-over pipe and above the wash-over pipe is usually a wash-over safety joint. The entire wash-over string is placed on the bottom o f a string o f drillpipe (entire assembly constitutes the fishing string). T h e wash-over string must have an inside d i a m e t e r that will allow the fish to pass into its interior once the cavings and cuttings are cut and washed away from the sides o f the fish. Figure 4-362 shows a typical wash-over shoe. Figure 4-363 shows the wash-over safety j o i n t that allows the wash-over string to be released if the string becomes stuck and provides the cross-over between the wash-over p i p e and the drillpipe. Once the wash-over o p e r a t i o n is c o m p l e t e d and the u p p e r e n d o f the fish exposed, n o r m a l fishing tools can b e used to retrieve the fish. T h e r e are a n u m b e r o f o t h e r devices that can be used to aid in the retrieval o f a fish. These vary from mechanical tubular cutting e q u i p m e n t to explosive devices. This type o f e q u i p m e n t can be very useful in s e p a r a t i n g the fish into smaller parts that can be retrieved m o r e easily than the whole fish.

Fishing O p e r a t i o n s a n d E q u i p m e n t

1119

Figure 4-358. Outside fishing tool, overshot. (Courtesy Bowen Tools, Inc.)

Hydraulic and Impact Tools. W h e n additional force is n e e d e d to remove a fish from the borehole, a hydraulic pulling tool can be used. T h e hydraulic pulling tool is essentially a d o w n h o l e hydraulic jack. This tool attaches to the top of t h e fish a n d to slips t h a t e n g a g e t h e casing. U s i n g a series o f pistons, a m e c h a n i c a l a d v a n t a g e as high as 100 to 1 can be o b t a i n e d . This force is transmitted to the casing instead of to the derrick. In general, this tool can apply much g r e a t e r a n d m o r e direct force to a fish than can b e b r o u g h t to b e a r t h r o u g h the d e r r i c k a n d the drilling line. T h e hydraulic pulling tool is used in conjunction with n o r m a l fishing tools and is used above the fishing tools in the string. This special tool must be used in the cased p o r t i o n of the borehole. A j a r is a device for providing an impact load to the fish when the fish cannot be retrieved by n o r m a l string and d e r r i c k forces. T h e r e are purely mechanical jars a n d hydraulic jars (see the section titled "Drilling Bits and Downhole Tools" for details on d r i l l i n g jars). In a fishing o p e r a t i o n the j a r is usually placed

1120

Drilling and Well Completions

Knuckle Joint in Knuckled Posit on

Knuckle Joint n Straight Position

Figure 4-359. Knuckle joint auxiliary tool. (Courtesy Bowen Tools, Inc.)

Figure 4-360. Well-hook guide auxiliary tool. (Courtesy Bowen Tools, Inc.)

Fishing O p e r a t i o n s a n d E q u i p m e n t

Knuckle Joint with Overshot and Wallhook Guide contacting Fish in a cavity

1121

After contacting the Fish, ready for retrieval

Figure 4-361. Knuckle joint action to retrieve a fish in a washout. (Courtesy

Bowen Too~s, Inc.) immediately above the fishing tool in the string. In this location the shock, or impulse, that the j a r provides to the fish is attenuated the least. The mechanical j a r provides for a direct mechanical impact load from a metalto-metal contact that is a multiple o f the tension (or compression) attainable by the drillstring. T h e hydraulic j a r again uses a direct mechanical impact blow. T h e hydraulic f l u i d in this tool acts mainly to p r o v i d e a delay while the desired d e r r i c k pull is achieved p r i o r to actuation o f the tool. Such tools may also be o p e r a t e d by c o m p r e s s e d gas in a closed chamber. T h e c o m p r e s s e d gas can be used to drive a h a m m e r within the j a r that strikes the top o f a tool anvil.

1122

Drilling and Well Completions

Figure 4-362. Washover shoe. (Courtesy Bowen Tools, Inc.)

Figure 4-363. Washover safety joint. (Courtesy Bowen Tools, Inc.)

Fishing O p e r a t i o n s a n d E q u i p m e n t

1123

Junk Fishing Tools There are items other than tubulars that must be fished from boreholes. These are drill bit parts, pieces o f downhole tools left in the b o r e h o l e and h a n d tools accidentally d r o p p e d in the borehole. Nearly all o f these items cannot be drilled by a n o r m a l rock bit. Such items are called junk.

Milling Tool. T h e milling tool is a c o m m o n device used for fishing j u n k . T h e milling tool is used to g r i n d the j u n k into small pieces so that the pieces can be circulated to the surface or removed in a j u n k basket. Figure 4-364 shows the various milling tools that can be used to drill up j u n k in the b o t t o m o f the

Figure 4-364. Milling tools. (Courtesy Bowen Tools, Inc.)

1124

Drilling and Well C o m p l e t i o n s

borehole. These milling tools are especially designed to drill steel. The milling tool is placed on the bottom of a drillstring designed to drill up junk. Such milling tools are designed with carbide-cutting surfaces. A properly designed milling tool will drill up the steel j u n k rapidly and not be effective in drilling rock.

Junk Basket. The j u n k basket is a tool that can be run in c o n j u n c t i o n with a milling tool or separately. It is designed to recover the smaller pieces that have b e e n milled or pieces too large to be circulated to the surface. Figure 4-365 shows a typical j u n k basket. The j u n k basket is placed directly above the milling tool in the string.

Magnetic Fishing Tools. Since many o f the items that are lost in the b o r e h o l e are steel, the use o f a m a g n e t to recover small j u n k has b e e n very successful. Magnetic fishing tools may be either a permanent magnet type, or an electromagnetic type. Most in use are o f the p e r m a n e n t m a g n e t type. In the p e r m a n e n t m a g n e t type, the p e r m a n e n t m a g n e t is located inside a n o n m a g n e t i c section. Figure 4-366 shows a fishing m a g n e t with p o r t s to allow circulation t h r o u g h the tool body. The p e r m a n e n t m a g n e t is a separate section o f the tool. The fishing m a g n e t is placed at the b o t t o m o f a string o f d r i l l p i p e and is lowered to the b o t t o m o f the hole. T h e r e the m a g n e t attracts and holds the j u n k in place while the string is retrieved. Free Point W h e n a drillstring or o t h e r tubular becomes stuck in a b o r e h o l e it is very i m p o r t a n t that the d e p t h where the p i p e is stuck be d e t e r m i n e d . In most cases this can be accomplished r a t h e r simply. The d e p t h to where the drillstring is free and where sticking o f the p i p e c o m m e n c e s is called the free point [148,150]. This free point depth can be calculated using measurements taken on the rig floor. Figure 4-367 shows a p i p e stuck at s o m e d e p t h Lf (ft) less than the total measure d e p t h D (ft). The length Lf is the distance to the free point, or the length from the surface to where the p i p e stuck. To obtain Lf, the following p r o c e d u r e is c a r r i e d out: 1. A n upward force F~ is a p p l i e d to the p i p e via the drawworks. This force is slightly greater than the total weight o f the drillstring. This ensures that the entire drillstring is in tension. 2. W i t h this tension on t h e drillstring, a reference mark is m a d e on the drillstring e x p o s e d at the top o f the rotary table. 3. A larger u p w a r d force F 2 is then a p p l i e d to the drillstring. This causes the free p o r t i o n o f the drillstring to elastically stretch by an amount L (ft). The stretch (or elastic displacement) is m e a s u r e d by the movement o f the original reference mark. The m a g n i t u d e o f F 2 is limited by the yield, or elastic limit o f the pipe steel. Knowing the stretch L and the forces a p p l i e d F I and F 2 and using H o o k e ' s law (see the section titled Strength of Materials in C h a p t e r 2), the length to the free point is L Lf = E A m (F 2 - F, )

(4-307)

Fishing Operations and Equipment

Figure 4-365. Junk basket. (Courtesy Bowen Tools, Inc.)

1125

1126

Drilling and Well C o m p l e t i o n s

Figure 4-366. Fishing magnet. (Courtesy Bowen Tools, /nc.) where

E A L F] a n d F~

= Young's m o d u l u s (30 x 106 psi) = cross-sectional area o f the pipe in ft ~ = stretch distance in ft = forces placed on the drillstring in lb

Example 1 A string o f 3 ~ in. diameter, 13.3 lb/ft, G r a d e E drillpipe is stuck in a 12,000-ft borehole. T h e driller places 150,000 lb o f tension on the drillstring above the normal weight o f the drillstring and makes a mark on the drillstring at the top o f the rotary table. T h e driller then increases the l o a d to 210,000 lb b e y o n d the weight o f the drillstring (which is less than the yield o f the pipe). T h e original m a r k on the d r i l l s t r i n g shows t h a t the free p o r t i o n o f the d r i l l s t r i n g has s t r e t c h e d 4 ft d u e to t h e a d d i t i o n a l l o a d p l a c e d on the d r i l l s t r i n g by the drawworks. W h e r e is the drillstring stuck? T h e cross-sectioned area o f the d r i l l p i p e is approximately 13.3 490

A----

= O. 0271 ft ~

Casing and Casing String Design

1127

5

L

Dm

~11 I~ Stuck Point

Figure 4-367. Free point.

where the specific weight of steel is 490 lb/ft ~. Equation 4-308 becomes

Lf=

(30 x 10~)(144)(0.0271)(4) (210,000-150,000)

= 7805

CASING AND CASING STRING DESIGN Types of Casing Based upon the primary function of the casing string, there are five types of casing to be distinguished.

Stove or Surface Casing The stove pipe is usually driven to sufficient depth (15-60 ft) to protect loose surface formation and to enable circulation of the drilling fluid. This pipe is sometimes cemented in predrilled holes.

1128

Drilling and Well Completions

Conductor String This string acts as a guide for the remaining casing strings into the hole. The purpose of conductor string is also to cover unconsolidated formations and to seal off shallow overpressured formations. The conductor string is the first string that is always cemented to the top and equipped with casing head and blowout prevention (BOP) equipment.

Surface Casing This is set deeply enough to protect the borehole from caving-in in loose formations frequently encountered at shallow depths, and protects the freshwater sands from contamination while subsequently drilling a deeper hole. In case the conductor string has not been set, the surface casing is fitted with casing head and BOP.

Intermediate Casing Also called protection string, this is usually set in the transition zone before abnormally high formation pressure is encountered, to protect weak formations or to case off loss-of-circulation zones. Depending u p o n geological conditions, the well may contain two or even three intermediate strings. Production string (oil string) is the string through which the well is produced. Intermediate or production string can be set as a liner string. The liner string extends from the bottom of the hole upward to a point about 150-250 ft above the lower end of the upper string.

Casing Program Design Casing p r o g r a m design is accomplished by two steps. In the first step, the casing sizes and corresponding bit sizes should be determined. In the second step, the setting depth of individual casing strings ought to be evaluated. Before starting the casing p r o g r a m design, the designer ought to know the following basic information: • the purpose of the well (exploratory or development drilling); • geological cross-sections that should consist of type of formations, expected hole problems, pore and formation's fracture pressure, number and depth of water, oil, gas horizons; • available rock bits and casing sizes; • load capacity of a derrick and mast if the type of rig has already been selected. Before starting the design, it must be assumed that the production casing size and depth of the well have been established by the petroleum engineer in cooperation with a geologist, so that the hole size (rock bit diameter) for the casing may be selected. Considering the diameter of the hole, a sufficient clearance beyond the coupling outside diameter must be provided to allow for mud cake and also for a good cementing job. Field experience shows that the casing clearance should range from about 1.0 in to 3.5 in. Larger casing sizes require greater value of casing clearance. Once the hole size for production string has been selected, the smallest casing through which a given bit will pass

Casing and Casing String Design

1129

is next d e t e r m i n e d . T h e bit d i a m e t e r should be a little less (0.05 in.) than casing drift diameter. A f t e r choosing the casing with a p p r o p r i a t e drift diameter, the outside coupling d i a m e t e r of this casing may be found. Next, the a p p r o p r i a t e size of the bit should be d e t e r m i n e d and the p r o c e d u r e repeated.

Example 1 T h e p r o d u c t i o n casing string for a certain well is to consist of 5-in. casing. D e t e r m i n e casing and c o r r e s p o n d i n g bit sizes for the intermediate, surface and c o n d u c t o r string. Take casing d a t a and bit sizes from Table 4-140.

Solution For production hole, select a 6 ~-in. rock bit. Therefore, the casing clearance = 6.75 - 5.563 = 1.187 in. For i n t e r m e d i a t e string, select a 7 g-in. casing, assuming that wall thicknesses that c o r r e s p o n d to drift d i a m e t e r of 6.640 and 6.5 in. will not be used. For the 7 g-in. intermediate string, use a 9 2a-in. bit. T h e casing clearance = 9.875 - 8.5 -1.375 in. For surface string, select 10¼-in. casing. Note that only unit weights corresponding to drift diameters of 10.036 and 9.896 in. can be used. For the 10 ~-in. casing, use a 13~-in. bit, so the casing clearance = 13.75 - 11.75 = 2.0 in. For c o n d u c t o r string, select 16-in. casing; the bit size will then be 20 in. and the casing clearance = 20 - 17 = 3 in. Having d e f i n e d bit and casing string sizes, the setting d e p t h of the individual strings should be d e t e r m i n e d . T h e o p e r a t i o n of setting is g o v e r n e d by the p r i n c i p l e a c c o r d i n g to which c a s i n g s h o u l d be p l a c e d as d e e p as p o s s i b l e . However, t h e d e s i g n e r must r e m e m b e r to ensure the safety of the drilling crew from possible blowout, and to maintain the hole stability, well c o m p l e t i o n aspects (formation damage) and state regulations. In general, casing should be set: * where drilling f l u i d could c o n t a m i n a t e freshwater that might be used for d r i n k i n g or o t h e r h o u s e h o l d purposes; • where unstable formations are likely to cave or slough into the borehole; * where loss of circulation may result in blowout; * where drilling f l u i d may severely d a m a g e p r o d u c i n g horizon. Currently, a g r a p h i c a l m e t h o d of casing setting d e p t h d e t e r m i n a t i o n is used. T h e m e t h o d is b a s e d on t h e principle according to which the b o r e h o l e pressure should always be g r e a t e r than p o r e pressure and less than fracture pressure. For practical purposes, a safety margin for reasonable kick conditions should be i m p o s e d (see Figure 4-368). Even when the b o r e h o l e pressure is adjusted correctly, p r o b l e m s may arise from t h e contact between the drilling f l u i d and the formation. It d e p e n d s u p o n the type of drilling f l u i d and formation, but, in g e n e r a l , the m o r e t i m e s p e n t d r i l l i n g in an o p e n hole, the g r e a t e r the p o s s i b i l i t y of f o r m a t i o n caving or s l o u g h i n g into t h e b o r e h o l e . F o r m a t i o n instability may lead to expensive work in the borehole, which influences the time and cost of the d r i l l i n g o p e r a t i o n . To arrest or reduce this p r o b l e m , special t r e a t m e n t drilling fluids might be used, b u t these special d r i l l i n g fluids are

1130

Drilling and Well Completions Table 4-140 Casing and Rock Bit Sizes Outside Diameter of Casing (inches)

Outside Diameter of Coupling (inches)

9%

10.625

8.907 8.845 8.765 8.679 8.599 8.525 8.379

103/4

11.750

10.036 9.894 9.794 9.694 9.604 9.504 9.404

6.010 5.924 5.796 5.666 5.550

113/4

12.750

10.994 10.928 10.844 10.724 10.616

6.413 6.331 6.241 6.151 6.059 5.969 5.879 5.795

13%

14.375

12.559 12.459 12.359 12.259 12.191

16

17.000

15.188 15.062 14.938

18%

20.000

17.567

20

21.000

18.936

Outside Diameter of Casing (inches)

Outside Diameter of Coupling (inches)

41/2

5.000

3.965 3.875 3.795

5

5.563

4.435 4.369 4.283 4.151

51/2

6.050

4.919 4.887 4.825 4.767 4.653 4.545

6%

7.390

7

7.656

7%

8%

8.500

9.625

Drift Diameter (inches)

7.000 6.900 6.844 6.750 6.640 6.500

Drift Diameter (inches)

7.972 7.892 7.796 7.700 7.600 7.500 7.386

These data have been extracted from API Bulletin 5C2, API Specifications 5A and Hughes Tool Company Bit Handbook. Source: From Ref. [155].

Casing and Casing String Design PRESSURE GRADIENT 0.4

0.5

0.6

0.7

1131

(psi/ft)

0.8

0.9

hO

0 • "~• • ',~. \

2000

\

Ref; Adoms.N., Well Control Problems ond Solutions". Petroleum Publishin~ Co., Tutso, 1980.

Fracture Pressure

",J" Gradient 4000

X 6000

%. %

D1

\

8000

Pore (Formation) Pressure Gradient

10.000

\

\ t

02

12.000

\

14.000 D 1 - Setting depth of first intermediate D 2 - Setting depth of second intermediate

16,000

8

9

I0

PRESSURE

11

12

13

14

15

16

17

18

19

G R A D I E N T (in equivolent ppg )

Figure 4-368. Well planning. (From Ref. [157].)

expensive. Therefore, the casing and drilling fluid programs depend on each other, and solving the issue of the correct casing setting depth evaluation is a rather complicated, optimizing problem. Example 2

Suppose that in some area the expected formation pressure gradient is 0.65 psi/ft and formation fracture pressure gradient is 0.85 psi/ft. A gas-bearing

1132

Drilling a n d Well C o m p l e t i o n s

f o r m a t i o n is expected at d e p t h o f 15,000 ft. Assume that a gas kick occurs that, to be removed from the hole, induces a surface pressure o f 2,000 psi. T h e first i n t e r m e d i a t e casing is set at a d e p t h o f 7,200 ft. D e t e r m i n e the setting d e p t h for the second intermediate casing string if required in given conditions. Assume d r i l l i n g f l u i d pressure g r a d i e n t ffi 0.65 p s i / f t .

Solution T h e f o r m a t i o n fracture pressure line is Pf-- (0.85)(D) T h e b o r e h o l e pressure line is Pbh ffi 2000 + (0.65)(D) SO

(0.85)(D)

=

2,000 + (0.65)(D)

2000 D = ~ = 10,000ft 0.2 T h e second i n t e r m e d i a t e casing string is r e q u i r e d a n d must be set at a d e p t h o f 10,000 ft.

Casing Data

Special Note: N o t h i n g in this specification should be i n t e r p r e t e d as indicating a preference by the c o m m i t t e e for any material or process, n o r as indicating equality between the various materials or processes. In the selection o f materials a n d processes, the p u r c h a s e r must be g u i d e d by his or her experience a n d by the service for which the p i p e is intended. Casing is classified a c c o r d i n g to its m a n n e r o f m a n u f a c t u r e , steel g r a d e , d i m e n s i o n s and weights, a n d the type o f coupling. T h e following are excerpts from API Spec. 5A, 35th Edition, March 1981. Process of Manufacture Casing a n d liners shall be seamless or electric welded as d e f i n e d below and as specified on the purchase. a. Seamless p i p e is d e f i n e d as a wrought steel tubular p r o d u c t m a d e without a welded seam. It is m a n u f a c t u r e d by hot working steel or, if necessary, by subsequently cold finishing the hot-worked tubular p r o d u c t to p r o d u c e the d e s i r e d shape, dimensions a n d properties. b. Electric-welded p i p e is d e f i n e d as p i p e h a v i n g o n e l o n g i t u d i n a l s e a m f o r m e d by electric-flash welding or electric-resistance welding, without the a d d i t i o n o f extraneous metal. T h e weld seam o f electric-welded p i p e shall b e h e a t t r e a t e d after w e l d i n g to a m i n i m u m t e m p e r a t u r e o f 1,000°F (538°C), or processed in such a m a n n e r that no u n t e m p e r e d martensite remains.

Casing and Casing String Design

1133

Physical Properties (Section 4, API Specification 5A) Tensile Properties. The tensile properties, except elongation, of the upset ends of the casing and tubing shall comply with the requirements given for the pipe body (see Table 4-141). In case of dispute, the tensile properties (except elongation) of the upset shall be determined from a tensile test cut from the upset. Where elongation is recorded or reported, the record or report shall show the nominal width of the test specimen when strip specimens are used, or state when full section specimens are used. Y i e l d S t r e n g t h . The yield strength (except of steel grades P-105, P-110) shall be the tensile strength required to produce a total elongation of 0.5% of the gage length as determined by an extensometer or by multiplying dividers. In case of steel grade P-105 and P-110, the yield strength is defined as the tensile stress required to produce a total elongation of 0.6% of the gage length.

Tensile Tests. Tensile properties shall be determined by tests on longitudinal specimens conforming to the requirements of Paragraph 4.4 (see API Specification 5A) and ASTM A370: Mechanical Testing of Steel Products, Supplement II, Steel Tabular Products. Dimensions, Weights and Lengths (Section 6, API Specification 5A) Dimensions and Weights Pipes shall be furnished in the sizes, wall thicknesses and weights as specified on the purchase order. (See Tables 4-142 to 4-145 for more detailed information on dimensions and weights of casing.)

Table 4 - 1 4 1 Casing Properties Yield Strength (psi) Steel Grade H-40 J-55 K-55 C-75 N-80 L-80 C-95 P-105 (tubing) P-110

Tensile Strength (psi)

rain

max

rain

4,000 55,000 55,000 75,000 80,000 80,000 95,000 105,000

-80,000 80,000 90,000 110,000 95,000 110,000 135,000

60,000 75,000 95,000 95,000 100,000 95,000 105,000 120,000

110,000

135,000

125,000

Min. elongation %, 2" specimens The minimum elongation in 2" specimens is determined by formula: e = 62500(A°2/U °'9) where: A = cross-sectional area of tensile test specimen, in3; U = specified tensile strength, psi.

Note: There are also other grades of casing available from various manufacturers. For example, Lone Star offers steel grades SS-95 for sour service, S-80 and S-95 for nominal service. Mannesmann offers a C-90 for sour service and S00-95, 124, 140 for high-strength service. There is also available a tentative API grade V-150 (Y~n~n= 150,000 psi, Y~n,x= 180,000 psi), which has not yet been adopted by the API.

Table 4-142 Short Round-Thread Casing Dimensions and Weights l

2

3

4

Nominal

5

6

l

Weight:l

Wall Thickness, in. t

Inside Diameter, in. d

Plain End, lb/ft Wpe

Threads2 and Co UPling ]b ew

Size: Outside Diameter, in. D

9.50 10.50 11.60

0.205 0.224 0.250

4.090 4.052 4.000

9.40 10.23 11.35

4.20 3.80 3.40

9~ 9~ 9~

5 5 5

11.50 13.00 15.00

0.220 0.253 0.296

4.560 4.494 4.408

11.23 12.83 14.87

5.40 4.80 4.20

5~ 5~ 5~

14.00 15.50 17.00

0.244 0.275 0.304

5.012 4.950 4.892

13.70 15.35 16.87

5.40 4.80 4.40

6~ 6~

20.00 24.00

0.288 0.352

6.049 5.921

19.49 23.58

11.00 9.60

7 7 7 7

17.00 20.00 23.00 26.00

0.231 0.272 0.317 0.362

6.538 6.456 6.366 6.276

16.70 19.54 22.63 25.66

10.00 9.40 8.00 7.20

7~ 7~

24.00 26.40

0.300 0.328

7.025 6.969

23.47 25.56

15.80 15.20

8~ 8~ 8~ 8-%

24.00 28.00 32.00 36.00

0.264 0.304 0.352 0.400

8.097 8.017 7.921 7.825

23.57 27.02 31.10 35.14

23.60 22.20 20.80 19.40

Size: Outside Diameter, in. D

Threads and Coupling, lb per ft

4~ 4~ 4~

2

Weight:l Threads and Coupling, lb per ft

5

6

Calculated Weight .-

32.30 36.00 40.00

0.312 0.352 0.395

9.001 8.921 8.835

31.03 34.86 38.94

24.40 23.00 21.40

10~4 103/4 103,4 103A 10~

32.75 40.50 45.50 51.00 55.50

0.279 0.350 0.400 0.450 0.495

10.192 10.050 9.950 9.850 9.760

31.20 38.88 44.22 49.50 54.21

29.00 26.40 24.40 22.60 20.80

113/4 11~/4 11~4 11~

42.00 47.00 54.00 60.00

0.333 0.375 0.435 0.489

11.084 11.000 10.880 10.772

40.60 45.56 52.57 58.81

29.60 27.60 25.00 22.60

13~ 138 13~ 13~ 13~

48.00 54.50 61.00 68.00 72.00

0.330 0.380 0.430 0.480 0.514

12.715 12.615 12.515 12.415 12.347

45.98 52.74 59.45 66.11 70.60

33.20 30.80 28.40 25.80 24.20

16 16 16

65.00 75.00 84.00

0.375 0.438 0.495

15.250 15.124 15.010

62.58 72.72 81.97

42.60 38.20 34.20

87.50

0.435

17.755

84.51

73.60

94.00 106.50 133.00

0.438 0.500 0.635

19.124 19.000 18.730

91.51 104.13 131.33

47.00 41.60 30.00

185~

Plain End, lb/ft Wpe

Threads2 and Coupling lb ew

Inside Diameter, in. d

1NominaI weights, threads and coupling (Col. 2 ), are shown for the purpose of identification in ordering.

Source: From Ref. [151].

4

Wall Thickness, in. t

20 20 20

2Weight gain due to end finishing.

3

Nominal

Calculated Weight

O~

O

O

Casing a n d Casing String Design

1135

Table 4 - 1 4 3 Long Round-Thread Casing Dimensions and Weights 1

2

$

4

Nominsl

IKsez Outaide Dis~s~P, in. D 4 ]&

4:~ 5 5

Wehrht:x Threads snd Wall C~mpli~. "t'hlekn~. lb. P~ ft. in. t 11.60

0.250

Itmide Diam~,~ ivd 4.000

5 6 Cadeul&t~ Wellrht Plain IZ"d, |b/ft wF,

Thread== and Coupli~, lb e,,

11.85

3.80

13.50 13.00

0.290 0.255

3.920 4.494

13.04 12.83

3.20 5.80

5 5 5 5~ 5 ]& 5~ 5~ 6%

15.00 18.00 21.40 24.10 15.50 17.00 20.00 23.00 20.00

0.296 0.862 0.437 0.500 0.275 0.804 0.861 0.415 0.288

4.408 4.276 4.126 4.000 4.950 4.892 4.778 4.670 6.049

5.20 4.20 2.95 1.95

5.921 5.791

14.87 17.93 21.30 24.03 15.35 16.87 19.81 22.54 19.49

23.58 27.65

6% 7 7 7 7 7 7 7% 7% 7%

32.00 23.00 26.00 29.00 32.00 35.00 36.00 26.40 29.70 33.70

0.475 0.817 0.362 0.406 0.453 0.498 0.540 0.328 0.375 0.430

5.675 6.366 6.276 6.164 6.094 6.004 5.920 6.969 6.875 6.765

31"20 22.63 25.66 26.72 31.68 84.68 37.26 25.56 29.04 33.04

7%

89.00

0.500

6.625

38.05

13.60

7% 7~ 8% 8% 8% 8%

42.80 47.10 32.00 86.00 40.00 44.00

0.562 0.625 0.352 0.400 0.450 0.500

6.501 6.375 7.921 7.825 7.725 7.625

42.39 46.72 31.10 35.14 89.29 43.89

12.01 10.16 27.60 25.60 23.80 21.80

8% 9% 9% 9%

49.00

0.557

7.511

48.00

6% 6%

24.00 28.00

0.352 0.417

36.00 0.852 40.00 0.395 43.50 0.435 9% 47.00 0.472 9% 53a50 0.545 20 94.00 0.438 20 106.50 0.500 20 133.00 0.635 1Nuldmtl weilrhta. ~reed8 ~ d aouplinlr (CoL t), are shown foe tl~ Imzl~ee d ideutlAeatio~ ha ozde~us.

8.921 84.86 8.835 38.94 8.755 42.70 8.681 46.14 8.585 52.85 19.124 91.51 19.000 104.13 18.730 131.33 S~Veights a i n due to end

5.80 5.40 4.40 3.20 13.60

12.00 10.20 8.80 10.40 9.40 8.00 6.60 5.60 4.40 19.00 17.40 15.80

19.60 32.00 30.00 28"20 26.60 23.40 6~.20 54.80 40.60 fln;-hJnz.

Source: API Spec 5A, 35th Edition, March 1981, p. 23. From Ref. [151].

Diameter T h e outside d i a m e t e r shall be within the tolerance specified in Table 4-146. For t h r e a d e d pipe, the outside d i a m e t e r at the t h r e a d e d ends shall be such that the length L 4 and the full-crest t h r e a d length L c are within the dimensions a n d tolerances in API S t a n d a r d 5B. (Inside diameters are governed by the outside diameters and weight tolerances.)

Wall Thickness Each l e n g t h o f p i p e shall be m e a s u r e d for c o n f o r m a n c e to wall thickness requirements. The wall thickness at any place shall not be less than the tabulated thickness minus the permissible u n d e r t o l e r a n c e specified in Table 4-146. Wall thickness m e a s u r e m e n t s shall b e m a d e with a m e c h a n i c a l c a l i p e r o r with a p r o p e r l y c a l i b r a t e d nondestructive testing device o f a p p r o p r i a t e accuracy. In

1136

Drilling and Well Completions Table 4-144 Buttress Thread Casing Dimensions and Weights 1

2

3

4

5

6

7

Calculated Weight Nominal Weight: 1 Threads and Coupling, lb p e r ft

Wall Thickness, in.

t

d

wpe

ew

ew

4],'2 4],'2 4]'2

10.50 11.60 13.50

0.224 0.250 0.290

4.052 4.000 3.920

10.23 11.35 13.04

5.00 4.60 4.00

2.56 2.16 1.56

5 5 5 5 5

13.00 15.00 18.00 21.40 24.10

0.253 0.296 0.362 0.437 0.500

4.494 4.408 4.276 4.126 4.000

12.83 14.87 17.93 21.30 24.03

6.60 5.80 4.40 2.46 1.24

2.42 1.62 0.22 - - 1.72 - - 2.94

5]'2 5]'2 5],'2 5]'2

15.50 17.00 20.00 23.00

0.275 0.304 0.361 0.415

4.950 4.892 4.778 4.670

15.35 16.87 19.81 22.54

6.40 5.80 4.60 3.40

2.10 1.50 0.30 - - 0.90

6,~ 6~ 6~ 6~

20.00 24.00 28.00 32.00

0.288 0.352 0.417 0.475

6.049 5.921 5.791 5.675

19.49 23.58 27.65 31.20

14.40 12.60 10.60 9.00

2.38 0.58 - - 1.42 - - 3.02

7 7 7 7 7 7

23.00 26.00 29.00 32.00 35.00 38.00

0.317 0.362 .0.408 0.453 0.498 0.540

6.366 6.276 6.184 6.094 6.004 5.920

22.63 25.66 28.72 31.68 34.58 37.26

11.00 9.60 8.20 6.80 5.60 4.20

-----

7~ 7~ 7~ 7~ 7,~ 7,~

26.40 29.70 33.70 39.00 42.80 47.10

0.328 0.375 0.430 0.500 0.562 0.625

6.969 6.875 6.765 6.625 6.501 6.375

25.56 29.04 33.04 38.05 42.39 46.72

20.60 18.80 17.00 14.60 11.39 9.23

6.21 4.41 2.61 0.21 - - 3.01 - - 5.17

8~ 8~ 8~ 8~ 8~

32.00 36.00 40.00 44.00 49.00

0.352 0.400 0.450 0.500 0.557

7.921 7.825 7.725 7.625 7.511

31.10 35.14 39.29 43.39 48.00

28.20 26.20 24.20 22.20 19.80

6.03 4.03 2.03 0.03 - - 2.37

9,% 9,% 9~ 9~ 9,%

36.00 40.00 43.50 47.00 53.50

0.352 0.395 0.435 0.472 0.545

8.921 8.835 8.755 8.681 8.535

34.86 38.94 42.70 46.14 52.85

31.00 29.00 27.20 25.60 22.40

6.48 4.48 2.68 1.08 - - 2.12

10~4 10~4 10~ 10~

40.50 45.50 51.00 55.50

0.350 0.400 0.450 0.495

10.050 9.950 9.850 9.760

38.88 44.22 49.50 54.21

34.40 31.80 29.40 27.00

7.21 4.61 2.21 - - 0.19

11 ~4 11~4 11~

47.00 54.00 60.00

0.375 0.435 0.489

11.000 10.880 10.772

45.56 52.57 58.81

35.80 32.40 29.60

.... .... ....

13:~ 134 13~ 13~

54.50 61.00 68. O0 72.00

0.380 0.430 0.480 0.514

12.615 12.515 12.415 12.347

52.74 59.45 66.11 70.60

40.20 36.80 33.60 31.60

.... .... .... ....

16 16

75.00 84.00

0.438 0.495

15.124 15.010

72.72 81.97

45.60 39.60

.... ....

87.50

0.435

17.755

84.51

86.40

....

94.00 106.50 133.00

0.438 0.500 0.635

19.124 19.000 18.730

91.51 104.13 131.33

54.80 48.40 35.20

.... .... ....

Size: Outside Diameter, in.

D

18~ 20 20 20

/T h r e a d s a n d Coupling2 Inside Diameter, in.

Plain End, lb/ft

Regular [b

1Nominal weights, threads a n d c o u p l i n g (Col. 2 ), are shown for the p u r p o s e of identification in ordering. 2Weight gain d u e to e n d finishing. Source: From API Spec 5A, 35th Edition, March 1981, p. 24, 25. From Ref. [151],

Special Clearance Ib

1.60 0.20 1.20 2.60 3.80 5.20

Casing and Casing String Design

1137

case of dispute, the measurements determined by use of the mechanical caliper shall govern.

Weight Each length of casing shall be weighed separately. Threaded-and-coupled pipe shall be weighed with the couplings screwed on or without couplings, provided proper allowance is made for the weight of the couplings. Threaded and coupled pipe, integral joint pipe and pipe shipped without coupling shall be weighed without thread protectors except for carload weighings for which proper allowances shall be made for the weight of thread protectors. The weights determined as described above shall conform to the specified calculated weights (or adjusted calculated weight) for the end finish specified on the purchase order, within the tolerances stipulated in Table 4-146. Calculated weights shall be determined in accordance with the following formula: W L =

(Wpe

X

L) +

ew

Table 4-145 Extreme-Line Casing Dimensions and Weights 1

2

Size: Outside Diameter, ha.

Nominal Weight: Upset and Threaded lb per ft

OD

3

4

5

6

7

Calctdated Weight Upset and Threads Wall

Inside

Thickness, in.

Dia.,

End,

Std.

Opt.

in.

lb/ft

wpe

lb

ew

lb e~ .... ....

WALL

~D

5 5

15.00 18.00

0.296 0.362

4.408 4.276

14.87 17.93

4.60 1.40

51,~ 5~ 5~ 5~

15.50 17.00 20.00 23.00

0.275 0.304 0.361 0.415

4.950 4.892 4.778 4.670

15.35 16.87 19.81 22.54

5.80 4.80 1.40 0.00

4.20 3.20 - - 0.20 - - 1.60

6-~ 6~ 6~

24.00 28.00 32.00

0.352 0.417 0.475

5.921 5.791 5.675

23.58 27.65 31.20

3.40 0.20 - - 1.40

1.80 - - 1.40 - - 3.00

7 7 7 7 7 7

23.00 26.00 29.00 32.00 35.00 38.00

0.317 0.362 0.408 0.453 0.498 0.540

6.366 6.276 6.184 6.094 6.004 5.920

22.63 25.66 28.72 31.68 34.58 37.26

6.00 2.80 0.60 - - 0.60 1.00 - - 0.20

-----

7~ 7~ 7~ 7~

26.40 29.70 33.70 39.00

0.328 0.375 0.430 0.500

6.969 6.875 6.765 6.625

25.56 29.04 33.04 38.05

6.40 2.60 0.00 - - 2.20

4.00 0.20 - - 2.40 - - 4.60

8~ 8-~ 8~ 8~ 8~

32.00 36.00 40.00 44.00 49.00

0.352 0.400 0.450 0.500 0.557

7.921 7.825 7.725 7.625 7.511

31.10 35.14 39.29 43.39 48.00

13.20 7.60 4.00 1.60 - - 0.80

9.80 4.20 0.60 - - 1.80 - - 4.20

9~ 9~ 9~ 9~

40.00 43.50 47.00 53.50

0.395 0.435 0.472 0.545

8.835 8.755 8.681 8.535

38.94 42.70 46.14 52.85

10.60 5.40 2.20 - - 1.20

7.20 2.00 - - 1.20 - - 4.60

10~ 10~ 10~

45.50 51.00 55.50

0.400 0.450 0.495

9.950 9.850 9.760

44.22 49.50 54.21

21.20 18.40 15.80

4.20 1.00 1.20 2.40 1.80 3.00

.... .... ....

1138

Drilling a n d Well C o m p l e t i o n s Table 4-145 (continued)

I

2

Nomina! Size:

Outzide Diameter. i=,

Welght:

Upset and

Threaded

lb. per ft.

8

Pin and Box Outside Dig, (Turned) in. +.020 --.010 Std. M

OD

9

OPt. M

10

11

12

13

14

Pin and Box Dimensionl--Finished Pin and Box Mad~upa (Power-Tight) Pin Box Inside Dia. Inside Dis. Outside Di~. Inside Dia. (Bored) tBoM) in. in. in. in. •(-.020 +.010 +.015 +.030 --.010 --.005 --.015 --.000 St~L Opt. ' St& a. Opt. Std. • OPt. Std & OPt. 2 2 B D

15

16

Drift Di~ Drift Dia.' for Finish for Full Bored Upset Length Members Drifting. in. in. rain. Std. & Opt. St& a. Opt

8 8

15.00 18.00

6.860 8.360

.... ....

4.208 4.208

4.285 4.235

5.360 5.360

.... ....

4.198 4.198

4.183 4.183

4.151 4.151

5~ 5~ 5~ 5~

15.50 17.00 20.00 23.00

5~60 5.860 5.860 5JB60

5.780 5.780 5.780 5.780

4.748 4.711 4.711 4.619

4.773 4.738 4.738 4.647

5.860 5.860 5.860 5.860

5.780 5.780 5.780 5.780

4.736 4.701 4.701 4.610

4.721 4.686 4.686 4.595

4.653 4.653 4.653 4.545

8% 6% 8%

24.00 28.00 82.00

7.000 7.000 7.000

6.930 6.930 6.930

5.792 5.741 5.624

5.818 5.768 5.652

7.000 7.000 7.000

6.930 6.930 6.930

5.781 5.731 5.615

5.768 5.716 5.600

5.730 5.666 5.550

7 7 7 7 7 7

23.00 26.00 29.00 32.00 85.00 38.00

7.390 7.390 7.390 7.390 7.530 7.530

7.310 7.310 7.310 7.310 7.390 7.390

6.182 6.182 6.134 8.042 6.949 5.869

6.208 6.208 6.160 6.069 5.977 5.897

7.390 7.390 7.390 7.390 7.530 7.530

7.310 7.310 7.310 7.310 7.390 7.390

6.171. 6.171 6.128 6.032 5.940 5.860

8.156 6.158 6.108 6.017 5.925 5.845

6.151 6.151 6.059 5.969 5.879 5.795

7% 7% 7% 7%

26.40 29.70 33.70 89.00

8.010 8.010 8.010 8.010

7.920 7.920 7.920 7.920

6.782 6.782 6.716 6.575

6.807 6.807 6.742 6.602

8.010 8.010 8.010 8.010

7.920 7.920 7.920 7.920

6.770 6.770 6.705 8.565

6.755 6.755 6.690 6.550

6.750 6.750 6.640 6.500

8% 8% 8% 8% 8%

32.00 36.00 40.00 44.00 49.00

9.120 9.120 9.120 9.120 9.120

9.030 9.030 9.030 9.030 9.030

7.737 7.737 7.674 7.575 7.460

7.762 7.762 7.700 7.602 7.488

9.120 9.120 9.120 9.120 9.120

9.030 9.030 9.030 9.030 9.030

7.725 7,725 7.663 7.565 7.451

7.710 7.710 7.648 7.550 7.436

7.700 7.700 7.600 7.500 7.386

9% 9% 9% 9%

40.00 43.50 47.00 69.50

10.I00 10.100 10.100 10.100

10.020 10.020 10.020 10.020

8.677 8.677 8.633 8.486

8.702 8.702 8.658 8.512

10.100 10.100 10.100 10.100

10.020 10.020 10.020 10.020

8.565 8.665 8.621 8.475

8.850 8.650 8.606 8.460

8.599 8.599 8.525 8.379

10~ 10~A 10~

45.50 51.00 55.50

11.460 11.460 11.460

.... .... ....

9.829 9.729 9.639

9.854 9.754 9.664

11.460 11.460 11.460

.... .... ....

9.819 9.719 9.629

9.804 9.704 9.614

9.794 9.694 9.604

Due to the nature of extreme-line casing, certain dimensional symbols and nomenclature differ from those for similar details for other pipe covered by this specification. 2 Made-up joint OD is same as outside diameter dimension M. a Shown for reference. 4 See Table 6.11, Ref. 4.15.1. s Weight gain or loss due to end finishing. See Par. 6.5, Ref. 4.15.1. Source: From API Spec 5A, 35th Edition, March 1981, p. 26, 27. From Ref. [151].

where W L = calculated weight o f a piece o f p i p e o f length L in lb Wpe = plain-end weight L = l e n g t h o f pipe, i n c l u d i n g e n d finish (see note on l e n g t h determination) in ft e . = weight gain or loss d u e to e n d finish in lb Length

Pipe shall be furnished in range lengths c o n f o r m i n g to Table 4-147, as specified on the purchase order. W h e n pipe is furnished with threads and couplings, the length shall be measured to the outer face o f the coupling, or if

Casing and Casing String Design

1139

Table 4-146 Casing Weight Tolerance Quantity

Tolerance

Outside Diameter, D 4 in and smaller (tubing) ............................................................................. +0.031 in 41/2 in and larger (casing) ............................................................................ +0.75 percent Wall thickness, t ............................................................................................... - 1 2 . 7 5 percent Weight Single Lengths .............................................................................................. Carload Lots ................................................................................................. A carload is considered to be a minimum of 40,000 Ibs.

+6.5 percent - 3 . 5 percent - 1 . 7 5 percent

Table 4-147 Casing Length Range Range Total range length, ff Range length for 95 percent or more of carload Permissible variation max. ft Permissible length min. ft

1 16-25

2 25-34

3 34-48

6 18

5 28

6 36

measured without couplings proper allowance shall be made to include the length of coupling. The extreme-line casing and integral joint tubing lengths shall be measured to the outer face of the box end. For pup joints and connectors, the length shall be measured from end to end. Casing Jointers If so specified on the purchase order for round-thread casing only, jointers (two pieces coupled to make a standard length) may be furnished to a maximum of 5% of the order, but no length used in making a jointer shall be less than 5 ft. Coupling API standards established three types of threaded joints: 1. coupling joints with rounded thread (Figures 4-369 and 4-370) (long or short) 2. coupling joints with asymmetrical trapezoidal thread buttress (Figure 4-371) 3. extreme-line casing with trapezoidal thread without coupling (Figure 4-372) There are also many non-API joints, like Hydril "CTS," Hydril "Super FJ-P," Armco SEAL-LOCK, Mannesmann metal-to-metal seal casing and others. The following are excerpts both from API Specification 5A, 35th Edition, March 1981 and API RP 5B1, 1st Edition, April 1983.

1140

Drilling and Well Completions

o

I ~.s,o ~o*E~T,o.T MAKEU~

W

I

.A~OT,0.. ~AKEU~ ~

Figure 4-369. Short round-thread casing and coupling. (From Ref. [51].) Taken from API Spec 5A 35th Edition, Ref. [151], p. 22. See Table 4.15.3 for pipe dimensions. See Table 4.15.9 for coupling dimensions. See API Std 5B for thread details.

NL

;i l

BAS0POWE ! TOXTKEOP

W

HANDT|GHT MAKEUP

Figure 4-370. Long round-thread casing and coupling. (From Ref. [51].) From API Spec 5A, 35th Edition, March 1981, Ref. [151], p. 23. See Table 4.15.4 for pipe dimensions. See Table 4.15.9 for coupling dimensions. See API Std 5B for thread details.

CNt.v ~

4~.

S~ClFto ONonozet.

DASEOF TR,ANGLESTJtMP '

--~--~.=.,'..ox

D

BASIO

POWERTIGHTMAKEUP

ilA,~ OFI~,~LE 53"JMP NI.

-[~

'

,

I ! ]

HANDTIGHTMAKEUP

~

I!

Figure 4-371. Buttress thread casing and coupling. (From Ref. [51].) From API Spec 5A, 35th Edition, March 1981, Ref. [151], p. 25. See Table 4.15.5 for pipe dimensions. See Table 4.15.10 for coupling dimensions. See API Std 5B for thread details.

Casing and Casing String Design •

_t

-

Lo

1141

TAPER,2" PEltPT

(ISSTmnVm) ONDiS

it~4-3/'4"~ t20,6 mintMIN FOR 7"518O0 a S~LLE~._._..[ e-I,,~'~ IS5, I mintMiN FOR 8-5/8 OD a LARGER~ ] /

"~

u

N OOX

L|

TAPER,2"PER FT

(IGS,Tmm/m)ONDIS

-,-,.

] L|

,

BOX a PiN MEMBERS

+

L+

NIFT :iA

,JOISTU

POWER TIGHT MAKEUP

Length of Upset

Size, in,

OD 5

5% 8%

7 7% 8% 95/~ 10%

"

Box,t Min.

I~n,$ Min. in.

t~

6%

mm

in,

Pin or Box, Max mm

In.

L; 168,3

8% 8%

lU,3

6% 6~J~ 8 8 8

168,3 168,3 203,2 203,2 203,2

168,3

7 7 7 7

mm Lo

177,8 177,8 177,8 177,8

7

177,8

83A 8sA 8SA

222,2 222,2 222,2

8 8 8 8" 8 11 11 123A

203,2 203.2 203,2 203,2* 203,2 279,4 279,4 323,8

i'Li is the minimum length from end of pipe of the machined diameter 8 on pin, or machined diameter D plus length of thread on box, to the beginning of the internal upset runout,

"Lo shall be 9 in. (228,6 mm) max. for 7 in. -- 35 Ib/ft and 7 in. -- 38 Ib/ft casing,

Figure 4-372. Extreme-line casing. (From Ref. [1410 From API Spec 5A, 35th Edition, March 1981, p. 28. S e e T a b l e 4.15.6 for pipe dimensions. See API Std 5B for t h r e a d details.

Elements of Threads Threaded connections are complicated mechanisms consisting of many elements that must interact in prescribed fashion to perform a useful function. Each of these elements of a thread may be gauged individually as described in API RP 5B1, 1st Edition, April 1983. The thread elements are defined as:

1142

Drilling a n d Well C o m p l e t i o n s

1. Thread height or depth. The t h r e a d height or d e p t h is the distance between the t h r e a d e d crest a n d the t h r e a d r o o t n o r m a l to the axis of the t h r e a d (Figure 4-373). 2. Lead. For pipe t h r e a d inspection purposes, lead is d e f i n e d as the distance from a point on a t h r e a d to a c o r r e s p o n d i n g point on the adjacent t h r e a d m e a s u r e d parallel to the t h r e a d axis (Figure 4-373). 3. Taper. T a p e r is the change in d i a m e t e r of a t h r e a d expressed in i n . / f t of t h r e a d length.

Round Threads (Figure 4-373) The p u r p o s e of r o u n d top (crest) and r o u n d b o t t o m (roots) is: a. to improve the resistance of the threads from galling in make-up; b. to provide a controlled clearance between make-up t h r e a d crest and root for foreign particles o r contaminants; and c. to make the crests less susceptible to harmful damage from m i n o r scratches or dents. If insufficient interference is a p p l i e d during makeup, the leak p a t h t h r o u g h the c o n n e c t i o n c o u l d be t h r o u g h the a n n u l a r c l e a r a n c e between m a t e d crest and roots. P r o p e r t h r e a d c o m p o u n d is necessary to ensure leak resistance.

Buttress Thread (Figure 4-374 and 4-375) Buttress t h r e a d s are d e s i g n e d to resist high axial tension or c o m p r e s s i o n loading in a d d i t i o n to offering resistance to leakage. The 3 ° load flank offers resistance to disengagement u n d e r high axial tension loading, while the 10 ° stub f l a n k offers resistance to high axial compressive loading. In any event, leak resistance is again accomplished with use of p r o p e r t h r e a d c o m p o u n d a n d / o r t h r e a d coating agents. Leak resistance is controlled by p r o p e r assembly (interference) within the perfect t h r e a d only.

L-\ •

\I" ,

I

\

X

\

,

\.

\

~.

'

........ /

/

Figure 4-373, Round-thread casing and tubing thread configuration. (From Fief. [154].7

Casing a n d Casing String Design \

I

,~\,,

\

,

oo

"",

/ /

\ \

/

., /

~ ,-" .,," , . " / . ~

~ ~ ,

/

." .-'

/,."2L_AL.,

/

./

/

//

-

_

,2,,

\

\

\~'z_

"Z_

,,, , . . . , .

/ ....

\ ,~!g. ,~;~.

"-," /

"'~""~" "

"

J---v-~ ,/,.51~

\

,/,..,~ ,.,. ,. ,... ,,,

;"/./I)~,"

/.2L_,_.~z

\

1143

",

.

,,

."

.... ' . . . . . . .

~

OR S I Z E S 16" & LARGER " T A P E R PER FOOT ON D I A M E T E R

[ I

Figure 4-374. Buttress thread configuration for 16-in. outside diameter and larger casing. ( F r o m Ref. [54].)

\ \ \ \ " " L , A ~

I v

/

/

/

A_..3.

/

/

\

/

,"

~\

/(

"

"

"

"

"

"

\

\ \ \

.... ;~A.;,,oi,.t-'~ . . . . . . . . 'P'"' / ~ \ \ .

,I

/

,"

-

,

,

\ \

~1.\~/\

N/

"

! ............... 3/8 u

12 II

__!

3,/4 ', T A P E R PE~R FOOT ON D * A M E T E R

Figure 4-375. Buttress thread configuration for 13%-in. outside diameter and smaller casing. ( F r o m Ref. [ 1 5 4 ] . ) Extreme-Line Casing (Integral Connection) (Figure 4-376) Extreme-line casing in all sizes uses a m o d i f i e d acme type t h r e a d having a 12 ° i n c l u d e d angle between stub a n d load flanks, a n d all threads have crests a n d roots flat and parallel to the axis (Figure 4-376). For all sizes, the threads are not i n t e n d e d to be leak resistant when m a d e up. T h r e a d s are used purely as a mechanical means to hold the j o i n t m e m b e r s together d u r i n g axial tension loading. T h e c o n n e c t i o n uses upset p i p e ends for pin a n d box m e m b e r s that are an i n t e g r a l p a r t o f the p i p e body. Axial compressive l o a d resistance is p r i m a r i l y offered by external shouldering to the c o n n e c t i o n or makeup. Leak resistance is o b t a i n e d on m a k e u p by interference o f metal-to-metal seal between a long radius curved seal surface on the pin m e m b e r engaging a conical metal seal surface o f the box m e m b e r (Figures 4-372 and 4-376).

Drilling and Well C o m p l e t i o n s

1144

. \

\

\

\

\

x,

"\

",,

\

,,. P i T c .

\

\,

".

,,

-.

x~,

', f

". t " x

"

~

\

x.

\

"x \\

\

~OX ( C P L G . )

.

.,.. . . . . . . \ ", "1 \ "-\ "" I.,T,, ..... ~ " ~'~ ,c~,.,,./~\Xq~..,~I. ( ~ - .' . . . / <

,\

;o

,

s


:¢ ~ :¢ --

L ~ N/l -

.k~/f /

i

,/ / I

"

/

=

/'-

.

/

-~

6 o x CR£ST

,,

,

.

L,,","

- - L \ . ~

\

"

,

" x~

~__\

\

~x

,

.,T~ . . . . .

\

" \

\

,,L ,,,~

,,

",.

\.

.

-,..

\.

/

d

l

. . . . ,x,, FOR SIZES LARGER THAN 7 5 / 8 ~z ; I / 4 ~z TAPER PER FOOT

~,/,,,.-.~ ~

,,,,

'

., ...... . O,...TE../.,,JL. P~TCN T~(R[AD

,z"

-]

~ PITCH . . . . .T£R THR(AO

F i g u r e 4-376. Extreme-line casing thread configuration. (From Ref. [154].)

T h r e a d c o m p o u n d is not necessarily a critical agent to ensure leak resistance, but instead is used primarily as an antigalling or antiseizure agent. Material

Couplings for p i p e (both casing and tubing) shall be seamless and, unless otherwise specified on the purchase order, shall be o f the same g r a d e as the pipe, except g r a d e H-40 and J-55 pipe which may be f u r n i s h e d with g r a d e J-55 or K-55 couplings. Note: Most buttress t h r e a d couplings will not develop the highest m i n i m u m j o i n t strength unless couplings o f the next higher o r d e r are specified. (See API Specification 5A for m o r e detailed information.) Physical Properties

Couplings for grades J-55, K-55 and N-80 shall conform to the tensile requirements specified in Table 4-142. A tensile test shall b e m a d e on each heat o f steel from which couplings are p r o d u c e d , and the coupling m a n u f a c t u r e r shall maintain a record o f such tests. This record shall be o p e n to inspection by the purchaser. E i t h e r r o u n d s p e c i m e n s p r o p o r t i o n e d as s p e c i f i e d in ASTME 8: Tension Testing o f Metallic Materials, or strip specimens shall be used, at the o p t i o n o f the manufacturer. Dimensions and Tolerances

Couplings shall conform to the dimensions and tolerances shown in Tables 4-148 and 4-149. Unless otherwise specified, threaded and coupled casing and tubing shall be furnished with regular couplings. Note: Couplings inspection p r o c e d u r e s are d e s c r i b e d by API RP 5B1, First Edition, April 1983. T h r e a d Protectors D e s i g n . T h e manufacturer shall apply external and internal t h r e a d protectors o f such design, material and mechanical strength to protect the t h r e a d e d e n d

Table 4-148 Round-Thread Casing Coupling Dimensions, Weights, and Tolerances 1 Sizez

2 Outside Diameter

W

3

4

Minimum Length • • ~ Short Long

5 •

6

Diameter o! Recess

Width of Bearing Face

N,.

N,.

Q

b

41%2 53/32

7

8 W e i g h t , Ib .A

"

Short'

Long

~ ~6

~

8.05 10.18 11.44

9.07 12.56 14.03

4~ 5

5~

5.000 5.563 6.050

6~ 6½ 6~

7 7% 8

6% 7 7% 8%

7.390 7.656 8.500 9.625

7~ 7~ 7½ 7~

8~ 9 9~ 10

62~ 7~2 7~,. 82~

~4 ~e ~ %2

19.97 18.34 26.93 35.58

24.82 23.67 34.23 47.48

9% 10~ 11~ 13~

10.625 11.750 12.750 14.375

7~ 8 8 8

10½ .... .... ....

9~2 10~,~2 1127/82 1315,~

~ 9/~ 9/~2 ~6

39.51 45.53 49.61 56.23

55.77 .... .... ....

16 18 % 20

17.000 20.000 21.000

9 9 9

....

16~2 182~2 20~

~6

78.98

~6

118.94

~s

98.25

.... .... 126.74

li~

51~/.~

Tolerance on outside diameter W, ± 1 per cent, but not g r e a t e r t h a n ± ~ ZThe size o f t h e c o u p l i n g is t h e s a m e a s t h e c o r r e s p o n d i n g p i p e size. All dimensions in inches. See Figures 4.15.2 and 4.15.3. Source: From Ref. [151], p. 38.

in.

~.

~.

~. oq

T a b l e 4-149 Buttress Thread Casing Coupling Dimensions, Weights, and Tolerances 1

S~e =

2

3

Outside Diameter A r • Special Regular Clearance

4

5

6

7

8 W e i = h t , Ib

Minimum Length

Diameter of Chamfer

Width of Bearing Face

Q

b

• Rea'ular

Special Clearance

•

W

W~

N,.

4~ 5 5~

5.000 5.563 6.050

4.875 5.375 5.875

8~ 9~ 9~

4.640 5.140 5.640

~ ~= ~

10.11 12.99 14.14

7.67 8.81 9.84

O

6~ 7 7~ 8~

7.390 7.656 8.G00 9.625

7.000 7.375 8.125 9.125

9~ 10 10~ 10~

6.765 7.140 7.765 8.765

~ ~ ~ ~

24.46 23.22 34.84 45.94

12.44 13.82 20.45 23.77

==

9~ 10~ 11~ 13~

10.625 11.750 12.750 14.375

10.125 11.250 ..... .....

10% 10~ 10~ lOr~

9.765 10.890 11.890 13.515

% % ~ ~

50.99 56.68 61.74 69.95

26.47 29.49 .... ....

16 18~ 20

17.000 20.000 21.000

...... .... ....

10~ 10% 10%

16.154 18.779 20.154

~ % %

87.56 138.03 110.33

.... .... ....

Tolerance on outside d i a m e t e r W, ~ 1 per cent, but not g r e a t e r than ~ Tolerance on outside d i a m e t e r ]~r~ .~-~, _ _ ~ in. 1 T h e s i z e o f t h e c o u p l i n g is t h e s a m e a s t h e c o r r e s p o n d i n g p i p e size.

All dimensions in inches. See Figure 14.5.4. Source: From Ref. [151], p. 38.

in.

O

Casing and Casing String Design

1147

of the pipe from damage under normal handling and transportation. External thread protectors shall cover the full length of the thread on the pipe and internal thread protectors shall cover the equivalent total pipe thread length of internal thread. Thread protectors shall exclude water and dirt from the thread during transportation and normal storage period. Normal storage period shall be considered as approximately 1 year. The thread forms in protectors shall be such that the product threads are not damaged by the protectors.

Material. Protector material shall contain no compounds capable of causing corrosion or promoting adherence of the protectors of the threads and shall be suitable for service temperature (-50 to +150°F) (-46 to +66°C).

Performance Properties. Results of years of field experience have revealed that to reduce the risk of failure, the minimum yield strength should be used instead of average yield strength to determine the performance properties of casing. Values for collapse resistance, internal yield pressure, pipe body, and joint strength for steel grades as in Table 4-141 are given in Table 4-150. Table 4-150 is directly taken from API Bulletin 5C2, 17th Edition, 1980. Formulas and procedures for calculating the values in Table 4-150 are given in Bulletin 5C3 [152] and are as follows: Collapse Pressure (Section 1 of API 5C3) Yield Strength Collapse Pressure Formula. The yield strength collapse pressure is not a true collapse xDressure but rather the external pressure p YP that / generates minimum yield stress Yp on the inside wall of a tube as calculated oy (D/t~- 1 pyp = 2Yp ~ I (D/t)

(4-308)

The applicable D/t ratios for yield strength collapse are shown in Table 4-151.

Plastic Collapse Pressure Formula. The minimum collapse pressure for the plastic range of collapse is calculated by A pp= y pl~-~-B -C

(4-309)

The formula for minimum plastic collapse pressure is applicable for D / t values as shown in Table 4-151. The factors A, B, and C are given in Table 4-152.

Transition Collapse Pressure Formula. The minimum collapse pressure for the plastic to elastic transition zone PT is calculated by

PT =

y [ F _

p1~-77 G i,-qL

(4-310)

(text continued on page 1154)

Table 4-150 Minimum Performance of Casing 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

I..t I..t 0o 19

20

21

22 *

Threaded and Coupled

S~e~ Outside Diame~

Nominal Welg~tt' Thread~ and Coupi~g

4M

9.50

Wan Grade T h i c k n ~

Inside Diame~

D~ft Dia~ter

Out,de OunCe D i a r i s te t D~o~te~ Spec~ o C]e~ Coupling Coupling

Exme~ Line

l~ft Dia~t~r

We

Rege~ CoupUa~

Spe~a~C=e~ Coup~g

Short

Grade

Grad~

Grad.

--

3.310 4.010 4.960

I52 163 184

4.38O

4.38O

4.875 4875

4,79O 5,35O

4,790 5.35O

3,310 4.010 4.9~O

152

4,S33

4.58O

5OOO 5.000

-4.875 4.875

165 184

4.790 5.350

4.790 5,359

-5.35O

4,790 5.35O

5.000 5.000

4.875 4.875

6,133 8,170

250 288

7.290 8,46O

--

7,290 8,46O

7.290 8,46O

3.875 3.795

5.000 5.000

4.875 4.875

6.~5O 8.54O

267 337

7,780 9,020

--

7,780 9,020

7,78O 9,020

7,780 9,020

7,780 7,990

7,780 9,02O

4.000 3.920

3.875 3.795

5.000 5.000

4.875 4.875

6.35O 8,540

267 3O7

7,780 9,02O

--

7,780 9.029

7,780 9.020

7,780 9.020

7,780 7.990

7,780 9.020

--

I0.690 12.410 I4.420

10.690 10.990 10.990

10.690 12.410 14.3t0

----

0.224 0.25O

4.090 4.052 4.0O0

3.965 3.9"27 3.875

0.2O5

4.090 4.052 4.000

3.965 3.927 3.875

5OOO

10.5o 11.60

K-55 K-55 K-55

11.60 13.50

575 075

0.290

4.~)0 3.920

5.875 5.795

11,60 1350

~ L,80

0.250 0.29O

4.000 3.920

11.6o 13.50

N40

0.25O 0.290

--

--

5.35O

4,790 5,.35O

4,79O 5.35O 4.79O 5.35O ---

101

4,7!~ 5.35O

132 154 112

4.790 5.350

-4.790 5,35O --

146 170 --

--

11.60 13.50

0.25O 0.290

4.000 3.920

3,875 3.795

5.000 5.000

4875

C-95

4.875

7,010 9,63O

317 364

9.240 10.710

--

9.249 10.710

9,240 10.710

11.60 1350 15,10

P-l]O P-IlO P-llO

0.25O 0.290 0.537

4.000 3.920 3.826

3,875 3.795 3.701

5.OOO 5.000 5.000

4.875 4.875 4,875

7,56O 10.670 H,330

367 422 485

10.690 12.410 14,429

--

10,690 12,4t0 I4.429

10.690 12.410 13,460

1150 13CO 15.00

J-55 J-55 J-55

0.220 0.255 0.'296

4.56O 4494 4.408

4.435 4.369 4.283

5.563 5.563 5.563

-5.375 5375

5.36o

3.06O 4,II0 5.55o

182 208 241

4,240 4,870

4,24O 4,870

4,870

4,870

4,870

4,870

-4,870

5,7OO

5,7OO

5,7O0

5,7OO

5,700

5,1~0

5,700

I 1.50 13.00 15.00

K-55 K-55 K~55

0.220 0.253 0.296

4,~50 4.494 4.408

4.435 4369 4.283

5.5,55 5.563 5.563

--

5.375 5,375

4.151

5.36O

3,060 4,140 5.55O

182 2O8 241

4,240 4,870

4,240 4,87O

. . . 4,870 4,870

. 4,87O

4,870

4~70

147 186

5,7~

5,7~

5,7~

5,700

5,7~

5,130

5,700

228

15,00 18.00 21.40 24.I0

(3-75 C-75 C-75 075

0296 0.362 0.437 0.500

440~ 4.276 4.126 4.000

4283 4.151 4.~I 3.875

5.563 5.563 5563 5.563

5.375 5.375 5.375 5.375

4.151 4.151

5.360 5.360

6.970 lO,OOO 11.060 t 3.50o

328

7,770

--

7,770

7,770

--

$96

6,990

9.500

9.5~0

9.290

470 533

11,470

]0,140

9,290

13,130

--

10,140

9,920

15.~

L~O

4,283 4.15I 4.001 3.875

5.563 5.563 5.563 5.563

5.375 5.375 5,375 5.375

4,151 4.151

5.360 5.360

7.25O 10.490 12,760 14,400

35O 422 501 505

--

8,290

8,290

8,290

7,460

8,290

1.80 ~ L~0

4.408 4.276 4.126 4,000

8,290

18.c41 21.40 24A0

0296 0,362 0437 0.500

I0,140 I2,240 14,000

I0,I40 I0,810 I0.810

9,910 9.910 9.910

10,140 --

7,460 7.460 7.460

15.~ 18.~ 21.40 24.10

N~0

0.296 0.362 0.437 0.500

4.408 4.276 4.126 4OO0

4.283 4.15t 4.1~)1 3.873

5.563 5.563 5.563 5.563

5.375 5375 5.375 5.375

4.15I 4.15I

5.360 5,360

7,230 10.400 12,760 14,400

350 422 501 566

8,290 10.149 12,240 14.000

--

8,29O I0,149 I0.810 I0.810

8,290 9.910 9.910 9.910

8.290 10,140 12,240 13.629

7.460 7,460 7.460 7.46O

15J~) 18.00 21.40 24.I0

C~95 C-95 G-~5 C~95

0.296

4.408 4276 4.126 4.000

4.283 4.151 4.001 3.875

5.563 5.563 5,563 5.563

5.375 5.375 5.375 5.375

4.151 4.151

8.090 12.010 15.150 17,100

415 501 595 672

9,840 12.040 14.530 16,630

--

9.840 12.040 12,840 12,850

9.840 11.770 11.770 11.770

--

0A37 0,500

---

8.850 8,850 8,850 8.850

15.00 18,00 21.40 24.I0

e-llO P-II0 P-]]0 P-110

0.206 0.362 0.437 0.50O

4.408 4.276 4.I26 4.000

5.283 4.I51 4.~1 3.875

5.563 5563 5.563 5,563

5.375 5375 5.375 5.375

4A51 4.15t

8.850 13.450 t7.550 10,800

481 580 689 778

11.400 13.933 16,829 19,250

--

11.4(~ 13,940 14.870 14,870

11,400 13,629 I 5.620 13,629

11.400 13.910 16,820 18,580

10,250 10,250 10,250 10,250

C~95

N4~O N~0 N-80

0.362

4.I51

5.360 5.36O

5.360 5.360

--

---

--

9,240 9.49o

~ Spe~a C]e~ce Coup~g

Shmdard Opfion~ Joh~t Jo~at

-162

203 225

.

.

. 2O3

.

249 277

212 257

288

--

331

--

212 257

29]

--

334

223 270

--

180

.

.

.

. 2~

.

2O3

225 . 249 277

.

225 .

---

225 .

249 277

. 249 '277

---

.

--

---

---

--

--

288 320

--

--

--

291 320

---

--

--

---

304 $49

304 349

304 337

304 349

---

--

--

--

234 284

325 374

325 374

325 353

---

---

---

279 ~8. 406

385 443 5O9

385 443 5O9

385 421 421

385 443 509

----

----

133 169

182

252

. 252

--

--

~7

223

~93

~93

328

--

201

309

. 309

246

359

295

375

376

. 252

. 252

'287

.

'293

.

. 309

. 3O9

359

359

--

364

. --

--

359

416

--

---

416 446

---

452

--

466

510

--

364

--

--

--

6,990

538

510

__

3~4

__

__

__

--

295

379

--

364

--

416

--

10,]40

--

376 466 538

457 510 510

----

364 364 364

----

446 ---

----

8.290 10,140 10,250 10,250

-----

311 396 490 567

396 477 537 537

396 477 566 639

3,83 383 383 383

396 477 479 479

437 469 ---

-----

326 416 515 505

424 512 563 563

-----

402 402 402 402

-----

459 493 ---

-----

388 495 613 708

503 6O6 671 671

503 606 720 812

479 479 479 479

503 606 613 613

547 587 ---

-----

11,400 13,940 13.980 13,080

-----

364

.

6,990

6,$90

--

Lo,~rRegul~ Regebx S~=I C o u p l i n g Coupth~g C l e ~ c e ltigh~ CoupKng

77

4.79O 5,350

7.290 7,49O

27

Gntde**

5.000

0.205

}55 }55

--

26

F~Weme Line

Buttcess T h r e a d

G~rad.

5.6OO 5.OOO

j-55

25

~d Coupled

R o ~ d ~

~

~

24

~ f

3.190

5.000

N~0

T~aded

BuUre~ Thread

3,190

3.965

0.25O

M

Plain Eud or

Round Thread ~~ Short Long

II1

4.O9O

0.224 0.250

~

~

2.700

0.205

9.5O

fight

PiPe Ik6y Y~ld Strength

--

H~0

9.5O 10.50 11.60

I n . t r o d Yield Pr~umre at M i n i m ~ Y'~Id, p ~

Outside Diameter otBox con=p~e PO~ Re~tt-

23

j o i u t Str=mgth- - 1,0~0 Ibs

O

e..,

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

* Joint ~ ThremJ~*d a n d C o u p l e d Noralnal We{gh t , Size: Threads Oatskle aad Diameter Cou#ing in. lb per ft D 5V2

W~ Grade " n a d m e ~ " ~"

lnd~de Di..~i~r

DAft D~ meter

d

O u t s i d e~ Outside Di~lteter Diameter Spe~d of ~ ~ ~ • • W We

14.00

H49

0.244

5.012

4.887

6.050

I4.00 15.5O I7+00

j-55 J-55 J-55

0.244 0.~e75 0.304

5+012 4+950 4.892

4.887 4.825 4.767

6.050 6.05.0 6,050

14.00 15£.0 17.00

K~55 K+55 K-55

0.244 0.275 0+304

5.012 4.~60 4.892

4.887 4,825 4.767

6.050 6+05O 6.05O

5.875 5+875

17.00 20.00 25.00

C-75 C-75 C-75

0.3O4 0.36I 0.415

4.892 4.778 4+670

4.767 4.6fi3 4.545

605O 6.05o 6.05o

5+875 5.875 5.875

17.00 20.00 23.00

DS0 L,80 1~80

0+304 0.361 0.415

4+892 4.778 4.670

4.767 4.655 4.545

6.05o 6.0£.O 6.05O

17.00 '20.00 ~.00

N~ N-80 N~0

0.304 0+$6I 0415

4.892 4778 4,670

4,7O7 4.6fi3 4.545

17.00 '2O,00 23+00

C-95 C-95 C~95

0.3O4 0.$61 0.415

4+892 4778 4.070

17.00 ~o.~ 23.00

P-]10 p-llO P-1IO

0.304 0.361 0.415

4.892 4.778 4.070

~ t t ] ~ m ¢ Line

interred y l e t d Pressoze a t )fffi~fim~IGeld, laol

O u t ~ l eTM Diar~leter PiPe Drift o f Box Colla~e Body DbP ~ ~ ~eld ~t~ ~at ~ .Sm~'th " I~ 1ooo Ibs M

F

Round ~ ~

Plain Sho~ End or Extreme Line

Regular Couplh~g

~ Same Grade

Higher Gra~r

Same Grade

4.810 5.320

4.810

4.730 4.730

2,630

161

3,IIO

3,I10

5.860 5.860

3320 4.040 4.910

222 248 273

4,270 4.810 5.320

4,270 4.810 5.320

4.653 4.653

5860 5.860

3,120 4.040 4,910

222 248 273

4.27O 4,810 5.$20

4.270 4,810 5.32O

4.653 4.655 4.545

5.860 5+860 5.86O

6.070 8,410 10,460

372 437 497

7,250 8,610 9,900

--

5.875 5.875 5,875

4655 4.655 4545

5+860 5,860 5.860

6.280 8.830 11.160

367 466 530

7,740 9,19O 10,560

--

6.050 6.0rio 6.05.0

5.875 5.875 5.875

4.655 4,553 4,545

5860 5+860 5+860

6.280 8.830 11,160

397 466 53O

7,740 9,t9O 10,560

--

4.767 4,653 45t5

6.050 6.05.0 6+0~0

5.875 5.875 5875

4653 4.653 4.545

586O 5.860 5.860

8.93O 1o,ooo 12.920

471 554 630

9.190 I0.910 12,540

--

4.767 4+653 4515

6.05o 6.0rio 6.05o

5.875 5,875 5.875

4.653 4.655 4.545

5.860 5860 5.860

%46O 11,080 14.520

546 641 729

.12,640 . . . . . . . . . . . . 12,640 . . . . . . .1.2., N. . . . .12,640 ....

2,520

229

3,040

3,04O

7.000 7.000

5,77~

7.000

2.970 4,560

:MS 352

4,180 5,II0

515 382 52O

5.875 5+875

4.655 4.653

--

14.520

4,810 5.320

Sp~al Cle~ Coupttng ~ f

5.$20 4,810 5,320

"~f Round Thretd "~ ~ Sho~ Long

~ Higher Gnde --

130

-5.320

I72 202 229

-4,810 5,$20

189 222 252

4.810

Eac~e~ llne Buare~ Thread

R e g u l a r Poegular Specild Coupang Coupl~g t ~ Higher Co.#n~ C.eade:

.

.

. 300 329

.

300 329

272 327 403 473

217 247

.

.

.

.

. $00 329

.

300 318

339 372

339 372

366 402

-366 402

-3*56 40'2

-3*56 402

429 471

429 471

425 497 5bo

----

405 403 405

---

471 497 549

471 479 479

7,250 8.450 8.43O

--

7,740 9.I90 9,880

7,740 8.990 8,990

7.740 9.190 10,560

6.880 6.880 6,880

7.740 9.190 9,460

--

335 416 489

428 505 5£*0

---

403 405 405

---

471 497 549

471 479 479

7,740 9,190 9.880

7,74O 8,990 8,990

7,740 9,190 10.560

6,88O 6,880 6.880

7,740 9,19(I 9.460

----

348 428 502

446 524 579

446 524 596

424 424 424

446 524 550

496 523 577

496 5O4 504

9.190 10.910 11,730

9,190 1068O 10,680

--

8.170 8.170 8A70

$74 46O 540

48O 563 608

----

445 445 445

----

521 549 606

521 530 530

548 643

667 7"24

5~

N

9.460 9,460

12,640 12.890

---

~

668

.654. 732

374 390

374 455

-477

477

453 548

453 494

453 520

-605

-605

585 68~ 771

----

494 494 494

----

605 648 717

605 644 644

473 576 666

592 693 783

----

494 494 494

----

605 648 717

605 644 644

481 586 677

615 721 814

615 721 814

520 520 520

615 650 6~)

637 682 756

637 678 678

545 605 769

6O6 780 880

---

546 546 546

----

688 716 793

608 712 712

641 781 904

786 922 1,040

786 922 1,040

650 650 650

786 832 832

796 K52 944

796 848 848

12,360

14.520

--

--

4,180 5,110

4,180 5,110

4,180 5,I10

4,180 5,110

4,O60 4,1)450

4,180 5,110

245 $14

266 $40

574 453

374 453

4,180 5,110

4,180 5,I10

4,180 5,110

4,I80 5,110

4,180 5,I10

4,0foO 4,060

4,180 5310

267 342

290 372

453 548

6,970 8.260 9,410

6,970 8,2F~ 9,200

--

5,540 5.540 5,540

453 552 658

H~4)

0.288

6.019

5.9"24

7.$90

20.00 28.00

J~55 j-55

0.288 0.352

6.019 5.921

5.924 5.756

7.234 7.$90

20.00 28.00

K-55 K-55

0,288 0.$52

6,019 5.921

5.924 5.756

7.234 7.390

7.000

5.73O

7.O4)O

2.970 4,560

24.00 28.00 320O

C-75 C-75 C-75

0352 0.4t7 0475

5.921 5.741 5.675

5.796 5.666 5.550

7.390 7.$90 7.$90

7.000 7.000 7.000

5330 5.666 5.550

7.000 7.O00 7.000

5,570 7,830 9,830

6,970 8,260 9,410

--

688

2400 28.0O 32.00

I~O [A~0 ~

0.352 0.417 0.475

5.921 5.741 5675

5.796 5.666 5.550

7.39O 7 390 7.$90

7.CO0 7.000 7.O00

5.730 5.605 5.550

7.000 7.0O0 7.000

5,760 8,170 10,320

555 651 734

7,440 8,810 10,040

---

7.4441 8,810 10,040

7,440 8,810 9,820

---

5.910 5,910 5,910

24.00 2800 32,00

N~O N~O N~O

11352 0.417 0.475

5,92I 5.741 5.675

5.796 5666 5,550

7390 7.390 7390

7.000 7.000 7000

5.730 5.666 5.550

7.00O 7.0O0 7.000

5,760 8,I70 I0,820

555 651 734

7,440 8,810 10,040

--

7,440 8,8111 10,040

7,440 8,810 0,820

7,440 8,810 10,040

5,910 5,910 5,9]0

24,0O

0.352 0.417 01475

5.921 5.74I 5.675

5.796 5.666 5.550

7.390 7.390 7.39O

7000 7,0OO 7.000

5.730 5.666 5.550

7.O00 7090 7.000

6.290 9.200 11,800

659 773 872

8,830 10,4¢:O 11,920

--

8,830 10,460 I 1,920

8,8~0 10,460 11,6~0

--

28.O9 32.00

C95 (~95 C-95

--

7,O2O 7,020 7,020

24.00 28.00 32.00

P-110 P-II0 PII0

0.352 0417 0.475

5.921 5.741 5.675

5.796 5.666 555O

7.399 7.390 7.390

7OOO 7.0G0 7.000

5730 5.666 55fi0

7000 7O00 7.000

6,710 10,140 13.2(I0

763 895 I009

10,230 12.120 I3.800

--

10.230 12,I20 13,800

10,230 12,120 13.500

10.230 12,120 13.800

8.120 8,120 8,120

--

--

--

--

--

7,440 8,I20 8,120

10.23,0 I1.080 11.080

184

---

----

759

530 530

15,880

--

" ~Standard O p t l o l ~ l ~ Joint Joint Speci~ ~ 3 ~ Co.pli~ F~er G r ~ t et

4,810 5,320

5,45O 6.45,0 6.4fi0

239

27

7,250 8.610 9.260

'2000

610

26

4,810 5.320

--

4,750 4.73O

25

~mr*aded ~ d ~

Buttre~ Thread ~Long

24 - - 1 , 0 ~ Ibs

.

o~

. 630 63O

--

ocl

o~

t=m t=m

Table 4-150 (continued) 1

2

$

4

5

6

7

8

9

T h r e a d e d ~ d Coupled Nomlnal Out.de D~ter.

7

and Coupl~g

Diaoofeter o

~

Di~neter d

[.4~0 [~qo 1~0 1~o N~0 Nd~0 N4~0 N.86 N~0 N4~0 (~95 G-95 G-96 ([:-96 C.05 (~95 P-I [0 P-I [o P-IH) P-[[O F.[IO H~0 J-55 K-56 ¢~75 (~75 ¢~76 (~75 'C-75 ~75 L-80 L~80 L440

0231 6.272 0.272 0.317 0.362 0272 0317 0.362 0.317 0.352 0.408 0.458 0.498 0.540 0317 0362 0.4O8 0.483 0.498 0.SgO 0.317 0.362 0.4O8 0.453 0.498 0.54O 0.317 0.36~ 0.408 0.453 0.498 0.54O 0362 0.408 0.455 O.498 0.540 0.3OO 0.328 0.328 0.328 0.375 o 430 050o 0.562 0.628 0.328 0375 0400

6.578 6.456 6.456 6~46 6.276 6.450 6.$6~ 6.276 6.366 6.276 6.184 6.604 6,004 5.920 6.866 6.276 6.184 6.694 6.004 5m920 6.866 6.270 6.184 6,036 6,006 5.920 6,$66 6.274 6.184 6.094 6.001 5.620 6`276 4.184 ~.~l 6,504 8.920 7,0~ 6.969 6.969 6.969 6,675 6.755 6.625 6.),01 6,378 6.969 6`875 6.765

3901~

I.~0

05iI0

42.~) 47.10 26.-~ ~ 29.70 :~370 :~} or) 42.~0 47 I0 264O 29.7¢) 3~$.70 3J¢90 42.80 47.10 2970 6370 39~t} 4280 47.10

1.~0 L-80

0.562 0.625 0.328 0.375 0.430 0500 0.562 0623 0328 0.375 0.400 0.580 0.562 0623 0375 0.430 0.500 0.542 6.625

~903

7~

w~a Grade Thidm~ t

I7.f10 2O0O 2080 23.~) 26.80 2006 2300 26OO 23.(~ 26.uo 32J~0 35.00 38.09 23.00 26.(~) 29.(~J 32 oo 35.0~ 3K80 73.80 26.(~) 29.(~) 320~ 35.1K) 3.~.00 23.(~} 26-0O 29.01; •'~2.(~ ) 35(~d 38(~ 26C~ 29~1 3200 95.(~ ,~.Gtl 24 0 0 264O 26`40 26.4O 29.7O 33.70 39.m, 42.R0 47.I0 2641) k'~70 337O

E~Ue~

Outside

H~O H~i0 ~55 j356 J~55 K~56 K-65 K~6 (~76 (~75 (~75 C-78 C.75 (~75 L~O ~)

N-M0

N-~0 N.8O N-80 N~q0 N~0 C.96 (~95 t~95 C.95 C.95 (~9~ P-I I0 p-[ [0 p.I[O P-H0 P-IIO

meter Coupl~g

•

Coupling

W

W¢

6.413 6.331 6.33I 6.241 6.131 6.331 6.241 6.135 6.21I 6.I5I 6.059 6.069 5.879 5.795 6.24I 6.151 6.059 5.368 5.879 5.793 6.24I 6.151 6.059 5.069 5.879 5795 6.711 6,15I 6.059 5.969 5.879 5.795 6`151 6.059 5.969 5.879 5.795 6.9OO 6.844 6.844 6.814 6.750 6.610 6.50o 6.374 6.25O 6844 6.7~0 6.620

7.656 7,656 7.656 7.65~ 7,660 7.656 7£x~6 7.556 7.056 7.656 7.650 7. fff~6 7.656 7.656 %656 7.656 7,6*56 7.656 7.6,66 73:'56 7,656 7,050 7,656 7.656 7,6.58 7.656 7.6.~8 7.656 7.656 7.656 7.656 76fi6 7.656 7.656 7.656 7.6.50 71686 e.600 8.550 6.YgR) S`860 8.50{) 8`850 8,580 8.5UO 8.560 65(X)

---

6.625

6500

6.30] 6`975 6.969 6.875 6.705 6625 6`501 6`875 6.962 6.675 6.765 6,686 6.601 6.375 6.675 6.755 6.425 6.501 6.375

6.374 6.250 6.844 6.7.50 4.810 6.500 6.776 6230 6.814 6.750 6.6t~ 6.500 6.725 6.250 6.750 6410 6.500 6.376 6.25O

10

12

18

Line

D~t meWr

6`151 6.151

7,~ 7.~9o

0.15I 6.151 6`151 6.151 6,059 6,969 5.879 5,795 KIS1 6161 6059 5,969 5.879 6.'/95 6.151 6,151 ~m0~ 5.969 5.879 0.795 6.151 6.151 6,059 5.959 5,879 5.795 6.I51 6.059 5m959 5.679 6.795

7.390 7390 7390 7 39O 7.$9O 7.390 7.$30 75~) 7.390 7390 7 390 7390 7.530 7539 7.89O 7.590 7390 7690 7539 7 530 7.390 7.59~ 7.390 %39O 7.539 7.53() 7 396 7.390 7.$90 7.53o 7.5~3

6`750 6.750 6.750 6`750 6.640 6.580

8.010 8.010 8010 8010 8.010 8.010

85(~3

6,750 6.750 6.610

8.010 8010 8.010

8,609

8.126

6.500

8010

6.6(Y0 8.5(X~ 8.5(~ 9.61~) 8.6fg) 8.51~) 8,3t~) 8.51~) 8.5(~) ~,500 8.600 ~.5[8) ~.St~ g,5(~ 6.51~ ~`8{gl 8.500 6,5Wd 8,5f8~

8.I25 8.17~6 8.125 8.I25 8125 8.125 8125 8.125 8.125 8125 8.1~5 8.125 8.125 8.I25 8125 8.I25 8125 8.125 8.125

6.760 6.750 6.640 6`500

8.010 8,010 8.010 8.010

6.750 6.720 6.640 6.500

8.010 8.010 P~01O 8.010

6,750 6600 0.000

8.010 8.010 8.010

16

17

18

~

'

,

~99 763 822 532 6O4 676 745 814 877 532 6O4 676 745 814 877 632 717 808 885 966 104I 830 929 1025 1119 1205 ~76 414 414 564 611 725 839 23] 1031 602 683 778

2,310 2.720

2,510 2,750

415 316 364 415 499 566

4,980 3,740 4,360 4,980 5,94O 6,790 7,85~ 8,~g~ 9,340 10,12(I 6,34O 7,240 8,I60 9,069 9.~ 10,8GO 6,34O 7,24O 8,160 9,050 9,960 I 0,850

4,980 3,740 4.560 4,980 --

3,810

895

10,810 12,040 6,40~ 4,700 6,560 5,810 10,81o 12,010 8,710 5,120 7,260 9,$89 12,400 14,$00 5,340 7,050 I1,140 13,810 16..%30

928 1100 602 683 778 695 998 lI00 714 81I 928 I0fll 1185 I396 94O 1O69 1231 1372 1512

--

------

8,6~ 9.690

10,760 11,830 12,820 9,960 11,220 12,450 16.7{]0 14,850 2,750 4,140 4,I40 5.650 6,450 7,400 8,610 9.670 10,760

6,020

6,89O 7,9OO 9,180 10,320 11.480 6.820 6,890 7,900 8,180 I0,320 I1,480 7,I50 8.180 9.380 16.900 12.250 13,630 9,470 ]O,86O 12,620 I4,I90 15.780

22 28 ~4 * j o i n t Strength - - 1,oo0 I ~

26

'lT~'eaded ~md C o u p l e d Ro~d Thread O e ~

S~o~

But~

~g

Eomcme "i~wea d

R~-.~

-5

•

Grade

I96 ' o316

654

21

~

Line 1,450 1,980 2,270 3,270 4,320 8,270 3,270 4,820 3,770 5,25O 6,760 8,230 9,710 10,500 $,&~0 5,410 7,020 8,600 10,186 11,390 3,830 6,410 7,020 8,600 10,180 11,850 4,150 5,870 7,820 9,730 11,640 13,429 6,210 8,610 10,700 I$.010 15,110 2,040 8,890 2,890 6,280 4,070 6,62O 8~439 10.240 11,200 3,400 4,700 6,560

20

Y/etd, ~

Spe~

Strength

19

But~es~ T h r e a d

l~d ~o~

M

7.~5 7.375

16

Ro~d Thread

of~ tight

14

Internal ~ield Pressure at M k t i m ~

O u u d d e~

7.~5 7375 7.375 7~75 7.375 7.375 7.$75 7.375 7.375 7.375 7.375 7375 7.375 7.375 7.375 7.375 7.375 7375 7.375 7.375 7.375 7.375 7.375 7.375 7375 7,376 7.375 7.375 7.$75 7.875 7.$75 -8.125 8.125 8.125 8125 8.125 8~125 8.125 8.125 8.126 8125 8.I25

X,StXt

I1

-----

-2,750 4,140 4,140 -----------

-----

.

.

.

. --

4,98O .

4,980 .

.

I22 176

4,980

3,950

4,980

834

4,350 4,980 --

3,950 3,95O 5,380 8,~0 8.389 5,~0 8,380 8,380 5,740 5,740 5,740 6,740 5,740 5,74O 5,749 5,740 5,740 5,740 5,740 5,74O

4,~60 4,980

309 364

.

. --

.

.

Oq

. --

367

490

49O

421

490

341 401 416 489 56~ 6~3 701 767 435 511 587 661 734 891 442 519 507 672 746 814

522 592 557 6,~1 7O7 779 63~ 833 505 641 718 791 833 8~3 588 667 745 823 876 876

572 592 --

5~2 561 --

--588 667 746 8'23 898 968

5'~'2 566 565 563 538 583 ~33 566 533 565 568 566 533 539 561 501

685

8O8

---

768 853 93I 693 797 897 096 1.087

69I 920 920 853 955 1,053 1.696 1,0~6

346 377 461 642 635 751 852 963 482 56">6 664 786 892 997 490 675 674 798 905 1,013 660 659 772 914 1,037 1,I69 769 501 1,066 1,210 t,355

483 581 624 709 806 929 1,035 1,I40 630 721 820 945 1,053 1,160 659 749 852 981 1,003 1,~)5 716 8[3 925 1,065 1,I87 1,300 960 1,093 1,258 1,402 1,845

506

254

4,360 4,980 5,94O 6350 7,65O 8,490 8,66O 8,66O 6,34O 7,240 8,I60 9,(Foo 9,240 9,240 6,34O 7,24O 8,I60 9,060 9,240 9,240

4.360 4,980 5,940 0,~90 7,650 7,959 7,93O 7,930 6,340 7,210 8,I60 8A60 8.46~ 8,460 6,3~0 7,240 8,160 8,460 8,46O 8,460

8.600

8.64]0

6,810

593

9.699

9,6~0

--

6.810

10.760 10,970 10,970 2,960 ] 1,220 12,460 12,7(]0 12.700

10,050 I0,050 10,050 9,96O 11,220 11,649 ll,640 11,840

--0,260 11,220 12,460 13.780 14,850

6,810 6,810 6.810 7,890 7,890 7,89O 7,89O 7,8~0

4,I40 4,I40 5,650 0,450 7,400 8,610 9.67O 9,840 6,020 6,890 7,~R) 9,180 10,320 10.490 6.020 f~890 7,900 2,I80 10,320 I0,490 7.I50 6.180 9,88@ 10,900 12.250 12,460 9,470 10,860 I2,620 14,I50 14.430

4,[40 4.I40 5.650 6,450 7.4(I0 ~.610 9.]90 gag0 6.020 6.F~90 7.9E~) 9A80 9.790 9.970 6.O2O 6.89O 79O0 9.I80 9.7(X} 9,790 7.150 6,180 9~3K(} I 0.91]o 1].620 I 1.620 9,470 I0.8~ I2,620 13,4£~) [ 3.4611

--

8,346 7,210 8,160 0,060 9.960 |0,880 6,34O 7,24O 8,160 9,060 9,960 I0,800

4,140 4,140 ---6.020 6,690 7,9OO 0,I80 -0.620 6,890 7,900 8,180 10,320 11,480 --

-0,470 I 0,86o I2,8~ 14,150 16.780

4.140 4.140 5.650 6.140 6,149 6.14(} 6.140 6.1~3 6,020 6.550 5.550 6.550 6.650 6.55O 6.O20 6.551~ 6,55O 6.550 6.550 6.550 7,]5~} 7.78o 7.78O 7TA0 7.780 7.78o 9.0{X~ 9J~O 9.(R~) 9.(.~ ~ 9.t~lO

6,840 7,210 7,890 7,850

----

7,890

7.890 6,34O 7,240 7,890 7,890 7,89O 7,890

9,960 10,760 10,766 10.769 10,760 -4,140 4,140

6,020 6,500 7,9OO 9,000 6,02O 6,890 7,O00 9,OOO 9,000 9,C00

0,470 10,860 12,280 12,'280 12,280

-----

--

-212 316 342

-------

----

--

------

--863 955 1,053 1.150 1,239 . 483 581 --------659 749 862 98I 1,093 1,204 ----960 1,093 1,258 1.402 1,545

--

6-{'2 641 685 61I 695

--------588 667 702 7O2 702 702

561

56I 561 501

681 855 917 662 641 680 761 856 917 666 075 781 801 805 896

6~2 64I 632 641 674 674 781 78I 632 641 674 674 761 761 666 678 709 7O9 801 801

589 ---

886

.

589 589 589 702 702 702 702 702 . 466 561 624 709 735 780 735 735 636 721 736 755 765 785 &59 749 776 776 775 773 710 812 818 812 812 812 060 907 907 207 967

841 940 1,016 844, 902 1,502 1,118 1,20'/

744 744 84I 84I 844 884 886 1.002 1,002

566 700 700 700 766 851 --

553 700 700 700 744 744 --

700 750 766 651 --

7OO 700 744 744 --

737 737 806 896 --

767 737 784 784 --

--

774 774 846 941 --

774 774 828 82.3 --

960 1.093 1,237 1,237 1,257

922 1,508 1,120 ---

922 979 979

-853 898 898 898 89~

757

. 483 581 --------659 749 862 967 967 967 ---

--

w..-

0

2 0

1

2

3

4

5

6

7

8

9

I0

II

12

13

14

15

16

17

18

19

20

21

22

23

"~o~, s ~ Thre~ed ~ d Coupl~l

.

.

.

.

.

. t"

8~

9~

" W

d

28.00 32,00 24.00 32.00 36.00 24,00 32.00 36.00 36.00 40.00 44.00 49.00 36.00 49.00 44.00 49.00 36.00 40.00 44.00 49.00 36-00 40.00 44.00 49.00 49.00 44.00 49,00

H-40 0.304 H-40 0.352 J ~ 5 0.264 J-55 0.352 J~55 0.400 K~58 0,264 K~55 0.352 K-55 0.400 C-75 0.400 C-75 0.450 C~75 0.500 C-75 0.557 L~0 0.400 ~ 0.450 L-80 0.500 L-80 0.557 N~80 0.400 N.g0 0.450 N-80 0.500 N-80 0.557 C-95 0.400 C-95 0.450 G-95 0.500 C-95 0.557 P-110 0.450 P-110 0.500 P-110 0.557

8.017 7.921 8.097 7.921 7.825 8.097 7.921 7.828 7.825 7,725 7.625 7.511 7.825 7.725 7.625 7.511 7~825 7.725 7.625 7.511 7.825 7.725 7.626 7.511 7.725 7.625 7.511

7.892 7.796 7.972 7.796 7,700 7,972 7.796 7.700 7.700 7.600 7.300 7.386 7.700 7.600 7.500 7.386 7.700 7.600 7.500 7.386 7.706 7.600 7.500 7.386 7.600 7.500 7.386

9.625 9,625 9,625 9.625 9.625 9.625 9,625 9,625 9.625 9.625 9.625 9.825 9.625 9.625 9,625 9,625 9.625 9.625 9,625 9.628 9.625 9.625 9.625 9,625 9.625 9.625 9.625

82.30 36.00 36.00 40.00 38,00 40.00 40.00 43.50 47.00 53.50 40.00 43.50 47.00 53.50 40.00 43.50 47.00 53.50 40.00 43,80 47,90 53,50 43.50 47.00 53.60

H 4 0 0.312 H40 0.262 J-56 0.352 J~55 0.395 K-55 0.~52 K-55 0.395 C-75 0.395 C-75 0,435 C-76 0.472 C-75 0.545 L~O 0.395 L-80 0.435 I~80 0.472 L80 0.545 N-80 0.395 N-g0 0.435 N~0 0.472 N-~0 0.545 C-95 0.395 C-95 0.435 C-95 0.472 C-95 0.545 P-110 0,435 P-D0 0,472 P-110 0.545

9.00I 8.921 8.921 8.835 8.921 8,835 8.835 &755 8.681 8.535 8.835 8.755 8.68I 8.535 8.835 8.755 8.681 8.535 8.835 8.755 8.68t 8.535 8.755 8.681 8.535

8.845 8.765 8.765 8,679 8.765 8,679 8.679 8.599 8.528 8.579 8.679 8.599 8.525 8.379 8.679 8.599 8.525 8.379 8.679 8.599 8.525 8.379 8.599 8.525 8.379

t0.625 10,625 10,625 10.625 10.625 10.625 I0.625 10,625 10.625 10.625 10.625 10.625 I0.625 10.625 10.625 10,625 10.625 I0.625 10.625 I0.625 10.625 10.623 10.625 10,625 10.625

~Line

. . . . W.

9.125 9.125 9.125 9.125 9.125 9,125 9.125 9.125 9.I25 9.125 9.125 9.125 9.125 9.I25 9.125 9.125 9.125 9.I25 9.125 9,125 9.125 9.125 9,125

10.128 10.125 10.125 10.125 10.125 10,125 10.125 10.125 10,125 10.125 10.125 10.125 10.125 I0,I25 10.125 10.125 10.125 I0,125 10.125 10.125 10.125 10,125 10.125

|otet't~ Yieldl%t~r¢ at Mi~mm Yi¢ld,p~i

". M

~

.

.

.

.

. Liee

.

.

.

.

~

518 366 381 503 568 381 503 568 775 867 957 1059 827 925 1021 1129 827 925 1021 1129 982 1098 1212 1341 1271 1404 1553

2,470 2,860 2,950 3,930 4,490 2,950 3,930 4,460 6,~0 6,850 7,610 8,480 6,4~ 7,390 8,120 9,040 6,490 7,300 8,120 9,040 7,710 8,670 9,640 10,740 10,040 II,160 12,430

2,470 2,860 2~950 3,98o 3,93o 3,930 4,460 4,46o 4,460 2,950 3,980 3,930 3,930 4,460 4,460 4,460 -6.090 6,900 ~ 6,850 6,850 ~ 7,610 7,610 -8,480 8,480 -6,490 6,490 -7,300 7,300 ~ 8,I20 8,120 -9,040 9,040 -6,490 6,490 -7,300 7,390 -8,I20 8,129 ~ 9,040 9,040 -7,710 7,710 -8,670 8,670 ~ 9,640 9,640 - - 10,740 10,740 - - t0,040 10,040 - - 11,160 11,160 - - 12,430 12,430

1,400 1,740 2,020 8.599 10.t00 2,570 2,020 8,599 1O.100 2,570 8.599 10,100 2,980 8.599 16,100 3,750 8,525 10.I00 4.630 8.$79 t0,100 6,380 8.599 I0.100 3,090 8.599 I0.100 3,816 8.525 10.100 4,750 8.379 I0.100 6,620 8.539 10.190 3,090 8.590 10d00 3,610 8.325 I0.100 4,750 8.379 10,I00 6,620 8.590 10.100 3,330 8,599 10.100 4,130 8.525 10.I00 5,080 8.379 I0.I00 7,230 8,599 10.100 4,430 8,525 10,100 5,310 8.379 10.100 7,930

365 410 569 680 564 630 859 942 1018 1166 918 1005 1086 1244 916 1005 t088 1244 1088 1193 1239 1477 1381 1403 1710

2,270 2,560 3,520 3,950 3,520 3,950 5,390 5,930 6,440 7,430 5,750 6,330 6,870 7,930 5,750 6,339 6,870 7,930 6,820 7,510 8,150 9,410 8,700 9,440 10,900

2,270 2,560 3,520 3,950 3,520 3,950 ~ ----- . ---~ --------

9.120 9.120

7.700 9.120 7.700 9,120 7.700 9.120 7.600 9.120 7.500 9.120 7.386 9,120 7.700 9.i20 7.600 9,120 7.500 9.120 7,386 9.120 7.700 9.120 7.600 9.120 7.500 9.120 7.386 9.120 7.700 9.120 7,600 9.I20 7.500 9,120 7.386 9.120 7.600 9.120 7.500 9.I20 7.386 9.120

---

3,520 3.520 8,950 3,980 3,520 3,520 3,950 3,950 6,390 5,390 5,930 5,930 6,446 6,440 7,430 7,430 5,750 5,750 6,330 8,330 6,870 6,870 7,930 7,930 5,750 5,750 6,339 6,330 6,870 6,870 7,930 7,930 6,820 6,820 7.510 7,510 8,150 8,150 9,410 9,410 8,700 8,700 9,440 9,440 10,900 I0,900

25

26

~e?

Grade:

F,x~

27 Line

C~pllng

Grade

1,640 2,210 1,870 2,580 3,450 1,370 2,530 3,450 4,020 5,350 6,680 8,200 4,100 5,520 6,950 8,570 4,100 5,520 6,950 8,570 4,360 6,010 7,730 9,690 6,380 8,400 10,720

7.700 7.700

G~d~

24

- t,o~,,

"1ffar~tde~~ d ~apled

e; -8,930 ¢460

8,93o ¢o6o

8,980 4,460 .% o,~o0 4,460

3,930 4,469 --------6,490 7,300 8,120 0,040 -~ --10,040 11,160 12,430

3,930 4,060 5,530 5,530 5,530 5,530 5,900 5,9~ 5,900 5,900 5 , 9 0 0 6,490 5 , 9 0 0 7,809 5 , 9 0 0 8,110 5,90O 8,110 7,010 7,010 7,010 7,010 8 , 1 1 0 t0,040 8,110 11,060 8,110 11,060

3,520 8,950 3,520 3,950 --------5,750 6,330 6,870 7,930 ----6,700 9,440 10,900

3,520 9,660 3,520 3,660 4,990 4,996 4,990 4,990 5,620 5,320 5,320 5,520 5,320 8,320 5,320 6,520 6,310 6,310 6,310 6,310 7,310 7,310 7,310

233 279 244 372 434 268 402 468

-----

----

-3,520 3,956 3,520 3,950

254 294 394 458 425 486

5,750 6,330 6,870 7,310

-----

8,700 -9,4~0 - 9,970 - -

--417 486

579 654

579 ~4

452 526 648 742 834 939 678 776 874 983 688 788 887 997 789 904 1,017 L144 1,055 I,I86 1,336

690 780 847 947 1,046 1.157 854 966 1,066 1,180 895 1,001 1,105 1,222 976 1,092 1,206 1,334 1,288 1,423 1,574

453 520 489 561 694 776 852 999 727 813 893 1,047 737 825 905 1,902 847 948 1,010 1,220 1,106 1,213 1,422

639 714 755 843 926 1,016 1,098 1,257 947 1,038 1,122 1,286 979 1,074 1,16I 1,329 1,074 1,178 1,273 1,458 1,388 1~ 1,718

T~

---

654

579 054

686 686 688 . 688

690 780 --------895 1,901 1,105 1~222 ----1,288 1,423 1,574

690 780 839 839 839 839 839 839 839 839 883 883 883 883 927 927 927 927 1,103 1,103 1,103

690 780 --------895 1,901 1,I03 1,103 ----1,288 1,412 1,412

639

--639

639

714

714

714

770

770

755 843 --------979 1.074 1,161 1,329 ----1,388 1,500 1,718

755 843 926 934 934 934 934 934 934 934 979 983 983 983 t,032 1,032 1,032 1,032 1,229 1,229 1,229

755 843 --------979 1,074 1,161 1,229 ----1,388 l,fi00 1,573

975 975 975 1,032 1,I75 975 975 1,032 1,173 1.027 1,027 1,086 1,238 1,078 1,078 1,141 1,297 1,283 1,358 1,544

975 975 975 1,032 1,053 975 975 1,032 1,053 1.027 1,027 1,086 I,I09 1,078 1,078 1,141 1,I64 1.283 1,358 1,686

869 871 871 942 1,907 1,007 871 942 1,907 1,907 917 992 1,060 1,060 963 1,042 1,113 1,113 1,240 1,326 1,326

869 871 871 886 886 886 871 886 886 886 9t7 932 932 932 963 979 979 979 1,165 1,165 1,165 ---

Oq

Table 4-150 (continued) 1

2

$

4

5

6

7

8

"lToreaded ~ d coupled

9

11~

11

II

l~

Extreme Line

Nominal Outside Wei~t, Otltslde Diameter Size: Threads Drift Diameter Speeial Drift Outside ~d Wall lr~ide Diaof Clearance DiaDinmeterCottpling G t - a d e T h i c l m ~ D t a m e t e r ~ t e r Coupting Coitpling r~eter in. lb per ft ha. in. in. in. in. . /7 t d W We 10~

10

14

15

16

17

18

19

io

L~lermtl Xtield]P~xe~m~e at M i n i m m Xtield~jam

Outside Dim~eter Pipe o f Box Collapse Body Power- Resist- Yield light a n t e Strength in. psi 1000 lbs M

21

II

~t:¢

24

26

Threaded ~ttldCoupled

Buttree~ Thread R o s a Thread f ~ ~ ~ Plain Short Long Regular SpeclatCle~ Fald Coupling Coupling or ~ x ~ ~ Ext~me Same Highe-- Same I~ne Gt~tde Gtede Grade . Grade

F ~ u e ~ Line

Round l~u~aa f B~th-ess Thread Standard Optional x ~ Joint Joint Short Long Regular Regular Special Spedal Coupling Coupling C ~ e ~ Cle~ Higher COup~g Coupling Grade." Ix.lg~ Grade2~

367 457

1,820 2,280

1,820 2,280

9.794 11.4:60 9.694 11.460

1,580 2,090 2.700

629 715 801

3,130 3,580 4,030

3,130 3,580 4,030

----

3,130 3,580 4,030

3,130 3,580 4,030

3, I30 3,290 3,290

3,130 3,580 4,030

420 493 565

----

700 796 891

700 796 89t

700 796 822

700 796 891

-075 1,092

----

11.250 I1.250 11.250

9.794 11.460 9.694 11.460

1,580 2,090 2,700

629 715 801

3,130 3,580 4,030

3,130 3,580 4,030

----

3,130 3,580 4,030

3,130 3,580 4,030

3,130 3,200 3,290

3,130 3,580 4,030

450 528 606

----

819 931 1,043

819 931 1,043

819 931 1,041

819 931 1,043

-1,236 1,383

----

11.250 11.250

9.694 11.460 9,604 11.460

3,100 3,950

1092 1196

5,490 6,040

5,490 6,040

---

5,490 6,040

---

756 843

---

1,160 1,271

---

1,383 1,515

---

9.694 11.750 9.604 11.750

11.250 11.250

9.694 11.460 9.604 11.460

3,220 4,020

1165 1276

5,860 6,450

5,860 6,450

---

5,860 6,450

---

794 884

---

1,190 1,303

---

1,383 1,515

---

9.694 11.750 9.604 11.750

11.250 11.250

9.694 9.604

11.460 11.460

3,220 4,020

1165 1276

5,860 6,450

5,860 6,450

---

5,860 6,450

804 895

---

1,228 1,345

1,456 1,595

---

9.850 9.760

9.694 11.750 9.604 11.750

11.250 11.250

9.694 1t.460 9.604 11.460

3,490 4,300

1383 1515

6,960 7,660

6,960 7,660

---

6,960 7,660

927 t,032

---

1,354 1,483

1,529 1,675

---

9.850 9.760 9.660 9.569

9.694 11.750 9.604 11.750 9.504 11.750 9A04:11.750

11.250 11.250 11.250 11.250

9.694 11.460 9+604 l l A 6 0 9.504 11.460

3,670 4,630 5,860 7,490

1602 1754 1922 2088

8,060 8,060 8,860 8,860 9,760 9,760 10,650 10,650

-----

1,080 1,203 1,338 1,472

-----

1,594 1,745 1,912 2,077

1,820 1,993 2,600 --

-----

H-40 H-40

0.279 0.350

10.192 t 0 . 0 3 6 11.750 10.050 9.894 11.750

40.50 45.50 51.00

J-55 J-55 J-55

0.350 0.400 0.450

10.050 9.950 9.850

9.894 11.760 9.794 11.750 9.694 11.750

11.250 11.250 11.250

40.50 45.50 51.00

K-55 K-55 K-55

0.330 0.400 0.450

10.050 9.950 9.850

9.804 I I . 7 5 0 9.794 11.750 9.694 11.750

51.00 55.50

C-75 C-75

0.450 0.495

9.850 9.760

9.694 11.750 9.604 11.750

51.00 55.50

L-80 L-80

0.450 0.495

9.850 9.760

51.00 55.50

N-S0 0.450 N-80 0.495

9.850 9.760

51.00 55.50

C-95 CO5

0.450 0.495

51.00 55.50 60.70 65.70

P-110 P-110 P-If0 P-II0

0.450 0.4:95 0.545 0.595

---

17

880 1,420

32.75 40.50

---

4,490 4,490

---

4,790 4~790

5,860 6,450 ---

8,060 8,060 8,860 8,860 9,760 9>760 10,650 10,650

4,760 4,790 5,680 5,680 6,580 6,580 6,580 6,580

5,860 6,450 --8,060 8,860 8,970 8,970

205 314

.

.

.

---

1,041 1,041

---

1,041 1,041

1,228 1,345 --1,594 1,745 1,912 2,077

1,096 1,096 1,151 1,151 1,370 1,370 1,370 1,370

4:2.00

Hde0 0.333

11.084 10.928 12.750

1,070

478

1,980

1,980

--

307

J-55 J-55 J-55

0.375 0.435 0.489

11.060 10.844 12.750 10.880 10.724 12.750 10.772 10.616 12.750

1,510 2,070 2,660

737 850 952

3,070 3,560 4,010

3,070 3,560 4,010

----

3,070 3,560 4,010

3,070 3,560 4,010

----

----

477 568 649

----

807 931 t,042

807 931 1,042

----

47.00 54.00 60.00

K-55 K~55 K-55

0.375 0.435 0.489

11.060 10.844 12.750 I0.880 10.724 12.750 10.772 10.616 12.750

1,510 2,070 2,660

737 850 952

3,070 3,560 4,010

3,070 3,560 4,010

----

3,070 3,560 4:,010

3>070 3,560 4,010

----

----

509 606 693

----

935 1,079 1,208

935 1,079 1,208

----

3,970

1298

5,460

5,460

--

5,460

--

869

--

1,361

--

3,180

1384

5,830

5,830

--

5,830

--

913

--

1,399

--

3,I80

1384

5,830

5,830

--

5,830

--

924

--

1,440

3,440

1644

6,920

6,920

--

6,920

--

1,066

--

1,596

60.60

C-75

0.489

10.772 10.616 12.750

60.00

I.,80

0.489

10.772 10.616 12.750

60.00

N..80 0.489

10.772 10.616 12.750

60.00

C-95

10.772 10.616 12.750

-----

.

. --

47.00 54.00 60.00

0.489

,?.5

--

1,440 --

--

-----

1,228 1,345 --1,594 1,745 1,754 1,754

--

-0

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

z5

i,6

* j o l m s u ~ g t h - - 1,00o Ib, Threaded and Coupled NomJaal Weight, O~de Size: Threads Drift Diameter Outside and Wall In~fide ~ of Diante~r Coupling Grade Thicknes~ Diameter meter Coupling in. lb per ft in. Ju. ill. in. D t d W 13~

16

18~4

20

48.00

H-40 0.330

12.715 12.559 14.375

Extreme Line

Internal Yield ~

Oil(side O u t , de Diameter Diameter Pipe Special Dt~ft o f B o x Collallse Body Y'~ld CAearance D/w PowerCoup/ing meter ~ t ance St~eng~ in. in. in. J~i lO00 IbGt We, M ' 770 541 Re~i~t-

at Minfl,a ~ ~ l d , pel

Round Tl~ead Plain Short Etld or Extreme Une

Long

Threaded ~ d Coupled

Buttre~ Thread Regular Coupling

Same ~ Grade

Grade

~,f

SpechdCl~ Coup~ag

f~e Gntde

Rou.d Thread Sbo~

Extreme Line

I~uttre~ Thread

"~ Long Regular Regular Sl~clal Spe~al Coupling C~uplmg Cleanm~ Qearance

~ Gntde

~ Gntd~

~U~

CO~ 141gher Gn~de~

1,730

1,730

--

322

--

--

54.50 61.00 68.00

J-55 J-55 J-55

0.380 0.430 0.480

12.615 12.459 14.375 12.515 12.359 14.375 12.415 I2.259 14.375

1,130 1,540 1,950

853 962 1069

2,730 3,090 3,450

2,730 3,090 3,450

----

2,730 3,090 3,450

2,730 3,090 3,450

----

----

514 595 675

----

909 1,025 1,140

909 1,025 1,140

----

--

54.50 61.00 68.00

K-55 K-55 K-55

0.380 0.439 0.480

12.615 12.459 14.375 12.515 12.359 14.375 12.415 I2.259 14.375

1,130 1,540 1,950

853 962 1069

2,730 3,090 3,450

2,730 3,090 3,450

----

2,730 3,090 3,450

2,730 3,090 3,450

----

----

547 633 718

----

1,038 1,169 1,300

1,038 1,169 1,300

----

----

68.00 72.00

C-75 C-75

0.480 0.514

I2.415 12.259 14.375 12.347 12.191 14.375

2,220 2,590

1458 1558

4,710 5,040

4,710 5,040

---

4,710 5,040

905 978

---

1,496 1,598

---

---

---

68.00 72.00

L-80 L80

0.480 0.514

12.415 12.259 14.375 12.347 12.191 14.375

2,260 2,670

1556 1661

5,020 5,380

5,020 5,380

---

5,020 5,380

952 1,029

---

1,545 1,650

---

---

---

68.00 72.00

N40 N~0

0.480 0.514

12.415 12.259 14.375 12.347 12.191 14.375

2,260 2,670

1556 1661

5,020 5,380

5,020 5,380

---

5,020 5,380

963 1,040

---

1,585 1,693

1,585 1,693

---

---

68.00 72.00

C-95 C-95

0.480 0514

12.415 12.259 14.375 12.347 12.191 14.375

2,320 2,820

1847 1973

5,970 6,390

5,970 6,390

---

5,970 6,390

1,114 1,204

---

1,772 1,893

---

---

--

65.00

H40

0.375

15.250 I5.062 I7.000

670

736

1,640

1,640

75.00 84.00

J-55 J-55

0.438 0.495

15.124 14.936 17.000 15.016 14.822 17.000

1,020 1,410

1178 1326

2,630 2,989

2,630 2,980

---

2,630 2,980

2,630 2,980

--

--

710 817

---

1,200 1,351

1,200 1,351

75.00 84.00

K-55 K-55

0.438 0.495

15.124 14.936 17.000 15.010 14.822 17.000

1,020 1,410

1178 1326

2,630 2,980

2,630 2,980

---

2,630 2,980

2,630 2,980

---

---

752 865

---

1,331 1,499

1,331 1,499

439

87.50

H-40 0.435

17.755 I7.567 20.000

*630

994

1,630

1,630

--

559

J-55

0.435

17.755

17.567 20.000

*630

1367

2,250

2,250

--

754

--

1,329

1,329

87.50

K-55

0.435

17.755 17.567 20.000

*630

1367

2,250

2,250

--

794

--

1,427

1,427

94.00

H-40 0.438

19.124 18.936 21.000

*520

1077

1,530

1,530

--

581

- -

~,

OO - -

94.00 106.50 133.00

J-55 j-55 j~55

0.438 0.500 0.635

19.124 18.936 21.000 19.000 18.812 21.000 18.730 18.542 21.000

*520 *770 1,500

1480 1685 2125

2,110 2,410 3,060

2,110 2,410 3,060

2,110 2,410 3,060

----

784 913 1,192

907 1,057 1,389

1,402 1,596 2,012

1,402 1,596 2,012

----

94.00 106.50 133.00

K-55 K-55 K-55

0.438 0.500 0.625

19.124 18.036 21.000 19.000 18.812 21.000 18.730 18.542 21.000

*520 *770 1,500

1480 1685 2125

2,100 2,410 3,060

2,I10 2,410 3,060

2,110 2,410 3,060

----

824 969 1,253

955 1,113 1,453

1,479 1,683 2,123

1,479 1,683 2,123

----

T a k e n f r o m API BuI 5 C 2 , 1 7 t h Edition, M a r c h I980. Source: P r o m Ref. [ 155]

--

--

87.50

+* For P-110 casing t h e n e x t h i g h e r g r a d e is 150YS, a non-APl steel g r a d e h a v i n g a m i n i m u m yield s t r e n g t h o f 150,000 psi. * S o m e j o i n t s t r e n g t h s listed in Col. 20 t h r o u g h 27 are g r e a t e r t h a n the c o n - e s p o n d i n g pipe b o d y yield s t r e n g t h listed in CoL 12. * Collapse resistance vaIues calcuIated by elastic f o r m u l a .

Standard Op00usd Joint Jo/n¢

,.,, Oq

1154

Drilling and Well Completions Table 4-151 D/t Ranges for Collapse Pressures

Steel Grade

D/t range for formula (1)

H-40 J-K-55 C-75 L-N-80 C-95 P-105 P-110

16.44 14.80 13.67 13.38 12.83 12.56 12.42

& & & & & & &

less less less less less less less

D/t range for formula (2) 16.44 14.80 13.67 13.38 12.83 12.56 12.42

to to to to to to to

D/t range for formula (3)

26.62 24.39 23.09 22.46 21.21 20.66 20.29

26.62 24.39 23.03 22.46 21.21 20.66 20.29

to to to to to to to

42.70 37.20 32.05 31.05 28.25 26.88 26.20

D/t range for formula (4) 42.70 37.20 32.05 31.05 28.25 26.88 26.20

& & & & & & &

greater greater greater greater greater greater greater

Table 4-152 Factors for Collapse Pressure Formulas Formula Factor Steel Grade

A

B

C

F

G

H-40 J-K-55 C-75 L-N-80 C-95 P-105 P-110

2.950 2.990 3.060 3.070 3.125 3.162 3.180

0.0463 0.0541 0.0642 0.0667 0.0745 0.0795 0.0820

755 1205 1805 1955 2405 2700 2855

2.047 1.990 1.985 1.998 2.047 2.052 2.075

0.03125 0.03360 0.0417 0.0434 0.0490 0.0515 0.0535

(text continued from page 1147)

The factors F and G and applicable D / t range for the transition collapse pressure formula are shown in Tables 4-152 and 4-151, respectively. Elastic Collapse Pressure Formula. The minimum collapse pressure of the elastic range of collapse is calculated by

pE =

46.95 × 10 6 (D/t)l(D/t _ 1)12

(4-311)

C o l l a p s e P r e s s u r e under Axial Tension Stress. T h e r e d u c e d m i n i m u m collapse pressure caused by the action of axial tension stress is calculated by

Pc, = P e o [ 4 1 - 0-75[(SA + Pi ) / g p ] 2 _ 0 . 5 ( S A + p i / g p ) ]

(4-312)

Equation 4-312 is not applicable if Pco is calculated from the elastic collapse formula.

Casing and Casing String Design

1155

Symbols in Equations 4-308 to 4-312 are as follows: = n o m i n a l outside d i a m e t e r in in. t = n o m i n a l wall thickness in in. y = m i n i m u m yield strength of the pipe in psi P p ~ = m i n i m u m yield strength collapse pressure in psi pp = m i n i m u m plastic collapse pressure in psi PT = m i n i m u m p l a s t i c / e l a s t i c transition collapse pressure in psi pE = m i n i m u m elastic collapse pressure in psi PCA = m i n i m u m collapse pressure u n d e r axial tension stress in psi PCO = m i n i m u m collapse pressure without axial tension stress in psi SA= axial tension stress in psi Pi = internal pressure in psi O

Internal Yield Pressure (Section 3 of API 5C3) Internal Yield P r e s s u r e for Pipe. Internal yield pressure for pipe is calculated from formula 4-133. T h e factor 0.875 a p p e a r i n g in formula 4-313 allows for m i n i m u m wall thickness.

Pl = 0.875 ~ where Pi Yp t D

= = = =

(4-313)

m i n i m u m internal yield pressure in psi m i n i m u m yield strength in psi n o m i n a l wall thickness in in. n o m i n a l outside d i a m e t e r in in.

Internal Yield Pressure for Couplings. Internal yield pressure for t h r e a d e d and coupled pipe is the same as for plain e n d pipe, except where a lower pressure is required to avoid leakage due to insufficient coupling strength. T h e lower pressure is b a s e d on

P= Y c l ~

(4-314)

where Y = m i n i m u m yield strength at coupling in psi D I = n o m i n a l outside d i a m e t e r of coupling d 1 = diameter of the root of the coupling thread at the end of the pipe in the powertight position (see API Bulletin 5C3, 3rd Edition, March 1980)

Pipe Body Yield Strength (Section 2 of API 5C3). Pipe body yield strength is the axial load required to yield the pipe. It is taken as the p r o d u c t o f the crosssectional area and the specified m i n i m u m yield strength for the particular g r a d e o f pipe. Values for pipe b o d y yield strength were calculated by means o f the following formula: Pv = 0"7854( D2 - d2)yp where Pv = p i p e b o d y yield strength in psi Yp = m i n i m u m yield strength

(4-315)

1156

Drilling and Well C o m p l e t i o n s D = specified outside d i a m e t e r in in. d = specified inside d i a m e t e r in in.

Joint Strength (Section 9 of API 5C3) Round Thread Casing Joint Strength. Round thread casing j o i n t strength is calculated from formulas 4-316 and 4-317. The lesser o f the values obtained from the two formulas governs. Formulas 4-316 and 4-317 apply to both short and long threads and couplings. Formula 4-316 is for minimum strength o f a joint failing by fracture and formula 4-317 for m i n i m u m strength o f a j o i n t failing by thread j u m p o u t or pullout. T h e fracture strength is T. = 0.95A. U JP

,1

P

(4-316)

T h e pull-out strength is

Tj =0.95A~L]0.5L+0.14D0"74-°59Up + L+Y~14D

(4-317)

where T. = m i n i m u m j o i n t strength in lb A. J = cross-sectional area o f the p i p e wall u n d e r the last perfect t h r e a d JP in in. 2 = 0.7854 I(D - 0.1425) 2 - d2[ for eight r o u n d threads D = n o m i n a l outside d i a m e t e r o f p i p e in in. d = n o m i n a l inside d i a m e t e r o f p i p e in in. L = e n g a g e d t h r e a d length in in. = L 4 - M for nominal makeup, S t a n d a r d 5B Y = m i n i m u m yield strength o f p i p e in psi U p = m i n i m u m ultimate strength o f p i p e in psi P

Buttress Thread Casing Joint Strength. Buttress t h r e a d casing j o i n t strength is calculated from formulas 4-318 a n d 4-319. T h e lesser o f the values o b t a i n e d from the two formulas governs. Pipe t h r e a d strength is Tj = 0.95ApUp I1.08 - 0. 0386(1. 083 - Y J U p ) D I

(4-318)

Casing t h r e a d strength is Tj = 0.95A U where T. = Y~p = Up = Uc = = AP¢ D = D =

(4-319)

m i n i m u m j o i n t strength in lb m i n i m u m yield strength o f p i p e in lb m i n i m u m ultimate strength o f p i p e in psi m i n i m u m ultimate strength o f coupling in psi cross-sectional area o f plain end pipe in in? where A = 0.7854(I~ - d 2) cross-sectional area o f coupling in in. 2 where A ='0.7854(D~ - d~) outside d i a m e t e r o f p i p e in in. outside d i a m e t e r o f coupling in in.

Casing and Casing String Design

1157

d = inside diameter of pipe in in. d i = diameter of the root of the coupling thread at the end of the pipe in the powertight position Extreme-line Casing Joint Strength. Extreme-line casing joint strength is calculated from Tj = AcrUv

(4-320)

where T. = minimum joint strength in lb A J = critical section area of box, pin or pipe, whichever is least, in in. 2 (see API Bulletin 5C3) Up = specified minimum ultimate strength in psi (Table 4-142) cr

Combination Casing Strings The term combination casing string is generally applied to a casing string that is composed of more than one weight per foot, or more than one grade of steel, or both.

Design Consideration Solving the problem of casing string design for known type and size of casing string relies on selection of the most economical grades and weights of casing that will withstand, without failure, the loads to which the casing will be subjected throughout the life of the well. There are various established methods of designing a technically satisfactory combination casing string. The differences between these methods rely u p o n different design models, different values of the safety factors and different sequences of calculations. There are no commonly accepted methods of combination casing string design nor accepted values for the safety factors. Some suggestions are offered below; however, the decision is left to the person responsible for the design. In general, the following loads must be considered: i.e., tension, collapse, burst and compression, and the reasonably worst working conditions ought to be assumed.

Collapse The casing must be designed against collapse to withstand the hydrostatic pressure of the fluid behind the casing at any depth, decreased by anticipated pressure inside the casing at the corresponding level. Usually, the maximum collapse pressure to be imposed on the casing string is considered to be the hydrostatic pressure of the heaviest mud used to drill to the lending depth of the casing string, acting on empty string. Depending u p o n design model, it is r e c o m m e n d e d to use a design factor of 1.0 to 1.2. For example, if it is known that casing will never be empty inside, this fact should be considered for collapse pressure evaluation and selection of the magnitude of safety factor.

Burst Casing must be designed to resist expected burst pressure at any depth. In burst pressure consideration, it is suggested to consider different design models depending u p o n the type of casing string.

1158

Drilling a n d Well C o m p l e t i o n s

Conductor String It is assumed that the external pressure is zero. In any case, the m a x i m u m expected internal pressure cannot be greater than fracture pressure at the o p e n hole below the c o n d u c t o r casing shoe; usually, it is the first f o r m a t i o n right below the casing shoe. If this pressure is not known (in e x p l o r a t o r y drilling), t h e b u r s t p r e s s u r e o f gas e q u i v a l e n t to 0.9 or 1.0 p s i / f t can b e a s s u m e d . Hydrostatic h e a d due to gas weight is neglected. For example, if the setting d e p t h o f conductor string is 1,100 ft, then the maximum expected burst pressure is even along the string and equal to (1,100)(1.0) = 1,100 psi; Safety factor = 1.1 to 1.15.

Surface and Intermediate Strings It is suggested to evaluate the b u r s t l o a d b a s e d on the i n t e r n a l p r e s s u r e expected, r e d u c e d by the e x t e r n a l pressure o f the drilling f l u i d outside the string. Internal pressure is b a s e d on the expected b o t t o m h o l e pressure o f the next string with the hole b e i n g evacuated from drilling f l u i d up to a m i n i m u m o f 50%. In e x p l o r a t o r y wells, a reasonable a s s u m p t i o n o f expected f o r m a t i o n p o r e pressure g r a d i e n t is required.

Example 3 Evaluate an expected burst pressure acting on surface casing string in exploratory drilling if setting d e p t h o f the string is 5,000 ft, m u d specific gravity is 1.2 and setting d e p t h o f the next string is 11,000 ft.

Solution Step 1: Internal pressure in the borehole. Because the next string is set at 11,000 ft, the f o r m a t i o n p o r e pressure g r a d i e n t is assumed to be 0.65 psi/ft. Thus, the b o t t o m h o l e pressure (at a d e p t h o f 11,000 ft) is (11,000)(0.65) = 7,150 psi. Assume 50% o f evacuation; thus, (11,000)(0.5) = 5,500 ft. Note: It is assumed that below 5,500 ft, the hole is filled with m u d which exerts a pressure g r a d i e n t o f 0.65 p s i / f t . T h e hole above 5,500 ft is filled with gas, the weight o f which is ignored. The internal pressure at a d e p t h o f 5,500 ft is (5,500)(0.65) = 3,575 psi. Since the weight o f gas is i g n o r e d for this type o f string, the internal pressure at the top o f the hole is also 3,575 psi. Step 2: External pressure. It is assumed that there is drilling f l u i d with specific gravity o f 1.2 outside the casing. Thus, the external pressure at the surface = 0.0 psi and at 5,000 ft is (5,000)(1.2)(8.34)(0.052) = 2,600 psi. Step 3: Burst load (Pb)" The burst pressure is equal to internal pressure r e d u c e d by the external pressure o f the drilling fluid outside the casing. Therefore, at surface: Pb = 3,575 - 0.0 = 3.575 psi at 5,000 ft: Pb = 3,575 - 2600 = 987 psi T h e b u r s t pressure line equation is as below: Pb = 3575 -- 0.52(D) (psi)

Casing and Casing String Design

1159

D = depth at the hole (ft) (from 0 to 5,000 ft) Note: For practical purposes, a graphic solution is very advisable.

Production String In exploratory drilling, it is assumed that internal pressure acting on the casing is reduced by external saltwater pressure gradient of about 0.5 psi/ft. Internal pressure is based on expected gas pressure gradient. For long strings, the weight of gas is not ignored.

Tension Load The maximum tensile load acting on the casing string is often considered as the static weight of the casing string as measured in air. Casing must be designed to satisfy these equations: pj = (W)(N)

(4-321)

py = (W)(Np)

(4-322)

where pj = casing joint strength in lb py = pipe body strength in lb W = weight of casing suspended below the cross-section under consideration in lb N. = safety factor for joint N J = safety factor for pipe body P

Safety factors (N., N ) of 1.6 to 2.0 are used and should be applied to the m i n i m u m joint tensale J " Pstrength or the m i n i m u m pipe body tensile strength, whichever is the smallest.

Compression Load Under certain conditions, casing can be subjected to the compression load, e.g., if the weight of the inner strings (conductor or surface casing string) is transferred to the outer string or if the portion of the casing weight is slacked off on the b o t t o m of the hole. This load may result in casing failure and, therefore, must also be considered. It should be pointed out that hydrostatic pressure does not p r o d u c e an effective compression and, therefore, is not considered. If the casing string is suspended at the top of the hole that is filled with fluid, then the only effect of hydrostatic pressure is reduction of casing weight per foot and the string is effectively u n d e r tension. An example is offered on the following pages of the design procedure to be followed in designing a combination casing string.

Example 4 Design a combination casing string if data are as below: Type of well: exploration well Type of casing: production for testing purposes

1160

Drilling and Well C o m p l e t i o n s

Casing setting depth: 12,000 ft Casing size: 7 in. Design model: Collapse: A s s u m e d external fluid pressure g r a d i e n t o f 0.52 p s i / f t and casing e m p t y inside. Safety factor for collapse = 1.0. Reduction o f collapse pressure resistance due to the axial l o a d is considered. Burst: A s s u m e d e x t e r n a l p r e s s u r e g r a d i e n t o f saltwater = 0.465 p s i / f t a n d f o r m a t i o n p o r e (gas) pressure g r a d i e n t = 0.65 psi/ft. Gas weight is neglected. Safety factor = 1.1. Tension: Casing s u s p e n d e d at the surface. Weight r e d u c t i o n due to buoyancy effect is ignored. Safety factor = 1.6. Compression: Casing not subjected to compression load. T h e selected coupling should be long with r o u n d thread. T h e available casing g r a d e is N-80 and unit weights as given in table below.

Steel grade

Unit weight (Ib/ft)

Crosssectional area (in.)

Collapse pressure resistance

Burst pressure resistance

Joint strength (10 3 Ib)

Pipe body strength (10 3 Ib)

N-80 N-80 N-80

26.0 29.0 32.0

7.548 8.451 9.315

5,410 7,020 8,600

7,240 8,160 9,060

519 597 672

604 676 745

Solution

Part 1. C o n s i d e r collapse pressure a n d tension load. Step 1. D e t e r m i n e the lightest weight o f casing to resist collapse pressure for a setting d e p t h o f 12,000 ft. Because the m a x i m u m collapse pressure is (12,000)(0.52) = 6,240 psi, select N-80, 29-1b/ft casing with collapse pressure resistance o f 7,020 psi. (Note: assumed safety factor for collapse = 1.0.) This is Section 1. Step 2. T h e next section (above Section 1) is to consist o f the next lighter casing, i.e., N-80, 26 l b / f t . This is Section 2. Neglecting the effect o f the axial load due to the weight o f Section 1 s u s p e n d e d below it, the setting d e p t h o f Section 2 is , D2 -

5,410 = 10,403ft (1.0)(0.52)

U n d e r this assumption, the weight o f Section 1 is W I" = (12000 - 10403)(29) = 46,313 lb For this axial load, the r e d u c e d m i n i m u m collapse pressure resistance o f Section 2 can be calculated from formula 4-312. (Note: internal pressure Pi for c o n s i d e r e d case = 0.)

Casing and Casing String Design

pCA(2)=5,410

1--0.

k. 80,000)

1161

80,000J

(Note: SA = W ' / A = 46,313/7.548 = 6,136 psi) Step 3. Using the obtained reduced minimum collapse pressure resistance of Section 2, calculate the setting depth of this section: D~'-

5,190 =9,980ft (1.0)(0.52)

For obtained setting depth of Section 2, the weight of Section 1 is W~' = (12,000 - 9,980)(29) = 58,580 lb and corresponding reduced minimum collapse pressure resistance of Section 2 is

PeA(Z) =

5,410fl1-0.75( 7,761 / 2 - ( 0 V t. 80,000)

5) 7,761 " ~

= 5,128psi

Step 4. The third assumed setting depth of Section 2 is usually taken as a correct setting depth, i.e., ,,,_ D~ -

5,128 = 9,861ft (1.0)(0.52)

Then, the length and weight of Section 2 is L~ = 12,000 - 9,861 = 2,128 ft

and

W~ = 62,015 lb

(Note: If the next lighter casing were available, then Steps 2 through 4 must be repeated for this casing and that would be Section 3, etc.). The m a x i m u m length of Section 2 is limited by coupling load capacity and is calculated below: L2.~ = 5 1 9 , 0 0 0 - (62,015)(1.6) = 10,090ft (1.6)(26) which is greater than its setting depth (9,861 ft). So, Section 2 extends to the top of the hole. (Note: If Section 2 would not cover the entire length of the hole, then the next stronger casing should be applied. That would be Section 3. The setting depth of Section 3 is governed by joint strength, not by collapse pressure.)

1162

Drilling a n d Well C o m p l e t i o n s Check casing string on burst pressure o b t a i n e d in Part 1 a n d make necessary corrections. Step 1. D e t e r m i n e external pressure. At top: 0.0 psi. At bottom: (12,000)(0.465) = 5,580 psi. Step 2. D e t e r m i n e internal pressure. At bottom: (12,000)(0.65) = 7,800 psi. At top: 7,800 psi (weight of gas is ignored). Step 3. D e t e r m i n e burst pressure. At top: 7,800 psi. At bottom: 7,800 - 5,580 -- 2,220 psi. Burst pressure line equation is

Part 2.

Pb = 7 , 8 0 0 -

7 , 8 0 0 - 2,220 (D) = 7,800- (0. 456)(D) 12,000

D = hole d e p t h in ft G r a p h i c a l solution is presented in Figure 4-377. Step 4. It is apparent that Section 1 is capable of withstanding the expected burst pressure. Step 5. Section 2 can withstand the expected burst pressure up to the d e p t h calculated below: 7,240

l.l

= 7,800 -

(0. 456)(D)

D = 7,800-6,581 - 2,673~ 0.456 Therefore, the length and weight o f Section 2 is 9,861 - 2,673 = 7,188 W 2 = (7,188)(26) = 186,888 lb To cover the u p p e r part of the hole (2,673 ft), stronger casing must be used. Step 6. Take the next stronger casing, i.e., N-80, 29 l b / f t with burst pressure resistance o f (8,160)/(1.1) = 7,418 psi. This is Section 3. This casing can be used up to the hole d e p t h of 7,418 = 7,800 - (0.456)(D) D = 7 , 8 0 0 - 7 , 4 1 8 = 837ft 0. 456 Then, the length a n d weight of Section 3 is 2,673 - 837 = 1,836 ft W 3 = (1,836)(26) = 53,244 lb

Casing and Casing String Design

psi

P R E S S U R E , 10 3 0

0

1.0

2.0

5.0

4.0

5.0

1163

6.0

7.0

8.0

9.~

1.0

2.0

External Pressure Line

3.0

Burst

Pressure

4.0 Q) Q)

Line

/

Internal

Pressure

5.0

Line o

6.0

-rl-Q. UJ (:3

7.0 8.0 9.0 I0.0 I1.0 2220

580 psi J 7 8 0 0 psi

12.0 Figure 4-377.

Graphical representation of burst load determination.

To cover the r e m a i n i n g 837 ft o f the hole, stronger casing must be used. Step 7. T h e next s t r o n g e r casing is N-80, 32 l b / f t with b u r s t p r e s s u r e resistance o f (9,060)/(1.1) = 8,236 psi. This is Section 4. N-80, 32-1b/ft casing is strong enough to cover the r e m a i n i n g part o f the hole (Note: 8,236 psi > 7,800 psi). Therefore, the length and weight of Section 4 is 837 - 0.0 = 837 ft and W 4 = 26,784 lb. Part 3. Check casing string on tension o b t a i n e d in Part 2 and, if necessary, make corrections to satisfy the required m a g n i t u d e o f safety factor.

1164

Drilling and Well Completions Step 1. Maximum length of Section 3 due to its joint strength is L3 = 5 9 7 , 0 0 0 - (1.6)(62,015 + 186,888) = 4,283ft (1.6)(29) Since the length of Section 3 is 1,836, the safety factor is even greater than required. Step 2. Maximum length of Section 4 due to its joint strength is L4 _-

6 7 , 2 0 0 - (1.6)(62,015 + 186,888 + 26,784) = 3,682ft (1.6)(32)

Because L 4 is greater than the length obtained in Part 2 (837), it may be concluded that the requirements for tension are satisfied. A summary of the results obtained is presented in the table below and in Figure 4-378.

Sectlon no. 4 3 2 1

Setting depth (ft)

Length

Weight (Ib)

Grade

Unit weight

837 2,637 9,861 12,000

837 1,836 7,188 2,138

26,784 53,244 186,888 62,015

N-80 N-80 N-80 N-80

32 29 26 29

Coupling Long Long Long Long

with with with with

round round round round

thread thread thread thread

Runnlng and Pulllng Casing The following excerpts are taken from API R e c o m m e n d e d Practice: 5C1, "Care and Use of Casing and Tubing," 12th Edition, March 1981 (Section 1, Preparation and Inspection before Running). 1.1 New casing is delivered free of injurious defects. Various nondestructive inspection services have been employed by users to assure that the desired quality of casing is being run. 1.2 All casing, whether new or used or reconditioned, should be handled with thread protectors in place. Casing should be handled at all times on racks or on wooden or metal surfaces free of rocks, sand or dirt other than normal drilling fluid. 1.3 Slip elevators are r e c o m m e n d e d for long strings. Both spider and elevator slips should be clean and sharp and should fit properly. Slips should be extra long for heavy casing strings. The spider must be level. Note: slip and tong marks are injurious. Every possible effort must be made to keep such damage at a minimum by using up-to-date equipment. 1.4 If collar-pull elevators are used, the bearing surface should be carefully inspected for (1) uneven wear, which may produce a side lift on the coupling with danger of j u m p i n g it off, and (2) uniform distribution of the load where applied over the bearing face of the coupling. 1.5 Spider and elevator slips should be examined and watched to see that all lower together. If they lower unevenly, there is danger of denting the pipe or badly slip-cutting it.

Casing and Casing String Design

SECTION No. 4 7" - 3 2 1 b / f t , N-80 Casing

857 ft , GO :i 2675 ft

1165

SECTION No. 3 7 " - 2 9 I b / f t , N - 8 0 Casing

ii

I

I

0 0 0

I

SECTION No. 2 7 " - 2 6 1 b / f t , N - 8 0 Casing

ol

]

!

9861 ft

[

SECTION No. I 7"-291b/ft, N-80 Coting

Figure 4-378. Schematic diagram of combination casing string.

1.6 Care must be exercised, particularly when running long casing strings, to ensure that slip bushing or bowl is in good condition. Tongs should be examined for wear on hinge pins and hinge surfaces. The backup line attachment to the backup post should be corrected if necessary to be level with the tong in the backup position, so as to avoid uneven load distribution on the gripping surfaces of the casing. The length of backup line should be such as to cause minimum bending stresses on the casing and to allow full stroke movement of the makeup tong. 1.7 The following precautions should be taken in the preparation of casing threads for makeup in the casing strings: a. Immediately before running, remove thread protectors from both field and coupling ends and clean the threads thoroughly, repeating as additional rows become uncovered.

1166

Drilling and Well C o m p l e t i o n s b. Carefully inspect the threads. Those found damaged, even slightly, s h o u l d be laid a s i d e unless s a t i s f a c t o r y m e a n s are available for correcting t h r e a d damage. C. T h e l e n g t h o f each p i e c e o f c a s i n g shall be m e a s u r e d p r i o r to running. A steel tape, calibrated in decimal feet to the nearest 0.01 ft, should be used. The m e a s u r e m e n t s should be m a d e from the outermost face o f the coupling or box to the position on the externally t h r e a d e d e n d where the coupling or the box stops when the j o i n t is made up powertight. O n round-thread joints this position is the place o f t h e v a n i s h p o i n t on the pipe; o n b u t t r e s s - t h r e a d casing, this position is to the base o f the triangle stamp on the pipe; on extreme line casing to the shoulder on the externally t h r e a d e d end. T h e total o f the i n d i v i d u a l length so m e a s u r e d will r e p r e s e n t the u n l o a d e d length o f the casing string. Note: T h e actual length u n d e r tension in the hole can be o b t a i n e d from p e r t i n e n t g r a p h s or approximately calculated from

AL = - ~ [ 7 ~ - 27f( 1 - g)] where AL = L = E = Z = 7f = p~ =

d.

e.

f.

g.

h. i.

(4-323)

casing e l o n g a t i o n in in. original length o f casing in in. casing modulus o f elasticity (for steel E = (30)(106) lb/in. 2) casing specific weight, l b / i n ? (for steel Z = 0.283 l b / i n ) ) fluid specific weight in l b / i n ? Poisson's ratio (for steel p~ = 0.28)

F o r m u l a 4-323 is valid for any c o n s i s t e n t system o f units a n d is applicable to vertical holes. Check each coupling for makeup. If the stand-off is abnormally great, check the coupling for tightness. Tighten any loose couplings after thoroughly cleaning the threads a n d applying fresh c o m p o u n d over the e n t i r e t h r e a d surfaces, a n d b e f o r e p u l l i n g t h e p i p e into the derrick. Before s t u b b i n g , l i b e r a l l y a p p l y t h r e a d c o m p o u n d to t h e e n t i r e internally and externally t h r e a d e d areas. It is r e c o m m e n d e d that highpressure m o d i f i e d thread c o m p o u n d as specified in API Bulletin 5A2: "Bulletin on T h r e a d C o m p o u n d s " be used except in special cases where severe conditions are encountered; it is r e c o m m e n d e d that high pressure silicone thread compound as specified in Bulletin 5A2 be used. Place a clean t h r e a d p r o t e c t o r on the field e n d o f the p i p e so that the t h r e a d will not be d a m a g e d while rolling p i p e on the rack and pulling into the derrick. Several t h r e a d protectors may be cleaned and used repeatedly for this o p e r a t i o n . If a mixed string is to be run, check to d e t e r m i n e that a p p r o p r i a t e casing will be accessible on the p i p e rack when required according to p r o g r a m . Connectors used as tensile a n d lifting m e m b e r s should have their t h r e a d capacity carefully checked to assure that the c o n n e c t o r can safely s u p p o r t the load. Care should be taken when making up p u p j o i n t s and connectors to assure that the mating threads are o f the same size and type.

Casing and Casing String Design

1167

1.8 Drifting of casing. It is r e c o m m e n d e d that each length of casing be d r i f t e d for its entire l e n g t h j u s t b e f o r e r u n n i n g with m a n d r e l s conf o r m i n g to the requirements of S t a n d a r d 5A: "Specification for Casing, T u b i n g and Drill Pipe." Casing that will not pass the drift test should be laid aside. 1.9 Lower or roll each piece of casing carefully to the walk without dropping. Use rope s n u b b e r if necessary. Avoid hitting casing against any p a r t of d e r r i c k or o t h e r equipment. Provide a h o l d back r o p e at window. For mixed and u n m a r k e d strings, a d r i f t or "jack rabbit" should be r u n through each length of casing when it is picked up f r o m the catwalk and p u l l e d onto the d e r r i c k floor, to avoid r u n n i n g a heavier length or one with a lesser inside d i a m e t e r than called for in the casing string.

Stubbing, Making Up, and Lowering 1.10 Do n o t r e m o v e t h r e a d p r o t e c t o r f r o m f i e l d e n d o f casing until r e a d y to stub. 1.11 If necessary, apply t h r e a d c o m p o u n d over entire surface of threads j u s t before stubbing. 1.12 In s t u b b i n g , lower casing carefully to avoid i n j u r i n g t h r e a d s . Stub vertically, preferably with assistance of s o m e o n e on the stubbing board. If the casing stub tilts to one side after stubbing, lift up, clean and correct any damaged thread with three-cornered file, then carefully remove any filings to ensure that threads are engaging properly and not cross-threading. If spinning line is used, it should pull close to the coupling. Note: R e c o m m e n d a t i o n s in p a r a g r a p h s 1.13 and 1.14 for casing makeup apply to the use of power tongs. For r e c o m m e n d a t i o n s of makeup of casing with spinning lines and conventional tongs, see p a r a g r a p h 1.15. 1.13 T h e use of p o w e r tongs for m a k i n g up casing m a d e d e s i r a b l e the establishment of r e c o m m e n d e d torque values for each size, weight and g r a d e of casing. Early studies and tests indicated that torque values are affected by a large n u m b e r of variables, such as variations in taper, lead, thread height and thread form; surface finish; type of thread compound; length of thread; weight and g r a d e of pipe; etc. In view of the n u m b e r of variables and the extent that those variables, alone or in combination, could affect the relationship of torque versus m a d e u p positions, it was evident that b o t h a p p l i e d torque and m a d e u p p o s i t i o n must be considered. Since the API joint pullout strength formula in API Bulletin 5C2 contains several of the variables believed to affect torque, the use of a m o d i f i c a t i o n of this f o r m u l a to obtain torque values was investigated. Torque values o b t a i n e d by taking 1% of the calculated pull-out value were f o u n d to be g e n e r a l l y c o m p a r a b l e to values o b t a i n e d by f i e l d m a k e u p tests using A P I - m o d i f i e d t h r e a d c o m p o u n d in accordance with API Bulletin 5A2. This p r o c e d u r e was, therefore, used to establish the o p t i m u m makeup torque values listed in Table 4-153. Maximum torque values listed are 75% of o p t i m u m values and m a x i m u m values listed are 125% of o p t i m u m values. These values must necessarily be c o n s i d e r e d a guide only, due to the very wide variations in torque requirements that can exist for a specific connection. Because of this, it is essential that torque be related to makeup position as outlined in p a r a g r a p h 1.14.

(text continued on page 1174)

1168

Drilling and Well Completions Table 4-153 Recommended Casing Make-Up Torque

1

2

Size: Outside Diameter in.

Weight Threads, and Coupling Ib per ft

3

4

5

6

7

8

9

Nominal

41/

Torque, ft-lb Grade < Short Thread ~ Optimum

Minimum

Long Thread ~~ Maximum Optimum

Minimum

Maximum

9.50

H40

770

580

960

--

--

--

9,50 10.50 11.60

J-55 J-55 J-55

1010 1320 1540

760 990 1160

1260 1650 1930

--1620

--1220

--2030

9.50 10.50 11.60

K-55 K55 K~55

1120 1460 1700

840 1100 1280

1400 1830 2130

--1800

--1350

--2250

11.60 13.50

G75 C75

---

---

---

2150 2600

1610 1950

2690 3250

11,60 13,50

L-80 L-80

---

---

---

2230 2710

1670 2030

2790 3390

11,60 13.50

N-80 N40

---

---

---

2280 2760

1710 2070

2850 3450

11.60 13.50

C-95 G95

---

---

---

2580 3130

1940 2350

3230 3910

11.60 13.50 15.10

P-110 P-110 P-110

-~ --

----

----

3020 3660 4400

2270 2750 3300

3780 4580 5500

11.50

J 55

1~0 2230

1~0 1670

2790

1350

1000

13.00

j-55

1690

1270

2110

15.00

.[-55

2070

1550

2590

1660

11.50

K-55

1470

22~0

ll00

1840

13.00

K-55

1860

1400

2330

2010

15"~0

2~10

15.00

K-55

2280

1710

2850

2460

1850

3080

15.00 18.00 21.40 24.10

C-75 Co75 G75 G75

-----

-----

-----

2960 3770 4660 5390

2220 2830 3500 4040

3700 4710 5830 6740

15.00 18.00 21,40 24.10

L-80 LS0 L-80 L-80

-----

-----

-----

3080 3950 4860 5610

2310 2950 3650 4210

3850 4910 6080 7010

15.00 18.00 21,40 24.10

N-80 N-80 N~80 N-80

-----

-----

-----

3140 4000 4950 5720

2360 3000 3710 4290

3930 5000 6190 7150

15.00 18.00 21.40 24.10

C-95 C#95 C,95 C-95

-----

-----

-----

3560 4550 5620 5500

2670 3410 4220 4880

4450 5690 7030 8150

15.00 18.00 21,40 24.10

P-110 P-110 Pll0 P-110

-----

-----

-----

4170 5310 6580 7600

3130 3980 4940 5700

5210 6640 8230 9500

Casing and Casing String Design

1169

Table 4-153

(continued) 1

2

Size: Outside Diameter in.

l~omina! Weight. Threads and Coupling 11~ Per fL

5½

4

Grade

5

Torque.

.-. ~ -.. Optimum

6

q

8

Optimum

Long T h r e a d • Minimum

9

ft.tb

,

Short T,h r n d Minimum

• , Maximum

. Maximum

14.00

H-40

1300

980

1630

--

~

14.00 15.50 17.00

J-55 J-55 J-55

1720 2020 2290

1290 1520 1720

2150 2530 2860

~70 2470

1630 1850

2"710 3090

14.00 15.50 17.00

K-55 K-55 K-55

1890 2220 2520

1420 1670 1890

2360 2780 3150

2-390 2720

1790 2040

~0 3400

17.00 20.00 23.00

C-75 C-75 C-75

-~ ~

~ ~ w

~ ~ ~

3270 4030 4730

2450 3020 3550

4090 5040 5910

17.00 20.00 23.00

L-80 L-80 L-80

~ ~ ~

--~

~ ~ w

3410 4200 4930

2560 3150 3700

4260 5250 6160

17.00 20.00 23.00

N-80 N-80 N-80

~ ~ ~

~ ~ w

~ ~ ~

3480 4280 5020

2610 3210 3770

4350 5350 6280

17.00

C-95 C-95 C-95

-~ ~

~ ~ w

~ ~ ~

3960 4870 5720

2970 3650 4290

4950 6090 7150 5780 7110 8350

20.00 23.00

6 ~

3

17.00 20.00 23,00

P-110

~

~

~

P-110 P-110

~

~

w

- -

~ ~

4620 5690 6680

3470 4270 5010

20.00

H-40

1840

1380

2300

m

--

20,00 24.00

3-55 3-55

2450 3140

1840 2360

3060 3930

2660 3400

2000 2550

3330 4250

20.00 24.00

K-55 K-55

2670 3420

2000 2570

3340 4280

2900 3720

2180 2790

3630 4650

24.00 28.00 82.00

C..75 C-75

~ ~

w --

~ ~

C-75

--

~

~

4530 5520 6380

3400 4140 4790

5660 6900 7980

24.00 28.00 32.00

L-80 L-80 I,-80

-~ ~

~ -w

~ ~ ~

4730 5760 6660

3550 4320 5000

5910 7200 8330

24.00 28,00 32.00

N-80 N-80 N-80

~ ~ ~

~ -~

~ ~ --

4810 5860 6770

3610 4400 5080

6010 7330 8460

24.00 28.00 32.00

C-95 C-95 C-95

w ~ ~

~ ~ ~

~ -~

5490 6690 7740

4120 5020 5810

6860 8360 9680

24.00 28.00 32.00

P-110 P-110 P-110

~

~

w

~ ~

~ ~

~ ~

6410 7810 9040

4810 5860 6780

8010 9760 11300

1170

Drilling and Well Completions Table 4-153

(continued) 1

2

3

~;}xe: Outside Dlgmeter In.

Nominal Weight, Threads and CouPling lb. p e r ft.

Grade

4

7

8

9

Torque, ft-lb A Optimum

H-40 H-40

1220 1760

20.00

J-66

23.00 26.00

J-55 J-55

20.00

K-55 K-55 K-55

23.00

6

Long Thread

S h o r t Thread

17.00 20.00

26.00

5

Minimum

Maximum

•

Optimum

920 1320

1530 2200

---

2340

1760

2930

--

2840 3340

2130 2510

3550 4180

3130 3670

2540 3090 3640

1910 2320 2730

3180 3860 4550

bIaxim~

---

---

2350 2750

3910 4590

3410 4010

2560 3010

4260 5010

3120

5200

3670

6110 7030 7910 8790 9590

- -

23.00

C-75

--

- -

--

4160

26.00 29.00 32.00 35.00 38.00

C-75 C-75 C-75 C-75 C-75

--~ ~ --

~

--

- -

--

----

----

4890 5620 6330 7030 7670

23.00

L-80

~

--

Minimum

4220 4750 6270 5750

--

4350

3260

26.00

L-80

~

--

--

5110

3830

6390

29.00 32.00 35.00

L-80 L-80 L-80

-~

-~

--

5870

4400

7340

--

6610

4960

- -

--

- -

7340

5510

9180

38.00

L-80

--

- -

--

8010

6010

10010

23.00 26.00 29.00 82.00 35.00

N-80 N-80

--

--

--

- -

- -

- -

N - 8 0

- -

~

~

N-80 N-80

~ --

~

- -

4420 5190 5970 6720 7460

3320 3890 4480 5040 5600

5530 6490 7460 8400 9330

38.00

N - 8 0

- -

- -

- -

8140

6110

10180

- -

--

--

w

__

~

--

--

--

5050 5930 6830 7680 8530

3790 4450 5120 5760 6400

6310 7410 8540 9600 10660

11640

~

--

5440

8260

23.00 26.00 29.00 32.00 35.00

C-95 (3-95 C-95 C-95 C-95

38.00

C-95

26.00

P-110

--

29.00 32.00 35.00

P-It0 P-IIO P-110

~ ~ ~

38.00

P-IIO

24.00

H-40

2120

1590

2650

--

--

26.40

J-55

3150

2360

3940

3460

2600

4330

26.40

K-55

3420

2570

4280

3770

2830

4710

26.40 29.70 33.70 39.00 42.80

C-75 C-75 C-75 C-75 C-75

~ -----

------

--~ ---

4610 5420 6350 7510 8520

3460 4070 4760 5630 6390

5760 6780 7940 9390 10650

47.10

C-75

--

--

--

9530

7150

11910

---

---

- -

-

-

-

-

-

-

-

--

--

--

--

~

--

~

--

--

-

-

-

-

9310

6980

6930

5200

7970 8970 9960

5980 6730 7470

9960 11210 12450

10870

8150

13590

8660

--

Casing and Casing String Design

1171

Table 4-153 (continued) 1

2

8iM: Out*Ide Diameter In.

Nominal W~ht. Threada and Coupling lb. m r ft.

88t

8

4

5

Optimum

Short Thread ,~ Minimum

6

7

8

9

~Ol~timum

Lon~ Thread ,'Minimum

Maximum

Torque. ft-lb

Grade .

MLxlmum

•

26A0 29~0 33.70 39.00 42.80 47.10

I,-80 L-80 L-80 L-80 L*80 L*80

-------

-------

-------

4820 5670 6640 7860 8910 9970

3620 4250 4980 5900 6680 7480

6030 7090 8300 9830 11140 12460

26.40 29.70 33.70 39.00 42.80 47.10

N-80 N-80 N-80 N-80 N-80 N-80

-------

-------

-------

4900 5750 6740 7980 9060 10130

3680 4310 5060 5980 6800 7600

6130 7190 8430 9980 11330 12660

26.40 29.70 33.70 39.00 42.80 47.10

C-95 C-95 C-95 C-95 C-95 C-95

-------

-------

-------

5600 6590 7720 9140 10370 11590

4200 4940 5790 6860 7780 8690

7000 8240 9650 11430 12960 14490

29.70 83.70 39.00 42.80 47.10

P-110 P-110 P-110 P-110 P-110

----

~ ---

----

- -

- -

- -

--

--

--

7690 9010 10660 12100 13530

5770 6760 8000 9080 10150

9610 11260 13330 15130 16910

28.00 82.00

H-40 H-40

2330 2/90

1750 2090

2910 3490

---

---

---

24.00

J-55 J-55 J-55

2440 3720 4340

1830 2790 3260

3050 4650 5430

- -

- -

- -

36.00

4170 4860

3130 3650

5210 6080

24.00 32.00 36.00

K-55 K-55 K-55

2630 4020 4680

1970 3020 3510

3290 5030 5850

-4520 5260

3390 3950

5650 6580

36.00 40.00 44.00 49.00

C-75 C-75 C-R5 C-75

-----

-----

-----

6480 7420 8340 9390

4860 5570 6260 7040

8100 9280 10430 11740

36.00

L*80 L*80 L-80

----

----

----

5090

5820 6560 7370

8480 9700 10930 12290

3 2 . 0 0

I,-80

--

--

--

6780 7760 8740 9830

36.00 40.00 44.00 49.00

N-80 N.80 N-80 N-80

-----

-----

-----

6880 7880 8870 9970

5160 5910 6650 7480

8600 9850 11090 12460

36.00 40,00 44.00 49.00

C-95 C-95 C-95 C+95

-----

-----

-----

7890 9040 10170 11440

5920 6780 7630 8580

9860 11300 12710 14300

40.00 44.00 49.00

P-110 P-110 P-IIO

--

--

- -

- -

- -

--

--

--

10550 11860 133,50

7910 8900 10010

13190 14830 16690

40.00

44.00 49.00

--

1172

Drilling a n d Well C o m p l e t i o n s

Table 4-153

(continued) 1

2

3

Size: Outside Diameter in.

Nominn! WeJcht, Thread~ an(| Couplin~ Ib, per ft.

Grade

32.30 36.00

H-40 H°40

2540 2940

1910 2210

3180 3680

36.00 40.00

J-55 J-55

3940 4520

2960 3390

4930 5650

4530 5200

3.100 39OO

5660 6500

36.00 40.00

K-55 K-55

4230 4860

3170 3650

5290 6080

4890 5610

3670 4210

6110 7010

40.00 43.50 47.00 53.50

C-75 C-75 C-75 C-75

----

6940 7760 8520 9990

5210 5820 6390 7490

8680 9700 10650 12490

40.00 43.50 47.00 53.50

L-80 L-80 L-80 L-80

7270 8130 8930 10470

5450 6100 6700 7850

9090 10160 11160 13090

40,00 43.50 47.00 53.50

N-80 N-80 N-80 N-80

7370 8250 9050 10620

5530 6190 6790 7970

9210 10310 11310 13280

40.00 43.50 47.00 53.50

C-95 C-95 C-95 C-95

8470 9480 10400 12200

6350 7110 7800 9150

10590 11350 13000 15250

43.50 47.00 53.50

P-110 P-II0 P-110

--

11060 12130 14220

8300 9100 10670

13830 15160 17780

32.75 40.50

H-40 H-40

2050 3140

1540 2360

2560 3930

u m

40.50 45.50 51.00

J-55 J-55 J-55

4200 4930 5650

3150 3700 4240

5250 6160 7060

m u

40.50 45.50 51.00

K-55 K-55 K-55

4500 5280 6060

3380 3960 4550

5630 6600 7580

u m m

51.00 55.50

C-75 C~5

7560 8430

5670 6320

9450 10540

51.00 55.50

L-80 L-80

7940 8840

5960 6630

9930 11050

m

51.00 55.50

N-80 N-80

8040 8950

6030 6710

10050 11190

m m

51.00 55.50

C-95 C~5

9270 10320

6950 7740

11590 12900

m u

51.00 55.50 60.70 65~0

1:>-110 po110 P-110 P-110

10800 12030 13380 14720

8100 9020 10040 11040

13500 15040 16730 18i00

m

9~

10¾

4

5

6

7

8

9

Torqu ,e. ft-lb Short Thread OlJtlmum

.Minimum

Long Threfld Maximum

m

m

---

m

m

m

--

m

--m

m

m

Ol~tlmum

.Minimum

~T~ximum

m m

m

u m u m

m

m

m

m

m

m m m

m

m

m m

Casing and Casing String Design

1173

Table 4-153 (continued) 1 Size;

Outside Diametez in.

11~

2 Nominal Wei=ht. Threads and ~uPltng lb. per ft.

*18%

*20

5

6

7 Toque.

Grade

8

Optimum

Short Thread ~ Minimum

ft-lb

Maximum

H-40

3070

2300

3840

J-55 J-55 J-55

4770 5680 6490

3580 4260 4870

5960 7100 8110

47.00

K-55 K-55 K-55

5090 6060 6930

3820 4550 5200

6360 7580 8660

60.00

C-75

8690

6520

10860

60.00

L-80

9130

6850

11410

60.00

N-80

9240

6930

60.00

C-95

10660

8000

11550 13330

60.00

P-110

12420

9320

15530

' Lonz Thr~d ~ Mlnlmum

Optimum

48.00

H-40

3220

2420

4030

64.50 61.00 68.00 54.50 61.00 68.00

J-55 J-55 J-55 K-55 K-55 K-55

5140 5950 6750 5470 6330 7180

3860 4460 5060 4100 4750 5390

6430 7440 8440 6840 7910 8980

68.00

C-75 C-75

9060

6800

72.00

9780

7340

11330 12230

68.00 72.00 68.00 72.00 68.00 72.00

L-80 L-80 N-80 N-80 C-95 C-95

9520 10290 9630 10400 11140 12040

7140 7720 7220 7800 8360 9030

11900 12860 12040 13000 13930 15050

68.00

72.00

P-110 P-110

12970 14020

9730 10520

16210 17530

65.00

H-40

--

4390

75.00 84,00

J-55 J-55

---

7100 8170

75.00 84.00

K-55 K-55

-~

7520 8650

87.50

H-40

--

5590

.

.

.

87.50

J-55

--

7540

.

.

.

.

87.50

K-55

--

7940

.

.

.

.

.

.

.

94.00

H-40

--

5810

.

3-55 J-55 J-55

~ ---

7840 9130 11920

-~ --

94.00 106.50 133.00

K-55 K-65 K-55

--~

8240 9600 12530

--

~

9550

---

m --

11130 14530

la|tr~¢tlon=.

Source: Taken from API RP 5C1, 12th Edition, March 1981.

-~ ~

Mszimum

.

94.00 106.50 133.00

• g e e ]Psr. 1 . 1 4 h f o r m a k e - u p

9

x .

42.00

54.00

"16

4

47.00 54.00 60.00

6~00

13=~

3

9070 10570 13800

--

--

--

1174

Drilling and Well C o m p l e t i o n s

(text continuedfrom page 1167)

The torque values listed in Table 4-153 apply to casing with zinc-plated couplings. W h e n making up connections with tin-plated couplings, 80% o f the listed value can be used as a guide.

Field Makeup 1.14 The following practice is r e c o m m e n d e d for field m a k e u p casing.

Round Thread, 41 through 13~ in. OD a. It is advisable when starting to run casing from each particular mill s h i p m e n t to m a k e up s u f f i c i e n t j o i n t s to d e t e r m i n e t h e t o r q u e necessary to provide p r o p e r makeup. See p a r a g r a p h 1.15 for p r o p e r n u m b e r o f t u r n s b e y o n d h a n d - t i g h t p o s i t i o n . T h e s e values may indicate that a d e p a r t u r e from the r e c o m m e n d e d o p t i m u m values listed in Table 4-153 is advisable. If other o p t i m u m torque values are chosen, the m i n i m u m torque should not be less than 75% o f the o p t i m u m selected. T h e m a x i m u m torque should be not m o r e than 125% o f the o p t i m u m torque. b. The power tong should be provided with a reliable torque gage o f known accuracy. To prevent galling when making up connections in the field, the connections should be made up at a speed not to exceed 25 rpm. c. Continue the makeup, observing both the torque gage and the approximate position o f the coupling face with respect to the last scratch position. d. The o p t i m u m torque values as shown in Table 4-153 have been selected to give o p t i m u m m a k e u p u n d e r n o r m a l c o n d i t i o n s and should be considered as satisfactory providing the face o f the coupling is flush with the last scratch or within two thread turns plus or minus the last scratch. e. If the makeup is such that the last scratch is buried, two t h r e a d turns and the m i n i m u m torque shown in Table 4-153 is not reached, the j o i n t should be t r e a t e d as a questionable j o i n t as p r o v i d e d u n d e r p a r a g r a p h 1.16. f. If several t h r e a d s r e m a i n e x p o s e d when the o p t i m u m t o r q u e is reached, apply additional torque up to the m a x i m u m shown in Table 4-153. If the stand-off (distance from face o f coupling to last scratch) is g r e a t e r t h a n t h r e e t h r e a d t u r n s when the m a x i m u m t o r q u e is reached, the j o i n t should be treated as a questionable j o i n t as prov i d e d u n d e r p a r a g r a p h 1.16.

Buttress Thread, 4 1 through 13~-in. OD g. Makeup t o r q u e for buttress t h r e a d casing c o n n e c t i o n in sizes t h r o u g h 13~a in. OD should be d e t e r m i n e d by carefully noting torque to make up each o f several connections to the base o f triangle; then, using the torque value thus established, make up the ance o f the pipe o f that particular weight and g r a d e in the string.

4-~ the the bal-

Round Thread and Buttress Thread, 16, 18~- and 20-in. OD h. Makeup o f 16, 18~a and 20-in. OD shall be to a position on each c o n n e c t i o n r e p r e s e n t e d by last scratch on 8-round t h r e a d and the

Casing and Casing String Design

1.15

1.16

1.17

1.18

1.19

1.20

1.21

1175

base of the triangle on buttress thread using the minimum torque shown in Table 4-153 as a guide. Care must be taken to avoid crossthreading in starting these large connections. When conventional tongs are used for casing makeup, tighten with tongs to proper degree of tightness. The joint should be made up beyond the hand-tight position at least three turns for sizes 4-~ through 7 in., and at least three-and-one-half turns for sizes 7~ in. and larger, except of 9~8 and 10¼ in. grade, P-110 and 20 in grade J-55 and K-55 which should be made up four turns beyond hand-tight position. When using a spinning line, it is necessary to compare hand-tightness with spin-up tight position. Compare relative position of these two makeups and use this information to determine when the joint is made up the recomm e n d e d number of turns beyond hand-tight. Joints that are questionable as to their proper tightness should be unscrewed and the casing laid down for inspection and repair. Ported joints should never be reused without shopping or regaging, even though the joints may have little appearance of damage. If casing has a tendency to wobble unduly at its upper end when making up, indicating that the thread may not be in line with the axis of the casing, the speed of rotation should be decreased to prevent galling of threads. If wobbling should persist despite reduced rotational speed, the casing should be laid down for inspection. In making up the field joint it is possible for the coupling to make up slightly on the mill end. This does not indicate that the coupling on the mill end is too loose, but simply that the field end has reached the tightness with which the coupling was screwed on at the mill. Casing strings should be picked up and lowered carefully, and care exercised in setting slips to avoid shock loads. Care should be exercised to prevent setting casing down on bottom, or otherwise placing it in compression because of the danger of buckling, particularly in the part of the well where hole enlargement has occurred. Definite instructions should be available as to the design of the casing string, including the p r o p e r location of the various grades of steel, weight of casing and type of joint. Care should be exercised to run the string in exactly the order in which it was designed. Casing should be periodically filled with mud while being run. In most cases, filling every 6-10 lengths should suffice. Filling should be done with mud of the proper weight, using a conveniently located hole of adequate size to expedite the filling operation. A quick-opening and closing plug valve on the mud hole will facilitate the operation and prevent overflow.

Casing Landing Procedure 1.22 Definite instructions should be provided for the proper string tension, also on the proper landing procedure after the cement has set. The p u r p o s e is to avoid critical stresses or excessive and unsafe tensile stresses at any time during the life of the well. In arriving at the proper tension and landing procedure, consideration should be given to all factors such as well temperature and pressure, temperature developed due to cement hydration, mud temperature, and changes of temperature during producing operations. The adequacy of the original tension safety factor of the string as designed will influence the landing procedure instructions (and this probably applies to a very large majority of

1176

Drilling and Well Completions the wells drilled), then the procedure should be followed of landing the casing in the casing head at exactly the position in which it was hanging when the cement plug reached its lowest point or "as cemented."

Care of Casing in Hole 1.23 Drillpipe run inside casing should be with suitable drillpipe protectors.

Recovery of Casing 1.24 Breakout tongs should be positioned close to the coupling but not too close since a slight squashing effect where tong dies contact the pipe surface cannot be avoided, especially if the joint is tight a n d / o r the casing is light. Keeping a space of ~ to ¼ of the diameter of the pipe between the tong and the coupling should normally prevent unnecessary friction in the threads. Hammering the coupling to break the joint is an injurious practice. If tapping is required, use the flat face, never the peak face of the hammer, and u n d e r no circumstance should a sledge hammer be used. Tap lightly near the middle and completely around the coupling, never near the end nor on opposite sides only. 1.25 Great care should be exercised to disengage all of the thread before lifting the casing out of the coupling. Do not jump casing out of coupling. 1.26 All threads should be cleaned and lubricated or should be coated with a material that will minimize corrosion. 1.27 Before casing is stored or reused, pipe and thread should be inspected and defective joints marked for shopping and regaging. 1.28 When casing is being retrieved because of casing failure it is imperative to future prevention of such failures that a thorough metallurgical study be made. Every attempt should be made to retrieve the failed portion in the "as-failed" condition. 1.29 Casing stacked in the derrick should be set on a firm wooden platform and without the bottom thread or protector since the design or most protectors is not such as to support the joint or stand without damage of the field thread.

Cause of Casing Troubles 1.30 The more c o m m o n causes of casing troubles are as follows: a. I m p r o p e r selection for depth and pressures encountered. b. Insufficient inspection of each length of casing or of field-shop threads. c. Abuse in mill, transportation and field handling. d. Nonobservance of good rules in running and pulling casing. e. I m p r o p e r cutting of field-shop threads. f. The use of poorly manufactured couplings for replacements and additions. g. Improper care and storage. h. Excessive torquing of casing to force it through tight places in the hole. i. Pulling too hard on a string (to free it). This may loosen the coupling at the top of the string. They should be retightened with tongs before finally setting the string. j. Rotary drilling inside casing. Setting the casing with improper tension after cementing is one of the greatest contributing causes of such failures.

Well Cementing

1177

k. Drillpipe wear while drilling inside casing is particularly significant in drifted holes. Excess doglegs in deviated holes or occasionally in straight holes where corrective m e a s u r e m e n t s are taken result in concentrated bending of the casing, which, in turn, results in excess internal wear, particularly when doglegs are high in the hole. 1. Wireline cutting, by swabbing or cable-tool drilling. m. Buckling of casing in an enlarged, washed-out, uncemented cavity if too much tension is released in landing. n. Dropping a string, even a very short distance. WELL CEMENTING Introduction

Cementing the casing and liner cementing (denoted as primary cementing) are probably the most important operations in the development of an oil and gas w.ell. The drilling group is usually responsible for cementing the casing and the liner. The quality of these cementing operations will affect the success of follow-on drilling, completion, production and workover efforts in the well [160-162]. In addition to primary cementing of the casing and liner, there are other i m p o r t a n t well cementing operations. These are squeeze cementing and plug cementing. Such operations are often called secondary or remedial cementing [161]. Well cementing materials vary f r o m basic Portland cement used in civil engineering construction of all types, to highly sophisticated special-purpose resin-based or latex cements. The purpose of all of these cementing materials is to provide the well driller with a fluid state slurry of cement, water and additives that can be p u m p e d to specific locations within the well. Once the slurry has reached its intended location in the well and a setup time has elapsed, the slurry material can become a nearly impermeable, durable solid material capable of b o n d i n g to rock and steel casing. The most widely used cements for well cementing are the Portland-type cements. The civil engineering construction industry uses Portland cement and water slurries in conjunction with clean rock aggregate to form concrete. The composite material formed by the addition of rock aggregate forms a solid material that has a compressive strength that is significantly higher than the solid formed by the solidified cement and water slurry alone. The rock of the aggregate usually has a very high compressive strength (of the order of 5,000 to 20,000 psi). The cement itself will have a compressive strength of about 1,000 to 3,000 psi. Therefore, the rock aggregate together with the matrix of solid cement can form a high-strength composite concrete with compressive strengths of the order of 4,000 to 15,000 psi. The well drilling industry does not generally use aggregate with the cement except for silica flour and Ottawa sand. This is mainly due to the tight spacing within a well that precludes the passage of the larger particles of aggregate t h r o u g h the system. Thus, the well drilling industry refers to this material as simply cement. The slurry p u m p e d to wells is usually a slurry of cement and water with appropriate additives. Because of the lack of aggregate, the compressive strength of well cements are restricted to the order of 200 to about 3,000 psi [160]. T h r o u g h the past half century the well cementing industry has considered cement compressive strengths of about 500 psi to be acceptable. However, such low compressive strengths plus some of the past cementing practices may not be adequate for future wells.

1178

Drilling and Well C o m p l e t i o n s

Chemistry of Cements Cement is m a d e o f calcareous and argillaceous rock materials that are usually o b t a i n e d from quarries. T h e process o f making cement requires that these raw rock materials be ground, mixed and subjected to high temperatures. The calcareous materials contain calcium carbonate or calcium oxide. Typical raw calcareous materials are as follows: Limestone. This is a sedimentary rock that is formed by the accumulation of organic marine life remains (shells or coral). Its main component is calcium carbonate. Cement rock. This is a s e d i m e n t a r y rock that has a similar c o m p o s i t i o n as the industrially p r o d u c e d cement. Chalk. This is a soft limestone c o m p o s e d mainly o f m a r i n e shells. Marl. This is loose or crumbly d e p o s i t that contains a substantial amount o f calcium carbonate. Alkali waste. This is a s e c o n d a r y source and is often o b t a i n e d from the waste o f chemical plants. Such material will contain calcium oxide a n d / o r calcium carbonate.

T h e argillaceous materials contain clay or clay minerals. Typical raw argillaceous materials are as follows: Clay. This material is found at the surface o f the e a r t h and often is the major c o m p o n e n t o f soils. T h e material is plastic when wetted, but becomes hard and brittle when d r i e d and heated. It is c o m p o s e d mainly o f hydrous aluminum silicates as well as o t h e r minerals. Shale. This s e d i m e n t a r y rock is f o r m e d by the consolidation o f clay, m u d and silt. It contains substantial amounts o f hydrous a l u m i n u m silicates. Slate. A dense fine-grained m e t a m o r p h i c rock containing mainly clay minerals. Slate is o b t a i n e d from m e t a m o r p h i c shale. Ash. This is a s e c o n d a r y source and is the by-product o f coal combustion. It contains silicates.

T h e r e are two processes used to manufacture cements: the d r y process and the wet process. T h e d r y process is the least expensive o f the two, but is the m o r e difficult to control. In the d r y process the limestone and clay materials are c r u s h e d and stored in separate bins and their composition analyzed. After the composition is known, the contents o f the bins are b l e n d e d to achieve the desired ultimate cement characteristics. T h e b l e n d is g r o u n d to a mesh size o f 100-200. This small mesh size maximizes the contact between individual particles. In the wet process the clay minerals are crushed and slurried with water to allow p e b b l e s and o t h e r rock particles to settle out. T h e l i m e s t o n e is also c r u s h e d and slurried. Both materials are stored in separate bins and analyzed. Once the desired ultimate composition is determined, the slurry blend is g r o u n d and then partially d r i e d out. A f t e r the blends have been p r e p a r e d (either in the d r y or wet process), these materials are fed at a u n i f o r m rate into a long rotary kiln. T h e materials are gradually heated to a liquid state. At t e m p e r a t u r e s up to about 1,600°F the free water evaporates, the clay minerals dehydroxylate and crystallize, and CaCOs d e c o m p o s e s . At t e m p e r a t u r e s above 1,600°F the CaCO 3 and CaO react with aluminosilicates and the materials b e c o m e liquids. H e a t i n g is c o n t i n u e d to as high as 2,800°E

Well C e m e n t i n g

1179

W h e n the kiln material is cooled it forms into crystallized clinkers. These are rather large irregular pieces of the solidified cement material. These clinkers are ground and a small amount of gypsum is added (usually about 1.5 to 3%). The gypsum prevents flash setting of the cement and also controls free CaO. This final cement product is sampled, analyzed and stored. The actual commercial cement is usually a blend of several different cements. This blending ensures a consistent product. T h e r e are four chemical c o m p o u n d s that are identified as being the active c o m p o n e n t s of cements.

Tricalcium aluminate (3CaO • Al~O3) hydrates rapidly and contributes most to heat of hydration. This c o m p o u n d does not contribute greatly to the final strength of the set cement, but it sets rapidly and plays an i m p o r t a n t role in the early strength development. This setting time can b e controlled by the a d d i t i o n of gypsum. T h e final h y d r a t e d p r o d u c t of tricalcium a l u m i n a t e is readily attacked by sulfate waters. High-sulfate-resistant (HSR) cements have only a 3% or less content of this c o m p o u n d . High early strength cements have up to 15% of this c o m p o u n d . Tricalcium silicate (3CaO * SiO~) is the major contributor to strength at all stages, b u t particularly during early stages of curing (up to 28 days). T h e average t r i c a l c i u m silicate content is f r o m 40% to m a x i m u m of 67%. T h e r e t a r e d cements will contain from 40% to 45%. T h e high early strength cements will contain 60% to 67%. Dicalcium silicate (2CaO • SiO~) is very i m p o r t a n t in the final strength of the cement. This c o m p o u n d hydrates very slowly. T h e average dicalcium silicate content is 25% to 35%. Tetracalcium aluminoferrite (4CaO * AI~O 3 * FeOs) has little effect on the physical p r o p e r t i e s o f the c e m e n t . For high-sulfate-resistant (HSR) c e m e n t s , A P I specifications require that the sum of the tetracalcium aluminoferrite content plus twice the tricalcium a l u m i n a t e may not exceed a m a x i m u m of 24%. In addition to the four c o m p o u n d s discussed above, the final Portland cement may contain gypsum, alkali sulfates, magnesia, free lime and o t h e r components. These do not significantly affect the p r o p e r t i e s of the set cement, but they can influence rates of hydration, resistance to chemical attack and slurry properties. W h e n the water is a d d e d to the final d r y cement material, the h y d r a t i o n of the c e m e n t begins immediately. T h e water is c o m b i n e d chemically with the c e m e n t m a t e r i a l to e v e n t u a l l y f o r m a new i m m o b i l e solid. As the c e m e n t hydrates, it will b o n d to the s u r r o u n d i n g surfaces. This c e m e n t b o n d i n g is c o m p l e x and d e p e n d s on the type of surface to be cemented. C e m e n t b o n d s to rock by a process of crystal growth. C e m e n t b o n d s to the outside of a casing by filling in the pit spaces in the casing b o d y [163].

Cementing Principles T h e r e are two basic oil well c e m e n t i n g activities: p r i m a r y c e m e n t i n g and s e c o n d a r y cementing. Primary cementing refers to the necessity to fix the steel casing or liner (which is placed in the drilled borehole) to the s u r r o u n d i n g formations adjacent to the casing or liner. T h e p u r p o s e s of p r i m a r y cementing are the following: 1. s u p p o r t vertical and radial loads a p p l i e d to casing; 2. isolate porous formations from p r o d u c i n g zone formations; 3. exclude unwanted subsurface fluids from the p r o d u c i n g interval;

1180

Drilling a n d Well C o m p l e t i o n s

4. protect casing from corrosion; 5. resist chemical d e t e r i o r a t i o n o f cement; 6. confine a b n o r m a l f o r m a t i o n pressures. W h e n applied to the various casing or liner strings used in oil well completions, the specific p u r p o s e s o f each string are as follows: C o n d u c t o r casing string is c e m e n t e d to prevent the d r i l l i n g f l u i d from escaping a n d circulating outside the casing. • Surface casing string must b e c e m e n t e d to protect fresh-water formations near the surface a n d p r o v i d e a structural c o n n e c t i o n between the casing a n d the subsurface c o m p e t e n t rock formations. This subsurface structural c o n n e c t i o n will allow the blowout preventor to be affixed to the top o f this casing to prevent high-pressure fluids from being vented to the surface. Further, this structural c o n n e c t i o n will give s u p p o r t for d e e p e r run casing or liner strings. • I n t e r m e d i a t e casing strings are c e m e n t e d to seal off a b n o r m a l pressure formations a n d cover b o t h i n c o m p e t e n t formations, which could cave or slough, a n d lost circulation formations. • P r o d u c t i o n casing string is c e m e n t e d to prevent the p r o d u c e d fluids from m i g r a t i n g to n o n p r o d u c i n g formations a n d to e x c l u d e o t h e r fluids from the p r o d u c i n g interval. •

C e m e n t i n g o p e r a t i o n s are c a r r i e d out with s u r f a c e e q u i p m e n t s p e c i a l l y d e s i g n e d to carry out the p r i m a r y a n d s e c o n d a r y cementing o p e r a t i o n s in oil wells. T h e key e l e m e n t in any well c e m e n t i n g o p e r a t i o n is the recirculating b l e n d e r (Figure 4-379). T h e recirculating b l e n d e r has r e p l a c e d the o l d e r j e t mixing hopper. T h e b l e n d e r provides a constant cement slurry specific weight that could never be achieved by the o l d e r equipment. A very careful control of the slurry weight is critical to a successful cementing operation. The recirculating b l e n d e r is c o n n e c t e d to a c e m e n t p u m p that in turn p u m p s the c e m e n t at low

Figure 4-379. Recirculating blender [161].

Well C e m e n t i n g

1181

circulation rates (and high pressures if necessary) to the c e m e n t i n g h e a d at the top of the casing string (see Figures 4-380 and 4-381 a n d Ref. [162]). T h e p r o p e r a m o u n t of water must be mixed with the dry cement p r o d u c t to ensure only sufficient water for h y d r a t i o n of the cement. Excess water above that n e e d e d for h y d r a t i o n will reduce the final strength of the set c e m e n t and leave voids in the cement column that are filled with unset liquid. Insufficient water for p r o p e r hydration will leave voids filled with dry unset cement, or result in a slurry too viscous to p u m p . T h e cement is usually d r y mixed with the additives that are usually a d d e d for a particular cementing application. Often this mixing of additives is c a r r i e d out at the service c o m p a n y central location. D e p e n d i n g on the application of the well cement, there are a variety of additives that can be used to design the c e m e n t s l u r r y characteristics. T h e s e are accelerators, r e t a r d e r s , dispersants, extenders, weighting agents, gels, foamers and fluid-loss additives. W i t h these additives the cement slurry and ultimately the set cement can be d e s i g n e d for the particular c e m e n t i n g o p e r a t i o n . It is necessary that the e n g i n e e r in charge of the well carry out the necessary engineering design of the slurries to be used in the well. In addition, the e n g i n e e r should ensure that the work is c a r r i e d out in accordance to the design specifications. This critical activity should not be left to the service c o m p a n y technicians.

UC~

SURFACE CASiNG~ PROOUCT~ON

'¢

CASING - CEMENT SLURRY--

BOSOM PLUG

CENTRALIZER FLOAT COLLAR--~

GU|DESHOE

. . . . . . . .

Figure 4-380. Blender, pump truck, cementing head and subsurface equipment [161]

1182

Drilling a n d Well C o m p l e t i o n s O ~l

7,

HEXPLUG , CAP

BODY MANIFOLD ASSEMBLY: 2" PIPE

BAILASSY. W/LOCKBOLT

FII-rlNGS

Figure 4-381. Cementing head [161].

S t a n d a r d i z a t i o n a n d Properties of C e m e n t s

T h e A m e r i c a n Petroleum Institute (API) has nine classes o f well cements. These are as follows [164]: Class A: I n t e n d e d for use from surface to 6,000 ft (1,830 m) depth, when special

p r o p e r t i e s are not required. Available only in o r d i n a r y type (similar to ASTM C 150, Type I*). Class B: I n t e n d e d for use f r o m surface to 6,000 ft (1,830 m) d e p t h , when c o n d i t i o n s r e q u i r e m o d e r a t e to high sulfate resistance. Available in b o t h m o d e r a t e (similar to ASTM C 150, Type II) and high-sulfate-resistant types. Class C: I n t e n d e d for use f r o m surface to 6,000 ft (1,830 m) d e p t h , when c o n d i t i o n s require high early strength. Available in o r d i n a r y and m o d e r a t e (similar to ASTM C 150, Type III) and high-sulfate-resistant types. Class D: I n t e n d e d for use from 6,000 to 10,000 ft (1,830 to 3,050 m) depth, u n d e r conditions o f m o d e r a t e l y high t e m p e r a t u r e s and pressures. Available in b o t h m o d e r a t e a n d high-sulfate-resistant types. Class E: I n t e n d e d for use from 10,000 to 14,000 ft (3,050 to 4,270 m) d e p t h , u n d e r c o n d i t i o n s o f high t e m p e r a t u r e s a n d pressures. Available in b o t h m o d e r a t e and high-sulfate-resistant types. Class F: I n t e n d e d for use from 10,000 to 16,000 ft (3,050 to 4,880 m) depth, u n d e r conditions o f extremely high t e m p e r a t u r e s and pressures. Available in b o t h m o d e r a t e and high-sulfate-resistant types. Class G: I n t e n d e d for use from surface to 8,000 ft (2,440 m) d e p t h as manufactured, or can be used with accelerators and retarders to cover a wide range o f well depths a n d temperatures. No additions o t h e r than calcium sulfate or water, or both, shall be i n t e r g r o u n d or b l e n d e d with t h e clinker d u r i n g

*American Society for Testing and Materials (ASTM).

Well C e m e n t i n g

118~

manufacture of Class G well cement. Available in m o d e r a t e and high-sulfateresistant types. Class H: Intended for use as a basic well cement from surface to 8,000 ft (2,440 m) depth as manufactured, and can be used with accelerators and retarders to cover a wide range of well depths and temperatures. No additions other than calcium sulfate or water, or both, shall be i n t e r g r o u n d or b l e n d e d with the clinker during manufacture of Class H well cement. Available in moderate and high- (tentative) sulfate-resistant types. Class J: I n t e n d e d for use as m a n u f a c t u r e d from 12,000 to 16,000 ft (3,660 to 4,880 m) depth u n d e r conditions of extremely high temperatures and pressures or can be used with accelerators and retarders to cover a range of well depths and temperatures. No additions of retarder other than calcium sulfate or b l e n d e d with the clinker d u r i n g manufacture of Class J well cement. The ASTM specifications provide for five types of Portland cements: Types I, II, III, IV and V; they are m a n u f a c t u r e d for use at atmospheric conditions [165]. The API Classes A, B and C c o r r e s p o n d to ASTM Types I, II and III, respectively. The API Classes D, E, F, G, H and J are cements m a n u f a c t u r e d for use in deep wells and to be subject to a wide range of pressures and temperatures. These classes have no c o r r e s p o n d i n g ASTM types. Sulfate resistance is an extremely i m p o r t a n t property of well cements. Sulfate minerals are abundant in some u n d e r g r o u n d formation waters that can come into contact with set cement. The sulfate chemicals, which include magnesium and sodium sulfates, react with the lime in the set cement to form magnesium hydroxide, sodium hydroxide and calcium sulfate. The calcium sulfate reacts with the tricalcium aluminate components of cement to form sulfoaluminate, which causes expansion and ultimately disintegrates to the set cement. To increase the resistance of a cement to sulfate attack, the amount of tricalcium aluminate and free lime in the cement should be decreased. Alternatively, the a m o u n t of pozzolanic material can be increased in the cement to obtain a similar resistance. The designations of ordinary sulfate resistance, moderate sulfate resistance and high sulfate resistance in the cement classes above indicate decreasing amounts of tricalcium aluminate. Table 4-154 gives the basic properties of the various classes of the dry API cements [165].

Properties of Cement Slurry and Set Cement In well e n g i n e e r i n g and applications, cement must be dealt with in both its slurry form and in its set form. At the surface the cement must be mixed and then p u m p e d with surface p u m p i n g equipment through tubulars to a designated location in the well. After the cement has set, its structure must support the various static and dynamic loads placed on the well tubulars.

Specific Weight Specific weight is one of the most i m p o r t a n t properties of a cement slurry. A neat cement slurry is a c o m b i n a t i o n of only cement and water. The specific weight of a neat cement slurry is defined by the a m o u n t of water used with the dry cement. The specific weight range for a particular class of cement is, therefore, limited by the m i n i m u m and m a x i m u m water-to-cement ratios permissible by API standards. The m i n i m u m a m o u n t of water for any class of cement is defined as that a m o u n t of water that can be used in the slurry with the dry cement that will

1184

Drilling a n d Well Completions Table 4-154 Properties of the Various Classes of API Cements

Cement Class Specific Gravity Surface Area (cma/gm) Weight Per Sack, Ib Bulk Volume, Ft3/sk Absolute Volume, gal/sk

A

B

C

D

E

F

G

H

3.14 1500 94 1 3.59

3.14 1600 94 1 3.59

3.14 2200 94 1 3.55

3.16 1200 94 1 3.57

3.16 1200 94 1 3.57

3.16 1200 94 1 3.57

3.16 1400 94 1 3.62

3.16 1200 94 1 3.57

still produce a neat slurry with a consistency that is below 30 Bearden units of consistency.* Note that the m i n i m u m water content d e f i n e d in this m a n n e r is much greater than the stoichiometric m i n i m u m for cement hydration and setting. The m a x i m u m a m o u n t of water for any class of cement is usually defined as the ratio that results in the cement particles r e m a i n i n g in suspension until the initial set of the slurry has taken place. If more than the m a x i m u m a m o u n t of water is used, then the cement particles will settle in such a m a n n e r that there will be pockets of free water within the set cement column. Table 4-155 gives the API r e c o m m e n d e d o p t i m u m water-to-cement ratios and the resulting neat slurry specific weight (lb/gal) and specific volume, or yield (ftS/sack) for the various classes of API cements [161]. Table 4-156 gives the m a x i m u m a n d m i n i m u m water-to-cement ratios a n d the resulting neat slurry specific weight a n d specific volume, or yield for three classes of API cement. T h e specific weight of a cement slurry ~ (lb/gal) is Cement (lb) + Water (lb) + Additive (lb) = Cement (gal) + Water (gal) + Additive (gal)

(4-324)

The volumes above are absolute volumes. For example, a 94-1b sack of cement contains 1 ft 3 of bulk cement powder, yet the actual or absolute space occupied by the cement particles is only 0.48 ft s. For d e a l i n g with o t h e r p o w d e r e d materials that are additives to c e m e n t slurries, the absolute volume must be used. T h e absolute volume (gal) is

Absolute value (gal) =

Additive material (lb) (8.34 lb/gal)(S. G. of material)

(4-325)

The volume of slurry that results from 1 sack of cement additives is defined as the yield. T h e yield (ft3/sack) is

Yield =

Cement (gal) + Water (gal) + Additives (gal) 7.48 gal/ft s

(4-326)

where the cement, water a n d additives are those associated with 1 sack of cement, or 94 lb of cement. *This was formally referred to as poise.

Well C e m e n t i n g

1185

Table 4-155 Properties of Neat Cement Slurries for Various Classes of API Cements

API Class (Portland)

A

B (Portland) (High Early) (Retarded) (Retarded) (Retarded) (Basic) (Basic)

C D E F G H

API Rec'd Water (gal/sk)

API Rec'd Water (gal/sk)

API Rec'd Water (gal/sk)

Percent of Mixing Water

5.20 5.20 6.32 4.29 4.29 4.29 4.97 4.29

15.6 15.6 14.8 16.46 16.46 16.46 15.8 16.46

1.18 1.18 1.32 1.05 1.05 1.05 1.15 1.05

46 46 56 38 38 38 44 38

Table 4-156 Maximum and Minimum Water-to-Cement Ratios for API Classes A, C and E Neat Cement Slurries Maximum Water Water Weight Volume (gal/sk) (Ib/gal) (ft3/sk)

API Class A C E

5.5 7.9 4.4

15.39 13.92 16.36

1.22 1.53 1.07

Minimum Water Water Weight Volume (gal/sk) (Ib/gal) (ftVsk) 3.90 6.32 3.15

16.89 14.80 17.84

1.00 1.32 0.90

Example 1 Calculate the specific weight a n d yield for a neat slurry of Class A cement using the m a x i m u m permissible water-to-cement ratio. Table 4-156 gives the m a x i m u m water-to-cement ratio for Class A cement as 5.5 gal/sack. Thus using the absolute volume for Class A cement from Table 4-154 as 3.59 gal/sack, Equation 4-324 is ~, = 9 4 + 5 . 5 ( 8 . 3 4 ) 3.59+5.5 = 15.39 lb/gal T h e yield d e t e r m i n e d from Equation 4-326 is Yield =

3.59+5.5 7.48

= 1.22 ft3/sack

1186

Drilling a n d Well C o m p l e t i o n s

It is often necessary to decrease the specific weight o f a cement slurry to avoid fracturing weak formations during cementing operations. There are basically two m e t h o d s for accomplishing lower specific weights. These are 1. A d d i n g clay or chemical silicate type extenders together with their required e x t r a water. 2. A d d i n g large quantities o f pozzolan, ceramic m i c r o s p h e r e s or nitrogen. These materials lighten the slurry because they have lower specific gravities than the cement. W h e n using the first m e t h o d above great care must be taken not to use too much water. T h e r e is a m a x i m u m permissible water-to-cement ratio for each cement class. This amount o f water can be used with the a p p r o p r i a t e extra water required for the a d d e d clay or chemical silicate material. Using too much water will result in a very p o o r cement o p e r a t i o n . It also may be necessary to increase the specific weight o f a cement slurry, p a r t i c u l a r l y w h e n c e m e n t i n g t h r o u g h h i g h - p r e s s u r e f o r m a t i o n s . T h e r e are basically two m e t h o d s for accomplishing higher specific weights. These are 1. Using the m i n i m u m permissible water-to-cement ratio for the p a r t i c u l a r cement class a n d a d d i n g dispersants to increase the fluidity o f the slurry. 2. A d d i n g high-specific-gravity materials to the slurry together with o p t i m a l or slightly r e d u c e d (but not necessarily the minimum) water-to-cement ratio for the p a r t i c u l a r cement class. T h e first m e t h o d above is usually restricted to setting plugs in wells since it results in high strength cement that is r a t h e r difficult to p u m p . T h e second m e t h o d is used for p r i m a r y cementing, but these slurries are difficult to design since the settling velocity o f the high-specific-gravity additive must be taken into consideration.

Thickening Time It is i m p o r t a n t that the thickening time for a given cement slurry be known p r i o r to using the slurry in a c e m e n t i n g o p e r a t i o n . W h e n water is a d d e d to dry cement a n d its additives, a chemical reaction begins that results in an increase in slurry viscosity. This viscosity increases over time, which will vary in accordance with the class o f cement used, the additives placed in the dry cement p r i o r to mixing with water a n d the t e m p e r a t u r e a n d confining pressure in the location where the cement slurry is placed. W h e n the viscosity b e c o m e s too large, the slurry is no longer pumpable. Thus, if the slurry has not b e e n placed in its p r o p e r l o c a t i o n within the well p r i o r to the c e m e n t slurry b e c o m i n g u n p u m p a b l e , the well a n d the surface e q u i p m e n t would be seriously damaged. Thickening time T (hr) is d e f i n e d as the time required for the cement slurry to reach the limit o f 100 B e a r d e n units o f consistency.* This thickening time must be considerably longer than the time necessary to c a r r y out the actual cementing operation. This can be accomplished by choosing the class o f cement that has a sufficiently long thickening time, or placing the a p p r o p r i a t e additives in the slurry that will r e t a r d the slurry chemical reaction a n d l e n g t h e n the thickening time. *70 Bearden units of consistency is considered to be maximum pumpable viscosity.

Well C e m e n t i n g

1187

It is necessary that an accurate estimate of the total time be for the actual operation. A safety factor should be added to this estimate. Usually this safety factor is from 30 min (for shallow operations) to as long as 2 hr (for deep complex operations). The cementing operation time T O (hr) is the time required for the cement slurry to be placed in the well: T O= T m + where

T d

+ Tp + T

(4-327)

time required to mix the dry cement (and additives) with water in hr Td = the time required to displace the cement slurry (that was p u m p e d to the well as mixing took place) by m u d or water from inside the casing in hr Tp = plug release time in hr T s = the safety factor of 0.5 to 2 hr

T m =

The mixing time

Tm=

T m

is

Volume of dry cement Mixing rate V c (sacks) Mixing rate (sack/min)(60)

(4-328)

where Vc is the dry volume of cement (sacks). The displacement time T d is Volume of fluid required to displace top plug T d --~

Displacement rate Volume (ft 3) Displacement rate (ft3/min)(60)

(4-329)

The cement slurry chosen must have a thickening time that is greater than the estimated time obtained for the actual cementing operation using Equation 4-327. Thus, T t > T o. Figure 4-382 gives a relationship between well depth and cementing operation time and the specifications for the various cement classes. This figure can be used to approximate cementing o p e r a t i o n time. The cement slurry thickening time can be increased or decreased by adding special chemicals to the dry cement prior to mixing with water. Retarders are added to increase the thickening time a n d thus increase the time when the cement slurry sets. Some c o m m o n retarders are organic c o m p o u n d s such as l i g n o s u l p h o n a t e , cellulose derivatives and sugar derivatives. Accelerators are added to decrease the thickening time and thus decrease the time when the cement slurry sets. Accelerators are often used when it is required to have the cement obtain an early compressive strength (usually of the order of 500 psi). Early setting c e m e n t slurries are used to c e m e n t surface casing strings or directional drilling plugs where waiting-on-cementing (WOC) must be kept to a

1188

Drilling a n d Well C o m p l e t i o n s

O-

I1,1 ~=~,,

-~" 2-

I

i"

" 8fh~

c.ss,s

A,8,C

I

I=~.~.'~1 CEMENTS I

4-

GBH CEMENTS

~ t

\

,i

CLASSES*

-

GI-

CLASS

~

~ t

I

z

~ IOIz

SPECIFIED MINIMUM THICKENING TIME

12

I J

1~..f

I

••

I

CEMENT

I

%1

~

•

CLASS

E

l CEMENT I ! i CLASSES F&J CEMENTS I

14

16

• -

18

CEMENTING TIME ASSUMING ~ !20 CUBIC FEET 0.57 CUBIC , . ~ 1. J •METRES PER MIN. MIXING RATE, 50 CFM (Z4 I/SeC|DtSPLACEMENT , a ~ 4r~IATEoIN 7- INCH (178mm) 17 Ib/ft -:253 kg//nt) CASING ill I, 300¢u.ftlSOO¢•.ftl IO~¢u.ft i~500¢u.ftJ ZO~Gu.ft.I Sm~ | i4m~ I 28m• I [ 42m~ ] 56m= I

20-

0

Figure

20

40

60

i ii

80 I00 120 TIME, MINUTES

iiiF

140

160

180

i

200

4-382. Well depth and cementing time relationships [164].

*Specified maximum thickening t i m e - - 1 2 0 minutes.

minimum. T h e most c o m m o n accelerators are calcium chloride a n d to a lesser extent s o d i u m chloride. In general the thickening time for all neat cement slurries of all classes of cement will decrease significantly with increasing well e n v i r o n m e n t t e m p e r a t u r e a n d / o r c o n f i n i n g pressure. Thus it is very i m p o r t a n t that t h e well e x t r e m e t e m p e r a t u r e s and c o n f i n i n g pressures be d e f i n e d for a p a r t i c u l a r c e m e n t i n g o p e r a t i o n before the cement slurry is designed. Once the well t e m p e r a t u r e and pressure conditions are known, either from offset wells or from actual well logs d u r i n g the drilling o p e r a t i o n , a n d the estimated c e m e n t i n g o p e r a t i o n time is

Well Cementing

1189

known, the cement slurry with the required thickening time can be designed. After the initial cement slurry design has been made it is usually necessary to carry out laboratory tests to verify that the actual cement batch mix used will give the required thickening time (and other characteristics needed). Such tests are usually carried out by the cementing service company laboratory using the operator's specifications.

Example 2 Calculate the m i n i m u m thickening time required for a primary cementing operation to cement a long intermediate casing string. The intermediate casing string is a 9 ~s-in., 53.5-1b/ft casing set in a 12{-in. hole. The string is 12,000 i°t in length f r o m the top o f the float collar to the surface. The c e m e n t i n g operation will require 1,200 sacks of Class H cement. The single cementing truck has a mixing capacity of 25 sacks per minute. The rig duplex mud p u m p has an 18-in. stroke (2.5 in. rod) and 6 {-in. liners and will be operated at 50 strokes per minute with a 90% volumetric efficiency. The plug release time is estimated to be about 15 min. The mixing time is obtained from Equation 4-328. This is

Tm =

1,200 25(60)

= 0.80 hr The inside diameter of 9 ~-in., 53.50-1b/ft casing is 8.535 in. (see Section tided "Fishing Operations"). The internal capacity per unit length of casing is Casing internal capacity =

(8.535) 2 4

12

= 0.3973 fts/ft Thus the total internal capacity o f the casing is Total volume = 12,000(0.3973) = 4768 ft 3 The volume capacity of the m u d p u m p per stroke q (ft3/stroke) (see section titled "Mud Pumps") is

0,} = 1.1523ft3/stroke

1190

Drilling and Well C o m p l e t i o n s

T h e displacement time is o b t a i n e d from Equation 4-329. This is

Yd =

4,768 50(1.1523)(60)

= 1.38 hr T h e plug release time is 15 Tp = 6--6 = 0.25 hr Using a safety factor o f 1 hr, the c e m e n t i n g o p e r a t i o n time is o b t a i n e d from Equation 4-327. This is T = 0.80 + 1.38 + 0.25 + 1.00 = 3.43 hr T h u s the m i n i m u m t h i c k e n i n g t i m e for the c e m e n t s l u r r y to be u s e d this c e m e n t i n g o p e r a t i o n is T t = 3.43 hr or 3 hr and 26 min.

Strength of Set Cement A p r o p e r l y d e s i g n e d cement slurry will set after it has b e e n p l a c e d in its a p p r o p r i a t e location within the well. C e m e n t strength is the strength the set cement has obtained. This usually refers to compressive strength, but can also refer to tensile strength. C e m e n t having a compressive strength o f 500 psi is c o n s i d e r e d adequate for most well operations. T h e compressive strength o f set cement is d e p e n d e n t u p o n the water-to-cement r a t i o u s e d in the slurry, c u r i n g time, the t e m p e r a t u r e d u r i n g curing, the c o n f i n i n g pressure d u r i n g curing and the additives in the cement. As p a r t o f the cement design procedures, samples o f the cement slurry to be u s e d in the cementing o p e r a t i o n are cured and compression strength tested and often shear b o n d s t r e n g t h tested. T h e s e tests are usually c a r r i e d out by the c e m e n t i n g c o m p a n y l a b o r a t o r y at the request o f the operator. In the compression test, four or five sample cubes o f the slurry are allowed to cure for a s p e c i f i e d p e r i o d o f time. T h e c e m e n t cubes are p l a c e d in a compression testing machine and the compressive strength o f each sample cube o b t a i n e d experimentally. T h e average value o f the samples is o b t a i n e d and r e p o r t e d as the compressive strength o f the set cement. In the shear b o n d strength test, the cement slurry is allowed to cure in the annulus o f two concentric steel cylinders. A f t e r curing the force to break the b o n d between the set cement and one o f the cylinders (usually the i n n e r one)

Well Cementing

1191

is obtained experimentally. The shear force, F (lb), which can be supported on the inner cylinder, or by the casing, is [163] F = 0.969 o dl

(4-330)

where ac = compressive strength of cement in psi d = outside of the casing in in. 1 = length of the cement column in in. Table 4-157 shows the influence of curing time, temperature and confining pressure on the compressive strength of Class H cement [162]. Also shown is the effect of the calcium chloride accelerator. In general, for the ranges of temperature and other values considered, the compressive strength increases with increasing curing time, temperature, confining pressure and the amount of calcium chloride accelerator. In general, the other classes of cement follow the same trend in compressive strength versus curing time, temperature and confining pressure. At curing temperatures of about 200°F or greater, the compressive strength of nearly all classes of cement cured under pressure will decrease. This decrease in compressive strength is often denoted as strength retrogression. An increase in cement permeability accompanies this decrease in strength. This strength retrogression usually continues for up to 15 days and, thereafter, the strength level will remain constant. This strength retrogression problem can be solved by adding from 30 to 50% (by weight) of silica flour or silica sand to the cement slurry. This silica additive prevents the strength retrogression and the corresponding increase in permeability of the cement. Table 4-158 shows the effect of silica flour on the compressive strength of Class G cement cured at 700°F. Example 3

For Example 2, determine the total weight that can be supported by the set cement bonded to the 9 ~-in. casing. Assume the cement slurry yield is 1.05 ft3/sack

T a b l e 4-1 5 7 I n f l u e n c e of T i m e a n d T e m p e r a t u r e o n t h e C o m p r e s s i v e of A P I C l a s s H C e m e n t [162] Curing Time

(hours) 6 8 12 24 6 8 12 24 6 8 12 24

Calcium Chloride

(percent) 0

I

Compressive Strength (psi) at Curing Temperature and Pressure ol 95°F 800 psi 100 500

110°F 1,600 psi 350 1,200

140°F 3,000 psi 1,270 2,500

1,090 3,000 900 1,600

1,980 4,050 1,460 1,950

4,100

5,100

3,125 5,500 2,320 2,900 3,440 6,5oo

1,100

1,700 2,600

2,650 3,600

2,200

2

Strength

1,850 2,420 4,7OO

2,970

3,380 5,6OO

3,900 6,850

170°F

3,000 psi 1,950 4,000 4,700 6,700 2,500 4,100 4,450 7,000

2,990 4,370 5,530 7,400

Drilling a n d Well Completions

1192

Table 4-158 Effect of Silica Flour on the Compressive Strength of Class G Cement Cured at Pressure Curing Time (days)

Silica Flour (percent)

Compressive Strength (psi), 1 Day at 130°F, All Remaining Days at 700°F

0

3525

1

2

988

4 8

1012 1000

1 2

40

4 8

2670 3612

3188 4588

Source: Courtesy B. J. Hughes

(see Table 4-155) a n d there are 120 ft of casing below the f l o a t collar. A compressive strength of 500 psi is to be used. T h e total volume of the cement slurry to be p u m p e d to the well is Volume of slurry = 1,200(1.05) = 1,260 ft 3 The volume of slurry that is pumped to the annulus between the open borehole and the outside of the casing is Volume of a n n u l u s = 1,260 - (0.3973)(120) = 1,212 ft 3 T h e height in the a n n u l u s to where the casing is cemented to the borehole well a n d casing is h =

1,212 ~/4 [(12.5/12) 2 - (9.625/12) 2]

= 3,493 ft T h e total weight that can be supported is calculated from Equation 4-330. This is F = 0.969(500)(9.625)(3,493)(12) = 195.5 × 106 Ib

Well C e m e n t i n g

1193

Cement Additives T h e r e are m a n y c h e m i c a l a d d i t i v e s that can be u s e d to a l t e r t h e basic properties of the neat cement slurry and its resulting set cement. These additives are to alter the cement so that it is m o r e a p p r o p r i a t e to the surface cementing e q u i p m e n t a n d the subsurface environment. Additives can be s u b d i v i d e d into six functional groups that are [167,168]: 1. 2. 3. 4. 5. 6.

specific weight control thickening and setting time control loss of circulation control filtration control viscosity control special p r o b l e m s control

Specific Weight Control As in drilling m u d design, the cement slurry must have a specific weight that is high enough to prevent high p o r e pressure formation fluids from flowing into the well. But also the specific weight must not be so high as to cause fracturing of the weaker e x p o s e d formations. In general, the specific weight of the neat cement slurry of any of the various API classes of cement are so high that most e x p o s e d f o r m a t i o n s will fracture. Thus, it is necessary to lower the specific weight of nearly all cement slurries. T h e slurry specific weight can be r e d u c e d by using a higher water-to-cement ratio. But this can only be accomplished within the limits for maximum and minimum water-to-cement ratios set by API standards (see Table 4o156). The r e d u c t i o n in specific weight is n o r m a l l y accomplished by adding low-specific-gravity solids to the slurry. Table 4-159 gives the specific gravity p r o p e r t i e s of a n u m b e r of the low-specific-gravity solids that are used to reduce the specific weight of cement slurries. T h e most c o m m o n low-specific-gravity solids used to reduce cement slurry specific weight are bentonite, diatomaceous earth, solid hydrocarbons, e x p a n d e d perlite and pozzolan. It may not be possible to reduce the cement slurry specific weight e n o u g h with t h e above low-specific-weight m a t e r i a l s when very weak formations are exposed. In such cases nitrogen is used to aerate the mud column above the cement slurry to assist in further decreasing the hydrostatic pressure. Nearly all materials that are a d d e d to a cement slurry require the a d d i t i o n of a d d i t i o n a l water to the slurry. Table 4-160 gives the a d d i t i o n a l requirements for the various cement additives [167].

Bentonite. Bentonite without an organic p o l y m e r can be used as an additive to cement slurries. T h e a d d i t i o n of b e n t o n i t e requires the use of additional water, t h e r e b y , f u r t h e r r e d u c i n g t h e s p e c i f i c weight o f t h e s l u r r y (Table 4-160). Bentonite is usually d r y b l e n d e d with the d r y cement p r i o r to mixing with water. High percentages of bentonite in cement will significantly reduce compressive s t r e n g t h a n d thickening time. Also, high p e r c e n t a g e s of b e n t o n i t e i n c r e a s e p e r m e a b i l i t y and lower the resistance of cement to sulfate attack. At temperatures above 200°F, the bentonite additive p r o m o t e s retrogression of strength in cements with time. Bentonite has been used in 25% by weight of cement. Such high concentrations are not r e c o m m e n d e d . In general, the bentonite additive makes a p o o r well cement.

1194

Drilling and Well Completions Table Physical

Material API cements Ciment Fondu Lumnite cement Tdnity Lite-Wate Activated charcoal Barite Bentonite (gel) Calcium chloride, flake b Calcium chloride, powder b CaI-Seal, gypsum cement CFR-1 b CFR-2 b DETA (liquid) Diacel A s Diacel D Diacel LWL b Diesel Oil No. 1 (liquid) Diesel Oil No. 2 (liquid) Gilsonite HALDAD~.9 b HALDAD~-I 4 b Hematite HR-4 b HR-7 b HR-12 b HR-L (liquid) b Hydrated lime Hydromite LA-2 Latex (liquid) LAP-1 Latex b LR-11 Resin (liquid) NF-1 (liquid) b NF-P b Pedite regular Perlite Six Pozmix® A Pozmix¢ D Salt (dry NaCI) Salt (in solution at 77°F with fresh w=ter) 6%, 0.5 Ibm/gal 12%, 1.0 Ibm/gal 18%, 1.5 Ibm/gal 24%, 2,0 Ibmlgal Saturated, 3.1 Ibmlgal Salt (in solution at 140°F with fresh water) saturated, 3.1 Ibm/gal Sand (Ottawa) Silica flour (SSA-1) Coarse silica (SSA-2) Tuf Additive No. 1 Tuf-Plug Water

Properties

4-159

of Cementing

Materials

Bulk Weight (Ibmlcu fl) 94 90 90 75 14 135 60 56.4

Weight 3.6 = Absolute Gal 94 97 96 75.0 e 47.1 126.9 79.5 58.8

Specif'¢ Gravity 3.14 3.23 3.20 2.80 1.57 4.23 2.65 1.96

50.5 75 40.3 43.0 59.5 60.3 16.7 29.0 51.1 53.0 50 37.2 39.5 193 35 30 23.2 76.6 31 68 68.5 50 79.1 61.1 40 8c 38d 74 47 71

1.96 2.70 1.63 1.30 0.95 2.62 2. I 0 1.36 0.82 0.85 1.07 1.22 1.31 5.02 1.56 1.30 1.22 1.23 2.20 2.15 1.10 1.25 1.27 0.98 1.30 2.20 -2.46 2.50 2.17

58.8 81.0 48.9 39.0 28.5 78.6 63.0 40.6 24.7 25.5 32 36.6 39.3 150.5 46.8 39 36.6 36.9 66 64.5 33 37.5 38.1 29.4 39.0 66.0

------100 70 100 -48 62.4

Absolute gal/Ibm 0.0382 0.0371 0.0375 0.0429 0.0765 0.0284 0.0453 0.0612

74 73.6 65.1

0.0612 0.0444 0.0736 0,0688 0.1258 0.0458 0.0572 0.0882 0.1457 0.1411 0.1122 0.0984 0.0916 0.0239 0.0760 0.0923 0.0984 0.0976 0.0545 0.0538 0.1087 0.0960 0.0945 0.1225 0.0923 0.0546 0.0499 0.0487 0.0489 0.0553

0.0082 0.0059 0.0098 0.0092 0.0168 0.0061 0.0076 0.0118 0.0195 0.0188 0.0150 0.0131 0.0122 0.0032 0.0103 0.0123 0.0131 0.0130 0.0073 0.0072 0.0145 0.0128 0.0126 0.0164 0.0123 0.0073 0.0O67 0.0065 0.0065 0.0074

------

------

0.0384 0.0399 0.0412 0.0424 0.0445

0.0051 0.0053 0.0055 0.0057 0.0059

-2.63 2.63 2.63 1.23 1.28 1.00

-78.9 78.9 78.9 36.9 38.4 30.0

0.O458 0.0456 0.0456 0.0456 0.0976 0.0938 0.1200

0.0061 0.0061 0.0061 0.0061 0.0130 0.0125 0.0160

Equivalent to one 94-1bin sack of cement tn volume. When leas than 5% is used, these chemicals may be omitted from calculstk)ns without significant error. ~WOr-8 Ibm of Petite regular use 6 vOlu¢~ of 1.43 gel 01 zero pressure. ~For 38 Ibm of Pedite Six use a volume of 2,89 gal at ze¢o p~ssure.

°75 Ibm- 3.22ab~km g~. Source: Courtesy Halliburton Services

Volume cu if/Ibm 0.0051 0.0050 0.(X)50 0.O057 0.0102 0.0038 0.0060 0.0082

Well C e m e n t i n g

Water

Table 4-160 Requirement of Cementing

Material API Class A and B cements API Class C cement (Hi Early) APt Class D and E cements (retarded) API Class G cement API Class H cement Chem Comp cement Ciment Fondu Lumnite cement HLC Trinity Lde-Wate cement Activated charcoal Barite Bentonite (gel) Calcium chloride Gypsum hemthydtate CFR. 1 CFR-2 Diacel A D~acel D Diacet LWL Gdsonite HALAD -9 HALAD -14 Hematite HR-4 HR-7 HR-12 HR-20 Hydrated lime Hydromite LA-2 Latex LAP-1 powdered latex NF-P Perlite regular Perlite Six Pozmix ~ A Salt (NaCI) Sand. Ottawa Silica flour (SSA-1) Coarse silica (SSA-2) Tuf Additive No. 1 Tuf Plug

1195

Materials

Water Requirements 5.2 gal (0.70 cu ft)/94-1bm sack 6 3 gal (0.84 cu ft)/94-1bm sack 4 3 gal (058 cu ft)/94-1bm sack 5.0 gal (067 cu ft)/94-1bm sack 4 3 to 5,2 gal/944bm sack 6.3 gal (0.84 cu ft)194-1bm sack 4.5 gal (0.60 cu ft)/94-1bm sack 4.5 gal (060 cu fl)/94-1bm sack 7.7 to 10.9 gal187-1bm sack 7.7 gat (1.03 cu ft)/75-1bm sack (maximum) none at I Ibm/sack of cement 2.4 gal (0.32 cu ft)/1OO-Ibm sack 1.3 gal (0.174 cu ft)/2% in cement none 4.8 gal (0.64 cu ft)/100-Ibm sack none Rang none 3 3 IO 7.2 gall10% in cement (see LI WI Cement) none (up to 0.7%) 0-8 to 1.0 gall1% in cement (except gel or Diacel D slurries) 2.0 gal (0.267 cu ft)/50 Ibmtcu It none (up to 0.5%) 0.4 to 0.5 gal/sack of cement at over 0.5% none 0.36 gal (0.048 cu ft)ll00-1bm sack none none none Rang 0.153 gal (0.020 cu ft)llbm 3.0 gal (0.40 cu ft)ll00-Ibm sack 0 to 0.8 gallsack of cement 1.7 gal (0.227 cu ft)/1% in cement none 4 0 gal (0.535 cu It)18 Ibm/cu ft 6.0 gal (0.80 cu ft)138 Ibmlcu ft 3.6 gal (0.48 cu ft)/74 Ibmlcu ft none none 1.5 gal (0.20 cu tt)/35% in cement (32.9 Ibm) none none none

Source: Courtesy Halliburtan Services Diatomaceous E a r t h , Diatomaceous e a r t h has a lower specific gravity than bentonite. Like bentonite this additive also requires additional water to be a d d e d to the slurry. This additive will affect the slurry properties similar to the addition o f bentonite. However, it will not increase the viscosity as b e n t o n i t e will do. Diatomaceous e a r t h concentrations as high as 40% by weight o f cement have b e e n used. This additive is m o r e expensive than bentonite.

1196

Drilling a n d Well Completions

Solid Hydrocarbons. Gilsonite (an asphaltite) a n d coal are used as very-lowspecific-gravity solids additives. These additives do not require a great deal of water to be added to the slurry when they are used. Expanded Perlite. Expanded perlite requires a great deal of water to be added to the slurry when it is used to reduce the specific weight of a slurry. Often perlite as an additive is used in a blend of additives such as perlite with volcanic glass fines, or with pozzolanic materials, or with bentonite. Without bentonite the perlite tends to separate a n d float in the u p p e r part of the slurry. Pozzolan. Diatomaceous earth is a type of pozzolan. Pozzolan refers to a finely ground pumice or fly ash that is marketed as a cement additive u n d e r that name. The specific gravity of pozzolans is slightly less than the specific gravity of cement. The water r e q u i r e m e n t s for this additive are about the same as for cements. Only a slight reduction in specific weight of a slurry can be realized by using these additives. The cost of pozzolans is very low. Where very high formations pore pressure are present the specific weight of the cement slurry can be increased by using the m i n i m u m water-to-cement ratio a n d / o r by adding high-specific-gravity materials to the slurry. The most c o m m o n high-specific-gravity solids used to increase cement slurry specific weight are hematite, i l m e n i t e , barite a n d sand. Table 4-159 gives the specific gravity properties of a n u m b e r of these high-specific-gravity additives. Hematite. This additive can be used to increase the specific weight of a cement slurry to as high as 19 l b / g a l . This is an iron oxide ore with a specific gravity of about 5.02. Hematite requires the addition of some water when it is used as an additive. Hematite has m i n i m a l effect on thickening time a n d compressive strength of the cement. Ilmenite. This additive has a specific gravity of about 4.67. It is a m i n e r a l composed of iron, t i t a n i u m a n d oxygen. It requires no additional water to be added to the slurry; thus, it can yield slurry specific weights as high as the hematite additive. Ilmenite also has m i n e r a l effect on thickening time a n d compressive strength of the cement.

Barite. This m i n e r a l additive requires m u c h more water to be added to the cement slurry than does hematite. This large amount of added water required will decrease the compressive strength of the cement. This additive can be used to increase the specific weight of a cement slurry to as high as 19 l b / g a l . Sand. Ottawa sand has a low specific gravity of a b o u t 2.63. But since no additional water is required when using this additive, it is possible to use sand to increase the cement slurry specific weight. The sand has little effect on the pumpability of the cement slurry. W h e n set the cement will form a very hard surface. Sand used as an additive can be used to increase the specific weight of a cement slurry to as high as 18 l b / g a l .

Example 4 A specific weight of 12.8 l b / g a l is required for a Class A cement slurry. It is decided that the cement be mixed with bentonite to reduce the specific weight of the slurry. Determine the weight of b e n t o n i t e that should be dry b l e n d e d with each sack of cement. Determine the yield of the cement slurry. Determine the volume (gal) of water n e e d e d for each sack of cement.

Well C e m e n t i n g

1197

T h e weight of b e n t o n i t e to b e b l e n d e d is found by using Equation 4-324. T a k i n g the a p p r o p r i a t e data f r o m Tables 4-154, 4-155, 4-159 and 4-160, a n d letting x b e the u n k n o w n weight o f b e n t o n i t e p e r sack o f c e m e n t , E q u a t i o n 4-324 is 94 + x + 8.34(5.20 + 0. 692x)

12.8 =

94 + x ) 3.14"~'.34) 2.65(8.34) + 5 . 2 0 + 0 . 6 9 2 x Solving the above for x gives x = 9.35 lb Thus, 9.35 lb o f b e n t o n i t e will n e e d to b e a d d e d for each sack o f Class A c e m e n t used. T h e yield can b e d e t e r m i n e d f r o m Equation 4-326. This is 94

9.35

Yield -- 3.14(8.34)

+ 5.20 + 0. 692(9.35)

2.65(8.34) 7.48

= 2.10 ft3/sack

T h e volume o f water n e e d e d is Volume o f water = 5.20 + 0.692(9.35) = 11.69 g a l / s a c k

Example 5 A specific weight o f 18.2 l b / g a l is required for a Class H cement slurry. It is d e c i d e d that the cement b e mixed with hematite to increase the specific weight o f the slurry. Determine the weight o f hematite that should b e dry b l e n d e d with each sack o f cement. D e t e r m i n e the yield of the cement slurry. D e t e r m i n e the volume (gal) o f water n e e d e d for each sack o f cement. T h e weight o f h e m a t i t e to b e b l e n d e d is f o u n d by using E q u a t i o n 4-324. Taking the a p p r o p r i a t e data f r o m Tables 4-154, 4-155, 4-159 and 4-160, a n d letting x b e the u n k n o w n weight o f h e m a t i t e p e r sack o f cement, Equation 4-324 is

18.2 =

94 + x + 8 . 3 4 ( 4 . 2 9 + 0.0036x) 94 x + ÷ ( 4 . 2 9 + 0.0036x) 3.14(8.34) 5.02(8.34)

Solving the above for x gives x = 25.8 lb Thus, 25.8 lb o f h e m a t i t e will n e e d to b e a d d e d for each sack o f Class H c e m e n t used.

1198

Drilling and Well Completions

The yield can be d e t e r m i n e d from Equation 4-326. This is 94

+

Yield -- 3.14(8.34)

25.8

÷ 4.29 +0.0036(25.8)

5.07(8.34) 7.48

= 1.15 ft3/sack

The volume of water needed is Volume of water = 4.29 + 0.0036(25.8) = 4.38 gal/sack

Example 6 A specific weight of 17.1 l b / g a l is required for a Class H cement slurry. It is decided that the cement be mixed with sand in order to increase the specific weight of the slurry. Determine the weight of sand that should be added with each sack of cement. Determine the yield of the cement slurry. Determine the volume (gal) of water n e e d e d for each sack of cement. The weight of sand to be added is found by using Equation 4-324. Taking the appropriate data from Tables 4-154, 4-155, 4-159 a n d 4-160, and letting x be the u n k n o w n weight of sand per sack of cement, Equation 4-324 is

17.1 ---

94 + x + 8.34(4.29) 94 x +4.29 3.14(8.34) 2.63(8.34)

Solving the above for x gives x = 31.7 lb Thus, 31.7 lb of sand will need to be added for each sack of Class H cement used. The yield can be d e t e r m i n e d from Equation 4-326. This is 94 Yield = 3.14(8.34)

31.7 2.63(8.34) 7.48

+ 4.29 __-1. 25 ft3/sack

Since no additional water is n e e d e d when using sand as the additive, the volume of water n e e d e d is Volume of water = 4.29 gal/sack

Thickening Setting Time Control It is often necessary to either accelerate, or retard the thickening a n d setting time of a cement slurry. For example, when cementing a casing string r u n to shallow depth or when setting a directional drilling kick-off plug, it is necessary to accelerate the cement hydration so that the waiting period will be minimized. The most c o m m o n l y

Well C e m e n t i n g

1199

used cement h y d r a t i o n accelerators are calcium chloride, s o d i u m chloride, a h e m i h y d r a t e form of gypsum and s o d i u m silicate.

Calcium Chloride. This accelerator may be used in concentrations up to 4% (by weight of mixing water) in wells having b o t t o m h o l e t e m p e r a t u r e s less than 125°F. This additive is usually available in an anhydrous g r a d e (96% calcium chloride). U n d e r pressure curing conditions calcium chloride tends to improve compressive strength and significantly reduce thickening and setting time.

Sodium Chloride. This additive will act as an accelerator when used in cements containing no bentonite and when in c o n c e n t r a t i o n s of about 5% (by weight of mixing water). In c o n c e n t r a t i o n s above 5% the effectiveness of s o d i u m c h l o r i d e as an accelerator is reduced. This additive should be used in wells with bottomhole t e m p e r a t u r e s less than 160°F. Saturated s o d i u m c h l o r i d e solutions act as a retarder. Such s a t u r a t e d s o d i u m c h l o r i d e s o l u t i o n s are used with c e m e n t slurries that are to be used to cement t h r o u g h formations that are sensitive to freshwater. However, potassium c h l o r i d e is far m o r e effective in inhibiting shale hydration. In general, up to a 5% concentration, s o d i u m chloride will improve compressive strength while r e d u c i n g thickening and setting time.

Gypsum. Special g r a d e s of g y p s u m h e m i h y d r a t e c e m e n t are b l e n d e d with Portland cement to p r o d u c e a cement with r e d u c e d thickening and setting time for low-temperature applications. Such cement blends should be used in wells with b o t t o m h o l e t e m p e r a t u r e s less than 140°F (regular-temperature g r a d e ) or 180°F (high-temperature grade). There is a significant additional water requirement for the a d d i t i o n of gypsum (see Table 4-160). W h e n very r a p i d thickening and setting times are required for low-temperature conditions (i.e., primary cementing of a shallow casing string or a shallow kick-off plug), a special blend is sometimes used. This is 90 lb of gypsum hemihydrate, 10 lb of Class A Portland cement and 2 lb of s o d i u m c h l o r i d e mixed with 4.8 gal of water. Such a cement slurry can develop a compression strength of about 1,000 psi in j u s t 30 min (at 50°). Sodium Silicate. W h e n d i a t o m a c e o u s e a r t h is used with the cement slurry, s o d i u m silicate is used as the accelerator. It can be used in concentrations u p to 7% by weight. W h e n it is necessary to cement casing or liner strings set at great depths, additives are o f t e n used in the d e s i g n of t h e c e m e n t s l u r r y to r e t a r d the t h i c k e n i n g a n d s e t t i n g time. Usually such r e t a r d i n g a d d i t i v e s are o r g a n i c c o m p o u n d s . T h e s e materials are also r e f e r r e d to as t h i n n e r s or dispersants. Calcium lignosulfonate is one of the most c o m m o n l y used cement retarders. It is very effective at increasing thickening and setting time in cement slurries at very low concentrations (of the o r d e r of 1% by weight or less). It is necessary to add an organic acid to the calcium lignosulfonate when h i g h - t e m p e r a t u r e conditions are encountered. C a l c i u m - s o d i u m l i g n o s u l f o n a t e is a b e t t e r r e t a r d i n g a d d i t i v e when high concentrations of b e n t o n i t e are to be used in the design of the cement slurry. Also s o d i u m t e t r a b o r a t e (borax) and carborymethyl hydroxyethyl cellulose are used as r e t a r d i n g additives. Filtration Control Filtration control additives are a d d e d to cement slurries for the same reason that they are a d d e d to drilling muds. However, u n t r e a t e d cement slurries have

1200

Drilling a n d Well C o m p l e t i o n s

much greater f i l t r a t i o n rates than u n t r e a t e d drilling muds. It is thus i m p o r t a n t to limit the loss o f water filtrate from a slurry to a p e r m e a b l e formation. This is necessary for several reasons: • • • •

minimize h y d r a t i o n o f formations containing water sensitive formations; limit the increase in slurry viscosity as cement is placed in the well; prevent annular bridges; allow for sufficient water to b e available for cement hydration.

Examples o f f i l t r a t i o n control additives are latex, b e n t o n i t e with a dispersant a n d o t h e r various organic c o m p o u n d s a n d polymers.

Viscosity Control T h e viscosity o f the cement slurry will affect the p u m p i n g requirements for the slurry a n d frictional pressure g r a d i e n t within the well. T h e viscosity must be kept low enough to ensure that the cement slurry can be p u m p e d to the well d u r i n g the entire c e m e n t i n g o p e r a t i o n period. High viscosity will result in high-pressure g r a d i e n t s that could allow f o r m a t i o n fractures. Examples o f c o m m o n l y used viscosity control additives are calcium lignosulfonate, s o d i u m chloride a n d some long-chain polymers. These additives also act as accelerators or retarders so care must be taken in d e s i g n i n g the cement slurry with these materials.

Special Problems Control T h e r e are some special p r o b l e m s in the design o f cement slurries for which additives have b e e n developed. These are •

• • • •

• •

Gel strength additives for the p r e p a r a t i o n o f spacers (usually fragile gel additives). Silica flour is used to form a stronger a n d less p e r m e a b l e cement, especially for h i g h - t e m p e r a t u r e applications. Hydrazine is used to control c o r r o s i o n o f the casing. Radioactive tracers are u s e d to assist in assessing where the c e m e n t has b e e n placed. Gas-bubble-producing c o m p o u n d s to slowly create gas bubbles in the cement as the slurry sets a n d hardens. It is felt that such a cement will have less t e n d e n c y to leak f o r m a t i o n gas. Paraformaldehyde and sodium chromate that counteract organic contaminants left in the well from drilling operations. Fibrous materials such as nylon are a d d e d to increase strength, in particular, resistance to impact loads.

Primary Cementing P r i m a r y cementing refers to the c e m e n t i n g o f casing a n d liner strings in a well. T h e cementing o f casing or liner string is c a r r i e d out so that p r o d u c i b l e oil a n d gas, or saltwater will not escape from the p r o d u c i n g formation to another formation, or pollute freshwater sands at shallower depth. The r u n n i n g o f long casing strings and liner strings to great depths and successfully cementing these strings required careful engineering design and planning.

Well C e m e n t i n g

1201

Normal Single-Stage Casing Cementing U n d e r g o o d rig o p e r a t i n g conditions, casing can be run into the hole at the rate of from 1,000 to 2,000 f t / h r . It is often necessary to circulate the drilling m u d in the hole p r i o r to r u n n i n g the casing string. This is to assure that all the cutting and any borehole wall prices have been removed. However, the longer a b o r e h o l e remains open, the m o r e p r o b l e m s will occur with the well. P r i o r to r u n n i n g the casing string into the well the mill varnish should be removed from the outer surface of the casing. T h e removal of the mill varnish is necessary to ensure that the cement will b o n d to the steel surface. T h e casing string is run into the well with a guide shoe on the b o t t o m of the string. Figures 4-383 and 4-384 show two typical guide shoes. Figure 4-383 is the regular p a t t e r n guide shoe that has no drillable internal materials. Figure 4-384 is the swirl guide shoe with drillable a l u m i n u m internal materials. A b o u t one or two j o i n t s above the guide shoe is the f l o a t collar. T h e f l o a t collar acts as a back-flow valve that keeps the heavier cement slurry from flowing back into the casing string after it has b e e n placed in the annulus between the outside of the casing and the b o r e h o l e wall. Figures 4-385 and 4-386 show two typical f l o a t collars. Figure 4-385 is a ball f l o a t collar and Figure 4-386 is a f l a p p e r f l o a t collar. Both f l o a t collars are constructed with drillable a l u m i n u m internal parts (larger f l o a t collars have a c o m b i n a t i o n of cement and a l u m i n u m internal parts). A l o n g the length of the casing string are placed scratchers and centralizers. Figure 4-387 shows t h e t y p i c a l s c r a t c h e r . F i g u r e 4-388 shows t h e t y p i c a l centralizer. T h e scratchers help remove the m u d cake as the casing string is lowered into the well. T h e centralizers ensure that the casing is nearly centered in the borehole, thus allowing a m o r e u n i f o r m distribution of cement slurry flow a r o u n d the casing. This nearly uniform flow a r o u n d the casing is necessary to remove the drilling m u d in the annulus. T h e casing string is lowered into the drilling m u d in the well using the rig drawworks and elevators. T h e displaced drilling m u d flows to the m u d tanks

Figure 4-383. Regular pattern guide shoe [161].

1202

Drilling and Well Completions

Figure 4-384. Swirl guide shoe [161].

Figure 4-385. Ball float collar [161].

and is stored there for later use. Once the entire casing string is in place in the borehole, the casing string is left hanging in the elevators through the cementing operation. This allows the casing string to be reciprocated (moved up and down) and possibly rotated as the cement is placed in the annulus. This movement assists the removal of the drilling mud.

Well Cementing

1203

Figure 4-386. Flapper float collar [161].

Figure 4-387. Scratcher [161]. While the casing string is hanging in the elevators a cementing head is made up to the upper end of the string (see Figure 4-381). The cementing head is then connected with flow liners that come from p u m p truck (see Figure 4-380). The blender mixes the dry cement and additives with water. The high-pressure, low-volume triplex cement p u m p on the p u m p truck pumps the cement slurry to the cementing head. Usually a preflush or spacer is initially p u m p e d ahead of the cement slurry. This spacer (usually about 15 to 25 bbl) is used to assist in removing the drilling mud from the annuiar space between the outside of the casing and the borehole wall. Figure 4-389 gives a series of schematics that show how the spacer and cement slurry displace drilling mud in the well. Two wiper plugs are usually used to separate the spacer and the cement slurry from the drilling mud in the well. The cementing head has two retainer valves that hold the two flexible rubber wiper plugs with two separate plug-release pins (see Figure 4-389a). W h e n the spacer and the cement slurry are to be p u m p e d to the inside of the casing

1204

Drilling and Well Completions

Figure 4-388. Centralizer [161]. through the cementing head, the bottom plug-release pin is removed. This releases the bottom wiper plug into the initial portion of the spacer flow to the well (see Figure 4.-389b). This bottom wiper plug keeps the drilling mud from contaminating the spacer and the cement slurry while they pass through the inside of the casing. When all the cement slurry has passed through the cementing head, the top plugrelease pin is removed releasing the top wiper plug into the flow to the well. At this point in the cementing operation the cement pump begins to pump drilling mud through the cementing head to the well (see Figure 4-389c). When the bottom wiper plug reaches the float collar there is a brief sharp rise in pump pressure. The pump pressure increase breaks the diaphragm in the lower wiper plug. Once the diaphragm is broken the spacer and the cement slurry flow through the float collar into the final joint or two of the casing

Well C e m e n t i n g

1205

Figure 4-389. Single-stage cementing: (a) circulating mud; (b) pumping spacer and slurry; (c) and (d) displacing; (e) end of job. o, plug-releasing pin in; o, plug releasing pin out. (Courtesy Dowell Schlumberger.)

string a n d then into the annulus between the casing and the b o r e h o l e wall (see Figure 4-389d). The spacer a n d the cement slurry displace the d r i l l i n g m u d below the f l o a t collar a n d the d r i l l i n g m u d in the annulus. T h e s p a c e r is designed to efficiently displace nearly all the drilling m u d in the annulus p r i o r to the cement slurry e n t e r i n g the annulus. W h e n the top wiper plug reaches the f l o a t collar, the p u m p pressure rises sharply again. This wiper plug does not have a d i a p h r a g m and, therefore, no f u r t h e r flow into the well can take place. At this point in the cementing operation the cement p u m p is usually shut down and the pressure released on the cementing head. T h e back-flow valve in the float collar stops the heavier cement slurry from flowing back into the inside o f the casing string (see Figure 4-389e). T h e volume of spacer and cement slurry is calculated to allow the cement slurry to either completely fill the annulus, or to fill the annulus to a height sufficient to accomplish the objectives of the" casing a n d c e m e n t i n g o p e r a t i o n . Usually a lighter drilling m u d is used to follow the heavy cement slurry. In this way the casing is u n d e r c o m p r e s s i o n from a higher differential pressure on the outside of the casing. Thus when the cement sets and drilling or p r o d u c t i o n o p e r a t i o n s continues, the casing will always have an elastic load on the cementcasing interface. This elastic l o a d is considered essential for maintenance of the cement-casing b o n d a n d to keep leakage between the cement a n d casing (i.e., the microannulus) from occurring.

1206

Drilling and Well Completions

Since the early 1960s there has been a great deal of discussion regarding the desirability of using a low viscosity cement slurry to improve the removal of drilling mud from the annulus [161,162]. More recent studies have shown that low viscosity slurries do not necessarily provide effective removal of drilling mud in the annulus. In fact, there is strong evidence that spacers and slurries should have a higher gel strength and a higher specific weight than the mud that is being displaced [169]. Also, the displacement p u m p i n g rate should be low with an annular velocity of 90 f t / m i n or less [169]. Figure 4-390 gives the annular residual drilling mud removal efficiency as a function of differential gel strength and differential specific weight between the drilling mud and the spacer. The most successful spacer is an initial portion of the cement slurry that will give about 200 ft of annulus and that has a higher gel strength and a higher specific weight than the drilling mud it is to displace. The cement slurry spacer should have a gel strength that is about 10 to 15 lb/100 ft 2 greater and a specific weight that is about 2 to 4 lb/gal greater than the drilling mud to be displaced. The spacer should be a specially treated cement slurry. It makes no sense to use a water or a drilling mud spacer. If such spacers are used, the follow-on normal cement slurry will be just as unsuccessful at removing the water or the drilling m u d of the spacer as it would at removing drilling mud if no spacer were used. The basic steps for planning the cement slurry to be used in the cementing operation are: 1. Determine the specific weight and gel strength o f drilling m u d to be displaced. 2. Estimate the approximate cementing operation time.

80

I00%

l° -2¢

,,,y-40 -I

0

1

2 SPACER - MUD

WEIGHT DIFFERENTIAL. &D. Ib/gll

Figure 4-390. Spacer gel and specific weight relationships [168].

Well C e m e n t i n g

1207

3. Select the most a p p r o p r i a t e API class of c e m e n t that meets the depth, temperature, sulfate resistance a n d other well limitations. Select the cement class that has a natural thickening time that most nearly meets the cementing o p e r a t i o n time requirement, or that will require only small amounts of r e t a r d i n g additives. 4. Do not add water loss control additives unless drilling m u d requires such additives. 5. If the major p o r t i o n of the cement slurry must have a r a t h e r low specific weight, do not use excess water to lower specific weight. Try to use only the o p t i m u m r e c o m m e n d e d water-to-cement ratio. Utilize only additives that will require little or no a d d e d water to lower the specific weight of the c e m e n t slurry. Avoid using b e n t o n i t e in large c o n c e n t r a t i o n s since it requires a g r e a t deal of a d d e d water a n d significantly reduces c e m e n t strength. Silicate f l o u r s h o u l d be u s e d w h e n e v e r p o s s i b l e to i n c r e a s e compressive strength a n d decrease p e r m e a b i l i t y of set cement. 6. Design the cement slurry a n d its initial spacer to have the a p p r o p r i a t e gel strength a n d specific weight. Have the c e m e n t i n g service c o m p a n y r u n l a b o r a t o r y tests on the cement slurry b l e n d selected. T h e s e tests should be run at the anticipated b o t t o m h o l e t e m p e r a t u r e a n d pressure. These tests should be carried out to verify thickening time, specific weight, gel strength (of spacer) a n d compressive strength. 7. T h e mixed cement slurry should be closely m o n i t o r e d with high-quality continuous specific weight m o n i t o r i n g a n d r e c o r d i n g e q u i p m e n t as the slurry is p u m p e d to the well. 8. W h e n cementing o p e r a t i o n is completed, b l e e d off internal pressure inside the casing a n d leave valve o p e n on cementing head.

Example 7 A 7-in., N-80, 29-1b/ft casing string is to be r u n in a 13,900-ft borehole. T h e casing string is to be 13,890 ft in length. Thus the guide shoe will be held about 10 ft from the b o t t o m of the hole d u r i n g cementing. T h e float collar is to be 90 ft from the b o t t o m of the casing string. T h e b o r e h o l e is cased with 9 ~-in., 32.30-1b/ft casing to 11,451 ft of depth. T h e o p e n hole below the casing shoe of the 9 ~-in. casing is 8~ in. in diameter. T h e 7-in. casing string is to be cemented to the top of the borehole. Class E cement with 20% silica flour is to be used from the bottom of the hole to a height of 1,250 ft from the bottom of the borehole. Class G cement with at least 10% silica flour is to be used from 1,250 ft from the b o t t o m to the top of the borehole. T h e drilling m u d in the b o r e h o l e has a specific weight of 12.2 l b / g a l a n d an initial gel s t r e n g t h of 15 lb/100 ft ~. A spacer sufficient to give 200 ft of length in the open-hole section will be used. A n excess factor of 1.2 will be applied to the Class G cement slurry volume. 1. 2. 3. 4.

D e t e r m i n e the specific weight a n d gel strength for the spacer. Determine the n u m b e r of cement sacks for each class of cement to be used. D e t e r m i n e the volume of water to be used. Determine the cementing o p e r a t i o n time and thus the m i n i m u m thickening time. A s s u m e a c e m e n t mixing rate of 25 s a c k s / m i n . Also a s s u m e an annular displacement rate no greater than 90 f t / m i n while the spacer is moving t h r o u g h the o p e n - h o l e section a n d a f l o w r a t e of 300 g a l / m i n thereafter. A safety factor of 1.0 hr is to be used. 5. D e t e r m i n e the pressure differential p r i o r to b u m p i n g the plug. 6. D e t e r m i n e the total m u d returns d u r i n g the cementing o p e r a t i o n .

1208

Drilling and Well C o m p l e t i o n s

The basic properties o f Class E and Class G cements are given in Table 4-154 a n d 4-155. 1. T h e drilling m u d has a specific weight o f 12.2 l b / g a l and an initial gel strength o f 15 l b / 1 0 0 ftL Thus from Figure 4-390 it will be desirable to have a cement slurry spacer with a specific weight o f at least 15.2 l b / g a l a n d an initial gel strength o f about 20 l b / 1 0 0 ftL T h e spacer will be designed with Class G cement. Taking the a p p r o p r i a t e data from Tables 4-159 a n d 4-160, the weight o f silica f l o u r to be used is 0.10(94) = 9.4 l b / s a c k Equation 4-324 b e c o m e s

=

94+9.4+8.34[4.97+0.0456(9.4)] = 16.4 Ib/gal 94 9.4 + + 4.97 + 0.0456(9.4) 3.14(8.34) 2.63(5.34)

Thus the spacer will be d e s i g n e d to have a specific weight o f 16.4 l b / g a l and sufficient fragile gel additive to have an initial gel strength o f about 20 lb/100 ftL 2. T h e spacer must have a volume sufficient to give 200 ft o f length in the open-hole section. T h e annular capacity o f the o p e n hole is

- F(857 _ (7 4 L \ 12 )

] 0 _-

~ 12 ) J

Equation 4-326 gives the yield o f the spacer as Yield = 3.59 + 0. 4286+ 4.97 + 0. 4286 = 1. 21ftS/sack 7.48 Thus the n u m b e r o f sacks to give that will b e 200 ft in length in the open-hole section is Sacks = 0.1268(200) = 20.96 1.21 T h e above is r o u n d e d off to the next highest sack, or 21 sacks. T h e volume o f Class G c e m e n t is the sum o f the spacer volume, a n n u l a r volume in the cased p o r t i o n o f the b o r e h o l e a n d the applicable annular volume in the open-hole section o f the borehole. T h e annular capacity o f the cased p o r t i o n o f the b o r e h o l e is

=0,740 ,..t T h u s the v o l u m e o f Class G c e m e n t s l u r r y to b e u s e d to c e m e n t the well (excluding spacer, b u t considering the excess factor) is

Well C e m e n t i n g V o l u m e = [(2,449 - 1,250) (0.1268) + 11,451(0.1746)]

1209

1.2 = 2,581.66 ft ~

T h e total n u m b e r of Class G sacks of cement needed, including the spacer volume, is

Total sacks = 2,581.66 +21 = 2 , 1 3 4 + 2 1 = 2,155 1.21 T h e v o l u m e o f Class E c e m e n t is

Volume =

8.5

10) +

n

6.184

90 + (1,250 - 10)(0.1268)

= 3 . 9 4 + 18.77 + 157.23 = 179.94 ft 3 T h e specific weight of the Class E c e m e n t is d e t e r m i n e d f r o m E q u a t i o n 4-324. T h e weight o f silica f l o u r to b e a d d e d is 0.20(94) = 18.8 lb E q u a t i o n 4-324 is

=

94 + 18.8 + 8 . 3 4 [ 4 . 2 9 + 0.0456(18.8)] = 16.21b/gal 94 18.8 + + 4 . 2 9 + 0.0456(18.8) 3.14(8.34) 2.63(8.34)

E q u a t i o n 4-326 is Yield = 3 . 5 9 + 0 . 8 5 7 1 + 4 . 2 9 + 0.8573 = 1.28 ft3/sack 7.48 T h e total n u m b e r o f Class E sacks o f c e m e n t n e e d e d are 179.94 Totalsacks = ~ = 1.28

141

3. T h e v o l u m e o f w a t e r to b e u s e d in t h e c e m e n t i n g o p e r a t i o n is V o l u m e = 2,155(4.97 + 0.4286) + 141(4.29 + 0.8573) ~- 11,634 + 726 ~- 12,360 gal o r a b o u t 295 bbl 4. T h e total c e m e n t i n g o p e r a t i o n t i m e is s o m e w h a t c o m p l i c a t e d since it is d e s i r e d to r e d u c e t h e r a t e o f f l o w w h e n t h e s p a c e r passes t h r o u g h t h e o p e n h o l e s e c t i o n o f t h e well. T h e m i x i n g t i m e is

1210

Drilling and Well Completions

Tm-

2,155 + 141 - 1.53 hr 25(60)

During this time the volume of cement slurry p u m p e d to the casing string is Volume p u m p e d = 2,155(1.21) + 141(1.28) -- 2,788.1 ft ~ The internal volume of the casing string above the float collar is Internal volume = 13,800(0.2086) = 2,878.7 ft 3 Therefore, the m u d pumps are used to fill the r e m a i n d e r of the casing string at a rate of 300 g a l / m i n . Thus, the additional time T 1 to get the bottom plug to the float collar is 2,878.7 - 2,788.1 = 0.04 hr

T h e time to release the plug is Tp = 15/60 = 0.25 hr From the time the plug is released the p u m p i n g rate is reduced to 85.4 g a l / min, which gives a velocity of 90 f t / m i n in the openhole section of the annulus. T h e time for the spacer to pass through the open-hole section T 2 (including the 90 ft of internal volume of the casing below the float collar a n d the 10 ft of o p e n hole below the casing string guide shoe) is T2 = 3.94 + 18.77 + (2,449 - 10)(0.1268) = 0.49 hr 85.4 (60)

After this time period, the rate of p u m p i n g to the well can be r e t u r n e d to 300 g a l / m i n rate. Equation 4-327 becomes T 0=1.53+0.04+0.25+0.49+2'878"7-91-332+1.0=4.33hr

Therefore, the thickening time for the cement slurries to be used must be greater than 4.33 hr.

Well C e m e n t i n g

1211

5. T h e pressure differential p r i o r to the top plug reaching the f l o a t collar is p = 122.7 (13,900 - 1,250) + 121.2 (1,250 - 90 - 10) - ~ ( 1 3 , 9 0 0 - 9O 144144 144

10)

= 2997 psi 6. T h e total volume of the m u d returns will be Mud volume = Total volume well without steel - Steel volume =

(9. 001) 3 ( 1 1 , 4 5 1 ) - 24~00 (13,890) --(8"5)2 ( 1 3 , 9 0 0 - 1 1 , 4 5 1 ) + 4 12 4 12

= 5,203 ft ~ or about 927 bbl

Large-Diameter Casing Cementing Often when large-diameter casing strings are to be cemented, an alternate m e t h o d to c e m e n t i n g t h r o u g h inside d i a m e t e r of the casing is used. This alternative m e t h o d requires that the i n n e r string of d r i l l p i p e be placed inside the large-diameter casing string. T h e d r i l l p i p e string is centralized within the casing and a special stab-in unit is m a d e up to the b o t t o m of the drillpipe string. A f t e r the d r i l l p i p e string is r u n into the well t h r o u g h the casing, the special unit on the b o t t o m of the d r i l l p i p e string is s t a b b e d into the stab-in c e m e n t i n g collar located a j o i n t or two above the casing string g u i d e shoe, or the unit is s t a b b e d into a stab-in c e m e n t i n g shoe (a c o m b i n a t i o n of the stab-in c e m e n t i n g collar and the guide shoe). Figure 4-391 shows the schematic of a large-diameter casing with the i n n e r d r i l l p i p e string u s e d for c e m e n t i n g [163]. Figure 4-392 shows the stab-in c e m e n t i n g shoe a n d a stab-in c e m e n t i n g collar. Also shown is a flexible latch-in plug used to follow the cement slurry. Once the stab-in unit of the drillpipe string is seated in the stab-in cementing shoe or cementing collar, a special circulating head is m a d e up to the top of the drillstring. Circulation is established t h r o u g h the circulating head to the d r i l l p i p e a n d up the annular space between the casing and the b o r e h o l e wall. T h e stab-in unit may be locked into the c e m e n t i n g collar. T h e collar will act as a back-flow valve [162]. A f t e r the cement slurry has b e e n run, the d r i l l p i p e string can be u n l o c k e d a n d withdrawn from the casing. T h e advantages of c e m e n t i n g large d i a m e t e r casing using an i n n e r d r i l l p i p e string are" • avoids excessive m u d contaminations of the cement slurry with drilling m u d p r i o r to reaching the annulus; • allows cement slurry to be a d d e d if wash out zones are excessive (avoids top-up job). W h e n c e m e n t i n g l a r g e - d i a m e t e r casing loss of circulation can occur. T h e solution to such p r o b l e m s is to r e c e m e n t d o w n the annulus. This t e c h n i q u e o f c e m e n t i n g is d e n o t e d as a t o p - u p j o b . This t y p e of c e m e n t i n g can b e a c c o m p l i s h e d by r u n n i n g s m a l l - d i a m e t e r t u b i n g c a l l e d " s p a g h e t t i " into the annulus space from the surface. U n d e r these c o n d i t i o n s usually low-specificweight cement is used so that the formations will not fracture.

1212

Drilling and Well Completions

~ "]

i~clCirculating !~ _ _ -

5i. DP

ill

Floatshoe

Shoe2-Sft off boffom

TD

Figure4-391. Cementing of large-diameter casing with and inner drillpipe string. (Courtesy Dowell Schlumberger.) The hook load after a cementing operation (but prior to the cement setting) is important to know, particularly when large-diameter casings are to be cemented. Figure 4-393 shows the schematic of a casing string with the cement slurry height shown. Prior to the cement slurry setting the hook load V h (Ib) will be

L~,) l

~

-7

-A~[(~c-~m)h]

where w c = unit weight of the casing in Ib/ft Yc = specific weight o f the cement slurry in Ib/ft 3 Ym = specific weight o f the drilling mud in Ib/ft 3

(4-331)

Well C e m e n t i n g

1213

i

STA,~

Figure 4-392. Stab-in unit, stab-in cementing shoe, stab-in cementing collar and flexible latch-in plug [161].

Ts = 1= h = A~ =

specific weight o f the steel, which is 490 l b / f t s length o f the casing in ft height the cement slurry is placed in the annular in ft internal cross-sectional d i a m e t e r o f the casing in ft 2

Equation 4-331 is valid for a back-flow valve at the b o t t o m o f the casing string such as a float collar. It is also valid for a back-flow valve located at the top o f the casing string.

Example 8 A large-diameter casing is to b e c e m e n t e d to the top in a 2,021-ft borehole. T h e casing string is 2,000 ft long a n d has ball float shoe at the b o t t o m o f the cement slurry. T h e b o r e h o l e is 26 in. in diameter. T h e casing is to be 20 in., J-55, 94 l b / f t . T h e d r i l l i n g m u d in the b o r e h o l e p r i o r to r u n n i n g the casing has a specific weight o f 10.0 I b / g a l . T h e cement slurry is to have a specific weight o f 17.0 I b / g a l . T h e conventional c e m e n t i n g o p e r a t i o n will be utilized, i.e., c e m e n t i n g t h r o u g h the inside o f the casing. D e t e r m i n e the hook load after the cementing o p e r a t i o n has b e e n completed.

1214

Drilling and Well Completions

7

T 5_ h

Figure 4-393. Schematic of casing after a cementing operation. The hook load may be determined from Equation 4-331. This is { + [ ( 127.3 )2,000 V = 94.00 1

(75.0) 0 ]12 000 Lt49--k-~.00)2,--b-~+t4-6b-~.0)2,--~]j ,

~~ (19" ~ 124)2-'127 It •3 -75.0)2,000] = -69,557 lb This answer means that the casing and its contained drilling mud will float when the cementing operation is completed and the back-flow valve is actuated. Thus the casing should be secured down at the well head prior to initiating the cementing operation.

Well Cementing

1215

It should be noted that if this cementing operation were to be carried out using an inner drillpipe string to place the cement in the annulus, the above force of buoyancy would be reduced by the buoyed weight of the drillpipe. However, unless very heavy drillpipe were used, the casing and drillpipe would still float on the cement slurry. As the cement Slurry sets the hook load will decrease from its value just after the cementing operation. If the cement slurry sets up to the height (freeze point) indicated in Figure 4-392, and if the casing has been landed as cemented, then the hook load V h will be approximately

(4-332)

Example 9 A 5 ~-in., J-55, 17.00-1b/ft casing string 16,100 ft in length is to be run into a 16,115-ft deep well. The float collar is 30 ft from the bottom of the casing string. The drilling mud in the well has a specific weight of 12.0 lb/gal. The casing string is to be cemented to a height of 4,355 ft above the bottom of the borehole with a cement slurry having a specific weight o f 16.4 lb/gal. 1. Determine the approximate hook load prior to the cementing operation. 2. Determine the approximate hook load just after the cement slurry has been run. 3. Determine the approximate hook load after the cement has set. 1. The hook load prior to the cementing operation should read approximately

Vh = 17.00(1 -- 4890.90)16,100 = 223,540 lb 2. The hook load just after the cementing operation can be approximated by Equation 4-331. This is

V, = 1 7 . 0 0 1

Lk 4 9 0 " 0 ) 1 6 , 1 0 0

k.490.0)~

16,100

7t ( "~4.892 2r.122 = 199,943 lb 3. The hook load after the cement has set can be approximated by Equation 4-332. This is

vh 1700/1 490 8°80 ) 16100 4 340 -163 282,b

1216

Drilling and Well C o m p l e t i o n s

Multistage Casing Cementing Multistage casing cementing is used to cement long casing strings. The reasons that multistage cementing techniques are necessary are as follows: • • • • •

reduce the p u m p i n g pressure o f the cement p u m p i n g equipment; reduce the hydrostatic pressure on weak formations to prevent fracture; selected formations can be cemented; entire length o f a long casing string may be cemented; casing shoe o f the previous casing string may be effectively c e m e n t e d to the new casing string; • reduces cement contamination. T h e r e are m e t h o d s for c a r r y i n g out multistage cementing. These are 1. regular two-stage cementing 2. continuous two-stage cementing 3. regular three-stage cementing

Regular two-stage cementing requires the use o f stage cementing collar and plugs in a d d i t i o n to the conventional casing cementing equipment. T h e stage cementing collar is placed in the casing string at near the mid point, or at a position in the casing string where the u p p e r cementing o f the casing is to take place. Figure 4-394 shows a schematic o f a regular two-stage casing cementing o p e r a t i o n . T h e stage c e m e n t i n g collar is a special collar with p o r t s to the annulus that can be o p e n e d and closed (sealed off) by pressure o p e r a t e d sleeves (see Figure 4-394). T h e first stage o f cementing (the lower section o f the annulus) is c a r r i e d out similar to a conventional single-stage casing cementing operation. T h e exception is that a wiper plug is generally not run in the casing p r i o r to the spacer and the cement slurry.* During the p u m p i n g o f the spacer and cement slurry for the lower section o f the annulus, the p o r t s on the stage cementing collar are closed. A f t e r the a p p r o p r i a t e volume o f spacer and c e m e n t slurry has b e e n p u m p e d to the well (lower section) the first stage plug is released. This plug is p u m p e d to its position on the float collar at the b o t t o m o f the casing string with drilling m u d or c o m p l e t i o n fluid as the disl~iacement fluid. This first plug is designed to pass through the stage cementing collar without actuating it. W h e n the first plug is l a n d e d on the float collar, there is a pressure rise at the pump. This plug seals the float collar such that further flow t h r o u g h o u t the collar cannot take place. A f t e r the first-stage cementing o p e r a t i o n has been c a r r i e d out the o p e n i n g b o m b can be d r o p p e d and allowed to fall by gravity to the lower seal o f the stage c e m e n t i n g collar. This can be d o n e i m m e d i a t e l y after the first-stage cementing has taken place, or at some later time when the cement slurry in the lower section o f the well has had time to set. In the later case great care must be taken that the first-stage cement slurry has not risen in the annulus to a height above the stage cementing collar. O n c e the o p e n i n g b o m b is seated, p u m p pressure is a p p l i e d that allows hydraulic force to be a p p l i e d to the lower sleeve o f the stage cementing collar. This force shears the lower sleeve retaining pins and exposes the ports to the annulus.

*A wiper plug may be accommodated with special equipment [161].

Well Cementing

1217

t i iI

Figure 4-394. Regular two-stage cementing [161]. Once the ports are opened the well is circulated until the appropriate drilling mud or other fluid is in the well. The second-stage cementing slurry is mixed and pumped to the well (again without a wiper plug separating the spacer from the drilling mud). This cement slurry passes through the stage cementing float ports to the upper section of the annulus. The closing plug is released at the end of the second-stage cement slurry and is displaced to the stage cementing collar with drilling mud or other fluid. The closing plug seats on the upper

1218

Drilling a n d Well C o m p l e t i o n s

sleeve o f the stage cementing collar. A pressure o f about 1,500 psi causes the retaining pins in the u p p e r sleeve to shear thus forcing the sleeve downward to close the p o r t s in the stage c e m e n t i n g collar. Continuous two-stage cementing is an o p e r a t i o n that requires that the cement slurry be mixed a n d displaced to the lower a n d u p p e r sections o f the annulus in sequence without stopping to wait for an o p e n i n g b o m b to actuate the stage c e m e n t i n g collar. In this o p e r a t i o n the first-stage cement slurry is p u m p e d to the well a n d a wiper plug released b e h i n d it (see Figure 4-395). Displacing the wiper plug is a volume o f drilling m u d or c o m p l e t i o n f l u i d that will displace the cement slurry out o f the casing a n d fill the inside o f the casing string from the f l o a t collar at the b o t t o m o f the casing string to a height o f the stage c e m e n t i n g collar. A bypass insert allows f l u i d to pass t h r o u g h the wiper plug a n d f l o a t c o l l a r a f t e r t h e p l u g is l a n d e d . T h e o p e n i n g p l u g is p u m p e d immediately behind the volume of drilling mud. Immediately behind the o p e n i n g plug is the second-stage spacer a n d cement slurry. T h e o p e n i n g plug sits on the lower sleeve o f the stage cementing collar, o p e n i n g the ports to the annulus. At the e n d o f the second-stage cement slurry the closing plug is run. This plug sits on the u p p e r sleeve o f t h e stage c e m e n t i n g c o l l a r a n d with h y d r a u l i c pressure, closing the ports in the stage c e m e n t i n g collar. Three-stage cementing is c a r r i e d out using the same p r o c e d u r e as the regular two-stage cementing o p e r a t i o n discussed above. In this case, however, two-stage cementing collars are placed at a p p r o p r i a t e locations in the casing string above the f l o a t collar. Each stage o f cementing is c a r r i e d out in sequence, the lower annulus section c e m e n t e d first, the middle annulus section next a n d the top annulus section last. Each stage o f c e m e n t can be allowed to set, but great care must be taken in not allowing the lower stage o f cement to rise above the stage cementing collar o f the next stage above.

Liner Cementing A liner is a short string o f casing that does not reach the surface. T h e liner is hung from the b o t t o m o f the previous casing string using a line hanger that grips the b o t t o m o f the previous casing with a set o f slips. Figure 4-396 shows typical liner types. T h e liner is r u n into the b o r e h o l e on the d r i l l p i p e a n d the cementing o p e r a t i o n for the liner is carried out through the same drillpipe. T h e placing o f liners a n d their c e m e n t i n g o p e r a t i o n s are some o f the most difficult o p e r a t i o n s in well d r i l l i n g a n d c o m p l e t i o n s . G r e a t care m u s t be taken in designing a n d p l a n n i n g these o p e r a t i o n s to ensure a seal between the liner a n d the previous casing. Figure 4-397 shows a typical liner assembly. T h e liner assembly is m a d e up with the following c o m p o n e n t s :

Float shoe. T h e f l o a t shoe may be p l a c e d at the b o t t o m o f the liner. This c o m p o n e n t is a c o m b i n a t i o n o f a guide shoe a n d a f l o a t collar.

Landing collar. This is a short sub placed in the string to p r o v i d e a seat for the casing string.

Liner. This is a string o f casing used to case off the o p e n hole without b r i n g i n g the e n d o f the string to the surface. Usually the liner overlaps the previous casing string (shoe) by about 200 to 500 ft. Liner hanger. This special tool is installed on the top o f the liner string. T h e top o f the liner hanger makes up to the d r i l l p i p e on which the entire liner assembly is lowered into the well. Liner hangers can be either mechanically or hydraulically actuated.

Well Cementing

1219

Figure 4-395. Continuous two-stage cementing [161].

The liner hanger is the key element in the running of liners and the followon cementing operations. The liner hanger allows the liner to be hung from the bottom section of the previous casing. After the cementing operation the upper part of the liner hanger is retrievable, thus allowing the residual cement above the liner hanger to be cleaned out of the annulus between the drillpipe and the previous casing (by reverse circulation) and the liner left in the well.

1220

Drilling a n d Well C o m p l e t i o n s

LINER TYPES

K CASING

IEDIATE CASING

:ILLING LINER !-BACK STUB LINER

N LINER

Figure 4-396, Liner types [161]. T h e casing j o i n t s o f the liner are placed in the well in the n o r m a l manner. T h e liner hanger is m a d e up to the top of the liner. T h e top o f the liner hanger is m a d e up to d r i l l p i p e a n d the whole assembly (i.e. liner, liner hanger and drillpipe) is lowered into the well. A f t e r the liner is at the desirable location in the well, the drillpipe is connected to the rig p u m p s and m u d circulation carried out. This allows c o n d i t i o n i n g o f the d r i l l i n g m u d in the well p r i o r to the cementing o p e r a t i o n and ensures that circulation is possible before the liner is hung a n d cemented. The liner hanger is set (either mechanically or hydraulically) and the drillpipe with the u p p e r part o f the liner hanger (the setting tool) released. T h e d r i l l p i p e a n d the setting tool are r a i s e d to make sure t h a t the setting tool a n d the d r i l l p i p e can be released from the lower p a r t o f the liner hanger a n d the liner. The drillpipe and the setting tool are lowered to make a tight seal with the lower p o r t i o n o f the liner hanger. After these tests of the equipment have been made, a liner cementing head is m a d e up to the d r i l l p i p e at the surface. Figure 4-398 shows the liner cementing h e a d a n d the p u m p - d o w n plug. T h e p u m p - d o w n plug is p l a c e d in the l i n e r

Well Cementing

ING B,R

Figure 4-397. Liner assembly [161],

1221

1222

Drilling and Well C o m p l e t i o n s

~-~ CEMENTMANIFOLD,

Figure4-398. Liner cementing

head [161].

c e m e n t i n g head, but not released. The cement p u m p is c o n n e c t e d to the liner cementing head and the spacer and cement slurry p u m p e d to the head (no wiper plug is r u n ahead o f the spacer). The p u m p - d o w n plug is released at the e n d o f the cement slurry and separates the slurry from the follow-on drilling mud. Figure 4-399 shows the sequence o f the liner cementing o p e r a t i o n . T h e drilling m u d displaces the pump-down plug to the liner hanger. As the pump-down plug passes through the liner hanger it latches into the liner wiper plug (see Figure 4-397). With increased surface pressure (1200 psi) by the p u m p the liner wiper plug with the p u m p - d o w n plug coupled to it are released from the liner hanger and begin to move again downward. These two coupled plugs eventually seat on the landing collar o r on the float collar. A n o t h e r pressure rise indicates the cement is in place b e h i n d the liner. Once the spacer and the cement slurry have b e e n successfully p u m p e d to their location in the well, the drillpipe and setting tool are released from the lower part o f the liner hanger. Also, the liner c e m e n t i n g h e a d is removed from the drillpipe. T h e drillpipe and setting tool are raised slightly and the excess cement slurry reverse circulated from a r o u n d the liner hanger area. These steps should be taken immediately after the completion o f the cementing operation, otherwise the excess cement slurry between the drillpipe and the previous casing could set and cause later drilling and completions p r o b l e m s if the excess cement is too great. If reverse circulation is not planned, then the excess cement slurry that comes through the liner hanger to the annulus between the d r i l l p i p e and the previous casing must be kept to a m i n i m u m so that it can be easily drilled out after it sets.

Well C e m e n t i n g M~×~NG

DtSPLAC~NG

D~SPLAC~NG

E~o OFJOB

1223

R~VE~S~NG

Figure 4-399. Liner cementing [161]. T h e d e t e r m i n a t i o n o f the excess cement slurry should be carefully calculated: too little and the c e m e n t seal at the liner hanger is c o n t a m i n a t e d with drilling mud; too much and there are problems r e m o v i n g it.

Secondary Cementing S e c o n d a r y or r e m e d i a l c e m e n t i n g refers to c e m e n t i n g o p e r a t i o n s that are i n t e n d e d to use c e m e n t as a means o f m a i n t a i n i n g or i m p r o v i n g the well's

1224

Drilling and Well Completions

operation. There are two general secondary cementing operations, squeeze cementing and plug cementing.

Squeeze Cementing Squeeze cementing operations utilize the mechanical power of the cement pumps to force a cement slurry into the annular space behind a casing a n d / o r into a formation for the following purposes: • repair a faulty primary cementing operation; • stop loss of circulation in the open hole during drilling operations; • reduce water-oil, water-gas and gas-oil ratios by selectively sealing certain fluid producing formations; • seal abandoned or depleted formations; • repair casing leaks such as joint leaks, split casing, parted casing or corroded casing; • isolate a production zone by sealing off adjacent nonproductive zones. There are numerous squeeze cementing placement methods that utilize many different special downhole tools. In general, the squeeze cementing operation forces the cement slurry into fractures under high pressure, or into casing perforations using low pressure. As a cement slurry is forced into rock fractures, or through casing perforations into the rock formations, the slurry loses part of its mix water. This leaves a filter cake of cement particles at the interface of the fluid and the permeable rock. As the filter cake builds up during the squeeze cementing operation, more channels into the formation are sealed and the pressure increases. If the cement slurry is poorly designed for an intended squeeze cementing operation, the filter cake builds up too fast and the cement pump capability is reached before the cement slurry has penetrated sufficiently to accomplish its purpose. Thus the squeeze cementing operation slurry should be designed to match the characteristics of the rock formation to be squeeze cemented and the equipment to be used. There are five important considerations regarding the cement slurry design for a squeeze cementing operation:

1. Fluid loss control. The slurry should be designed to match the formation

2.

3.

4. 5.

to be squeezed. Low permeability formations should utilize slurries with 100-200 ml/30 min water losses. High permeability formations should utilize slurries with 50-100 ml/30 min water losses. Slurry volume. The cement slurry volume should be estimated prior to the squeeze operation. In general, high-pressure squeeze operations of highpermeability formations that have relatively low fracture strengths will require large volumes of slurry. Low-pressure squeeze operation through perforations will require low volumes. Thickening time. High-pressure squeeze operations that pump large volumes in a rather short time period usually require accelerator additives. Lowpressure slow-pumping-rate squeeze operations usually require retarder additives. Dispersion. Thick slurries will not flow well in narrow channels. Squeeze cement slurries should be designed to be thin and have low yield points. Dispersive agents should be added to these slurries. Compressive strength. High compressive strength is not a necessary characteristic of squeeze cement slurries.

Well C e m e n t i n g

1225

T h e r e are basically two squeeze cementing techniques used: the high-pressure squeeze o p e r a t i o n and the low-pressure squeeze o p e r a t i o n . High-pressure squeeze cementing o p e r a t i o n s are utilized where the hydraulic pressure is used to make new channels in the rock formations (by fracturing the rock) and force the cement slurry into these channels. Low-pressure squeeze cementing o p e r a t i o n s are utilized where the existing permeability structure is sufficient to allow the cement slurry to efficiently move in f o r m a t i o n without making new fracture surfaces with the hydraulic pressure. Hesitation m e t h o d of applying pressure is applicable to both high and lowpressure squeeze cementing o p e r a t i o n s . This m e t h o d of applying pressure (and thus volume) appears to be more effective than continuous pressure application. The hesitation m e t h o d is the intermittent application of pressure, s e p a r a t e d by a p e r i o d of pressure leakoff caused by the loss of filtrate into the formation. The leakoff p e r i o d s are short at the b e g i n n i n g of an o p e r a t i o n but get l o n g e r as the o p e r a t i o n progresses. Figure 4-400 shows a typical squeeze cementing downhole schematic where a retrievable packer is used. T h e cement slurry is spotted adjacent to the perforations in the casing. The packer raise and set against the casing wall. Pressure is then a p p l i e d to the drilling m u d and cement slurry below the packer forcing the cement slurry into the p e r f o r a t i o n s and into the rock f o r m a t i o n or voids in the annulus b e h i n d the casing. Figure 4-401 shows how a retrievable packer with a tail pipe can be used to precisely spot the cement slurry at the location of the perforations. Figure 4-402 shows how a drillable cement retainer can be used to ensure that the cement slurry will be a p p l i e d directly to the perforations. Most squeeze c e m e n t i n g o p e r a t i o n s take place in cased sections of a well. However, open-hole packers can be used to carry out squeeze cement operations of thief zones d u r i n g drilling operations. A n o t h e r technique for c a r r y i n g out a squeeze cementing o p e r a t i o n is the B r a d e n h e a d technique. This technique can b e used to squeeze a cement slurry

Figure 4-400. Retrievable packer near perforations [161].

1226

Drilling and Well Completions

N N PACK~A ASOV~T ~ CEM~T

Figure 4-401. Retrievable packer with tail pipe [161].

Figure 4-402. Drillable cement retainer [161].

in a cased hole or in an o p e n hole. Figure 4-403 shows a schematic of the technique. Instead of using a downhole packer, the cement slurry is spotted by drillpipe (or tubing) adjacent to the perforations or a thief zone. After the drillpipe has been raised, the pipe rams are closed over the drillpipe and pump pressure applied to the drilling m u d which in turn forces the cement slurry into the perforations or fractures.

Well C e m e n t i n g

1227

Figure 4-403. Bradenhead squeeze [161].

T h e basic squeeze c e m e n t i n g o p e r a t i o n p r o c e d u r e s are as follows [161]: 1. Lower zones are isolated by a retrievable or drillable b r i d g e plug. 2. Perforations are washed using a p e r f o r a t i o n wash tool or they are r e o p e n e d by surging. If there is no d a n g e r of d a m a g i n g the lower p e r f o r a t i o n s , this o p e r a t i o n can be c a r r i e d out before r u n n i n g the b r i d g e plug, which may be run in one trip with the packer. 3. T h e p e r f o r a t i o n wash tool is retrieved and the packer run in the hole with a work string, set at the d e s i r e d d e p t h a n d tested. A n annular pressure test of 1,000 psi is usually sufficient. T h e packer is r u n with or without a tail pipe, d e p e n d i n g on the o p e r a t i o n to be p e r f o r m e d . If cement is to be spotted in front of the p e r f o r a t i o n s , a tail p i p e that covers the length of the zone plus 10 to 15 ft must be run with the packer. 4. A n injectivity test is p e r f o r m e d using clean, solids-free water or brine. If a low f l u i d loss c o m p l e t i o n f l u i d is in the hole, it must be displaced from the p e r f o r a t i o n s before starting the injecting. This test will give an i d e a of the p e r m e a b i l i t y of the f o r m a t i o n to the cement filtrate. 5. A spearhead or breakdown fluid followed by the cement slurry is circulated downhole with the packer by-pass open. This is done to avoid the squeezing of d a m a g i n g fluids a h e a d of the slurry. A small a m o u n t of back pressure must be a p p l i e d on the annulus to prevent the slurry fall caused by U tubing. If no tail p i p e has b e e n run, the packer by-pass must be closed 2 or 3 bbl before the slurry reaches the packer. If the cement is to be spotted in front of the p e r f o r a t i o n s , with the packer unset, circulation is s t o p p e d as soon as the cement covers the d e s i r e d zone, the tail p i p e p u l l e d out of the cement slurry and the packer set at the desired depth. T h e d e p t h at which the packer is set must be carefully decided. If tail p i p e is run, the m i n i m u m d i s t a n c e b e t w e e n p e r f o r a t i o n s a n d packer is limited to the length of the tail pipe. T h e packer must not be set too close to the p e r f o r a t i o n s as pressure c o m m u n i c a t i o n t h r o u g h the

1228

6.

7.

8.

9.

Drilling a n d Well C o m p l e t i o n s annulus above the packer might cause the casing to collapse. A safe setting d e p t h must be d e c i d e d on after seeing the logged quality o f the cement b o n d . Casing c o n d i t i o n s a n d possible c e m e n t c o n t a m i n a t i o n limit the m a x i m u m spacing between packer a n d treated zone. Squeeze pressure is a p p l i e d at the surface. If high-pressure squeezing is practiced, the f o r m a t i o n is b r o k e n down a n d the cement slurry p u m p e d into the fractures before the hesitation technique is applied. If low-pressure squeezing is desired, hesitation is started as soon as the packer is set. Hesitation continues until no pressure leak-off is observed. A further test o f about 500 psi over the final injection pressure will indicate the end o f the injection process. Usually, well-cementing p e r f o r a t i o n s will t o l e r a t e pressures above the f o r m a t i o n fracture pressure, but the risk o f fracturing is increased. Pressure is released a n d returns are checked. If no returns are noticed, the packer by-pass is o p e n e d a n d excess cement reversed out. Washing o f f cement in front o f p e r f o r a t i o n s can be p e r f o r m e d by releasing the packer a n d slowly lowering the work string d u r i n g the reversing. Tools are p u l l e d out a n d the cement is left to cure for the r e c o m m e n d e d time, usually 4 to 6 hr.

Plug Cementing The major reasons for plug cementing are:

Abandonment. State regulations have rules on plugging a n d a b a n d o n i n g wells. C e m e n t plugs are normally used for that p u r p o s e (see Figure 4-404).

Kick-off plug. Usually an Ottawa sand-cement plug is used to plug off a section o f the borehole. This plug uses a hard surface to assist the kick-off p r o c e d u r e (see Figure 4-405). Lost circulation. A cement plug can be placed adjacent to a zone o f lost circulation in the hope that the cement slurry will penetrate a n d seal fractures (see Figure 4-406). Openhole completions. Often in o p e n h o l e c o m p l e t i o n s it is necessary to shut off water flows, o r to provide an a n c h o r for testing tools, o r o t h e r maintenance o p e r a t i o n s (Figure 4-407). T h e r e are t h r e e m e t h o d s for placing cement plugs.

1. Balance plug method is the most commonly used. The cement slurry is placed at the desired d e p t h t h r o u g h the d r i l l p i p e or tubing run to that depth. A spacer is placed below a n d above the slurry plug to avoid c o n t a m i n a t i o n o f t h e c e m e n t s l u r r y with s u r r o u n d i n g d r i l l i n g m u d a n d to assist in balancing the plug. 2. Dump bailing method utilizes a bailing device that contains a measure volume o f cement slurry. The bailer is r u n to the a p p r o p r i a t e d e p t h on a wireline and releases its load u p o n b u m p i n g the bottom o r a p e r m a n e n t bridge plug set at the desired d e p t h (see Figure 4-408). 3. Two-plug method is a r a t h e r new m e t h o d a n d requires the use o f the telltale catcher sub (Dowell Schlumberger) to set a cement plug in a well at a r a t h e r precise location with m i n i m u m contamination. The tell-tale catcher sub is m a d e up to the lower e n d o f a d r i l l p i p e string. T h e sub also has an a l u m i n u m tail pipe, a b o t t o m wiper plug (which carries a dart) a n d a top wiper plug. The sub on the d r i l l p i p e is lowered to the d e p t h desired for

Well C e m e n t i n g

1229

PLUG

PLUG

Figure 4-404. Abandonment plugs [161]. the location of the plug a n d similar to a p r i m a r y cementing operation, the b o t t o m plug (with dart) is run ahead of the cement slurry. W h e n the plug reaches the sub, i n c r e a s e d p u m p pressure s e p a r a t e s the d a r t f r o m the bottom plug. T h e dart continues through the tail pipe as a wiper plug. T h e top plug is p u m p e d b e h i n d the cement slurry. W h e n the top plug reaches the sub there is a n o t h e r increase in pressure. T h e cement slurry in the sub can be reverse-circulated from the sub.

1230

Drilling and Well C o m p l e t i o n s

PLUG

Figure 4-405. Kickoff plug [161]. C e m e n t plugs fail for the following reasons: • • • •

lack o f hardness (kick-off plug) c o n t a m i n a t e d cement slurry placed at wrong d e p t h plug migrates from intended d e p t h location due to lack of balancing control

W h e n placing a plug in well the fluid column in the tubing or d r i l l p i p e must balance the fluid column in the annulus. If the fluid in the drillpipe is heaviest, then the f l u i d from the d r i l l p i p e (the slurry) will continue down and out the e n d of the d r i l l p i p e a n d then up into the annulus after p u m p i n g has stopped. If the fluid in the annulus is heaviest, then the f l u i d from the d r i l l p i p e will

Well Cementing

Figure 4-406. Lost circulation plug [161].

--

TEST STR~NG

i~ ~.............

Figure 4-407. Openhole completions plug [161].

1231

1232

Drilling and Well C o m p l e t i o n s

R¥

~E

Figure 4-408. Dump bailer [161]. continue downward in the annulus after pumping. The two columns are balanced by using a spacer (or wash) above and below the cement slurry. Since the cement slurry usually has a higher specific weight than the annular fluid, the spacers are normally water.

Example 10 Balance a 100-sack cement plug of Class C neat cement slurry when 15 bbl of water are to be run ahead o f the slurry. T h e plug is to be run t h r o u g h 2-in., 4.716-1b/ft, EUE tubing. T h e d e p t h of placement is 4,000 ft. 1. D e t e r m i n e 2. D e t e r m i n e the 15 bbl 3. D e t e r m i n e

the top of the plug. the volume of water to run b e h i n d cement slurry to balance of water run ahead of the slurry. the volume of m u d to p u m p to balance plug.

The annular volume p e r ft is 0.1997 ft3/ft. The tubing volume p e r ft is 0.0217 ft3/ft). The yield of a Class C neat cement slurry is 1.32 ft3/sack (see Table 4-155). Thus the volume of the cement slurry is

Tubing and Tubing String Design

1233

Volume = 1.32(100) = 132 ft s 1. The height H (ft) of the plug is H =

132 = 742ft 0.1997- 0.0217

Depth to top of plug D (ft) is D = 4,000 - 742 = 3,258 ft. 2. The amount of water to place behind the plug to balance the 15 bbl ahead of the cement slurry is = 1.6bbl Volume= 15(0"0217~ t ~ ) 3. The height h (ft) of trailing water in the tubing is h =

1.6(42) = 414ft (0.0217)(7.48)

The volume of mud to pump to balance plug is Volume = [4,000

-

(742+

'~l'~)J ~0.0217 - ~ = . . . . .

llbbl

TUBING AND TUBING STRING DESIGN Tubing string is installed in the hole to protect the casing from erosion and corrosion and to provide control for production. The proper selection of tubing size, steel grade, unit weight and type of connections is of critical importance in a well completion program. Tubing must be designed against failure from tensile/compressive forces, internal and external pressures and buckling. Tubing is classified according to the outside diameter, the steel grade, unit weight (well thickness), length and type of joints. The API tubing list is given in Tables 4-161 and 4-162.

API Physical Property Specifications The tubing steel grade data as given by API Specification 5A, 35th Edition (March 1981), Specification 5AX, 12th Edition (March 1982) and Specification 5AC, 13th Edition (March 1982), are listed in Table 4-163.

Dimensions, Weights and Lengths The following are excerpts from API Specification 5A, 35th Edition (March 1981), "API Specification for Casing, Tubing, and Drill Pipe."

1234

Drilling and Well Completions

Table 4-161 API Tubing List 1 Size: Outside Diameter

in.

mm D

t t 1.050 1.050 1.315 1.315 1.315 1.660 1.660 1.660 1.660 1.900 1.900 1.900 1.900 2.063 2~ 25 2~ 2~ 2~ 2~ 27~ 25 25 3~ 3~ 3~A 3~ 3~ 3~ 4 4 4~A 4~

26, 7 26,7 33,4 33,4 33,4 42,2 42,2 42,2 42,2 48,3 48,3 48,3 48,3 52,4 60,3 60,3 60,3 60,3 60,3 73,0 73,0 73,0 73,0 88,9 88,9 88,9 88,9 88,9 88,9 101,6 101,6 114,3 114,3

2 Nominal Weight, Threads and Coupling, lb per ft

3

4

Grade

Wall Thickness

1.14 1.20 1.70 1.72 1.80 2.10 2.30 2.33 2.40 2.40 2.75 2.76 2.90 3.25 4.00 4.60 4.70 5.80 5.95 6.40 6.50 8.60 8.70 7.70 9.20 9.30 10.20 12.70 12.95 9.50 11.00 12.60 t2.75

H, J, N H,J, N H, J, N H,J, N H,J, N H,J H,J, N H,J, N H,J, N H,J H,J, N H,J, N H,J, N H,J, N H.J. N H,J, N H,[, N ~ N H,J, N H,J, N N N H,J, N H,J, N H,J, N H,J, N N N H,J, N H,J, N H,J, N H,J, N

~

5

-,

in.

~ of Endsl

mm t

O.113 0.I 13 0.133 0.133 0.133 0.125 0.140 0.140 0.140 0.125 0.145 0.145 0.145 0.I56 0.167 0.t90 0.t90 0.254 0.254 0.217 0.217 0.308 0.308 0.216 0.254 0.254 0.289 0.375 0.375 0.226 0.262 0.271 0.271

2. 87 2.87 3,38 3,38 3,38 3,18 3,56 3,56 3,56 3,18 3,68 3,68 3,68 3,96 4,24 4,83 4,83 6,45 6,45 5,51 5,51 7,82 7,82 5,49 6,45 6,45 7,34 9,52 9,52 5,74 6,65 6,88 6,88

Non-Upset Ext. Upset Non-Upset Integral Joint Ext. Upset Integral Joint Non-Upset Integral Joint Ext. Upset Integral Joint Non-Upset Integral Joint Ext. Upset IntegraI Joint Non-Upset Non-Upset Ext. Upset Non-Upset Ext. Upset Non-Upset Ext. Upset Non-Upset Ext. Upset Non-Upset Non-Upset Ext. Upset Non-Upset Non-Upset Ext. Upset Non-Upset Ext. Upset Non-Upset Ext. Upset

INon-upset tubing is available with regular couplings or special bevel couplings. External-upset tubing is available with regular, special bevel, or special clearance couplings. t t F o r information purposes only. Source: From Re£ [173].

Table 4-162 API Work Tubing List 1 Size: Outside Diameter

2

--, in.

Norahaal Weight, lb/ft

nun

3 Calculated Plaln-end Weight,

lb/ft

D 1.050 1.315 1.660 1.900

4

5

Grade

Wall Thickness,

kg/m

in.

we, 26,7 33,4 42,2 48,3

1.55 2.30 3.29 4.t9

1.47 2.17 3.09 3.93

6 Upset Ends, for Weld-on Tool Joints

mm t

2,19 3,23 4,60 5,85

N N N N

0.t54 0.179 0.t98 0.219

3,91 4,32 5,03 5,56

Int.-Ext. Int.-Ext. Int.-Ext. Int.-Ext.

Upset Upset Upset Upset

*Heavy wall tubing for small diameter work strings. Source: From Ref. [173].

1. Dimensions and weights. Pipe shall be furnished in the sizes, wall thicknesses and weights (as shown in Tables 4-164, 4-165 and 4-166) as specified by API Specification 5A: "Casing, Tubing and Drill Pipe." 2. Diameter. The outside diameter of 4 in.-tubing and smaller shall be within -+0.79 mm. Inside diameters are governed by the outside diameter and weight tolerances.

T u b i n g and T u b i n g String Design

1235

Table 4-163 Tubing Steel Grade Data Yield Strength, psi

Steel Grade

Min.

Max.

Min. Tensile Strength, psi

H-60 J-55 C-75 C-95 N-80 P-105

40,000 55,000 75,000 95,000 80,000 105,000

80,000 80,000 90,000 110,000 110,000 135,000

60,000 75,000 95,000 105,000 100,000 120,000

Elongation* 27 20 16 16 16 15

*The minimum elongation in 2 in. (50.80 mm) should be determined by the following formula: e = 625,000

A o2

where e = minimum elongation in 2 in. (50.80 mm) in percent rounded to the nearest '/2% A = cross-sectional area of the tensile specimen in in?, based on a specified outside diameter or nominal specimen width and specified wall thickness, rounded to the nearest 0.01 or 0.75 in. 2, whichever is smaller U = specified tensile strength in psi.

Table 4-164 Nonupset Tubing--Dimensions and Weights 1 Size: Outside Diame~, in.

2 Nominal We~rht =1 Thrm~b and CouPling. lb. p~- ft.

D

8 Wall 'thick. n~,

4 Inside Dtamm,er, in.

5 6 C~=~.t~ We/zht. Plain End lb/ft

Threads-*" and Coupling lb

t

d

~op.

*1.050 1.815 1.680 1.900

1.14 1.70 2.80 2.'75

0.118 0.188 0.140 0.145

0.824 1.049 1.380 1.610

1.15 1.68 2.27 2.'72

0.20 0.40 0.80 0.60

2% 2% 2%

4.00 4.60 5.80

0.190

2.041

0.254

1.995

1.867

8.94 4.48 5.75

1.60 1.60 1.40

2% 2%

6.40 8.60

0.217 O..q08

2.441 2.259

6.16 8.44

3.20 2.60

$½ $½ 3½ 3½

7.70 9.20 10.20 12.70

0.216 0.254 0.289 0.875

8.068 2.992 2.922 2.750

7.58 8.81 9.91 12.52

5.40 5.00 4.80 4.00

4 4½

9.50 12.60

0.226 0.271

8.548 8.958

9.11 12.24

6.20 6.00

0.167

INominal weights, threads and coupling (Col. 2), are shown for the purpose of identification in ordering.

*For information only. zWeight gain due to end finishing.

See Figure 4-409. Source: From Ref. [173].

3. Wall thickness. Each length o f p i p e shall be m e a s u r e d for c o n f o r m a n c e to

wail-thickness requirements. T h e wall thickness at any place shall not be less than the tabulated thickness minus the permissible u n d e r t o l e r a n c e o f 12.5%. Wall-thickness m e a s u r e m e n t s shall b e m a d e with a m e c h a n i c a l c a l i p e r o r with a p r o p e r l y c a l i b r a t e d n o n d e s t r u c t i v e t e s t i n g d e v i c e o f (text continued on page 1238)

~o

Table 4-165 External Upset Tubing--Dimensions and Weights 1

2

3

4

5

6

'/

8

9

Cakuhtted Weight Size:

Outside Dhtmeter. Pipe Body, in.

Nominal Weight: t Threads and Coupling. lb. per ft.

D

Wsdl Thickness, in.

Inside Diameter, in.

Plain End Ib/ft

~

d

we.

Threads and Coupling" . . Special RegUhtr Clearance lb lb

%

I0

11

%

OutsideI Diameter, in. +0.0628

Length, Lenzth. Length, End of Pipe End of Pipe F,nd of Pipe to start of to zltj'ing to s t a r t of ttl~r, in. plane, in. pipe body, +0, --I in. max.

D.

L~

L. . . . .

. . . .

Lb

1.050 1.315 1.660 1.900

1.20 1.80 2.40 2.90

0.113 0.133 0.140 0.145

0.824 1.049 1.380 1.610

1.13 1.68 2.27 2.72

1.40 1.40 1.60 2.00

.... .... .... ....

1.315 1.469 1.812 2.094

2% 2~ 2eA 2it

. . . .

2% 2%

4.70 5.95

0.190 0.254

1.995 1.867

4.43 5.75

4.00 3.60

2.96 2.56

2.594 2.594

4 4

6 6

10 10

2% 2~A

6.50 8.70

0.217 0.308

2.441 2.259

6.16 8.44

5.60 5.00

3.76 3.16

3.094 3.094

4Yt 4K

6~, 61A

10~, 10K

3½ 3½

9.30 12.95

0.254 0.375

2.992 2.750

8.81 12.52

9.20 8.20

5.40 4.40

3.750 3.750

4½ 4½

6½ 6½

10 ½ 10½

. . . .

. . . .

. . . .

. . . .

. . . .

4

11.00

0.262

3.476

10.46

10.60

....

4.250

4½

6½

10 ½

4½

12.75

0.271

3.958

12.24

13.20

....

4.750

4%

6%

10%

INominal weights, threads and coupling (Col. 2), are shown for the purpose of identification in ordering. Source: From Ref. [173]. See Figure 4-410.

o~

Uptmt

ZThe minimum outside diameter of upset, D4, is limited by the minimum length of full-crest threads. See API Std SB. 3Weight gain due to end finishing.

C3 O

O

==

Tubing and Tubing String Design

1237

Table 4-166 Integral Joint TubingmDimensions and Weights I

2

Size: Outside Diameter, in. D

1

3

Nominall Weigh~ Upset and Threaded, lb per ft

4

5

6

Calculated Weight

t

Inside Diameter, in. d

1.315

1.72

0.133

1.049

1.68

0.20

1.660 1.660

2.10 2.33

0.125 0.140

1.410 1.380

2.05 2.27

0.20 0.20

1.900 1.900

2.40 2.76

0.125 0.145

1,650 1.610

2.37 2.72

0.20 0.20

2.063

3.25

0.156

1.751

3.18

0.20

2

7

Wall Thickness in.

8

9

I0

11

Plain End lb/ft Wpe

12

Upset2 and Threads lb ew

13

14

15

U ~ e t Dimemfions, in. Nominall Size: Weight: Outside Upset and Dbm~eter, Threaded, in. lbper fi

Phi

Box

Outsides Inslde4 Diameter, Diameter, Length, +0.0625 +0.015 Min.,

Length of Taper Min.,

Outside Diameter, +0.005 -0.025

Length Min.,

Length of Taper,

Diameter of Recess

Width of Face Min.,

L~

m~

Q

b

94

~u

~.

~,

Wb

1.315

1.72

. . . . .

970

1~

~4

1.550

1.750

1

1.378

1,~2

1.660 1.660

2.10 2.33

.... ....

1.301 1.301

lP2 11~

~ ~4

1.880 1.880

1.875 1.875

1 1

1.723 1.723

~2 ~2

1.900 1.900

2.40 2.76

.... ....

1.531 1.531

1~ 15~

~ 14

2.110 2.110

2.000 2.000

I 1

1.963 1.963

~2 ~2

2.063

3.25

2.094

1.672

11~6

~

2.325

2.125

1

2.156

~2

D

INominal weights, upset and threaded (Col. 2), are shown for the purpose of identification in ordering. ~/eight gain due to end finishing. SThe minimum outside diameter 1)4, is limited by the minimum length of full crest threads. See API Std 5B. 4The minimum inside diameter, d/u, is limited by the drift text. Source: From Ref. [173]. S~e Figure 4-411.

/•20

~..."~ICOR~ERS/I i,~,~--w for R,OKZ~

-I~----------i¢~ ~..~ROUNDED

° SPECIAL BEVEL COUPLING

W

I

w Figure 4-409. Non-upset tubing and coupling. (From Ref. [173].) See Table 4-164 for pipe dimensions.

1238

Drilling and Well Completions

/-'~=o-

/'~20" SPEOIAL CLEARANCE COUPLING

O

BASIC POWERTIGHTMAKEUP

ROUNO(O O~S

We I~ Q

HANDTIGHTMAKEUP

*SEE TABLE 6.11 FOR TOLERANCE ON OUTSIDE DIAMETER AT DISTANCE I.= FROM END OF PIPE*

Figure 4-410. External-upset tubing and coupling. (From Ref. [173].) See Table 4-165 for pipe dimensions.

T ~!

----~-Irn=, DASHED

LINES INDICATE POWERTIGHT

MAKEUP

Figure 4-411. Integral-joint tubing. (From Ref. [173].) S e e Table 4-166 for pipe dimensions.

(text continued from page 1235)

appropriate accuracy. In case of dispute, the measurement determined by use of the mechanical caliper shall govern. 4. Weight. Each length of tubing in sizes 1.660 in. and larger shall be weighed separately. Lengths of tubing in sizes 1.050 and 1.315 in. shall be weighed either individually or in convenient lots. Threaded-and-coupled pipe shall be weighed with the couplings screwed on or without couplings, provided proper allowance is made for the weight of the coupling. Threaded-and-coupled pipe, integral joint pipe and pipe shipped without couplings shall be weighed without thread protectors except for carload weighings, for which proper allowances shall be made for the weight of the thread protectors. 5. Calculated weights shall be determined in accordance with the following formula:

Tubing and Tubing String Design

1239

W L= (Wpe x L) + e w where W L = Wpe = L -ew =

calculated weight of a piece of pipe of length L in lb (kg) plain-end weight in lb/ft (kg/m) length of pipe, including end finish, as defined below in ft (m) weight gain or loss due to end finishing in lb (kg) (for plainend pipe, e w = 0) 6. Length. Pipe shall be furnished in range lengths conforming to the following as specified on the purchase order: When pipe is furnished with threads and couplings, the length shall be m e a s u r e d to the outer face of the coupling, or if measured without couplings, proper allowance shall be made to include the length of the coupling. For integral joint tubing, the length shall be measured to the outer face of the box end. Pipe R a n g e L e n g t h s

Total range length* Range length for 100% of carload: t Permissible variation, max. Permissible length, min.

Range 1

Range 2

20-24

28-32

2 20

2 28

*By agreement between purchaser and manufacturer, the total range length for Range 1 tubing may be 6.10-8.53 m. tCadoad tolerances shall not apply to orders less than a carload shippedfrom the mill. For any carload of pipe shippedfrom the mill to the final destinationwithout transfer or removal from the car, the tolerance shall apply to each car. For any order consistingof more than a carload and shippedfrom the mill by rail, but not to the final destination in the rail cars loaded at the mill, the carload tolerances shall apply

to the total order, but not to the individualcarloads, Performance Properties

Tubing performance properties, according to API Bulletin 5C2, 18th Edition (March 1982), are given in Table 4-167. Formulas and procedures for calculating the values in Table 4-167 are given in API Bulletin 5C3, 3rd Edition (March 1980). Running and Pulling Tubing

The following are excerpts from "API R e c o m m e n d e d Practice for Care and Use of Casing and Tubing," API RP 5C1, 12th Edition (March 1981). Preparation and Inspection before Running

1. New tubing is delivered free of injurious defects as defined in API Standard 5A, 5AC and 5AX, and within the practical limits of the inspection procedures therein prescribed. Some users have found that, for a limited n u m b e r of critical well applications, these procedures do not result in casing sufficiently free of defects to meet their needs for such critical applications. Various nondestructive inspection services have been employed by users to assure that the desired quality of tubing is being run. In view of this practice, it is suggested that the individual user: (text continued

on

page 1246)

1240

Drilling and Well Completions Table 4-167 Minimum Performance Properties of Tubing

1

2

3

4

5

Nominal Weight lb per ft

Size: Outside r Diameter Threads and in. Coupling

Grade

~ NonUpset

1.315

1.660

1.900

8

9

r Wall Inside Drift Thick- Diameter Diameter ness in. in. r in.

Upset

D 1.050

7

10

11

Threaded and Coupled

Integral

Joint

6

t

d

Outside Diameter of Coupling, in. Upset Non- ~" "Upset Regular Special Clearance W W We

1.14

1.20

--

H-.40

0.113

0.824

0.730

1.313

1.660

--

1.14

1.20

--

J-55

0.113

0.824

0.730

1.313

1.660

--

1.14

1.20

--

C-75

0.113

0.824

0.730

1.313

1.660

--

1.14

1.20

--

L-80 & N-80

0.113

0.824

0.730

1.313

1.660

--

1.70

1.80

1.72

H-.40

0.133

1.049

0.955

1.660

1.900

--

1.70

1.80

1.72

J-55

0.133

1.049

0.955

1.660

1.900

--

1.70

1.80

1.72

C-75

0.133

1.049

0.955

1.660

1.900

--

1.70

1.80

1.72 L-80 & N-80

0.133

1.049

0.955

1.660

1.900

--

-2.30

-2.40

2.10 2.33

H-40 H-40

0.125 0.140

1.410 1.380

. 1.286

.

. 2.054

. 2.200

--

-2.30

-2.40

2.10 2.33

J-55 J-55

0.125 0.140

1.410 1.380

. 1.286

.

. 2.054

. 2.200

--

2.30

2.40

2.33

c-75

0.140

1.380

1.286

2.054

2.200

--

2.30

2.40

2.33

L..80 & N-80

0.140

1.380

1.286

2.054

2.200

--

-2.75

-2.90

2.40 2.76

H-40 H-40

0.125 0.145

1.650 1.610

. 1.516

.

. 2.200

. 2.500

--

-2.75

-2.90

2.40 2.76

J-55 J-55

0.125 0.145

1.650 1.610

. 1.516

.

. 2.200

. 2.500

--

c-75

0.145

1.610

1.516

2.200

2.500

--

0.145

1.610

1.516

2.200

2.500

--

2.75

2.90

2.76

2.75

2.90

2.76 L-80 & N-80

Tubing and Tubing String Design

1241

T a b l e 4-167 (continued) 1

2

3

4

5

Size: Outside Dinmetes" in. ,

Threadsand Coupling

6

7

8

9

Integral Joint

Grade

Wall I n s i d e Drift Thick- Diameter Diameter area in. in. in.

Upset

d

D 2.063

2%

Outeide Diametero! Coupling. in. UA;~et NonUpset l~eguiar Special Clearance

W

3.25

H-40

0.156

1.751

--

W

Wc

m

I

m

m

3.25

J-55

0.156

1.751

--

D

m

g

m

I

3.25

C-75

0.156

1.75!

--

u

I

0

1 . 7 5 1

- -

D

2~

11

,

N o n °

Uput

10

Threaded~ d Coupled

NominalWeight lb. I~r ft.

m

3.25 L-80&N-80 0.156

4.00 4.60

-4.70

---

H-40 H-40

0.167 0.190

4.00 4.60

-4.70

--

J-55 J-55

0.167 2.041 1 . 9 4 7 2.875 -0 . 1 9 0 1.995 1.901 2 . 8 7 5 8 . 0 6 8

4.00 4.60 5.30

4.70 5.95

C-75 C-75 C-75

0.167 2.041 1 . 9 4 7 2.875 0 . 1 9 0 1 . 9 9 6 1.901 2 . 8 7 5 $ . 0 6 8 2.910 0 . 2 5 4 1.867 1 . 7 7 3 2 . 8 7 5 3 . 0 6 3 2.910

4.00 4.60 5.80

4.70 5.95

- -

4.60 5.30

4.70 5.95

---

P-105 i)-105

0.190 0.254

6.40

6.50

--

H-40

0.217 2.441 2.347

3.500 8 . 6 6 8 3.460

8.40

8.50

--

,I'-55

0 . 2 1 7 2.441 2.847

8.500 3 . 6 6 8 8A80

6.40 8.60

6.50 8.70

---

C-75 C-76

0 . 2 1 7 2.441 0.308 2.259

2.347 2.165

2.500 3.500

8.668 8.668

8.460 8.460

6.40 8.60

6.50 8.70

---

2.441 2.259

2.347 2.165

3.500 3.500

8.668 8.668

$A60 8.460

6.40 8.60

6.50 8.70

---

2.441 2,259

2.347 2.165

8.500 3.500

8.668

3.460

- -

- -

- -

- -

--- -

--

2.875 237B

-8.068

- -

L-80&N-80 0.167 L-80&N-80 0.190 L-80&N-80 0.254

L-80&N-80 0.217 L-80&N-80 0.308 P-105 P-105

2.041 1 . 9 4 7 1.995 1.901

u

0.217 0.308

2.041 1.947 1.995 1.901 1 . 8 6 7 1.773

2.875 2.875 2.875

1 . 9 9 5 1.901 2.875 1 . 8 6 7 1.773 2 . 8 7 5

- -

-2.910 -2.910 - -

- -

3.063 3.065

2.910 2.910

8.068 3.068

2.910 2.910

3.668 3.460

1242

Drilling and Well Completions

Table 4-167 (continued) 12

13

14

15

Outside Diameter of Box

Collapse Resistance

Internal Yield Pressure

in.

psi

psi

16

IntegralJoint

in.

0.955

Wb

1.550

18

Joint Yield Strength, lb

~ Drift Diameter

17

-f

Threaded and Coupled

Integral

Joint Non-Upset

Upset

7,680

7,530

6,360

13,310

10,560

10,360

8,740

18,290

14,410

14,130

11,920

24,950

15,370

15,070

12,710

26,610

7,270

7,080

10,960

19,760

15,970

0.955

1.550

10,000

9,730

15,060

27,160

21,960

0.955

1.550

13,640

13,270

20,540

37,040

29,940

0.955

1.550

14,550

14,160

21,910

39,510

31,940

1.286 1.286

1.880 1.880

5,570 6,180

5,270 5,900

-15,530

-26,740

22,180 22,180

1.286 1.286

1.880 1.880

7,660 8,490

7,250 8,120

-21,360

-36,770

30,500 30,500

1.286

1.880

11,580

11,070

29,120

50,140

41,600

1.286

1.880

12,360

11,810

31,060

53,480

44,370

1.516 1.516

2.110 2.110

4,920 5,640

4,610 5,340

-19,090

-31,980

26,890 26,890

1.516 1.516

2.110 2.110

6,640 7,750

6,330 7,350

-26,250

-43,970

36,970 36,970

1.516

2.110

10,570

10,020

35,800

59,960

50,420

1.516

2.110

11,280

10,680

38,180

63,960

53,780

Tubing and Tubing String Design

1243

T a b l e 4-167

(continued) 12 13 Integr~ Joint Drift Diameter in.

14 •

Outside Diameter of Box in.

Collapse Resistance psi

15

16 17 Internal Yield PreMu~e ~ Plain-~md UP~t and " Regular Sl~eial N o n - U P ~ t COuPlinE Clearance Couplin~ psi psi Psi

18

19 Joint Yield Strehash, I~ Threaded and Coupled

~ r Non-Upset

Upxt

20

I nteEra] Joint

Wb 1.657

2.325

5,590

5,290

.

.

.

.

35,700

1.657

2.325

7,690

7,280

.

.

.

.

49,000

1.657

2.325

10,480

9,920

.

.

.

.

66,900

1.657

2.325

11,180

10,590

.

.

.

.

71,400

5,230

4,920

5,600

~00

6,600

7,190 8,100

6,770 7,700

7"~00

- -

-- -

--

5,890

30,100

36,000

~00

7500

41,400 49,500

71"~00

- -

9,520

9,230

11,040 14,330

10,500 14,040

10"~00 13,960

10"~00 10,720

67,400 96,600

97"~00 126,900

--

9,980 11,780 15,280

9,840 11,200 14,970

11"~00 14,890

11"~00 11,440

60,300 71,900 103,000

10~00 135,400

---

15,460 20,060

14,700 19,650

14,000 19,540

14,700 15,010

94,400 135,200

136,900 177,700

5,580

5,280

52,80

5,510

52,800

72,500

- - -

-- -

m

56,500

--

7,680

7,260

7,200

7,260

72,600

99,700

---

10,470 14,350

9,910 14,060

9,910 14,010

9,910 10,340

99,000 149,400

135,900 186,300

---

11,160 15,300

10,570 15,000

10,570 14,940

10,570 11,030

105,600 159,300

145,000 198,700

--

14,010 20,090

13,870 19,690

13,870 19,610

13,870 14,480

138,600 209,100

190,300 260,800

m

1244

Drilling and Well Completions

Table 4-167 (continued) 1 S i z e ." Outside Dinmet~ in.

2

6

4

5

,

~relds and CouAPling

Integrll Joint

Grade

Wall ~i©kne~

tn

9

Inside Drift Diameter Diameter in. in. ,

10

11

O u t s i d e D i a m e t e r Of Coupling, in.

Upset Non-

Upset

t 7.70 920 10.20

-9.80 --

m

7.70 920 1020

~ 9.30 --

9.80

7.70 920 1020 12.70

d

fibular

W

W

3.068 2.992 2.922

2.943 2.867 2.797

4250 4250 4250

-4.500

~ ---

J-55 J-55 J-65

0216 0254 0.289

3.068 2.992 2.922

2.943 2.867 2.797

4250 4250 4.250

-4.500 ~

m m

C-75 C-75 C-75 C-75

0216 0254 0289 0.875

3.068 2.992 2.922 2.750

2.943 2.867 2.797 2.625

4250 4250 4250 4250

-4.500 ~ 4.500

L-80&N-80 L-80&N-80 L-80&N-80 L-80&N-80

0216 0.254 0.289 0.375

3.068 2.992 2.922 2.750

2.943 2.867 2.797 2.625

4250 4250 4250

-4.500 ~ 4.500

4.180

1=-105

0254 0.875

2.992 2.750

2.867 2.625

4.250 4250

4.500 4.500

4.180 4.180

- -

12.95

920 12.70

9.60 12.95

--

ll.OO

E

H-40 H-40

0.2266.548 0262 6.476

6.426 6.851

4.750 --

-5.000

11.00

E Q

J-55 J-55

0226

0262

3.548 8.476

6.423 3.351

4.750 --

-5.000

C-75 C-75

0~26 0262

3.548 8.476

6.428 3.351

4.750 --

-5.000

L-80&N-80 0.226 L-80&N-80 0.262

3.548 3.476

6.423 6.851

4.750 --

-5.000

9.30

9.50

--

--

11.00

--

9.50

W~

0216 0254 0.9.89

7.70 9.20 10.20 12.70

9.50 --

SPeCial " Clearance

H-40 H-40 H-4O

m

12.95

9.50

-11.00

4~

8

Up6~

D

4

7

Threaded and Coupled

.

NonUp~t

3~

6

N~inal Weieht lb. ~ ft,

P-105

4250

-4.180 - -

4.180

4.180 4.180

4.180

--

--

12.60

12.75

TT-40

0271

3.958

3.833

5200

5.563

12.60

12.75

J-56

0271

8.958

6.883

5200

5,568

12.60

12.75

--

0271

3.958

$.855

5200

5.568

--

12.60

12.75

--

L-80&N-80 0.271

3.958

6.833

5200

5.568

--

0-75

Tubing and Tubing String Design

1245

Table 4-167 (continued) 12 In , t ~ Drift

13

14

15

J~nt OutJl't"

Golla~M

of ! ~ in.

in. Wb

---

16

17

18

lnlt~lml yAi~dd ~ ]'lain-end Non-U~Nt

U~pmt

.

~linlr

Co,~plie~ p~

lxd

pal

---

4,680 5,380

4,320 5.080

-5,080

5"-,'~80

79.500

~

6,060

5,780

~

~

92,600

-

-

5,970

5~,o

-

--

7,,00

--

8,380

0,990 7,950

6,990 ~

~90

--

---

--~ --

9--,'~30 ~ 14,060

9~30

14,850

8,100 9,530 10,840 14,060

7,870

8,640

--w

----

7,540 10,040

10,530

10,160

12.120

11,560

10~60

20

']['hr~adod ~ d

~

11,360

19 ,ToJnt yieM stm~/~ r~

Non-U~et

UP~

65,100 103~'600 --

.~oo --

9-~-990

10~60

---

-

109,400 127,800

1,~00 --

---

122,000 149,100 173,500 281,000

-194,300 ~ 276,100

----

180,100 159,100

--

186,100

207,200 ~

-----

--

--

15,310

15,000

15~-000

10~-660

246,400

294,500

--

---

~ --

13,050 20,090

18,840 19,690

13,340 19,690

13,340 13,990

208,900 323,400

272,000 386,600

---

m m

w

4,060 4,900

3~60 4,590

~ 4,590

-~

72,00O --

128"~00

m m

5,110

5,440

--

99,0O0

m

I

w

SoarcetFromlhl.[174~

6too

,,~

Goo

-

0,~o 8~1o

7,eo 8,~

8,~

-

185,ooo -

0~,o 8,800

7,91o

-

1.,ooo

9,170

9,170

~

~

4,500

4,220

4,220

--

104,400

144,000

5,720

5,800

5,800

--

148,500

19~,000

7,200

7,900

7,900

--

195,700

270,000

7,500

8,480

8,480

--

204L700

288,000

-

-

10~oo 28o7~oo

24~00

m

1246

Drilling and Well C o m p l e t i o n s

(text continued from page 1239)

a. Familiarize h e r or himself with i n s p e c t i o n practices s p e c i f i e d in the standards and e m p l o y e d by the respective mills and with the definition of "injurious defect" contained in the standards. b. Thoroughly evaluate any nondestructive inspection to be used by him or her on API tubular goods to ensure that the inspection does in fact correctly locate and differentiate injurious defects from o t h e r variables that can be and frequently are sources of misleading "defect" signals with such inspection methods. Caution: Due to the permissible tolerance on the outside d i a m e t e r immediately b e h i n d the tubing upset, the user is c a u t i o n e d that difficulties may occur when w r a p a r o u n d seal-type hangers are installed on tubing manufact u r e d on the high side of the tolerance; therefore, it is r e c o m m e n d e d that the user select the j o i n t of tubing to be installed at the top of the string. 2. All tubing, w h e t h e r new, used or r e c o n d i t i o n e d , should always be h a n d l e d with t h r e a d protectors in place. T u b i n g should be h a n d l e d at all times on racks or on w o o d e n or metal surfaces free of rocks, sand o r dirt o t h e r t h a n n o r m a l d r i l l i n g m u d . W h e n l e n g t h s o f t u b i n g are i n a d v e r t e n t l y d r a g g e d in the dirt, the threads should be recleaned. a. Before r u n n i n g in the hole for the first time, tubing should be drifted with an API drift mandrel to ensure passage of pumps, swabs and packers. b. Elevators should be in good repair and should have links of equal length. c. Slip-type elevators are r e c o m m e n d e d when r u n n i n g special clearance couplings, especially those beveled on the lower end. d. Elevators should be e x a m i n e d to note if latch fitting is complete. e. Spider slips that will not crush the tubing should be used. Slips should be e x a m i n e d before using to see that they are working together. Note: Slip and tong marks are injurious. Every possible effort should be made to keep such damage at a minimum by using p r o p e r up-to-date equipment. f. Tubing tongs that will not crush the tubing should be used on the body of the tubing and should fit p r o p e r l y to avoid unnecessary cutting of the pipe wall. Tong dies should fit properly and conform to the curvature of the tubing. T h e use of pipe wrenches is not r e c o m m e n d e d . g. T h e following precautions should be taken in the p r e p a r a t i o n of tubing threads: 1. I m m e d i a t e l y before running, remove protectors from b o t h field end and coupling end and clean threads thoroughly, r e p e a t i n g as additional rows b e c o m e uncovered. 2. Carefully inspect the threads. Those found damaged, even slightly, should be laid aside unless satisfactory means are available for correcting t h r e a d damage. 3. T h e l e n g t h of each piece of t u b i n g should be m e a s u r e d p r i o r to running. A steel tape calibrated in decimal feet to the nearest 0.01 ft should be used. The m e a s u r e m e n t should be m a d e from the o u t e r m o s t face of the coupling o r box to the position on the externally t h r e a d e d end where the coupling or the box stops when the j o i n t is m a d e up powertight. The total of the individual length so measured will represent the u n l o a d e d length of the tubing string. 4. Place clean protectors on the field end of the pipe so that the t h r e a d will not be d a m a g e d while rolling the pipe onto the rack and pulling it into the derrick. 5. Check each coupling for makeup. If the stand off is abnormally great, check the coupling for tightness. Loose couplings should be removed,

Tubing and Tubing String Design

1247

the threads thoroughly cleaned and fresh compound should be applied over the entire thread surfaces. Then the coupling should be replaced and tightened before pulling the tubing into the derrick. 6. Before stabbing, liberally apply thread compound to the entire internally and externally threaded areas. It is recommended that highpressure, modified thread compound as specified in API Bulletin 5A2: "Bulletin on Thread Compounds" be used except in special cases where severe conditions are encountered. In these special cases it is recommended that high-pressure silicone thread compound as specified in Bulletin 5A2 be used. h. For high-pressure or condensate wells, additional precautions to insure tight joints should be taken as follows: 1. Couplings should be removed and both the mill-end pipe thread and coupling thread thoroughly cleaned and inspected. To facilitate this operation, tubing may be ordered with couplings handling tight, which is approximately one turn beyond hand tight, or may be ordered with the couplings shipped separately. 2. Thread compound should be applied to both the external and internal threads, and the coupling should be reapplied handling tight. Field-end threads and the mating coupling threads should have thread compounds applied just before stabbing.

Stabbing, Making Up and Lowering 1. Do not remove thread protector from field end of tubing until ready to stab. 2. If necessary, apply thread compound over entire surface of threads just before stabbing. 3. In stabbing, lower tubing carefully to avoid injuring threads. Stab vertically, preferably with the assistance of someone on a stabbing board. If the tubing tilts to one side after stabbing, lift up, clean and correct any damaged thread with a three-cornered file, then carefully remove any filings and reapply compound over thread surface. Intermediate supports may be placed in the derrick to limit bowing of the tubing. 4. After stabbing, start screwing the pipe together by hand or apply regular or power tubing tongs slowly. To prevent galling when making up connections in the field, the connections should be made up to a speed not to exceed 25 rpm. Power tubing tongs are recommended for high-pressure or condensate wells to ensure uniform makeup and tight joints. Joints should be made up tight, approximately two turns beyond the hand-tight position, with care being taken not to gall the threads.

Field Makeup 1. Joint life of tubing under repeated field makeup is inversely proportional to the field makeup torque applied. Therefore, in wells where leak resistance is not a great factor, minimum field makeup torque values should be used to prolong joint life. Table 4-168 contains recommended optimum makeup torque values for nonupset, external upset, and integral joint tubing, based on 1% of the calculated joint pullout strength determined from the joint pull-out strength formula for eight-round thread casing in Bulletin 5C3. Minimum torque values listed are 75% of optimum values, and maximum torque values listed are 125% of optimum values. All values are rounded to the nearest 10 ft-lb. The torque values listed in Table 4-168

1248

D r i l l i n g a n d Well C o m p l e t i o n s

Table 4-168 Recommended Tubing Makeup Torque 1

2

$

81mR: In.

T h ~

1.315

1.660

and

C~U~Aling ^

Ulna: 1.050

4

5

6

7

8

9

Nmainsl W,dght lb. ~ f~ Integral

Joint

10

11

12

18

14

Torque. ft-lb Grad@

Upl~4

Non-UpNt Opt.

Mln.

Ups/re Msz.

Opt.

Mln.

Intsfrral Joint

MAT,.

Opt.

Min.

m

m

m

m

m

m

1.14

1.20

~

H-40

140

110

180

460

350

580

1.14

1.20

~

J-55

180

140

280

600

450

750

1.14

1.20

~

C-75

230

170

290

780

590

980

1.14

1.20

--

L-80

240

180

300

810

610

I010

1.14

1.20

~

N-80

250

190

310

830

620

1040

m

Max.

m

1.70

1.80

1.72

H-40

210

160

260

440

330

550

310

230

1.70

1.80

1.72

J-55

270

200

340

570

430

710

400

300

500

1.70

1.80

1.72

C-75

360

270

450

740

560

930

520

390

650

1.70

1.80

1.72

L-80

370

280

460

760

570

950

540

400

680

1.70

1.80

1.72

N-80

380

290

480

790

590

990

550

410

690

2~0

2.40

--

2.10

HA0

~0

2-00

~0

--

--

--

660

330

230

~-80 2.80

2.40 2.40

--

2.10

2.~ 2.33

J~5

~0 460

~0 350

~0 53o

--

--

--

~0 500 1140 650

500

380

380 490

830 31o

2.30

2.40

2.33

L-S0

470

350

590

940

710

1180

670

500

850

2.80

2.40

2.33

N-80

490

370

610

960

720

1200

690

520

860

--

2.40 H~0

560

~5

2.90

2.76

H-40

3"20

2"40

~5

-2.90

2.40 2.76

J-55 J-55

~0

~0

2.75

2.90

2.76

C-75

540

410

680

1150

860

2.75

2.90

2.76

L-80

560

420

700

1190

890

2.75

2.90

2.76

N-80

570

430

710

1220

920

1530

1.900

2.33

H40 :-55 c~75

.

530

~0 91o

.

.

400

520 ~0

.

380

280

390

430

430 63n

450

340

400

670

500

840

450

340

560

~0

__ 880

__ 660

m 1100

580 580

440 440

730 730

1440

760

570

950

1490

790

590

990

810

610

1010

apply only to tubing with zinc-plated couplings. W h e n making up connections with tin-plated couplings, 80% of the listed value can be used as a guide. 2. Spider slips a n d elevators should be cleaned frequently, a n d slips should be kept sharp. 3. F i n d i n g b o t t o m should be accomplished with extreme caution. Do not set tubing down heavily.

Pulling Tubing 1. A caliper survey prior to p u l l i n g a worn string of tubing will provide a quick means of segregating badly worn lengths for removal. 2. Break-out tongs should be positioned close to the coupling. H a m m e r i n g the coupling to break the j o i n t is an injurious practice. 3. Great care should be exercised to disengage all of the thread before lifting the tubing out of the coupling. Do not j u m p the tubing out of the coupling. 4. T u b i n g stacked in the derrick should be set o n a firm wooden platform without the bottom thread protector since the design of most protectors is not such as to support the j o i n t or stand without damage to the field thread.

Tubing and Tubing String Design

1249

Table 4-168 (continued) 1

2

3

Sise:

Outside

•

Diameter in.

Threads

--

__

2~

and

Coupling

Hon-

Upset 2.063

5

Integral Joint

6

7

8

9

u

m

10

11

12

13

Max.

Opt.

14

Torque. ft-lb , Grade

Non.Upset

Opt.

Upset

Min,

Integral Joint

Upset

Max.

Opt.

Min.

Mln,

Max. 710

3.25

H-40

.

.

.

.

.

.

570

430

3.25

J-55

.

.

.

.

.

.

740

560

920

3.25

C-75

.

.

.

.

.

.

970

730

1210

3.25

L-80

.

.

.

.

.

.

1010

760

1260

3.25

N-80

.

.

.

.

.

.

1030

770

1290

4.00 4.60

4.~0

---

H-40 H-40

470 560

350 420

590 700

~0

~0

1240

--

--

4.00 4.60

-4.70

---

J-55 J-55

610 730

460 550

760 910

-1290

-970

1610

--

--

--

C-75

S00

600

1000

4.00

2%

4

Nominal Weight tb, ~ ft.

4.60 5.80

4.-~0 5.95

---

C-75 C-75

960 1380

720 1040

1200 1730

17-00 2120

1~0 1590

2130 2650

---

--

4.00 4.60 5.80

~ 4,70 5.95

----

L-80 L-80 L-80

830 990 1420

620 740 1070

1040 1240 1780

-1760 2190

~ 1320 1640

2200 2740

-~

--

4.00 4.60 5.80

4.~0 5.95

~ -~

N-80 N-80 N-80

850 1020 1460

640 770 1100

1060 1280 1830

1~0 2240

-1350 1680

2250 2800

~ ~

4.60 5.80

4.70 5.95

---

P-105 1>-105

1280 1840

960 1380

1600 2300

2270 2830

1700 2120

2840 3540

~ --

6.40

6.50

--

H-40

800

600

1000

1250

940

1560

m

6.40

6.50

~

J-55

1050

790

1310

1650

1240

2060

m

6.40 8.60

6.50 8.70

-m

C-75 C-75

1380 2090

1040 1570

1730 2610

2170 2850

1630 2140

2710 3560

6.40 8.60

6,50 8.70

---

L-80 L-80

1430 2160

1070 1620

1790 2700

2250 2950

1690 2210

2810 3690 2880

6.40

6.50

--

N-80

1470

1100

1840

2300

1730

8.60

8.70

~

N-80

2210

1660

2760

3020

2270

3780

6.40

6.50

~

P-105

1850

1390

2310

2910

2180

3640

8.60

8.70

--

P-105

2790

2090

3490

3810

2860

4760

m

5. Protect threads from dirt or injury when the tubing is out of the hole. 6. Tubing set back in the derrick should be properly supported to prevent undue bending. Tubing that is 2 ~a-in. OD and larger preferably should be pulled in stands approximately 60 ft long or in doubles of range 2. Stands of tubing 1.900-in. OD or smaller and stands longer than 60 ft should have intermediate support.

Causes of Tubing Trouble The more common causes of tubing troubles are as follows: 1. 2. 3. 4. 5. 6.

Improper selection for strength and life required. Insufficient inspection of finished product at the mill and in the yard. Careless loading, unloading and cartage Damaged threads resulting from protectors loosening and falling off. Lack of care in storage to give proper protection. Excessive hammering on couplings.

Drilling and Well Completions

1250

Table 4-168 (continued) 1

Size: Outside , Diameter in.

2

3

4

5

6

7

8

9

Nominal Weight lb. l ~ r ft. Threads and CouPllng

10 Tol~

Intclrral • Joint Grade

11

12

14

ft-lb lY~l~t

Non-Up~.t

13

In'"

Joint

Non-

U~t

3%

7.70 9.20 10.20

-9.30

7.70 9.20 10.20

-9.30 --

--

Opt.

---

H-40 H40

--

H 4 0

---

--

J-55 J-55 J-55

Min.

Max.

690 840 980

1150 1400 1640

. 1730

1210 1480 1720

910 1110 1290

1510 1850 2150

. 2280 .

7.70

--

--

C-75

1600

1200

2000

9.30 -12.95

--

--

C-75 C-75 C-75

1950 2270 3030

1460 1700 2270

2440 2840 3790

--

L-80

1250 1520 1770 2360

2080 2540 2950 3930

--

7.70 9.20 10.20 12.70

9.30 -12.95

----

L-80 L-30 L-80

1660 2030 2360 3140

7.70

--

--

N-80

1700

1280

2130

2590

9.20

--

9.30

--

Opt.

920 1120 1310

9.20 10.20 12.70

.

.

3010 . 4040 .

Min.

-.1300 .

.

. 1710 . .

.

2260 3030 .

.

2350 . 3150 .

. .

--

--

--

--

--

--

--

--

--

. --

.

.

-.

-.

. --

.

.

N-80

2070

1550

--

--

--

--

N-80

2410

1810

3010

--

N-80

3210

2410

4010

4290

3220

5360

--

--

-

9.20 12.70

9.30 12.95

---

P-105 P-105

2620 4060

1970 3050

3280

6080

4050 5430

3040 4070

5060 6790

---

---

-

9.50 --

-11.00

---

H-40 H-40

940 --

710 --

1180 --

~ 1940

-1460

2430

--

--

1240 --

930 --

1550 --

~ 2560

m

-

.

4000

--

.

12.95

.

2400

--

. ~

- - .

- -

-.

.

3910 . -5250 .

3200

- -

M~

.

3760 . 5050

.

Min.

-.

.-2850 .

.

.

Opt.

- -. 2160

.

3130 . 4200 .

Max*

12.70

10.20

4%

Upset

.

--

--

.

.

9.50 --

11.00

--

J-55 J-55

1920

3200

9.50 --

-11.00

---

C-75 C-75

1640 --

1280 --

2050 --

-3390

-2540

4240

L-80 L -.3 0

1710 .

2140

1 ~.0

-.

1280

9.50 .

-3530

2~0

4~0

9.50

-11.00

--

N-80 N-30

1740

1310

2180

-3600

-2700

4500

m

--

-

--

-

w

I

12.60

12.75

--

H-40

1320

990

1650

2160

1620

2700

12.60

12.75

--

J-55

1740

1310

2180

2360

2150

3530

--

12.60

12.75

--

C-75

2300

1730

2880

3780

2840

4730

--

12.60

12.75

--

L-80

2400

1800

3000

3940

2960

4930

--

12.60

12.75

--

N-80

2440

1830

3050

4020

3020

5030

-

-

m

$ o m ~ , From Rd. [175].

7. 8. 9. 10. 11.

Use of worn-out and wrong types of handling equipment. Nonobservance of proper rules in running and pulling tubing. Coupling wear and rod cutting. Excessive sucker rod breakage. Fatigue that often causes failure at the last engaged thread. There is no positive remedy, but using external upset tubing in place of nonupset tubing greatly delays the start of this trouble. 12. Replacement of worn couplings with non-API couplings. 13. Dropping a string, even a short distance. 14. Leaky joints, under external or internal pressure.

Tubing and Tubing String Design

1251

15. Corrosion. Both the inside and outside o f tubing can be damaged by corrosion, The damage is generally in the form of pitting, box wear, stress-corrosion cracking, and sulfide stress cracking, but localized attack like c o r r o s i o n erosion, ringworm and caliper tracks-can also occur. Since corrosion can result from many causes and influences and can take different forms, no simple and universal remedy can be given for control. Each problem must be treated individually, and the solution must be attempted in light o f known factors and operating conditions. a. Where internal or external tubing corrosion is known to exist and corrosive fluids are being produced, the following measures can be employed: 1. In flowing wells the annulus can be packed off and the corrosive fluid confined to the inside o f the tubing. The inside o f the tubing can be protected with special liners, coatings or inhibitors. Under severe conditions, special alloy steel or glass-reinforced plastics may be used. Alloys do not eliminate corrosion. W h e n H~S is present in the well fluids, tubing o f high-yield strength may be subject to sulfide corrosion cracking. The concentration o f H~S necessary to cause cracking in different strength materials is not yet well defined. Literature on sulfide corrosion or persons competent in this field should be consulted. 2. In pumping and gas-lifting wells, inhibitors introduced via the casingtubing annulus afford appreciable protection. In this type o f completion, especially in p u m p i n g wells, better operating practices can also aid in extending the life o f tubing; viz., t h r o u g h the use o f rod protectors, rotation o f tubing and longer and slower p u m p i n g strokes. b. To determine the value and effectiveness o f the above practices and measures, cost and equipment failure records can be compared before and after application o f control measures. c. In general, all new areas should be considered as being potentially corrosive, and investigations should be initiated early in the life o f a field, and repeated periodically, to detect and localize corrosion before it has done destructive damage. Where conditions favorable to corrosion exist, a qualified corrosion engineer should be consulted.

Selection of Wall Thickness and Steel Grade of Tubing Tubing design relies on the selection o f the most economical steel grades and wall thicknesses (unit weight o f tubing) that will withstand, without failure, the forces to which tubing will be exposed throughout the expected tubing life. Tubing must be designed on: • • • •

collapse burst tension possibility o f permanent corkscrewing

Tubing string design is very much the same as for casing. For shallow and moderately deep holes, uniform strings are preferable; however, in deep wells, a tapered tubing can be desirable. A design factor (safety factor) for tension should be about 1.6. The collapse design factor must not be less than 1.0, assuming an annulus filled up with fluid and tubing empty inside. The design factor for burst should not be less than 1.1.

1252

Drilling a n d Well Completions

Tubing Elongation/Contraction Due to the Effect of Changes in Pressure and Temperature During the service life of a well, tubing can experience various combinations of pressures a n d temperatures that result in tubing length changes. The four basic effects to consider are as follows: 1. 2. 3. 4.

piston effect helical buckling effect b a l l o o n i n g a n d reverse b a l l o o n i n g effect temperature change effect

The t u b i n g movement due to piston effect is

ALI

=

[(Ap-Ai)APi-(AP

-A°)AP°]

EA,

L

(4-333)

T u b i n g movement due to helical buckling is

AL 2 = -

8EI(W.

r2F~ + W i

-

Wo)

(4-334)

where

I = ~4(OD4 - ID 4)

Ff = (AP i - APo)A P Note: If Ff < 0, AL2 = 0. The t u b i n g movement due to b a l l o o n i n g effect is

V Api - R2A9° ALs =

E

1 + 2V 8 2v L~ _ 2v Api - R~Apo L R2 - 1 E R2 - 1

(4-335)

The t u b i n g movement due to change in t e m p e r a t u r e is AL4 = [3LAT

(4-336)

Two approaches can be used to handle tubing movement: 1. Provide seals of enough length. 2. Slack off e n o u g h weight of t u b i n g to prevent movement. For practical purposes a c o m b i n a t i o n of the approaches m e n t i o n e d above can be applicable.

T u b i n g a n d T u b i n g String Design

1253

If slack off weight is applied, the tubing c o m p e n s a t i n g movement is calculated from AL 5 = LFs ~ r2F~ EA s 8EI(Ws + Wi _ Wo )

(4-337)

Notations used in the above equations are area c o r r e s p o n d i n g to tubing ID in in3 area c o r r e s p o n d i n g to tubing OD in in3 A = area c o r r e s p o n d i n g to packer b o r e in in3 cross-sectional area of the tubing wall in i n ? s F f = fictitious force in presence of no restraint in the packer in lb r I = moment of inertia of tubing cross-section with respect to its diameter in in.* L = length of tubing in in. P i , P o = pressure inside and outside the tubing at the packer level respectively in psi AP e AP o = change in pressure inside and outside of tubing at the packer level in psi Ap~, Apo = change in pressure inside a n d outside of tubing at the surface in psi R = ratio O D / I D of the tubing r = tubing and casing radial clearance in in. APi = change in density of liquid in the tubing in l b m / i n ? change in density of liquid in annulus in l b m / i n ? coefficient of t h e r m a l expansion of the tubing material (for steel, 13 = 6.9 x 10-6/°F) W s = average (i.e., i n c l u d i n g coupling) weight of tubing p e r unit length in l b / i n . Wi= weight of liquid in the tubing p e r unit length in l b / i n . W = weight of outside liquid displaced p e r unit length g: drop of pressure in the tubing due to flow p e r unit length in psi/in. A T = change in average tubing t e m p e r a t u r e in °F V = Poisson's ratio of the tubing material (for steel, v = 0.3) E = Young's modulus (for steel, E = 30 x 106 psi) A i = A ° =

N o m e n c l a t u r e used is as in the p a p e r by A. Lubinski et al. [171].

Example 1 Calculate the e x p e c t e d m o v e m e n t of t u b i n g u n d e r c o n d i t i o n s as specified below. Initially b o t h t u b i n g a n d annulus are filled with a c r u d e of 30°API. Thereafter, the c r u d e in the tubing is replaced by a 15-1b/gal cement slurry to p e r f o r m a squeeze c e m e n t i n g o p e r a t i o n . While the squeeze cementing j o b is p e r f o r m e d , pressures Pi = 5,000 psi a n d Po = 1,000 psi are a p p l i e d at the surface on the tubing a n d annulus respectively. Tubing: 2 ~ in; 6.5 l b / f t Casing: 7 in.; 32 lb/ft (r = 1.61 in.) A ° = 6.49 in?, A i = 4.68 in?, A s = 1.81 in3 Ratio of O D / I D of tubing, R = 1.178

1254

A

Drilling a n d Well Completions

= 8.30 in. 2

L~ngth of tubing = 10,000 ft (120,000 in.) Average change in temperature: - 2 0 ° F Pressure drop due to flow is disregarded (5 -- 0)

Solution Pressure changes are the following. At the surface the pressures are Api = 5,000 psi and APo = 1,000 psi. At the packer level, APi = 9,000 psi and APo = 1,000 psi. Liquid density changes are APi = 0.0332 p s i / i n , a n d APo = 0.0 p s i / i n . The unit weight of tubing is 6.5 + 1.5 x 4.68 12 231

W ~-- Ws + W i - W o = -

0 . 8 7 6 x 8 . 3 4 x 6.49 = 0.641b/in. 231

The moment of inertia is I = 1.61 in. 4 The tubing movement due to piston effect is AL, = 120,000 30 x 106 [(8.3 - 4 . 6 8 ) 9 , 0 0 0 - (8.3 - 6.49)1,000] = -68.0 in. T h e tubing movement due to buckling effect is

AL 2 =

(1.612) x ( 8 . 3 2 ) ( 9 , 0 0 0 - 1,000) 2 8 x 30 x 106 x 1.61 x 0.64 = -46.23 in.

T h e t u b i n g movement due to b a l l o o n i n g effect is 0.3 0. 0 3 3 2 - 0 (120,000)2 L~ = 10-----3 0 x ~ 1.1782_1

2 x 0.3 30x106

5,000 - (1.1782)1, 000 120, 000 = -34.69 in. 1.1782 - 1 T h e temperature effect is AL4 = -6.9 x 10 -6 x 120,000 x 20 = -16.56 in. The total expected t u b i n g m o v e m e n t is AL6 = AL, + AL2 + AL3 + AL4 = -165.48 in.

Packer-To-Tubing Force Certain types of packers permit no tubing motion in either direction. Depending u p o n operational conditions, a t u b i n g can be l a n d e d either in compression (slack off) or tension (pull up). L a n d i n g t u b i n g in compression is desirable if the expected t u b i n g movement would produce tubing s h o r t e n i n g while l a n d i n g in tension to compensate the expected tubing elongation.

Tubing and Tubing String Design

1255

Restraint of the tubing in the packer results in a packer-to-tubing force. To find the expected packer-to-tubing force, the following sequence of calculations is applicable: Ff = Ap (P~ - Po)

(4-338)

F = (Ap - Ai)P i - (Ap - Ao)P °

(4-339)

ALp = -AL 6

(4-340)

LFf EA

ALl =

r 2 Ff2 8EI(W~ + W i - W o )

(4-341)

ALl = ALl + ALp

(4-342)

If ALl is positive, then

~f =

ALfEA, L

(4-343)

If ALl is negative, then

41, L+ L Ar

1

(4-344)

and finally Fp = F f - Ff

(4-345)

Upon determining the packer to tubing force Fp, the actual force F~ immediately above the packer is given by F~ = F a + Fp

(4-346)

The symbols used are F a = actually existing pressure force at the lower end of tubing subjected to no restraint in the packer in lbf Ff = fictitious force in presence of no restraint in the packer in lbf F = actually existing force at the lower end of tubing in lbf Ff = fictitious force in presence of packer restraint in lb~ AL6 overall tubing length change in in. ALp = length change necessary to bring the end of the tubing to the packer =

Other symbols are as previously used.

Drilling and Well Completions

1256

Example 2 The operating conditions are the same as those described in Example 1. Assume that the packer does not permit any tubing movement at the packer setting depth (10,000 ft). Since tubing shortening is expected, a 20,000qb force is slacked off before the squeeze job. Find the tubing-to-packer force.

Solution Length change due to slack-off force is AL~ = 120,000 x 20,000 + (1.61) ~ x (20,000 ~) = 48.39 in. 30×106×1.81 8×30×106.×1.61×0.64 The overall tubing length change is AL6 = -165.48 + 48.39 = -117.09 in. The fictitious and actual forces are Ff = 8.3(12,800 - 4,800) = 66,400 lbf F a = 12,800(8.3 - 4.68) - 4,800(8.3 - 6.49) = 37,648 lbf Note: A positive sign indicates a compressive-type force, a negative sign indicates

a tensional force. ALp = -AL 6 = 115.5 in. ALf =

120,000x66,400_ (1.61~)x(66,400 ~) 30×106×1.81 8×30×106×1.61×0.64

=-192.9in.

ALl = -192.9 + 115.5 = -77.4 in. Since AL t is negative, the force Ft is calculated from Equation 4-344:

F t = 40.66[1~]_x(1.._~ x 1.61x L-120'000 + ((120'000)~

-

(1.81)~ (1_.61~)x_ 3_0 x_106 (_77.4))0.5] : 2xl.61x0.64 J ] 30,050.451bf

Since the force Ff is positive (compressive), a helical buckling o f tubing is expected above the packer. The tubing-to-packer force is Fp = Ff - Ff = 30,050.45 - 66,400 = 36,349.55 lbf

Corrosion and Scaling

1257

Permanent Corkscrewing To ensure that permanent corkscrewing will not occur, the following inequalities must be satisfied:

t, p.~ - 1 ) + t,

3 R

p.' - 1

+ a~ _+ a~

~ Vm

o) ~ + Pi R- ~R~Po - I + Oa +

(4-347)

< Ym

(4-348)

where Fa o~ - A-'-~

and

Ob = D x r ~f 4I

All symbols in Equations 4-347 and 4-348 are as previously stated.

CORROSION AND SCALING Introduction A great number of specialized tools have evolved in drilling of oil and gas wells utilizing very different alloys specially suited for their service requirements. The main concern in designing the drilling equipment is controlling the high pressures and the ability to resist fractures. The fractures can be induced by low-temperature service of the surface equipment and fatigue failures of subsurface equipment. Most of the drilling equipment components are made from AISI 4,100 and 4,300 series of steel alloys that are heat treated to specific strength and hardness necessary to their particular operation conditions. The blowout preventer (BOP) failures due to corrosion are very rare for two main reasons. First, as the BOP represents the primary method of preventing potential blowout under uncontrollable circumstances, they are usually overdesigned with very high structural integrity. The second reason is that the surface equipment usually does not experience very severe conditions in terms of corrosive environment and complexity of stress state. API Specifications 5A, 5AX, 5AC, 6A, and API RP 53 provide more information [176-180]. Although all equipment exposed to drilling fluids is affected by corrosion problems, it is beyond the scope of this discussion to cover all the corrosion problems. Thus, from this point on, the main discussion will be limited to subsurface equipment and concentrate on drillstring corrosion. This is due to the fact that the drillstring represents the largest capital expenditure, directly and indirectly during drilling operations. For more information on drillstring see the section titled "Drillstring Design" and API RP 76 [181]. The tool joints made by forging are heat treated by quenching and tempering. They are either friction welded or flash welded to the pipe body. For friction

1258

Drilling and Well C o m p l e t i o n s

welding, the tool j o i n t is rotated on the stationary p i p e body. This results in elevated contact pressure and t e m p e r a t u r e with subsequent welding. In flash welding both the p i p e and the tool j o i n t are held stationary while an electric current is i m p r e s s e d across the joint. Electrical resistance at the tool j o i n t and p i p e interface g e n e r a t e s e n o u g h heat to cause welding. A f t e r each welding process, postweld heat treatment is applied to the weld zone. T h e heat treatment improves the uniformity and structural p r o p e r t i e s o f the welded zone. Material used for tool joints is generally AIS 4100 series low-alloy steel, usually AISI 4135-4140, although AISI 4145H is also used sometimes. For a greater resistance to cracking in hydrogen sulfide e n v i r o n m e n t s AISI 4100 series alloy steels with i n t r o d u c t i o n o f m o l y b d e n u m and n i o b i u m are used for tool j o i n t construction. Tool j o i n t s are n o r m a l l y q u e n c h e d and t e m p e r e d to a hardness o f 30 to 37 Rockwell C, with resulting yield strengths o f 120-150 ksi. A c c o r d i n g to API Specification 7, Section 4, t e m p e r i n g is p e r f o r m e d for 2 hr at 1,1001,200°F to p r o d u c e the mechanical p r o p e r t i e s o f the new tool j o i n t s [182]. Drillstring subs are made from AISI 4140 or 4145H steel and sometimes from AISI 4340 or 4340H steel. T h e steel is q u e n c h e d and t e m p e r e d to a hardness range o f 285 to 341 Bhn. Drilling jars, stabilizers and, usually, core barrels are also m a d e from AISI 4140 or 4145H steel and sometimes AISI 4340 or 4340H steel is also used. T h e steel is heat treated to the hardness level o f 285 to 341 Bhn. T h e drill collars are m a d e o f AISI 4135-4140 or 4145H steel. T h e steel is q u e n c h e d and t e m p e r e d to hardness o f 285 to 341 Bhn. N o n m a g n e t i c drill collars are manufactured from various alloys, although the most c o m m o n are Monel K500 (approximately 68% nickel, 28% c o p p e r with some iron and manganese, and 316L austenitic stainless steel). A stainless steel with the c o m p o s i t i o n o f 0.06% carbon, 0.50% silicon, 17-19% manganese, less than 3.50% nickel, 12% c h r o m i u m , and 1.15% m o l y b d e n u m , with mechanical p r o p e r t i e s o f 110 to 115 Ksi tensile strength is also used. T h e drillpipes are available in various grades according to API spec 5A and 5AX [176,177]. G r a d e E d r i l l p i p e is heat treated by n o r m a l i z i n g and t e m p e r i n g and has almost the same chemistry as AISI 1040 or 1045 steels, with an addition o f 1.50% m a n g a n e s e and 0.20% molybdenum. G r a d e s X, G and S are q u e n c h e d and t e m p e r e d and contain 0.2 to 0.30% carbon, 1.20 to 1.5% manganese, 0.40 to 0.60% c h r o m i u m and 0.20 to 0.50% molybdenum. However, g r a d e S-135 may contain 0.27 to 0.35% carbon, 1.50 to 1.60% manganese, 0.10 to 0.50% chromium, 0.30 to 0.40% m o l y b d e n u m and 0.012 to 0.016% o f vanadium. Heavy-wall d r i l l p i p e has approximately twice the usual wall thickness and is usually m a d e from AISI 4140-4145H. T h e steel is q u e n c h e d and t e m p e r e d to the Rockwell C hardness o f various grades from 20 to 28 for g r a d e E, 27 to 30 for g r a d e X-95, 30 to 34 for g r a d e G-105 and 34 to 37 for S 135. A l u m i n u m d r i l l p i p e is generally m a d e o f 2014 type a l u m i n u m - c o p p e r alloy. C o m p o s i t i o n o f this alloy is 0.50 to 1.20% silicon, 1.00% iron maximum, 3.90 to 5.0% copper, 0.40 to 1.20% manganese, 0.25% zinc m a x i m u m and 0.05% titanium. T h e alloy is heat treated to T6 conditions that represent 64 ksi tensile strength, 58 Ksi yield strength, 7% e l o n g a t i o n and a H b n o f 135. A l u m i n u m d r i l l p i p e generally comes with steel tool j o i n t s that are t h r e a d e d on to ensure m a x i m u m strength that cannot be attained with a l u m i n u m joints. T h e rotary drill bits are generally made from quench and t e m p e r e d steel alloys such as AISI 3115 to 3120, 4620, 4815 to 4820 and 8620 to 8720. T h e only c o r r o s i o n related p r o b l e m that can arise may result from a hydrogen sulfide e n v i r o n m e n t . T h e b e a r i n g in t h e r o l l e r rock bits can be d a m a g e d by H~S c o n t a m i n a t i o n o f drilling fluid. However, a well c o n d i t i o n e d drilling fluid at

Corrosion and Scaling

1259

all times can control the problem. Failure of bits due to corrosion has not b e e n r e p o r t e d i n the l i t e r a t u r e . T h u s , from now on the d i s c u s s i o n will n o t b e c o n c e r n e d with drill bits.

Corrosion Theory Corrosion is the deterioration of a substance or its properties because of a reaction with its e n v i r o n m e n t . For our purposes, we can be a little more precise in this definition; therefore, corrosion is a destructive attack of a metal by either chemical or electrochemical reaction with a given e n v i r o n m e n t [183]. Most metals naturally occur as "ores" in the form of metallic oxides or salts. Refining the pure metal from these ores requires energy input. Different metals require varying a m o u n t s of energy for r e f i n i n g and, hence, show different tendencies to corrode. These tendencies are related to the driving voltage when the metal is placed in an aqueous solution a n d are called the potentials or the electromotive forces (emf) of the metal. The emf values of some selected metals are given in Table 4-169 [184]. This stored energy is released when the metal converts back to its original state-its "ore." Therefore, it is the energy stored in the metal during the refining process that makes corrosion possible. Figure 4-412 illustrates this process schematically. Thus, we can say that metals in general are relatively unstable with respect to most e n v i r o n m e n t s a n d have a natural t e n d e n c y to r e t u r n to their original state, or corrode.

Electrochemical Aspects of Corrosion In oilfield situations we are generally faced with corrosion attacks in aqueous e n v i r o n m e n t s . Basically all attacks in aqueous solutions are electrochemical in nature. This means that besides the chemical reaction there will also be a flow of electrons, resulting in a flow of current. The c u r r e n t flows from a higher potential to a lower one. Hence, there are two reactions taking place simultaneously in the system. O n e reaction occurs as the electrons are discharged from the surface, called the anode. The released electrons are c o n s u m e d in the other

Table 4-169 Electromotive Force Series of Metals Metal Most energy required for refining I

Least energy required for refining

Magnesium Aluminum Zinc iron Tin Lead Hydrogen Copper Silver Platinum Gold

Volts( I ) -2.37 Greatest tendency -1,66 to corrode -0.76 -0.44 -0.14 -0.13 0,00 +0,34 to +0.52 +0.80 +1.20 Least tenden©y -1.1.50 to "-1.68 •,o ¢orrod8

([)v$ standard hydrogen electrode. Source: From Ref. [184].

I

Refining

Hilling

\

r~

C3 0

~//////////A 0

== Steel

Zron Ore

/

lIron Oxidtl

Corroding Pipe

Pipe

Figure 4-412. Metallurgical cycle; all metals eventually corrode. (From Ref. [183].)

Corrosion and Scaling

1261

reaction at the surface, called the cathode. In order to complete the electrical circuit of the corrosion cell shown schematically in Figure 4-413 we need an aqueous solution called an electrolyte. T h e corrosion cell shown in Figure 4413 consists of the following four components:

1. Anode. As f o r e m e n t i o n e d , an a n o d e is the surface where oxidation or release of electrons takes place. Consequently the metal is corroded and goes into solution as metal ions. T h e chemical reaction for iron is Fe ~ Fe ~÷+ 2e-

2. Cathode. At the surface at which the reduction reaction occurs, the electrons are c o n s u m e d by oxidizing agents present in the aqueous solution. 2H ÷ + 2e- ~ H~

(in an acidic solution)

However, if oxygen is present, two other reactions may occur: O~ + 4H ÷ + 4e- ~ 2H~O O~ + 2H~O + 4e- ~ 4OH-

(acid solutions) (neutral a n d alkaline solutions)

3. Electrolyte. T h e a q u e o u s s o l u t i o n that s u p p o r t s the above reactions a n d completes the electrical circuit is called an electrolyte. Both electrodes must be completely submerged.

4. Electronic connector. T h e metallic path between the anode and the cathode that c o n d u c t s electricity o u t s i d e the electrolyte. In practice, the two

2e .-)

I

®

+

Anode

?-,athodc

t'~"~"~""~" A ~ ~ H . ~ eB Hydrogenions ere t2 reduced at the cathode to e~ + 4 j fomr H2 gas / MetalAis | ,, r~' j / oxidized(corroded)~. end goes into w~

Metal ~

Two electrons flow to Metal B

Q

i

--

The

Metal

Flow of corrodingcurrent corrodingsolution- electrolyte is water here

Figure 4-413. Electrochemical corrosion of metals.

1262

Drilling a n d Well Completions electrodes may be a part of the same metal as shown in Figure 4-414. This could be due to small variations in metallurgy, surface films, etc.

Many factors and conditions affect the tendency of metals to corrode. Once the right conditions and all the c o m p o n e n t s are present, corrosion may proceed in o n e or more forms. Before c o n s i d e r i n g the a f o r e m e n t i o n e d points, it is necessary to consider the concepts of polarization and passivity. Polarization

A n electrochemical reaction is said to be polarized or retarded when it is limited by various physical a n d chemical factors. In other words, the reduction in p o t e n t i a l d i f f e r e n c e in volts d u e to n e t c u r r e n t flow b e t w e e n the two electrodes of the corrosion cell is termed polarization. Thus, the corrosion cell is i n a state of n o n e q u i l i b r i u m d u e to this polarization. Figure 4-415 is a schematic illustration of a Daniel cell. The potential difference (emf) between zinc a n d copper electrodes is about one volt. U p o n allowing current to flow through the external resistance, the potential difference falls below one volt. As the current is increased, the voltage continues to drop a n d u p o n completely short c i r c u i t i n g (R = 0, therefore m a x i m u m flow of c u r r e n t ) the potential d i f f e r e n c e falls toward a b o u t zero. This p h e n o m e n o n can be plotted as a polarization diagram shown in Figure 4-416. The overall reaction is controlled by the slowest reaction, anodic or cathodic. If the slower reaction is anodic or the polarization occurs mostly at the anode,

Iron H

H0

H0

Eleclrolyle

F i g u r e 4-414. Schematic of local anode and cathode on a steel surface.

(From Fief [185].)

C o r r o s i o n a n d Scaling

1263

the c o r r o s i o n reaction is said to be "anodically controlled". This can be seen in Figure 4-417a; as c o r r o s i o n potential E c is closer to the o p e n circuit potential o f the cathode, therefore, the reaction is u n d e r anodic control. W h e n the slower reaction is cathodic and polarization occurs mostly at the cathode, the corrosion rate is "cathodically controlled". In this case corrosion potential is near the opencircuit a n o d e potential, as shown in Figure 4-417b. Resistance o f the electrolyte and resistance o f polarization o f the electrodes limits the current m a g n i t u d e that can flow through the cell. Thus, the reaction is said to be u n d e r resistance control when the electrolyte resistance is so high that the c u r r e n t p r o d u c e d is not enough to polarize either the c a t h o d e o r the anode, Figure 4-417c. T h e c o r r o s i o n current in this situation is u n d e r the i n f l u e n c e o f IR drop. IR d r o p

R

4:"

CuSO~

ZnS04

Figure 4-415. Polarized copper-zinc cell. (From Ref. [186].)

/mat Log current

11

Figure 4-416. Polarization diagram for copper-zinc cell. (From Ref. [186].)

1264

Drilling a n d Well Completions

simply means a voltage or potential drop in an electrochemical cell due to the resistance in the electrolyte or other resistances, such as insulations or coatings. Finally, if the p o l a r i z a t i o n occurs at b o t h the a n o d e a n d the cathode, the reaction is u n d e r mixed control as seen in Figure 4-417d. Polarization can be divided into "activation polarization" a n d "concentration polarization". Activation polarization is an electrochemical reaction that is controlled by the reaction occurring on the metal-electrolyte interface. Figure 4-418 illustrates the concept of activation polarization where hydrogen is being reduced over a zinc surface. Hydrogen ions are adsorbed on the metal surface; they pick up electrons from the metal a n d are reduced to atoms. The atoms c o m b i n e to

~

(~cofr

m

¢~co,r [-- -- -- --

I Log current lc°rr Cathodic control

I¢=, Anodic control

(b)

(a)

~c

I=o,, R

~=orr

;=o,, Resistance control

(c) Figure

leo,, Mixed control

(d)

4-417.Typesofcorrosioncontrol(From . Ref. [186].)

Corrosion and Scaling

1265

form molecules of hydrogen and the molecules combine to form gas bubbles. The gas bubbles at the cathode decrease the corrosion rate as they keep other hydrogen ions from reaching the metal surface. Activation polarization is usually the controlling factor when high concentrations of active species (i.e., concentrated acids) are involved in the corrosion process. Concentration polarization is an electrochemical process controlled by the diffusion within the electrolyte. Figure 4-419 illustrates the concept of corrosion process under concentration polarization control. Considering hydrogen evolution at the cathode, reduction rate of hydrogen ions is dependent on the rate of diffusion of hydrogen ions to the metal surface. Concentration polarization therefore is a controlling factor when reducible species are in low concentrations (e.g., dilute acids). Although the above discussion is a very simplified picture of the polarization process, it does give a basic u n d e r s t a n d i n g of the processes involved. It is essential to determine which kind of polarization is controlling the reduction reaction. For example, any change in the system that increases the diffusion rate of the reducible species will increase the reduction rate under concentration polarization-control. However, this change will not have any affect on the activation-polarization-controlled reduction process. Thus, in order to control the corrosion rate, it is important to know exactly what types of reactions are occurring, and considering the polarization of the corrosion cell helps in doing just that.

Passivity Passivity is the loss of chemical reactivity of certain metals and alloys under specific environmental conditions. In other words, certain metals (e.g., iron, nickel, chromium, titanium, etc.) become relatively inert and act as noble metals (e.g., gold and platinum). Figure 4-420 shows the behavior of a metal immersed in an air-free acid solution with an oxidizing power corresponding to point A

@ 4

z,°0

\

Figure 4-418. Hydrogen-reduction reaction under activation control (simplified). (From Ref. [183].)

1266

Drilling and Well Completions Diffusion

//\\\-°T

e e

Figure 4-419. Concentration polarization during hydrogen reduction. (From

Ref. [183].)

o o

=.g :6 o

O

I

10

I

I

tO0 1,000 Corrosion rote

I

t0,000

Figure 4-420. Corrosion rate of a metal as a function of solution oxidizing power (electrode potential). (From Ref. [183].)

and a corrosion rate corresponding to this point. If the oxidizing power of this solution is increased, by adding oxygen or ferric ions for example, the corrosion rate increases rapidly. This rate increase is exponential and often yields a straight line when it is plotted on a semilogarithmic scale. Figures 4-421 and 4-422 illustrate the behavior of a metal which demonstrates passivity effects. The behavior of this specimen exhibits three distinct regions: active, passive and transpassive. In the active region, the specimen behaves exactly the way it did in Figure 4-420. As the oxidizing power of the solution increases, the corrosion rate suddenly decreases and the

Corrosion and Scaling

1267

Tronspossive

t

Possive

Solution oxidizing power (electrode potentiol

Actt--ive I 10

I 1OO Corrosion rote

I 10OO

I t 0,000

Figure 4-421. Corrosion characteristics of an active passive metal as a function of solution oxidizing power (electrode potential). (From Ref. [183].)

t

4

¢1: IJJ O,.J 0,<[ (3 I-'Z Z m gJ m

Nt-. C30

X

I

2

Z

O0

ILl - -

-.0

[

3

1

~0

~

Fe

0 10 -2

1

102

104

106

CORROSION RATE (MPY) Figure 4-422. Corrosion characteristics of iron and 18% Cr stainless steel in dilute sulfuric acid and as a function of solution oxidizing power (corrosion potential). (From Ref. [187].)

1268

Drilling a n d Well C o m p l e t i o n s

b e h a v i o r enters the passive zone. F u r t h e r increase in oxidizing power of the solution p r o d u c e s hardly any change in c o r r o s i o n rate. However, at a very high c o n c e n t r a t i o n of oxidizers the c o r r o s i o n rate starts to increase rapidly as the b e h a v i o r enters the transpassive zone. It is not fully u n d e r s t o o d why metals exhibit active-passive-transpassive transitions, although it is thought that it is a special case of activation polarization. This is due to the formation of an inert surface film or a protective barrier, which fails in very strong oxidizing solutions. T h e r e are various theories on how passive films are formed; however, there are two c o m m o n l y accepted theories. O n e t h e o r y is called the oxide film theory a n d states that the passive film is a diffusion-barrier layer of reaction p r o d u c t s (i.e., metal oxides or o t h e r compounds). The b a r r i e r s s e p a r a t e the metal from the hostile e n v i r o n m e n t and thereby slow the rate of reaction. A n o t h e r t h e o r y is the adsorption theory of passivity. This states that the film is simply a d s o r b e d gas that forms a b a r r i e r to diffusion of metal ions from the substrata. C o n s i d e r i n g Figure 4-421 we can conclude that metals that exhibit passivity can be used in moderately to strongly oxidizing environments. In highly oxidizing e n v i r o n m e n t s they will lose their corrosion-resistant p r o p e r t i e s and, therefore, cannot be used. It is, however, possible to passivate some metals by exposing t h e m to passivating e n v i r o n m e n t s (i.e., iron in c h r o m a t e or nitrite solutions) or by anodic polarization at sufficiently high-current densities (i.e., in H2SO4). The desired passivity can be achieved by a p p r o p r i a t e alloy additions to the metal. F i g u r e 4-422 illustrates t h e c o r r o s i o n b e h a v i o r of iron (Fe) a n d c h r o m i u m stainless steel. Introducing 18% chromium to iron reduces the amount of oxidizer necessary to achieve passivity. The a d d i t i o n of c h r o m i u m to iron also reduces the corrosion rate in the passive state. P r o p e r alloying is an effective way to improve the c o r r o s i o n resistance of a metal.

Forms of Corrosion Attack C o r r o s i o n may take various forms and may combine o t h e r forms of damage (erosion, wear, fatigue, etc.) to cause e q u i p m e n t failure. The forms of c o r r o s i o n most encountered in drilling equipment are uniform corrosion and galvanic corrosion.

Uniform Corrosion All h o m o g e n e o u s metals without differences in potential between any points on their surfaces are subject to this type of general attack u n d e r some conditions. Uniform corrosion is usually characterized by a chemical or electrochemical attack over the entire e x p o s e d surface, Figure 4-423. Metal c o r r o d e s in an even

Original surface -,e-----/

Gas or liquid corrodent /

Figure 4-423. Uniform corrosion. (From Ref. [185].)

Corrosion and Scaling

1269

and regular m a n n e r b e c o m i n g thinner, and consequently leads to failure due to reduction of the material's load-carrying capabilities. The rate of p e n e t r a t i o n or the t h i n n i n g of a structural m e m b e r can be used directly to predict the service life of a given c o m p o n e n t . Therefore, the expression mils p e n e t r a t i o n per year (mpy) is used to express corrosion resistance directly in terms of penetration. This expression can be calculated by the following [185,186]:

mpy where W D A T

534W DAT = = = =

(4-349)

weight loss in mg density of specimen in g / c m 3 area of specimen in inY exposure time in hr

Using the value of mpy, we can classify metals into three categories according to the corrosion rates and intended applications. The categories are the following: < 5 m p y - M e t a l s in this group have good resistance to corrosion and are quite suitable for use as critical e q u i p m e n t parts. 5 to 50 m p y - M e t a l s in this group have an acceptable corrosion resistance if a higher rate of corrosion is tolerable. > 50 m p y - M e t a l s of this group are usually not acceptable for service use. This form of corrosion is not of great concern from the engineering aspect, as the service life can be estimated within reasonable accuracy. Uniform corrosion can be prevented or reduced by using the following methods singly or in combination: • proper selection of materials for the types of service e n v i r o n m e n t s and conditions • proper selection of inhibitor • proper selection of coatings • cathodic protection These methods will be discussed in more detail.

Galvanic Corrosion Galvanic corrosion occurs when two dissimilar metals or alloys come into electronic contact in a conductive solution. The severity of galvanic corrosion d e p e n d s primarily on the difference in solution potentials b e t w e e n the two materials and the relative sizes of the cathode and the a n o d e areas. The farther apart these metals are from each other in the galvanic series, the greater the possible corrosion of the anodic m e m b e r of the galvanic couple. The galvanic series for some commercial metals and alloys in seawater is shown in Table 4-170. Figure 4-424 shows schematically an example of galvanic corrosion [186,187]. Species with more positive corrosion potential, located toward the bottom of the series, are called noble or cathodic metals and alloys. Those species with more negative corrosion potential located toward the top of the series are referred to as active or anodic metals and alloys. Conductive films such as "magnetite" (FesO4) or "mill scale" on steel, and conductive nonmetals such as carbon can function as cathodes when in contact with anodes

1270

Drilling and Well C o m p l e t i o n s

Table 4-170 Galvanic Series of Some Commercial Metals and Alloys in Seawater Active or Anodic (-)

Magnesium Magnesium Alloys Zinc Galvanized Steel Aluminum 1100 Aluminum 2024 (4.5 Cu, 1.5 Mg, 0.6 Mn) Mild Steel Wrought Iron Cast Iron 13% Chromium Stainles Steel Type 410 (Active) 18-8 Stainless Steel Type 304 (Active) Lead-Tin Solders Lead Tin Muntz Metal Manganese Bronze Naval Brass Nickel (Active) 76 Ni-16 Cr-7 Fe Alloy (Active) 60 Ni-30 Mo-6 Fe-1 Mn Yellow Brass Admirality Brass Red Brass Copper Silicon Bronze 70:30 Cupro Nickel G-Bronze Silver Solder Nickel (Passive) 76 Ni-16 Cr-7 Fe Alloy (Passive) 13% Chromium Stainless Steel Type 410 (Passive) Titanium 18-8 Stainless Steel Type 304 (Passive)

Noble or Cathodic (+)

Silver Graphite Gold Platinum

Source: From Ref. [187].

of clean metal. Aluminum drillpipes can experience localized galvanic corrosion attack resulting in pitting. The attack generally occurs immediately adjacent to the steel tool joints. Although not very severe, the extent of attack depends on salt concentration of the drilling fluid and exposure time. One reason the attack is not very severe is the favorable anode-to-cathode surface area ratio. That is, the

Corrosion a n d Scaling

1271

Noble bolt material ! Less noble plate

Figure 4-424. Galvanic corrosion. (From Ref. [185].) aluminum anode surface area is much larger than the steel cathode surface area. Galvanic corrosion becomes very serious when an a l u m i n u m drillpipe string rests against the steel casing for long periods of time (e.g., stuck drillstring). The anode-to-cathode surface area ratio is unfavorable in this situation. The condition develops galvanic corrosion a n d results in severe pitting attack of a l u m i n u m . To prevent or reduce galvanic corrosion we can employ several techniques. Any one of these techniques may be used either by itself or in c o m b i n a t i o n of two or more of the techniques. These techniques are as follows: 1. If a metal or alloy c o m b i n a t i o n is to be selected, choose c o m b i n a t i o n of metals as close together in the galvanic series as possible. 2. Choose the metal or alloy so that the anode area is larger than the cathode area. 3. I f any dissimilar metals are in c o n t a c t with each other, isolate t h e m electrically so that no electricity flows between them. 4. Apply proper coatings with caution, and keep the coatings in good repair. 5. Add proper inhibitors with appropriate practices. 6. Avoid threaded joints for materials that are far apart in galvanic series. 7. Anodic parts should be designed so that they are easily replaceable. They may also be designed thicker than what is required to extend their service life.

Localized Attack Any normally-employed metal surface is a composite of anodic and cathodic sites. These electrodes are electrically short-circuited through the body of the metal itself (Figure 4-425). As long as the metal surface does not come into contact with an electrolytic solution, there is no flow of current. However, exposure of the metal to an electrolyte results in a flow of electric c u r r e n t accompanied by corrosion of the anodic areas. The flowing current of this kind is called a local-action current and the c o r r e s p o n d i n g cell is called local-action cell Local-action cells are set u p when there are h e t e r o g e n e i t i e s a n d / o r other e n v i r o n m e n t a l variations present. Table 4-171 illustrates geometrical factors and heterogeneities in relation to localized attack [188].

Pitting Attack Pitting is a form of extreme, localized attack. The rate of corrosion is greater at some areas than at others, resulting in holes in the metal. Heterogenous metal

1272

Drilling a n d Well C o m p l e t i o n s

Figure 4-425. Metal surface enlarged, showing schematic arrangement of local action cells. (From Ref. [19510 or alloy surfaces are susceptible to such kinds of attack. It can also occur u n d e r deposits of foreign m a t t e r or at i m p e r f e c t i o n s in a protective film or coating. Pitting is o n e of t h e most d e c e p t i v e and, hence, most destructive forms of corrosion. It is often very difficult to detect the problem. It is also very hard to predict the severity of the p r o b l e m as it is to m e a s u r e quantitatively since the pits vary in size, d e p t h a n d frequency. S u d d e n failures occur as the perforations p e n e t r a t e d e e p into the metal, creating weak areas. D e p t h of pitting can be expressed by a term k n o w n as the pitting factor. Pitting factor is the ratio of the deepest metal p e n e t r a t i o n to average metal p e n e t r a t i o n calculated by the overall weight loss. A pitting factor of unity represents u n i f o r m attack. This factor is [186] P Pitting factor = - d

(4-350)

where P = d e e p e s t metal p e n e t r a t i o n in m m d = average metal p e n e t r a t i o n in m m Figure 4-426 shows a geometric representation of the terms in the above equation. A l t h o u g h the pitting factor gives us a rough estimate of the pit damage, it by no means enables us to predict the service life of the equipment. Figure 4427 illustrates t h e p i t t i n g f o r m of attack. Pits can cause washouts a n d serve as i n i t i a t i n g p o i n t s for f a t i g u e cracks. Chlorides, oxygen, c a r b o n dioxide, a n d hydrogen sulfide or any c o m b i n a t i o n of these c o r r o d e n t s may contribute to this form of attack. To minimize the attack or prevent it, the following points should be considered: • Avoid materials p r o n e to pitting. • Use p r o p e r inhibitors carefully, as i m p r o p e r use may result in an accelerated attack. • Avoid stagnant areas in design. • Use p r o p e r h a n d l i n g practices for e q u i p m e n t - a v o i d d a m a g i n g protective film, avoid nicks or scratches, etc.

C o r r o s i o n a n d Scaling

1273

Table 4 - 1 7 1 Geometric Factors and Heterogeneities in Relation to Localized Attack System

Metal Area which Is Predominantly Anodic*

Dissimilar metals in contact.

Metal which is more reactive in a given solution (i.e., metal which has a greater tendency to ionize).

Crevices, deposits on metal surface or any geometrical configuration which results in differences in the concentration of oxygen or other cathodic depolarizers (e.g., Cu2*).

M e t a l in contact with the lower concent r a t i o n - t h i s follows from considerations of an equivalent reversible cell, although the situation is more complex in practice.

Differences in metallurgical structure.

Grain boundaries, more reactive phases (solid solutions, intermetallic compounds, etc.).

Differences in metallurgical condition due to thermal or mechanical treatment.

Cold worked areas anodic to annealed areas, metal subjected to external stress anodic to unstressed metal.

Discontinuities in conducting oxide film or scale or discontinuities in applied metallic or non-metallic coatings.

Exposed substrate (provided that this is more electrochemically active than the coating).

Metal

Environment Differences in aeration or concentration of cathodic depolarizers.

Metal in contact with lower concentration.

Differences in velocity.

Metal in contact with solution of higher velocity.

Differences in pH or salt concentration.

Metal in contact with solution of lower pH or higher salt concentation.

*The table gives a general indication of the area which is likely to be anodic. There are many exceptions, e.g., grain boundaries can be cathodic, the area of metal in contact with a higher salt concetration will be cathodic if the oxygen concentration is higher, etc. Source: From Ref. [188].

• Maintain g o o d and regular inspection p r o g r a m s and, at frequent intervals, remove any deposits formed. • A r r a n g e as u n i f o r m an e n v i r o n m e n t as possible.

Intergranular Corrosion I n t e r g r a n u l a r c o r r o s i o n is a localized type o f attack at the g r a i n boundaries, with relatively little c o r r o s i o n o f the grains. T h e metal or the alloys lose their strength, ductility and eventually disintegrate (grains fall off). Relatively small areas o f g r a i n - b o u n d a r y material act as anodes, and are in contact with larger areas o f g r a i n material, the cathodes. The attack can be caused by impurities at the grain boundaries, enrichment o f one o f the alloying elements, or depletion o f one o f these elements in the g r a i n - b o u n d a r y areas. This type o f attack is

1274

Drilling and Well C o m p l e t i o n s

_,__,

Pitting factor = --P d

Figure 4-426. Sketch of deepest pit with relation to average metal penetration and the pitting factor. (From Ref. [186].) ~

Corrodent

Figure 4-427. Pitting corrosion. (From Ref. [185].) c o m m o n on i m p r o p e r l y h e a t - t r e a t e d m e t a l s a n d t h e i r alloys. F i g u r e 4-428 schematically illustrates i n t e r g r a n u l a r c o r r o s i o n [183]. I n t e r g r a n u l a r c o r r o s i o n can be p r e v e n t e d o r m i n i m i z e d by the following considerations: • • • • •

Choose p r o p e r treatment for the e n v i r o n m e n t a l conditions o f service. Use p r o p e r l y heat-treated metals and alloys. Use materials that contain strong carbide-formers, the stabilizers. Use low-carbon g r a d e materials. Avoid high-strength a l u m i n u m alloys.

Erosion Corrosion Most metals a n d their alloys are susceptible to erosion corrosion as various m e d i a may p r o v i d e the r i g h t c o n d i t i o n s for it. Many m e t a l s d e p e n d on a protective oxide film o r tightly-adherent deposit for corrosion resistance. Erosion c o r r o s i o n o c c u r s w h e n t h e p r o t e c t i v e f i l m s o r d e p o s i t s a r e r e m o v e d by mechanical wear effects o f abrasion. O n c e the protective surface is damaged, accelerated corrosive attack occurs at the fresh metal surface. T h e damage d o n e by this form of corrosion appears as grooves, gullies, waves, r o u n d e d holes, pits and valleys, and generally, exhibits a directional pattern. Figure 4-429 illustrates erosion c o r r o s i o n schematically [185]. T h e r e are basically five ways to reduce or prevent erosion corrosion: • Choose materials with a high resistance to erosion and wear. • Keep erosion corrosion in m i n d while designing the equipment.

C o r r o s i o n a n d Scaling

~

i

n

1275

boundaries corroded

Figure 4 - 4 2 8 . I n t e r g r a n u l a r c o r r o s i o n of s e n s i t i z e d ( i m p r o p e r l y a n n e a l e d ) s t a i n l e s s steel. (From Ref. [185].)

Woterflow Corrosion film l: :-

':"

".'I .

.

Originalmetal surfoce /

Impingement corrosion pits I / /

/. /

.

.

Z

......

._r rr_' " '," :" "" :::l."" 7,

Figure 4 - 4 2 9 .

Erosion corrosion.

(From Ref. [183].)

• Use p r o p e r coatings. • A l t e r e n v i r o n m e n t - - a d d inhibitors, remove abrasives as soon as possible.

• Use cathodic protection wherever possible. This does not affect the erosion p a r t o f the attack, b u t it may reduce the corrosive attack.

Cavitation Corrosion Cavitation is a special form of erosion c o r r o s i o n results from f o r m a t i o n a n d collapse o f vapor bubbles in a liquid near a metal surface. Collapsing b u b b l e s destroy the protective surface film, thereby e x p o s i n g the metal to i n c r e a s e d c o r r o s i o n attack. Cavitation c o r r o s i o n is shown schematically in Figure 4-430. Cavitation damage is often seen in high-velocity, turbulent, liquid-flow areas such as drilling-mud pumps. To reduce p r o b l e m s associated with this kind of corrosion, m e t h o d s d e s c r i b e d for e r o s i o n c o r r o s i o n s h o u l d b e c o n s i d e r e d . Also materials with high hardness a n d strength with tenacious passive films should be used. Titanium and corrosion-resistant, cobalt-base alloys a p p e a r to be suitable for a wide range o f e n v i r o n m e n t s causing cavitation erosion [184].

Rlngworm Corrosion D u r i n g hot-forming or u p s e t t i n g o p e r a t i o n s the steel is subjected to large t e m p e r a t u r e gradients. These thermal gradients cause variations in metallurgical c o m p o s i t i o n a l o n g the pipe. In t h e s e c t i o n s e x p o s e d to i n t e r m e d i a t e temperatures, the iron carbides condense, f o r m i n g spheroids. D u r i n g exposure to corrosive e n v i r o n m e n t this narrow section c o r r o d e s preferentially, as shown in

1276

Drilling and Well C o m p l e t i o n s

A bubble collapses and a liquid jet results

0

|

t:

~ J~ .'I~ i ~

.

0

Figure 4-430. Cavitation corrosion. (From Ref. [185].)

Figure 4-431. This type o f attack can be completely eliminated by annealing the entire length o f the pipe after forging. T h e a n n e a l i n g results in a u n i f o r m metallurgical structure t h r o u g h o u t the length o f the pipe [184,186].

Concentration Cells C o n c e n t r a t i o n cells have two similar electrodes in contact with a solution o f differing composition. T h e two kinds o f c o n c e n t r a t i o n cells are salt concentration cells and differential a e r a t i o n cells [186].

Salt Concentration Cells. In

this type o f cell the two electrodes are o f the same metal (i.e., copper). These electrodes are i m m e r s e d completely in electrolytes o f the same salt solution (i.e., c o p p e r sulfate) but o f different concentrations. W h e n the cell is short circuited, the electrodes (anode) e x p o s e d to the dilute solution will dissolve into the solution and plate the electrode (cathode) exposed to the m o r e c o n c e n - t r a t e d solution. T h e s e r e a c t i o n s will c o n t i n u e until the solutions are o f the same concentration. Figure 4-432 shows a schematic o f a salt c o n c e n t r a t i o n cell.

Differential Aeration Cells. This type o f c o n c e n t r a t i o n cell is m o r e i m p o r t a n t in practice than is the salt c o n c e n t r a t i o n cell. T h e cell may be m a d e from two electrodes o f the same metal (i.e., iron), immersed completely in dilute sodium chloride solution (Figure 4433). T h e electrolyte a r o u n d one electrode (cathode) is thoroughly a e r a t e d by b u b b l i n g air. Simultaneously the electrolyte a r o u n d the o t h e r electrode is d e a e r a t e d by b u b b l i n g nitrogen. T h e difference in oxygen c o n c e n t r a t i o n causes a d i f f e r e n c e in p o t e n t i a l . This, in turn, i n i t i a t e s t h e flow o f current. This type o f cell exists in several forms. Some o f t h e m are as follows [188]. Crevice Corrosion. Crevices are f o r m e d at the interface o f two coupled pipes, near the ends o f drillpipe protectors, at t h r e a d e d connections and where surface

Corrosion and Scaling

1277

.... . ....... .,:~:~:

• ,. t . . . .

"....~ ,,.~

.

" 'i4 ~ri;-"

,e ; • : . , l i t . I,

~i'-~!.]~ :~::* J.:5.1~ L". t • ~-~i,~.

• ..'i~...~.

?,'e~i"

~.'~C,.".. "..,v~. ,. , ,. .. . . . .-...~~., ~..~.

~.,...

j ." . . . . /'..:.~2

,~ ',.: ~,'.V..:...;'~ ~..,~.,

I ' ~ , ~ " "-.'.~.i::

~:.=. ..,.~ ~1}%-. .,.,,, !"

11

,

Figure 4-431. "Ringworm" corrosion--at the inside of the tubing where grain structure near edge of upset portion makes metal susceptible to rapid corrosion. (From Ref. [219].)

imp

4-

It It Dil, CuS04

Conc. CuS04 ,,=

Figure

4-432. Salt concentration cell. (From Ref. [186].)

1278

Drilling and Well Completions

deposits create rate inside the in the crevice corrosion rate.

stagnant conditions. Oxygen may be consumed at a much faster crevice than it can diffuse into the crevice. This lowers the pH and creates acidic conditions, which, in turn, increases the Figure 4-434 illustrates the concept schematically.

Oxygen Tubercles. Similar to crevice attack, it is encouraged by the deposit of a layer, semipermeable to oxygen (porous layer of iron oxide or hydroxide).

N=

Air

/

\

\

+

i

m

1

I I I I I I I

'I Dil.

Figure 4-433.

NaC]

Dil.

NaCl

Differential aeration cell. (From Ref. [186].)

__~ 02 ..,,.r0 2\.~F,~I NaOH formed .,or. Dilute NaC[

x Xxx ~ x x~ ~

FeCI2 . . . / ~ formed here

x Xx x Rust ~ x ,~,.. precipitated

here

~~

Figure 4-434. Differential aeration cell illustrated by waterline corrosion. (From Ref. [185].)

C o r r o s i o n and Scaling

1279

T h e deposit partially shields the steel surface, creating a differential a e r a t i o n cell (Figure 4-435).

Air-Water Interface. This is a n o t h e r g o o d example o f a differential aeration cell (Figure 4-436). H e r e the water at the surface contains m o r e oxygen than the water slightly below the surface. This difference in concentration can cause preferential attack j u s t below the waterline.

Scale Deposits Scale deposits create conditions for concentration-cell corrosion as they do not form uniformly over the metal surface. Sulfate-reducing bacteria thrive u n d e r these deposits, p r o d u c i n g hydrogen sulfide and, consequently, increasing the rate of corrosion. Due to the following factors, the drilling fluid environment is ideal for scale deposition [189]. T h e s e factors are as follows: • high p H levels • turbulent flow • pressure variations • t e m p e r a t u r e changes

NW//SN Figure 4-435. Differential aeration cell formed by rust on iron. (From Ref. [184].) High concentration

Dilute concentration and high oxygen content 0 2

o

M"

of metal ions and depletion o f o x y g e n

O

I///

Figure 4-436. Crevice corrosion. (From ReL [186].)

1280 • • • •

Drilling a n d Well C o m p l e t i o n s dissolution o f f o r m a t i o n salts influx o f carbon dioxide influx o f low-pH, high-total-dissolved-solid content a n d f o r m a t i o n fluids evaporation

Calcium c a r b o n a t e (CaCO3) calcium sulfate o r gypsum (CaSO 4) a n d iron(II) c a r b o n a t e (FeCOs) are the most c o m m o n types o f scales f o r m e d in drilling. If hydrogen sulfide is present, then there is a possibility o f iron sulfide (FeS) scale depositing. From the corrosion point o f view, it is very important to control the deposition o f scale. Removal o f deposited scale by mechanical means is the first step. Standard, industrial water-treating techniques can be used to control scale deposition in general. In deep, hot wells o r geothermal wells it is best to avoid untreated makeup water (i.e., geothermal brines). To prevent o r m i n i m i z e p r o b l e m s associated with c o n c e n t r a t i o n cells, the following m e t h o d s should be c o n s i d e r e d in general: • • • • • • •

Welded butt j o i n t s should be used instead o f b o l t e d o r riveted ones. Existing crevices should be closed by soldering, welding o r caulking. Stagnant conditions should be avoided. "Solid" nonabsorbent gaskets such as Teflon should be used when necessary. P r o p e r use o f a p p r o p r i a t e inhibitors. Maintain regular inspections o f e q u i p m e n t a n d treatment status. Drillpipe protectors should be moved to different locations at each trip.

Hydrogen Damage In general corrosion, hydrogen ions (H ÷) are reduced to atomic hydrogen (H°). These hydrogen atoms c o m b i n e with each o t h e r a n d form molecular hydrogen [186,190,191]. 2H ÷+ 2e- ~ 2H ° ~ H~ 1" However, certain substances such as sulfide ions, p h o s p h o r u s a n d arsenic c o m p o u n d s reduce the rate at which hydrogen combines to form molecules. A t o m i c h y d r o g e n can diffuse t h r o u g h m e t a l m a t r i x a n d cause m e c h a n i c a l damage. Therefore, hydrogen damage is a mechanical damage o f metal caused by the presence o f atomic hydrogen. Some o f the forms o f hydrogen damage are as follows.

Hydrogen Blistering. P e n e t r a t i o n o f h y d r o g e n in l o w - s t r e n g t h steel with any discontinuities in the steel such as laminations, inclusions o r voids may result in hydrogen blistering. H y d r o g e n p r o d u c e d on the surface o f the metal evolves in part as gas bubbles a n d the rest diffuses t h r o u g h the metal. The different hydrogen atoms collect in the void, a n d c o m b i n e to form hydrogen gas molecules. H y d r o g e n gas molecules are too large to diffuse back t h r o u g h the metal. Thus, the gas concentration and pressure continue to increase within the void. In time, the gas pressure increases to sufficient levels to b u r s t out to the m e t a l surface. F i g u r e 4-437 s c h e m a t i c a l l y illustrates the m e c h a n i s m o f hydrogen blistering [183].

C o r r o s i o n a n d Scaling

1281

Electrolyte H~

H~

H -~ H2-~-H

H

H

H

H

H .-.~Hz.~-. H Air

Figure 4-437. The simplified mechanism of hydrogen damage. (From Ref. [191].)

Hydrogen EmbrltUement. H y d r o g e n e m b r i t t l e m e n t is a form of mechanical damage of a high-strength steel in a brittle failure. Limited to high-strength steels, the mechanism a n d cause are similar to those which cause hydrogen blistering. H y d r o g e n gas is t r a p p e d within the metal lattice, causing loss in ductility of the metal. Once ductility is r e d u c e d or lost, and the metal is subjected to high tensile stress, the metal will fail in a brittle manner. T h e path of the failure will be transgranular when the process takes place at n o r m a l temperatures when hydrogen diffuses through the grain, a n d gathers at inclusions, voids, or any other lattice defects. The failure is said to be integranular when the temperatures are higher and the a b s o r b e d hydrogen gathers at the grain boundaries [183,184]. To prevent or minimize hydrogen blistering a n d embrittlement, the following m e t h o d s should be considered: • • • • • •

P r o p e r use of a p p r o p r i a t e c o r r o s i o n inhibitors. Using suitable, more-resistant alloys for the environment. Practice p r o p e r welding techniques. Apply suitable coatings in a p r o p e r manner. Select steels with m i n i m u m voids or discontinuities. Remove "poisons" such as sulfide ions from the environment.

Hydrogen Sulfide Cracklng. Known also as sulfide stress cracking, the exact mechanism of this form of hydrogen damage is not yet fully understood. Thus, some experts classify it as a form of hydrogen embrittlement. Nevertheless, for hydrogen sulfide cracking of steel, the following conditions should b e present [186,192]:

1282

Drilling a n d Well Completions

• Hydrogen s u l f i d e gas, as low as one ppm. • Even traces of water are sufficient. • High-strength steel (i.e., yield strength above 90,000 psi or Rc 20 to 22). • The steel must be u n d e r residual or applied tensile stress. With the above conditions present, hydrogen sulfide stress cracking may take anywhere from a couple of hours to years to occur. Figure 4-438 illustrates some examples of typical hydrogen sulfide cracking failure, with a characteristic brittle fracture a n d final ductile-shear lip. Hydrogen sulfide stress cracking occurs on most nonferrous materials, for example a l u m i n u m alloys. Hydrogen sulfide stress cracking can occur if appropriate conditions such as high residual or applied tensile stress, corrosive environment and susceptible metallurgy exist simultaneously. To prevent or reduce the possibilities of problems associated with hydrogen sulfide cracking the following measures should be considered [184]: • Strength: steels with yield strength of 90,000 psi or less a n d Rc 22 hardness or less should be used. As the strength goes up, the time to failure goes down. This can be seen in Figure 4-439. • Reduce applied or residual stress levels. • Reduce hydrogen sulfide c o n c e n t r a t i o n levels. • Increase pH levels. Figure 4-40 shows that steel fails much less rapidly when the pH is above 7 or 8. • As the temperature goes above 150°F (66°C), the susceptibility to cracking decreases.

Stress Corrosion Stress-corrosion cracking occurs when a metal is u n d e r constant tensile stress and exposed simultaneously to a corrosive environment. The source of this stress can be external (caused by slip or tong notch, etc., on drillpipes, collars and tool joints, and the weight of the drill stem) or it can be residual in the metal from heat treatment or cold working. The area damaged by the slips becomes stressed and undergoes accelerated corrosion as it becomes anodic to the rest of the unstressed area of the pipe. The appearance of damage is of a brittle mechanical fracture, but it results from local corrosion attack. The cracks are i n t e r g r a n u l a r or t r a n s g r a n u l a r d e p e n d i n g on the metal structure a n d the corrosive e n v i r o n m e n t . Most structural metals and alloys are susceptible to this form of attack in specific environments. Cracks generally develop perpendicular to the applied stresses. They are randomly oriented and can vary in degree of b r a n c h i n g d e p e n d i n g on the metal structure and composition, the nature of stress and the corrosive e n v i r o n m e n t . Cracks vary from being totally branchless to extremely b r a n c h e d like the "river delta." As the stress increases, the time before failure decreases. It is speculated that there is a m i n i m u m stress required to prevent cracking, d e p e n d i n g on the alloy composition, e n v i r o n m e n t a l temperature and composition. The m i n i m u m stress may vary from 10% of the yield stress to 70% of the yield stress. Thus, for each alloy-environment c o m b i n a t i o n there is m i n i m u m or threshold stress [185]. It is very i m p o r t a n t to have some idea of the service life of a component. As stress corrosion proceeds, the cross-sectional area is reduced, resulting in a cracking failure d u e to m e c h a n i c a l action. Figure 4-441 shows the rate of cracking as a f u n c t i o n of crack d e p t h for a specimen subjected to constant tensile load. At first, the crack p r o p a g a t i o n rate is roughly constant; but as cracking progresses, the cross-sectional area decreases. Eventually, the rate of

Corrosion and Scaling

1283

{a}

[b)

{¢}

Figure 4-438. SSC failure, drillpipe (a); tubing failure (b); coupling (c). (From Refs. [184,218].)

1284

Drilling and Well Completions

3~

$$

TiME TO

FAILURE ~ HOURS

Figure 4-439. Approximate failure time of carbon steel is 5% NaCI and various parts per million of hydrogen sulfide. (From Ref. [184].)

+0 $

0 0 0

7

5 4 3

( O

O

O I+7~&+~ ~

T~N| ~ J i ~ ie 5% N+~C~

0

T~ME TO FAILURE

~ HOURS

Figure 4-440. Steel fails much less rapidly when pH is above 7 or 8. (From

Ref. [184].)

cracking increases to the crack depth, where rupture occurs as the applied stress is greater than the ultimate strength of the metal at that point. Figure 4-442 shows the relationship b e t w e e n the t i m e o f e x p o s u r e and e x t e n s i o n o f a s p e c i m e n during stress-corrosion cracking. The width of the crack does not i n c r e a s e as t i m e progresses. However, just before rupture, c o n d i t i o n s are

Corrosion and Scaling

1285

l +.=° 0

0

Crack depth

Figure 4-441. Rate of stress--corrosion crack propagation as a function of crack depth during tensile loading. (From Ref. [183].)

t

Ru pture,,,.~,

tO C X

LU

J

0 0 Time~

Flgure 4-442. Specimen extension as a function of time during constant-load stress-corrosion cracking test. (From Ref. [183].)

1286

Drilling a n d Well C o m p l e t i o n s

d i f f e r e n t , extensive plastic d e f o r m a t i o n is o b s e r v e d a n d large i n c r e a s e s in extension occur. This b e h a v i o r f u r t h e r emphasizes the i m p o r t a n c e o f b e t t e r u n d e r s t a n d i n g this concept. To reduce or prevent stress c o r r o s i o n cracking the following m e t h o d s can be employed: • Eliminate unfavorable e n v i r o n m e n t s . T h e presence of oxygen a n d o t h e r oxidizers is a critical factor in stress corrosion cracking. For example, the cracking o f austenitic stainless steel in chloride solutions can be r e d u c e d or completely eliminated if oxygen is removed. • Avoid surface discontinuities such as pits, slip marks (notches) a n d o t h e r damage that act as stress risers. Stresses concentrate at the tip of the "notch." Therefore, stress-corrosion cracks usually originate from the base of a pit. • Lower the stress levels below the "threshold" by annealing, using thicker sections or by reducing the load. • Change the alloy to one which is more resistant to stress-corrosion cracking. • Use suitable corrosion inhibitors in sufficient quantities. Corrosion Fatigue

As pointed out earlier, even if the metal is u n d e r stress for an infinite n u m b e r of cycles, it will not fail as long as the stress level is below its fatigue limit. However, if the metal is d a m a g e d or n o t c h e d in any way, the fatigue resistance decreases, as shown in Figure 4-443. Note that the n o n f e r r o u s metals have no

\

\ \

LLI I--

\

Fatigue limits Steel A w

6

w

~'---~

Notchedsteel

,e~onferrous

104

105

106

107

108

NUMBEROFCYCLESFORFAILURE Figure 4-443. Fatigue behavior of ferrous and nonferrous alloys. (From Ref. [183].)

C o r r o s i o n and Scaling

1287

fatigue limit. T h e i r fatigue resistance increases with reduction in a p p l i e d stress, but continues to d e p e n d on the stress level [183,193]. T h e simultaneous action o f cyclic stress alternating tensile a n d compressive a n d corrosive attack is known as c o r r o s i o n fatigue. Corrosive attack can be in the form o f pitting. These pits function as notches, acting as stress risers a n d i n i t i a t e cracks. O n c e a c r a c k is f o r m e d , the p r o b a b i l i t y o f p i p e failure is e n h a n c e d by further c o r r o s i o n as c o r r o s i o n is accelerated by action o f stress. The tip o f the crack deep within the fracture, the area u n d e r the greatest stress, is anodic to the wider part o f the crack. As c o r r o s i o n progresses, the metal at the tip o f the crack goes into the solution, the crack d e e p e n s and eventually p e n e t r a t e s the wall o f the tube. Figure 4-444 graphically illustrates the effect o f corrosive e n v i r o n m e n t s on the fatigue life o f a steel. It is e v i d e n t in F i g u r e 4-444 that the fatigue life is subject to considerable r e d u c t i o n u n d e r corrosive conditions. T h e r e d u c t i o n is severe in highly corrosive e n v i r o n m e n t s a n d behaves like n o n f e r r o u s S-N behavior shown in Figure 4-443. This is due to the fact that in the presence o f corrodents, there is no true e n d u r a n c e limit, and the failure may occur after any c o m b i n a t i o n o f n u m b e r o f stress cycle and stress level. J a m a l Azar states that an increase in c o r r o d e n t s such as oxygen, c a r b o n d i o x i d e a n d c h l o r i d e content result in decrease in fatigue strength of the drillpipe. Figures 4-445 to 4-450 s u m m a r i z e the c o r r o s i o n f a t i g u e d a t a o b t a i n e d a n d p r e s e n t e d by Azar [194]. (text continued on page 1291)

Stress. psi. x I 0 .

3

30 25 20 15 I0 5 0 I Number

2 of C y ¢ 1 , 1

3

,I

x 106

Figure 4-444. Effect of corrosive environment on fatigue life. (From Ref. [193].)

1288

Drilling and Well Completions Stress= 70% of yield 279,766

164,769

LI-

.,9

143,612

"G

110,434 82,350

I

Air

Normal Chloride

ppm chloride

Figure 4-445. Chloride fatigue test--dispersed lignosulfonate mud, 9.5 pH.

(From Ref. [194].) Stress= 60% of yield 539.5

133,594

131,186 128,275 127,32,._..,.~1

Air

Normal Chloride

ppm chloride

Figure 4-446. Chloride fatigue test--nondispersed bentonite mud, 8.5 pH.

(From Ref. [19410

Corrosion and Scaling

StPejj

• 605b O f

1289

yield

S3S.SS8

a/ L. n) L~ -

~

"~

1S1.|59

ll~moL

AJP

_t1T236

t ..

ChLoride

Dpj

chloride

Figure 4-447. Chloride fatigue test--nondispersed bentonite mud, 9.5 pH. (From Ref. [194].)

5 t r e s s • 60°/, 0f yield

539,SS6 u

u o

310,916

Mr

t., ppm 02

Figure 4-448. Oxygen fatigue test--lignosulfonate mud, 9.5 pH. (From Ref. [194].)

1290

Drilling and Well Completions Stress ';0% of yield

2?9. 766 u/ *u

u. o

L,4

131,035 92.460,

Air

! ppm CO2

Figure 4-449. Fatigue test CO 2 in freshwater mud. (From Ref. [194].)

Stres"6

60% y i e l d

539,65|

200.I)6 1~2,229

Air

I ppa 02

Figure 4-450. Oxygen fatigue test--nondispersed mud, 8.5 pH. (From Ref. [194].)

C o r r o s i o n a n d Scaling

1291

(text continued from page 1287)

C o r r o s i o n fatigue, therefore, is a special case of stress-corrosion cracking and fatigue failure. Figure 4-451 shows an example of pipe failures due to c o r r o s i o n fatigue. C o r r o s i o n fatigue can be prevented or r e d u c e d by: • • • °

reducing the stress on the m e t a l by altering the design, heat treatment; use of p r o p e r c o r r o s i o n inhibitors; use of p r o p e r coatings; keeping the drillstring u n d e r continuous tension.

Figure 4-451. Corrosion--fatigue failure of drillpipe caused by internal pitting. (From Fief. [21810

1292

Drilling and Well C o m p l e t i o n s

Factors Influencing Corrosion Rate

pH T h e p H is o n e o f t h e m o s t i m p o r t a n t c h a r a c t e r i s t i c s o f an e l e c t r o l y t e , c o m m o n l y expressed as a n u m b e r between zero and fourteen, and is the negative l o g a r i t h m o f the hydrogen ion c o n c e n t r a t i o n [195]. p H = - l o g [ H +] The greater the c o n c e n t r a t i o n o f hydrogen ions, the higher the acidity o f the solution a n d the lower the pH. Solutions with p H o f 7 are n e u t r a l solutions. Hydrogen ions (H ÷) force the p H towards zero, and solutions with lower p H than p H o f 7 are acidic. Hydroxyl ions (OH-), on the o t h e r hand, make the solution alkaline and the solutions have higher p H values than 7. The p H variation affects the S-N curve b e h a v i o r o f steel. Figure 4-452 shows that as the p H is increased from 6.6 to 12.1 or 13, the t h r e s h o l d or fatigue limit o f steel is restored in a e r a t e d saltwater systems. Figure 4-453 shows the relationship o f failures by e m b r i t t l e m e n t (sulfide cracking) and p H . T h e time to failure increases as the p H rises. Below p H 7, failure occurs in less than an h o u r in the p r e s e n c e o f hydrogen sulfide. As the p H rises above 7, time to failure rapidly increases. Both carbon dioxide and hydrogen sulfide lower the p H level to acidic regions and, consequently, increase the c o r r o s i o n rate. Figure 4-454 illustrates the effect o f p H on c o r r o s i o n o f m i l d steel. In high-pH r a n g e t h e c o r r o s i o n r e a c t i o n is a n o d i c a l l y c o n t r o l l e d . As t h e p H values d e c r e a s e , t h e c o r r o s i o n r e a c t i o n g r a d u a l l y shifts to cathodic control. T h e resulting decrease in c o r r o s i o n rate can be explained by the formation o f a protective layer o f hydrous ferrous oxide

6O

"

JJ!

I

|

!

I

!

I I |

I

!

"

I "

|

I

s I

mal Solution 5O

"o 4O . ~ ~ ~ H

- 11.1

3O - 9.2

pH "6.6 'd ~ ' ~ , A , , , pH " 10 20

!

i

I I1

0,1

!

I

!

I

I

I

II1

~ . ~

1.0 z Number of Cycles X 106

l

t

I

t

I

10

Figure 4-452. Effect of pH on corrosion fatigue in aerated saltwater. (From Ref. [19710

Corrosion and Scaling

]

11 9

J

8

7

-r-

O~

1293

NE 1300 HR-£

,(>.-~-

NEC -

.JO

6

_L"

5

~

3 2

0 m

Of -1 0.04

1700-1900 ppm total sulfide in 5% NaCI All rings Rc 33 g 1 stressedto 115% YD 0.1

i

i

10

100

1000

Time to failure, hours Figure 4-453. Relationship between pH and time to failure.

(From Ref. [219].)

0009 0008

0

E 0007

e",-

0006

.E ,

c-

0005

O

0004

""

0003

~.. 0002 0001 ~L~

0 14 Figure

13 12

11

10

9

8

7

6

5

pH 4-454. Effect of pH on corrosion of mild steel.

4

3

2

(From Ref. [219].)

on the metal surface formed by the corrosion reaction. The corrosion rate is d e p e n d e n t u p o n the diffusion rate of oxygen through the protective layer to the metal surface. The corrosion rate increases with increasing oxygen concentration and with erosion of the protective layer in the presence of high-velocity,

1294

Drilling a n d Well C o m p l e t i o n s

turbulent flow, which is often i m p o s e d on the drillstring. As the p H decreases further, the protective film breaks down, the reaction shifts back u n d e r anodic control, and the corrosion rate rises rapidly. During drilling operations it is very i m p o r t a n t to maintain high-pH levels a r o u n d the flat part o f the curve shown in Figure 4-451. However, it should be n o t e d that a l u m i n u m alloys exhibit an increased rate o f corrosion at p H higher than 10.5. Therefore, when a l u m i n u m drillpipes are used the pH values are generally kept between 7 a n d 10.5.

Temperature T h e effect o f t e m p e r a t u r e on c o r r o s i o n rate is i n f l u e n c e d by the following factors [188]: 1. Increase in t e m p e r a t u r e increases the redox reaction. 2. Solubility o f gases in water decreases with increasing temperature. 3. Change in viscosity may affect the circulation, diffusion and other properties p e r t i n e n t to the c o r r o s i o n process. 4. S o l u b i l i t y o f s o m e r e a c t i o n p r o d u c t s can be a f f e c t e d by t e m p e r a t u r e variation. W h e n c o r r o s i o n is due to the presence o f mineral acids dissolved in water, resulting in h y d r o g e n evolution, the c o r r o s i o n rate g e n e r a l l y increases with increasing temperatures. O n the o t h e r hand, if the corrosion is due to dissolved oxygen in water, the rate decreases with increased t e m p e r a t u r e . This is due to the fact that oxygen solubility in water decreases with a rise in temperature. T h e f o r e m e n t i o n e d fact will only be true in an o p e n system where oxygen coming out o f solution is free to escape. However, in a closed system, where oxygen coming out o f solution cannot escape, the rate o f c o r r o s i o n increases with increase in t e m p e r a t u r e (Figure 4-455). 0"030

0O25 CLOSED SYSTEM (OXYGEN HELD IN SYSTEM)~ 50-020

>.

,

J

/,f"

,.e

~ 0-015. w O.

~

w1'

O'OIC

[OXYGEN FP.EE TO ESCAPE) 000 $

0"000

0

20

40

00

80

tOO

120

140

160

TEMPERATURE~°C

Figure 4-455. Effect of temperature on the corrosion of steel in water containing dissolved oxygen. (From Ref. [188].)

I~0

C o r r o s i o n and Scaling

1295

I f c a l c i u m o r m a g n e s i u m b i c a r b o n a t e s are p r e s e n t in water, t h e rise in t e m p e r a t u r e d e c o m p o s e s them, and subsequent evolution o f carbon dioxide will result in a higher corrosion rate, while at the same time calcium and magnesium carbonates may d e p o s i t on the metal surface. This scale may be protective, thus slowing the c o r r o s i o n rate; however, it can create c o n c e n t r a t i o n cells if it is d e p o s i t e d loosely, exposing parts o f the surface. In systems with c o n s i d e r a b l e t e m p e r a t u r e variations over the metal surface, the w a r m e r areas will b e a n o d i c to the c o o l e r areas. T h e c r e a t i o n o f a cell usually leads to pitting c o r r o s i o n o f the anodic area.

Velocity T h e velocity o f fluids over the metal surface has an effect on the c o r r o s i o n rate t h r o u g h i n f l u e n c i n g o t h e r factors responsible for corrosion. High velocity may increase erosion c o r r o s i o n by either washing away the protective film or by mechanically agitating the metal surface. O n the other hand, stagnant systems where the f l u i d velocity is zero may e x p e r i e n c e d e p o s i t i o n o f sludge and o t h e r s u s p e n d e d solids. This d e p o s i t i o n may create c o n c e n t r a t i o n cells, resulting in pitting c o r r o s i o n [196-198]. Systems with extremely high velocity o f t u r b u l e n t flow give rise to pressure variations that may result in cavitation corrosion. W h e n oxygen is present, lowvelocity areas receive less oxygen and b e c o m e anodic to the high-velocity areas r e c e i v i n g high c o n c e n t r a t i o n s o f o x y g e n a n d , thus, c o r r o d e . F i g u r e 4-456 illustrates the effect o f velocity and t e m p e r a t u r e on corrosion rates o f steel pipes in an oxygen-contaminated system. Figure 4-457 shows the effect o f velocity on the c o r r o s i o n rate o f steel pipes o f various sizes. At 80°F the c o r r o s i o n rates for all t h r e e pipes rise to t h e i r respective limits a n d b e c o m e m o r e o r less constant. However, at higher t e m p e r a t u r e s the c o r r o s i o n rates o f ¼ and -~-in. 60

180°F 50

i

4O

1.1.1

z

f /

30

o o

2O

o

/

10

0

J

2

4 VELOCITY -

6

8

10

ft/sec

Figure 4-456. Velocity of the fluid accelerated corrosion rates. (From Ref. [198].)

1296

Drilling a n d Well C o m p l e t i o n s 140

I

100 150°F/

~,,=, 80 ~.g. ~.~

# J

g.

"

P

I

z~ o~

s S 150°F

1/4" Pipe 1/2" Pipe., 3/4" Pipe ,

. . . . . 120 , ~

J

J

e~*

//7

60

I

s

120°F

120OF

."_."--'"

150oF

80OF,,,

/,'//, ;/'.,...=..

40

80OF

2O

120°F

80°F

0

2

3

4

FLOW RATE - ft/sec

Figure 4-457. Effect of v e l o c i t y pipe. (From Ref. [197].)

of f l o w on t h e initial rate of c o r r o s i o n of steel

pipes continue to increase as the velocity increases. A possible explanation for this behavior is that the corrosion rate increases with increasing velocity in smalld i a m e t e r pipes, probably due to turbulence effects. Thus, the corrosion rate may be r e d u c e d by using either an oversized flow area or by reducing the velocity and, hence, minimizing the turbulence effect. T h e critical velocity, which when e x c e e d e d may result in erosion corrosion, can be calculated by the equation p r e s e n t e d in API RP 14E, which is [199] C Vc = ~

(4-351)

where V = m a x i m u m allowable velocity in f t / s = a constant, typically 100-125 7 = fluid specific weight in I b / f t ~

Heterogeneity C o n d i t i o n s necessary for the onset o f c o r r o s i o n are quite often p r o v i d e d by heterogeneities. These heterogeneities may very well exist within the metal or alloy or may be i m p o s e d by external factors. These heterogeneities can give rise to variations in potential on a metal surface i m m e r s e d in an electrolytic fluid. T h e galvanic cell thus f o r m e d gives rise to flow o f c u r r e n t that a c c o m p a n i e s c o r r o s i o n [188].

Corrosion and Scaling

1297

High Stresses Highly stressed areas generally corrode faster than areas of lower stress. This is due to the fact that the more stressed areas are usually anodic and corrode more readily. The drillstem just above the drill collars is often susceptible to a b n o r m a l corrosion damage. High stresses and b e n d i n g m o m e n t s in this region may be partially responsible for this failure.

Microbial Activity Microorganisms are present in most systems in one form or another. Their mere presence does not necessarily mean that they present a problem. Microbiali n f l u e n c e d corrosion is not a very significant problem in drilling operations. Their activity, however, does introduce corrodents in drilling fluids, reduces the pH of the e n v i r o n m e n t a n d can attack the organic additives of the drilling fluids, thus producing corrosive products. Since the potential for problems does exist, it becomes necessary to consider the effects on metal corrosion resulting from microbial activity. All microbes are classified into two main groups according to their oxygen requirements. These groups are:

Anaerobic organisms--Flourish in the absence of oxygen in e n v i r o n m e n t with low redox potential.

Aerobic organisms--Require oxygen for survival. The most c o m m o n types of microorganisms found in oil fields that can cause corrosion related problem are now discussed.

Sulfate Reducers. Most of the oilfield c o r r o s i o n p r o b l e m s arise from the activity of sulfate-reducing bacteria (SRB) b e l o n g i n g to genus Desulfovibrio a n d one of the genus Clostridium. They are anaerobic, but although inactive, they will survive in systems containing dissolved oxygen. They may grow u n d e r scale, debris or other bacterial masses where oxygen cannot penetrate, and in fresh or saltwater environments. SRB c o n t r i b u t i o n to corrosion of metals is twofold; by direct corrosion attack, a n d by attack from products produced as a result of microbial activity. Figure 4-458 shows schematically the SRB direct corrosion of steel. A simplistic chemical mechanism of this process is as follows: 1. The metal goes into solution at the anode Fe --~ FC ÷ + 2e2. Reaction at the cathode results in molecular hydrogen that polarizes the cathode. Figure 4-459 shows the cathode polarization: H20 ~ H + + OH2H + + 2e- --~ H 2 3. Depolarization of the cathode by SRB. SRB contain an enzyme called hydrogenase, which allows the utilization of hydrogen to reduce sulfate to sulfide:

1298

Drilling and Well Completions

i 4 H20+ $2~

FeS

SOLUTION

= FeS

S042 + 8H

8H+ SO42

H20

DESULFOVIBRIO

DESULFOVIBRIO ~

8 H20 ~

I

"~"((~'-~"S 2 + 4

80H-+GH+8e .--~/8H

8H -.,-

3_Fe(O /H)2

8 e + 8H

/ 4 Fe++

Fe++

"*..| ~." . ~,,,, Cathode ~ 4Fe 4Fe ) Cathode / ----"-"%, Anode ~,. . . . . . . . /

~,

Iron Metal

Figure

4-458. Diagram of polarization of local cathode by a film of hydrogen gas bubbles (cathodic area to right of a n o d e is polarized). (From Ref. [208].)

SOLUTION

Fe+*

H÷

Fe÷+ H+

Fe++

H÷

@ %

H+

H+

e

"~,.

e

e

e z

Fe~..~,,..,~

Cathode~ e *" . . . . . _ _ _ ~ . . .

! |

" * ' - - " e/"~z Anode •

/

Cathode

.J

/

i¢

Iron Metal

Figure 4-459. Desu/fovibrio

Diagram of the bacterial corrosion of steel or iron by bacteria (corrosion products are underlined). (From Ref.

[208].)

Corrosion and Scaling

1299

R

SO~- + 8H---)S ~- + 4H~O 4. Corrosion product reaction •

Ferrous ions (FC +) c o m b i n e with sulfide ions (S 2-) to form black ferrous sulfide FeS): Fe ~÷ + S2- ---) FeS

•

Ferrous ions (Fe ~+) c o m b i n e with hydroxyl ions (OH-) to form brownish red ferrous hydroxide [Fe(OH)~]: 3FC ÷ + 6OH- ---) 3Fe(OH)2 T h e overall corrosion reaction equation is 4Fe + SO4~- + 3H~O ---) FeS + 3Fe(OH)2 + 2OHIf the water system contains dissolved carbon dioxide, iron carbonate may form: CO 2 + H~O ---) H2CO 3 FeS + H~COa ---) FeCO 3 $ + H~S $ T h e second way SRB influences corrosion of metal is by p r o d u c i n g products such as hydrogen sulfide that can affect corrosion resistance of metals. SRB

SOl- + 2 H ÷ + 4 H 2 ---) H2S + 4H~O In the above mechanism, both hydrogen ion and molecule are utilized by SRB to convert SO42- to H2S. T h e c o n s u m p t i o n of hydrogen depolarizes the cathode a n d leads to an increased rate of corrosion.

Slime-Forming Bacteria. Several forms of bacteria p r o d u c e a slimy capsule u n d e r certain e n v i r o n m e n t a l conditions. These organisms are "heterotrophic," that is, they obtain their energy from organic sources such as sodium lactate. The reaction is 2CH3CHOHCOONa + MgSO 4 ---) 2CH3COONa + CO 2 $ + MgCO 3 + H2S $ + H~O T h e s e m i c r o o r g a n i s m s b e c o m e a p r o b l e m when their n u m b e r s are large e n o u g h to produce corrosives such as c a r b o n dioxide a n d hydrogen sulfide. Pseudomonas, Bacillus and Flavobacterium are examples of slime-forming bacteria.

Iron-Oxidizing Bacteria.

These are aerobic organisms capable of growing in systems with iess than 0.5 p p m oxygen. They oxidize iron from ferrous to the ferric state by the following mechanism:

1300

Drilling and Well C o m p l e t i o n s

4FeCOs + 02 + 6H20 ~ 4Fe(OH)sJ, + 4CO2'[" T h e carbon dioxide p r o d u c e d can contribute to the c o r r o s i o n of metal. T h e deposits of ferric hydroxide that precipitate on the metal surface may p r o d u c e oxygen concentration cells, causing corrosion u n d e r the deposits. GaUionalla and Crenothrix are two examples of iron-oxidizing bacteria.

Sulfur-Oxidizing Bacteria. T h e s e are aerobic bacteria that oxidize sulfur or sulfur-bearing c o m p o u n d s to sulfuric acid according to the following equation: 2S + 302 + 2H20 --* 2H2SO 4 T h e resulting e n v i r o n m e n t is low in p H and extremely corrosive. Thiobacillus and Beggiatoa are g o o d examples of this form of bacteria. Other Microorganisms. T h e r e are several o t h e r microorganisms that affect the c o r r o s i o n of metal directly or indirectly. Some examples are yeasts and molds, algae and protozoa. For the present purposes it is sufficient to realize that there are other microorganisms capable of presenting c o r r o s i o n problems. T h e r e are several m e t h o d s of m o n i t o r i n g m i c r o b i a l - i n f l u e n c e d c o r r o s i o n . Some m e t h o d s are as follows: • Sample culturing • Filtration technique • Metal surface examination, i.e., use of coupons Methods to prevent or reduce problems associated with microbial c o r r o s i o n will be discussed later. Some of t h e m are: • • • • • •

use of effective microbiocides removal of nutrients p H adjustment p r o p e r coatings cathodic p r o t e c t i o n m o n i t o r i n g the effectiveness of microbiocides

Corrodents in Drilling Fluids T h e principal corrosive agents affecting the drillstem c o m p o n e n t s in drilling fluids are dissolved gases, dissolved salts and acids. These corrodents may enter the system from the formations being drilled. They can also be introduced by the a d d i t i o n of m a k e u p water, or o t h e r t r e a t i n g chemicals and processes. Also, they can be products of t h e r m a l d e g r a d a t i o n of chemicals and m i c r o o r g a n i s m activity, etc.

Dissolved Oxygen Oxygen dissolved in aqueous solutions, even in very low concentrations, leading cause of c o r r o s i o n problems (i.e., pitting) in drilling. Its presence accelerates the c o r r o s i o n rate of o t h e r c o r r o d e n t s such as hydrogen sulfide carbon dioxide. Oxygen plays a dual role both as a cathodic d e p o l a r i z e r an anodic polarizer or passivator. Within a certain range of c o n c e n t r a t i o n

is a also and and the

Corrosion a n d Scaling

1301

attack is d e p e n d e n t on the oxygen concentration. Above a certain concentration it may act as anodic passivator for certain metals resulting in reduction of the corrosion rate. It is thought that the c o n c e n t r a t i o n of oxygen is sufficient to cause ferrous to ferric oxidation at a faster rate than ferric ion has a chance to diffuse away from the metal surface. This results in deposition of a protective film of ferrous hydroxide on the steel surface. The chemical reaction in oxygen corrosion of steel in an aqueous solution is 2Fe + 2H20 + 02 ~ 2Fe 2+ + 4OH- ~ 2Fe(OH)2 .[.

(4-352)

Ferrous hydroxide precipitates from solution. Since this c o m p o u n d is unstable in oxygenated solution, it is oxidized to the ferric salt: (4-353)

2Fe(OH)2 + H20 + !202 ~ 2 F e ( O H ) 3 Step-by-step explanation of the reaction is as follows:

1. Oxidation occurs at the anode, where the metal goes into solution as it corrodes: Fe ~ Fe 2+ + 2e-

(4-354)

2. Reduction occurs at the cathode, where oxygen combines with water a n d gains electrons to form the hydroxyl ion: 02 + 2H20 + 4e- ~ 4OH-

(4-355)

3. The hydroxyl ion thus p r o d u c e d combines with ferrous ion produced in the first step and forms ferrous hydroxide (rust), which coats the cathode: (4-356)

Fe 2+ + 2(OH)- ~ Fe(OH)2

There are basically two ways through which oxygen promotes corrosion. First, it is a strong cathodic depolarizer; that is, it retards cathodic polarization. In a corrosion process with an acid substance (dissolved hydrogen sulfide or carbon dioxide), hydrogen molecules (H2) formed d u r i n g reduction reaction accumulate at the cathode. The gaseous hydrogen thus forms an insulating blanket that reduces the current flow and increases the corrosion rate. This process is called polarization. 2H* + 2e- ~

2H ° Step 1 (atomic hydrogen)

~

H2

(4-357)

Step 2 (molecular hydrogen)

However, if dissolved oxygen is present, the second step of Equation 4-357 does not occur and instead 2 H ° + -~O 2 ~ H20

(4-358)

Second, oxygen attacks the metal directly by precipitating iron oxide at the anode, thus, preventing anodic polarization by Fe2÷ ions.

1302

Drilling and Well Completions

The corrosion rate of steel has been found by some investigators to be approximately proportional to the oxygen content up to 5.5 cmS/L (Figure 4-460). Beyond this concentration the corrosion rate begins to decline. The probable cause for this behavior is that the oxide layer deposited at low oxygen concentrations is much more protective than the one formed in high concentrations of oxygen. Oxygen solubility in an aqueous fluid tends to decrease with increasing salinity (Figure 4-461) and increases with decreasing temperatures (Figure 4-462). As the drilling progresses, oxygen is continuously dissolved into the drilling fluid, through the surface part of the circulatory system. As the drilling mud flows through solid-removal systems, gas separators, chemical additions or treatment systems and mud mining systems, it picks up oxygen. The addition of makeup water also increases the oxygen content in the drilling mud. The increase of oxygen content is further enhanced if the viscosity is high enough to impede gas or air breakout from the mud. Low temperatures and low salinity also cause increased oxygen absorption in drilling muds. The most effective m e t h o d of controlling corrosion due to oxygen is by minimizing the contamination of oxygen into the drilling mud. With methods available it is possible to minimize the concentrations to reasonable levels. Further control can be obtained by use of oxygen scavengers and degasification of drilling fluids. The control methods will be discussed later.

/

O3

=E .-.I .-.I

=E

~3 O3 0 .--.I I--"

/

~ 2 1.1.1

1

0/ 0

1

/ 2

/

3

4

5

6

DISSOLVED-OXYGENCONTENT-CCPER LITER F i g u r e 4-460. Corrosion in sodium chloride solution containing dissolved

oxygen. (From Ref. [19710

Corrosion and Scaling Dissolved

Carbon

1303

Dioxide

Carbon dioxide dissolves in water to form a weak acid (carbonic acid), which reduces the pH of the solution and, consequently, increases its corrosivity. Corrosion caused by carbon dioxide is generally referred to as "sweet" corrosion, a n d results in pitting. The mechanism of carbon dioxide corrosion is as follows [197,198]:

'oL B

I

I

-

I

"

I

I

I

!

1

!

4

5

6

_~~ne brNaCI ines@22±2°C

d 4

2

L o 0

I

!

1

2

.! 3

Ionic Strength Figure 4-461. Oxygen solubility in salt solutions. (From Ref. [197].)

16,

!+i i IZ E 13,

!0 a 6

-~-Jth w=l~ IO l'urm atL'~d Ill l|l'O or COl d o . . It o c t hoe ;on+z¢ in w a t e r .

~

4 2 C 40 80

120 160200

2 4 0 2 ~ 0 320

Tempcracure.°F,

Figure 4-462. Oxygen solubility in water at varying temperatures. (From Ref. [189].)

1304

Drilling and Well C o m p l e t i o n s

1. C a r b o n dioxide dissolves in water to f o r m carbonic acid C O 2 + H 2 0 ---) H2CO s

(4-359)

2. which ionizes first to H2CO s --~ H ÷ + H C O - s

(3-360)

and then to HCO- 3 ~

H ÷ + CO32-

(4-361)

3. At the a n o d e metal goes into solution as it ionizes to Fe ~

Fe 2÷ + 2e-

(4-362)

4. Finally, t h e c a r b o n a t e i o n c o m b i n e s with f e r r o u s ion to f o r m f e r r o u s carbonate and hydrogen is evolved: Fe 2÷ + 2e- + 2H ÷ + CO32- ~

FeCO 3 + H 2 1"

(4-363)

T h e c o r r o s i o n rate o f carbon dioxide d e p e n d s on metallurgy o f the material, o x y g e n c o n t e n t a n d solubility o f c a r b o n d i o x i d e in t h e a q u e o u s s o l u t i o n . Solubility, in turn, depends on the amount o f dissolved salt, temperature, partial pressure o f carbon dioxide and oxygen, and velocity o f the system. A n aqueous s o l u t i o n that contains b o t h oxygen and c a r b o n d i o x i d e in solution is m o r e c o r r o s i v e than t h e s o l u t i o n that contains only o n e o f t h e s e gases e q u a l in c o n c e n t r a t i o n to both gases. Figure 4-463 shows this fact by c o m p a r i n g various

60

I

Temperature-195°F

0.017 Oxygen Oxygen

4o

/ N

-0.0 Oxygen

2o 10

~

0 5

10

15

20

CARBONDIOXIDE- PPM Figure 4-463. Effect of carbon dioxide concentration on corrosion rate. (From Ref. [211].)

C o r r o s i o n and Scaling

1305

combinations of carbon dioxide and oxygen in a static system. The corrosion rate increases with increasing oxygen and carbon dioxide concentrations. Figure 4-464 shows that the solubility of carbon dioxide increases with decreasing temperature. Figure 4-465 shows the influence o f carbon dioxide partial pressure on the rate of corrosion. T h e corrosion rate increases rapidly until partial pressure o f 200 psia, t h e n g r a d u a l l y b e c o m e s m o r e o r less c o n s t a n t after 300 psia.

3,200

i

i

{C~1 arm pressure) Reacfs w i t h w a t e r to

2 ,z~O0

O. U

I ,600

800

0

+

80

160

2~0

320

T e mpera lure ° F

Figure 4-464. Effect of temperature on carbon dioxide solubility. (From Ref. [189].)

I0

i:~,o 'i.[7

/ .,.L PARTIAl.

PlltSSUllE

/ Of

¢ARll0N

DJOli01[

400 --

ll~

PSIA

Figure 4-465. Corrosion of steel in distilled water containing carbon dioxide at various partial pressures. (From Ref. [197].)

1306

Drilling and Well C o m p l e t i o n s

Increase in partial pressure increases the solubility, consequently lowering the p H of the system (Figure 4-466). W h e n carbon dioxide is present during drilling operations, the corrosion rates are three to six times higher than those shown in Figure 4-463 according to EnDean [198]. Carbon dioxide may enter the drilling f l u i d through one or more of the following ways: • • • •

i n f l u x of f o r m a t i o n gas or f o r m a t i o n water ( p r i m a r y way) through a d d i t i o n of makeup water thermal decomposition of dissolved salts and organic drilling fluid additives microbial activity

C a r b o n dioxide c o r r o s i o n can be controlled by the use of caustic soda and lime and the a d d i t i o n of various inhibitors. Film-forming a m i n e inhibitors are used to reduce the corrosion rates. The control measures will be discussed later.

Dissolved Hydrogen Sulfide Hydrogen sulfide, as well as carbon dioxide, dissolves in water to form a weak acid. The acid solution thus formed is weaker than carbonic acid; nevertheless, it is corrosive enough to cause pitting problems on the drillstem. The presence of sulfide also promotes hydrogen absorption into the drillstem components. Hydrogen absorption, coupled with cyclic stressing of the drillstem, leads to failure such as sulfide stress cracking or hydrogen embrittlement of drillstem components. The chemical mechanism of hydrogen sulfide corrosion is as follows [191,197,200]: 1. O x i d a t i o n at the a n o d e - w h e r e metal goes into solution: Fe --~ Fe 2÷ + 2e-

4.t

.

.

.

.

(4-364)

.

.

.

4J

4.0

I.I pH

~4

"~,Z

104 *F.

f

B.Y

!

]1.6

" ~ o IQ *It. i •

•

,,| t 5p

J 16

PARVIIL P f l £ S $ ~

1 ~0

24

II

I

lbll

~ooPII.

Figure 4-466. Effect of carbon dioxide partial pressure on the pH of condensate water. (From Ref. [184].)

1307

C o r r o s i o n and Scaling 2. Ionization o f H2S occurs H2S ~

H*+SH-

(4-365)

T h e anion, bisulfide SH- f u r t h e r dissociates into anionic sulfide S 2- and cationic hydrogen ion H*: SH- ~ S 2- + H ÷

(4-366)

3. T h e ion S 2- reacts with ferrous Fe 2÷ ion to form black iron sulfide FeS c o r r o s i o n product. T h e hydrogen ions are r e d u c e d by electrons p r o d u c e d by anodic reaction in step 1 and form hydrogen atom H°: Fe z* + S z- + 2H ÷ + 2e- ---> FeS + 2H °

(4-367)

In absence o f oxygen some hydrogen does manage to evolve and polarize the c a t h o d e to some extent. However, if oxygen is present, this polarization does not o c c u r as discussed earlier, a n d results in a c c e l e r a t e d c o r r o s i o n attack. H y d r o g e n sulfide ionizes in two m a i n stages w h e n dissolved in fluid. T h e reactions mechanisms are H2S + N a O H ~ Na ÷ + HS- + H 2 0 NariS + N a O H ~ 2Na ÷ + S 2- + HzO T h e s e reactions are easily reversed if the solution p H decreases, as can be seen in Figure 4-467.

100.0

.

50.0

m

--

10.0

m

o

5.0

"o

•

..

...

i

lu

i

|,

i

u3 o

0

o~

1.0

co

c

0.5

o; U I.

0J

O.

!

0.1 3

5

7

9

11

13

pH Figure 4-467. Approximate ionization of hydrogen sulfide in water at different pH values. (From Ref. [19110

1308

Drilling a n d Well C o m p l e t i o n s

If c a r b o n dioxide is present, the solution p H is r e d u c e d e n o u g h to convert the sulfide (S 2-) ion back into the dangerous bisulfide or molecular sulfide (H2S) state. Figure 4-468 shows the variation o f c o r r o s i o n o f a mild steel in distilled water containing varying concentrations o f hydrogen sulfide. T h e corrosion rate increases sharply with increasing concentrations o f hydrogen sulfide up to 150 ppm. It begins to decline rapidly after 400 p p m until it a p p r o a c h e s 1,600 ppm. From 1,600 to 2,640 p p m it b e c o m e s a p p r o x i m a t e l y c o n s t a n t , d u e to i n h i b i t i v e character o f d e p o s i t e d iron sulfide at high concentrations. Figure 4-469 shows the effect on c o r r o s i o n rates o f 1020 steel in different water systems with dissolved hydrogen sulfide. The difference in corrosion rates is due to different corrosion products formed in different solutions. In solution I, kansite forms. Kansite is widely protective as the pyrrhotite coats the surface giving slightly m o r e p r o t e c t i o n until a very protective pyrite scale is formed. In s o l u t i o n II, only kansite scale forms, resulting in c o n t i n u e d i n c r e a s e in the c o r r o s i o n rate. Finally, in solution III, pyrite scale is f o r m e d as in solution I; however, c o n t i n u e d c o r r o s i o n may be due to the presence o f carbon dioxide. H y d r o g e n sulfide may enter the drilling f l u i d in one or m o r e o f the following ways:

• I n f l u x o f f o r m a t i o n gas or f o r m a t i o n water is the principal way. • T h r o u g h a d d i t i o n o f m a k e u p water. • T h e r m a l d e g r a d a t i o n o f sulfur-containing d r i l l i n g f l u i d s additives (e.g., lignosulfates). • Chemical reaction o f sulfur-containing compounds (e.g., tool joint lubricants). • Microbial activity. T h e most effective m e t h o d s o f avoiding or r e d u c i n g p r o b l e m s associated with hydrogen sulfide c o r r o s i o n are: • Avoid the use o f high-strength steels. Relatively soft steels with low yield strength (up to Rc 22 a n d 90,000 psi) are resistant.

I

24

\

T[klP : 26 7°C ( 8 0 ° F |

0 off off u O0

300 600 J200 DISSOLVED HzS

~a30 2400 - PPM

F i g u r e 4 - 4 6 8 . Corrosion rate of mild steel in distilled water containing varying concentrations of hydrogen sulfide. (From Ref. [197].)

Corrosion a n d Scaling

1309

• Use sulfide scavengers. • Controlling pH with lime or caustic soda. More detail o n these control measures will be discussed later. D i s s o l v e d Salts

Dissolved salts (chlorides, sulfates, carbonates or bicarbonates) generally increase the corrosivity of the drilling fluid. Figure 4-470 illustrates the i n f l u e n c e of chloride, sulfate and bicarbonate o n corrosion of steel. From the figure, it is obvious that the i n f l u e n c e of dissolved salts is not governed by the salt concent r a t i o n alone, b u t also by the type of dissolved salt. The ions can be divided into two groups: aggressive, such as chloride a n d sulfate, and inhibitive, such as carbonate or bicarbonate. All types of ions have inhibitive and aggressive properties to some extent, d e p e n d i n g o n their concentrations [197,201,202]. The aggressive ions either break down the protective films or prevent their formation and, in effect, increase the corrosion rate. In presence of chloride a n d sulfate ions the corrosion attack is more localized and, as a result, causes deep pitting. Inhibitive ions, o n the other hand, tend to limit the attack and decrease the corrosion rate by forming protective films. The film is similiar to a d h e r e n t c a r b o n a t e - c o n t a i n i n g rust, which polarizes the anodic areas. W h e n aggressive a n d inhibitive ions are present together, the aggressive ions, if present in sufficient quantities, interfere with the deposition of the protective layers. Generally, the corrosivity of water containing dissolved salts increases at lowsalt concentrations, until some m a x i m u m is reached, and beyond this m a x i m u m the corrosion rate decreases. Corrosion rate throughout the salt c o n c e n t r a t i o n range is u n d e r the i n f l u e n c e of oxygen's ability to depolarize. It is believed that

120 >,, ~. 1 0 0 -

1[" H2 $ -

DISTILLED

X

H25-

BRINE

HZS-

C;Oz - B R I N E

WATER

2 !

~j B O - ).-

/

g: Z

60--

J

o

J

U)

o 4.0 - nO O

20

o,;

20

40

60

TIME-

80

tO0

120

140

DAYS

F i g u r e 4-469. Corrosion rates in hydrogen sulfide-water systems, (From Ref.

[197].)

1310

Drilling and Well Completions

the initial increase in corrosion rate is because oxygen solubility is not greatly decreased by low-salt c o n c e n t r a t i o n s . However, an increase in dissolved salt c o n c e n t r a t i o n increases the ion c o n c e n t r a t i o n of the electrolyte, which, in turn, reduces electrolytic resistance. This increases the electrical conductivity of the solution, allowing more c u r r e n t to flow between the a n o d e a n d the cathode of the corrosion cell (Figure 4-471), resulting in an increased corrosion rate. Once the salt concentration is great enough to cause an appreciable decrease in oxygen solubility, there is a decreased rate of depolarization a n d the corrosion rate begins to decrease. Dissolved salts may also serve as a source of carbon dioxide or hydrogen sulfide contamination. Chloride

Salts

Chloride salts (sodium chloride, potassium chloride) tend to interfere with the f o r m a t i o n of a protective layer over metals. Chloride salts destroy the passivity of some stainless steels and cause them to fail by rapid cracking u n d e r tensile stress at temperatures higher than about 176°F (80°C). This type of failure is called chloride stress cracking (CSC) [186,194]. Salts are sometimes added to drilling muds to obtain certain desired m u d characteristics. They can also enter the drilling fluid through c o n t a m i n a t i o n by addition of makeup water, formation-fluid inflow, and drilled formations such as salt domes, gypsum or anhydride formations. In freshwater systems, if salt c o n t a m i n a t i o n reaches u n d e s i r a b l e levels, the following m e t h o d s should be considered for control.

ii,

tG

|ICAnlIONATIC

.!

_1 =0

! - ~bO

t, " ¢0

I

!

!

tO

bo

tO

! AS ¢eCO:l~

..... I lO

0 ~ * ,~

ic~

&iqlON ¢ONC,ItNTilAI'ION - PPM

F i g u r e 4-470. Influence of sulfate, chloride and bicarbonate on the corrosion of steel. (From Ref. [197].)

C o r r o s i o n a n d Scaling

1311

2001

180(

o

1600

X E

o

1~00

u

~J

c

1200 o

1000

800

1oooL. 50

100 150 200 250 Chtoride in Thousands of ppm

300

Figure 4-471. Conductivity of brine. (From Ref. [202].) • A d d chemical thinners such as Q u e b r a c h o c o m p o u n d s , m o d i f i e d tannins a n d m o d i f i e d lignosulfonates. • Use c o r r o s i o n inhibitors such as film-forming inhibitors. • Use internally plastic-coated drillpipes. • Dilute the d r i l l i n g fluid with fresh m a k e u p water. However, d i l u t i o n can lead to a d d e d costs o f mud-treating materials such as weighting materials and other chemical additives. In addition, disposal of excess d r i l l i n g fluid can create p r o b l e m s on offshore d r i l l i n g projects.

1312

Drilling and Well C o m p l e t i o n s

Organic Acids Acids are substances that increase the hydrogen ion (H ÷) concentration of the solution they are dissolved in. This, in turn, reduces t h e p H of the solution, and the corrosion rate increases. Acids may also attack the metal by dissolving the protective film on the metal surface. Presence of acid aggravates the oxygen-influenced attack and also hydrogen s u l f i d e - p r o m o t e d hydrogen e m b r i t t l e m e n t [203]. Organic acids can enter the drilling fluid t h r o u g h microbial activity or by t h e r m a l d e g r a d a t i o n of organic, drilling-fluid additives. T h e acids may also be f o r m e d by chemical reactions between drilling-mud additives or a result of other contamination. Some c o m m o n acids found in drilling fluids are formic (HCOOH), acetic (CH3COOH) and carbonic [H2CO 3 (CO 2 in H20)].

Corrosion Monitoring and Equipment Inspections The best way to c o m b a t c o r r o s i o n is to m a i n t a i n an effective c o r r o s i o n m o n i t o r i n g p r o g r a m to s u p p l e m e n t g o o d preventative measures. It is also very i m p o r t a n t to keep c o m p l e t e records of m o n i t o r i n g p r o g r a m s , control p r o g r a m s and failures that occur. The i m p o r t a n c e of well-qualified responsible personnel cannot be overemphasized as effective corrosion control d e p e n d s on their efforts [201,204,205]. An effective corrosion control program should be able to detect evidence of corrosion and early identify the causes. Therefore, continuous monitoring is essential during drilling operations because the nature of drilling fluid corrosivity changes as the hole is drilled and different formations are penetrated. It is very important never to rely on any single method of monitoring corrosion. Several techniques should be used simultaneously whenever possible, and complete records should be kept.

Linear Polarization Instruments Linear polarization instruments provide an instantaneous corrosion-rate data, by utilizing polarization p h e n o m e n a . These instruments are commercially available as two-electrode "Corrater" and three electrode "Pairmeter" (Figure 4-472). The instruments are portable, with probes that can be utilized at several locations in the drilling fluid circulatory systems. In both Corrater and Pairmeter, the technique involves monitoring electrical potential of one of the electrodes with respect to one of the other electrodes as a small electrical current is applied. The amount of applied current necessary to change potential (no more than 10 to 20 mV) is p r o p o r t i o n a l to c o r r o s i o n intensity. The electronic meter converts the amount of current to read out a n u m b e r that represents the corrosion rate in mpy. Before recording the data, sufficient time should be allowed for the electrodes to reach equilibrium with the environment. The corrosion-rate reading obtained by these instruments is due to c o r r o s i o n of the p r o b e element at that instant [184]. The limitation of these instruments is that they only indicate overall corrosion rate. T h e i r sensitivity is affected by d e p o s i t i o n of c o r r o s i o n products, mineral scales or accumulation of hydrocarbons. Corrosivity of a system can be measured only if the continuous c o m p o n e n t of the system is an electrolyte.

Galvanic Probe The galvanic p r o b e continuously monitors the corrosion characteristics of the drilling fluid. The p r o b e (Figure 4-473) consists of two dissimilar metal electrodes, usually brass and steel. The electrodes are m o u n t e d on, but insulated

Corrosion and Scaling

1313

Threaded Connectors Body i mm i

ij,

m

i

)

I...

!

'!

Metal. Etectrodes

To Instrument Threaded Connectors

Metal Electrodes

/ To Instrument Figure 4-472. Linear polarization instrument probes. from, a threaded high-pressure plug. These electrodes are connected to each other through a DC ammeter capable of detecting microamperes when the probes are immersed in an electrolyte. Enough time is allowed for the electrodes to reach equilibrium and read the current flow through the external loop. The current is generated by the corrosion process occurring on the electrodes [184]. The amount of current flow related to the environment is a measure of its corrosiveness. The probe generally registers low-current flow (0-10 mA) in slightly corrosive environments. However, high-current flows (40-100 mA) have been recorded in severely corrosive environments. T h e current intensity generally depends on oxygen concentration of the system, since oxygen depolarizes the brass cathode, thereby continuing the corrosion process of the cell. A m o n g various locations of surface circulatory system, the instrument can be installed downstream of deaerator and in the standpipe. If the instrument indicates current surge in an air-free system, it generally implies hydrogen sulfide contamination, but the galvanic probe is usually best suited to detect corrosion influenced by oxygen contamination.

1314

Drilling a n d Well C o m p l e t i o n s

O t h e r limitations o f this i n s t r u m e n t are the same as those o f linear polarization instruments discussed earlier.

Hydrogen Probe The hydrogen probe (Figure 4-474) basically consists of a hollow, thin-walled, steel tube that is sealed on one end and the other end is equipped with a pressure gage. Once mounted in the system, the probe body corrodes. Some of the nascent hydrogen generated by the corrosion process in the presence of hydrogen sulfide diffuses through the tube wall. Once inside the void space in the tube, the hydrogen atoms combine to form molecular hydrogen gas. As these hydrogen gas molecules are too large to diffuse back through the tube wall, the pressure in the tube rises. The

Hex Nut ~Threaded. Housing Connector ELectrode A

1

1 _ i

ELectrode B ~,. Wire to Meter for Measuring OC Microampheres

Figure 4-473. Typical galvanic probe. 4r---p.... Bl.eed

Pressure Guage

Hol.tow Tube Figure 4-474. Hydrogen probe.

Threaded Housing [ onnector

Cavity

Corrosion and Scaling

1315

pressure rise in the tube is a function of the amount of hydrogen generated by the corrosion process. Hydrogen probes do not perform well in aerated fluids [201].

Corrosion Coupons The most direct method of evaluating the corrosivity of a drilling fluid is the use of corrosion coupons (Figure 4-475). A drillstring corrosion coupon is a ring coupon machined from a section of tubing and sized to fit into the relief groove in the tool joint box (Figure 4-475). The coupons are normally installed

.PLASTICINSULATOR _ _ ~ STf'EL RInG

COATING~ ~i 'I'- DiI~ PIPESTEEL

$111L

J Figure 4-475. Drillstring corrosion coupon ring. (From Fief. [220].)

1316

Drilling and Well C o m p l e t i o n s

at the b e g i n n i n g o f the d r i l l i n g o p e r a t i o n s a n d c h a n g e d at p r e d e t e r m i n e d intervals ( m i n i m u m o f 40 h). The surface o f the coupon is finished smoothly so that the effect o f corrosion attack can be easily seen. The coupon is m o u n t e d in thermoplastic, which insulates it from the d r i l l p i p e to prevent the f o r m a t i o n o f a galvanic cell (Figure 4-472). Two coupons are generally used p e r string, one in the kelly-saver sub and a second at crossover sub above the drill collars [205]. To employ effective control measure, it is very important to determine the type o f corrosion attack. Spot analysis o f the corrosion film and careful visual examination o f the coupon surface can help in determining the type and severity o f corrosion attack. Generalized corrosion is represented by continuous attack over the entire surface, but no pitting. The pitting type o f corrosion is represented by a high concentration o f pits on the coupon surface. This type o f corrosion attack is the most serious attack resulting from drilling fluids, as discussed earlier. The severity o f general corrosion attack can b e d e t e r m i n e d by weighing the coupon before and after exposure, and comparing the change in weight. Before installation the coupon must be clean (i.e., free o f any corrosion, grease marks, drops o f perspiration, etc.) and weighed. After e x p o s u r e to the system for a m i n i m u m o f 40 hr, the coupon is retrieved, visually examined, then cleaned and reweighed within one tenth o f a milligram. The difference between the initial and final weights is attributed to corrosion and converted to the corrosion rate (mpy) using Equation 4-349. There are several factors such as handling, surface preparation and cleaning, etc., which can affect the results o f the tests. The results obtained from this test assume uniform corrosion. Therefore, for p r o p e r analysis it becomes very important to include a complete description o f the exposed coupons. One o f the most important factors is visual inspection o f the coupon, describing the form o f attack and identifying the corrosion by-product. It is not very difficult to reduce the corrosion rate, so that overall mpy drops; however, the problem may still persist due to some pitting. It only takes a few sharp pits to cause failure. AP! Standard RP 13B contains complete information on this test [206]. Procedures provided by manufacturers o f corrosion coupons should be followed. To an appreciable d e g r e e the c o u p o n experiences the same downhole conditions as the drillstring does. Therefore, its c o n d i t i o n represents the corrosive effects o f the downhole environment. However, limitations o f this test are that the coupon is only e x p o s e d to the inside o f the drillstring and not subject to the same stresses. The results o b t a i n e d are only for certain d e p t h o f exposure, while the corrosion may vary appreciably up a n d down the hole. Finally, the results are not available until the tool is p u l l e d out o f the hole.

Chemical Testing During drilling operations, chemical testing o f drilling fluids is routinely carried out in the field. AP! has published r e c o m m e n d e d test procedures such as API RP 13B: "Standard Field Procedure for Testing Drilling Fluids" [206]. A number o f service companies such as NL Baroid, Milchem and IMCO Services supply test kits for chemical analysis with procedures. These tests conform to standards set in API RP 13B [206]. The tests monitor the p H o f drilling fluids and detect contaminants, such as dissolved gases and salts. These results are used either to detect any potential problem or to verify the effectiveness o f remedial measures.

pH Determination The two most c o m m o n l y used m e t h o d s o f measuring the p H o f a drilling fluid are a m o d i f i e d coalorimetric m e t h o d , such as the p H y d r i o n Dispenser;

C o r r o s i o n a n d Scaling

1317

a n d the electrometric m e t h o d using a glass-electrode instrument, such as the Beckman or Analytical p H meter.

pHydrion Oispenser. p H y d r i o n Dispenser provides a series o f p a p e r indicator strips that d e t e r m i n e p H from 1 through 14. O n c e e x p o s e d to the m e d i u m , the strip changes color. T h e color, is m a t c h e d to the r a n g e o f color a n d corres p o n d i n g p H values p r o v i d e d on the dispenser. T h e m e t h o d is sufficiently accurate to allow the o p e r a t o r to read within 0.5 p H units. A limitation o f this m e t h o d is that it does not give accurate m e a s u r e m e n t s in fluids c o n t a i n i n g high-salt c o n c e n t r a t i o n s . T h e m e t h o d d e p e n d s on the o p e r a t o r ' s ability to distinguish between different shades o f color, a n d can vary from one o p e r a t o r to a n o t h e r [195]. pH Meter. T h e analytic p H m e t e r offers a greater d e g r e e o f accuracy than the c o a l o r i m e t r i c m e t h o d does. T h e i n s t r u m e n t consists o f two half-cells, the glass e l e c t r o d e half-cell a n d a reference half-cell. T h e glass electrode consists o f a p l a t i n u m electrode in a solution o f fixed acidic pH. T h e e l e c t r o d e is placed inside a thin, glass m e m b r a n e p e r m e a b l e to H ÷ ions. T h e reference half-cell is usually either a calomel electrode [mercury in contact with mercury(I) chloride in s a t u r a t e d potassium chloride] or a silver/silver chloride electrode (silver wire c o a t e d with silver c h l o r i d e s a t u r a t e d p o t a s s i u m chloride). T h e two half-cells are c o n n e c t e d to each o t h e r through a sensitive voltmeter to form a p H meter. T h e e l e c t r o d e potential o f the glass electrode is d e p e n d e n t on the (H ÷) conc e n t r a t i o n o f the s o l u t i o n in which it is p l a c e d . T h e electrical p o t e n t i a l is a m p l i f i e d by means o f a vacuum tube. In a c o m m e r c i a l p H m e t e r the glass electrode a n d reference half-cell are n o r m a l l y c o m b i n e d in a single unit that can b e d i p p e d into the solution u n d e r test, a n d the p H r e a d i n g is i n d i c a t e d directly on a meter. Oxygen Meter Several commercially available oxygen meters are capable o f reading dissolved oxygen concentrations in seconds. They can be calibrated for t e m p e r a t u r e a n d salt concentration for accurate readings. T h e oxygen p r o b e operates on the same principle as the p H electrode, a n d develops a potential p r o p o r t i o n a l to oxygen concentration. T h e potential is read on the oxygen m e t e r as m g / L or p p m o f dissolved oxygen p r e s e n t in solution [207].

Gas and Specific Ion Meters Similar to the p H meter, gas meters e m p l o y specific ion electrodes. T h e electrodes g e n e r a t e a potential p r o p o r t i o n a l to the activity o f a specific ion in solution. T h e calibration is achieved in s t a n d a r d solution a n d results read in m v or concentration in m g / L or p p m on the meter. T h e water can b e a d a p t e d to m o n i t o r the c o n c e n t r a t i o n o f carbon dioxide, h y d r o g e n sulfide, a m m o n i a , chloride, calcium, potassium a n d s o d i u m to n a m e a few.

Hydrogen Sulfide Detection Hydrogen sulfide can be detected by several tests. Some o f the most commonly used in the drilling industry are as follows [195,207]:

1318

Drilling a n d Well C o m p l e t i o n s

1. A n Alka-Seltzer® tablet gives off carbon dioxide when dissolved in aqueous solution. T h e gas is used to drive hydrogen sulfide out o f drilling fluid samples. T h e H2S then reacts with lead acetate paper in the bottle cap. T h e d e g r e e o f d i s c o l o r a t i o n is related to hydrogen sulfide concentrations. 2. T h e presence o f sulfate-reducing bacteria can be detected by using API sulfate-reducing broth. If the broth is inoculated with drilling f l u i d a n d the color changes from yellow to black, the result is positive. 3. S o d i u m arsenite can be used to detect the presence o f iron sulfide on the metal surface. Iron sulfide is the corrosion product o f the reaction between hydrogen sulfide in drilling fluid and iron in the drillpipe. A n acid solution o f sodium arsenite reacts with the sulfide to form a bright yellow precipitate. 4. W h e n present in low concentrations the presence o f hydrogen sulfide can be detected by its characteristic o d o r o f rotten eggs. 5. A prestressed roller b e a r i n g is used to detect the presence o f hydrogen sulfide, but m o r e specifically it is used to test for hydrogen e m b r i t t l e m e n t t e n d e n c y o f the drilling fluid. W h e n i n t r o d u c e d to the environment, the bearing has sufficient residual stresses to cause failure if sufficient hydrogen sulfide c o n c e n t r a t i o n is present. 6. A slight d r o p in p H level o f the drilling fluid.

Carbon Dioxide Detection If the p H level o f drilling f l u i d drops a n d the hydrogen sulfide test result is negative, there is a g o o d possibility that carbon dioxide will be present. Positive results o f microbial activity tests (described later) also indicate the possibility o f carbon dioxide presence. C a r b o n dioxide meters are also available commercially a n d can be used.

Ultrasonic Inspection Ultrasonic inspection is a m e t h o d o f m e a s u r i n g the pipe wall thickness. T h e basic concept o f the test is that the sound travels through metals at a constant s p e e d a n d does not travel well t h r o u g h air. T h e m e t h o d consists o f cleaning the test surface smooth a n d coating the surface with a layer o f coupling fluid such as oil a n d glycerine. T h e coupling fluid facilitates the transmission o f sound from the test unit to the metal surface. A curved face t r a n s d u c e r is used to convert a high-frequency electrical impulse to sound vibration. T h e sound travels through the metal at a known speed a n d is reflected or e c h o e d back to the s e n d i n g transducer. T h e time interval b e t w e e n the initial pulse a n d the r e t u r n echo is calibrated electronically, a n d the instrument displays a digital readout o f the metal thickness. Limitation o f this m e t h o d is that it only gives the wall thickness at the point tested. Thus, there is a possibility o f missing the d a m a g e d area. Also, this m e t h o d does not indicate the type o f d a m a g e o c c u r r i n g [201].

Magnetic Particle Inspection W h e n iron filings are sprinkled on a bar magnet, they are attracted to the poles o f the m a g n e t (Figure 4-476). If the bar m a g n e t is notched, each side o f the notch b e c o m e s a pole o f a m a g n e t as seen in Figure 4-473. Cracks on d r i l l p i p e a n d collars behave the same way when magnetized. Magnetic particle inspection is based on this concept. T h e m e t h o d consists o f magnetizing the pipe with a suitable field to cause a magnetic flux. T h e pipe is then sprayed

Corrosion and Scaling

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1319

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Figure 4-476. Principle of magnetic particle inspection. (From Ref. [220].) with a fluid containing fluorescent magnetic particles (fluorescent tracer). Ultraviolet light is used to detect any buildup of magnetic particles. A limitation of this method is that it is only good for surface or near-surface areas of the pipe.

Visual Inspection On-site visual inspection of drilling equipment before use is one of the most important factors for successful operation. The drillpipes and drill collars are inspected for signs of pitting corrosion, corrosion fatigue cracks and other damage or defects that may lead to their failure. It is very important to take notes describing the problem and measuring anything relevant, taking pictures (with reference scale) of the damage and making sketches. Any other relevant information helpful in later analysis should be included. The inspection consists of two tests, the external pipe body and internal pipe surface. The external pipe body is inspected by thoroughly cleaning the surface and examining the whole length with either the naked eye or with the help of a magnifying glass. Internal inspection is carried out by cleaning the internal surface and using a borescope optical instrument. This method is limited by the fact that small cracks may be two small to be detected, and by the speed of the procedure.

1320

Drilling a n d Well C o m p l e t i o n s

Plastic Coating Inspection F r e q u e n t a n d r e g u l a r i n s p e c t i o n s are very i m p o r t a n t at every step o f the process. Inspections should ensure adequate surface p r e p a r a t i o n a n d u n i f o r m coating application with p r o p e r curing process. Once completed, the coatings must be inspected for any pinholes o r "holidays" (discontinuities). A low-voltage, wet-sponge, holiday-detector can be used to detect any pinholes in the coating (Figure 4-477). T h e water in the s p o n g e should contain a b o u t 0.5% s o d i u m chloride. T h e power source imposes a voltage o f up to 90 V (usually 67.5 V) across the coating t h r o u g h the wet sponge. T h e wet sponge is p u l l e d t h r o u g h a j o i n t o f internally coated p i p e at low enough speed to detect the holidays. W h e n the sponge is p u l l e d across a holiday, an alarm in the d e t e c t o r is activated, a n d the electrical resistance o f the coating drops below 80,000 f). Care must be taken to avoid b u r n i n g holes in the coating by using high voltage. Voltage a n d current must be regulated to safe levels for the film thickness involved. Manufacturer's instructions should be carefully followed [201].

Monitoring Microbial Activity As m e n t i o n e d earlier, m i c r o o r g a n i s m s can attack drilling f l u i d additives a n d i n t r o d u c e corrosive agents to the system. T h e r e f o r e , it is very i m p o r t a n t to m o n i t o r their activity a n d detect any source o f p r o b l e m as early as possible. API RP 38 is probably the most widely used testing p r o c e d u r e in the industry [201]. T h e m e t h o d s that can be u s e d to m o n i t o r the m i c r o b i a l activity can include the following [201,208]: • filtration technique • b a c t e r i a l p o p u l a t i o n count • metal-surface examinations • evaluation o f c u r r e n t m i c r o b i o c i d e t r e a t m e n t

Filtration Technique. A m e a s u r e d quantity o f sample water is filtered through the m e m b r a n e filter. T h e filter is dried, cut and sections placed on microscope slides. T h e filter sections are r e n d e r e d t r a n s p a r e n t by a d r o p o f i m m e r s i o n oil. T h e slides are e x a m i n e d to identify the m i c r o o r g a n i s m s listed below: a. algae a n d p r o t o z o a b. bacteria c. fungi

Bacterial Populatlon Count. Commercially available test media following API specifications are available for f i e l d testing. T h e two test s e r a available for inoculation by sample solutions are: 1. clear-yellow b r o t h for anaerobic bacteria (i.e., sulfate-reducing bacteria). 2. p h e n o l red b r o t h for general aerobic bacterial counts. T h e test sera are available in sealed bottles. Six bottles are used in each test. They are labeled 1, 10 -1, 10 -2, 10 -3, 10 -4, a n d 10 -~, indicating the dilution factor. O n e unit (one ml o r one cm 3) o f the sample solution is collected in a disposable,

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Figure 4-477. Holiday detector for thin film internal pipe coatings. (From Ref. [201].)

1322

Drilling a n d Well C o m p l e t i o n s

sterile, plastic syringe. T h e syringe needle is inserted all the way t h r o u g h the r u b b e r seal o f the bottle labeled 1, and the contents are injected. One unit from bottle 1 is drawn into the syringe and injected into the bottle labeled 10 -1. O n e unit o f mixture from bottle 1 contains 0.1 or 10 -1 units o f the original sample solution concentration. The p r o c e d u r e is repeated for the remaining four bottles with one unit o f liquid each. Once all six bottles are inoculated, the syringe is discarded. The inoculated bottles are held at a temperature o f within 41°F (or 5°C) o f the original sample temperature in the system being tested. W h e n phenol red broth changes from red to yellow and looks turbid, it indicates growth o f aerobic bacteria. When clear-yellow broth turns dark, it shows the growth o f anaerobic bacteria. T h e main disadvantage o f these m e t h o d s is the time these tests take, five days for p h e n o l red b r o t h a n d 21 days for clear-yellow broth. A l t h o u g h not very precise, the bacterial count can be estimated by using the i n f o r m a t i o n p r o v i d e d in Table 4-172.

Table 4 - 1 7 2 Bacterial Count Type of BacteriaPAnaerobic Bottle No. Positive After Twenty-one Days

Estimated Count Cells/Unit

1 10-1

1-10 10-102

10-2 104

102-103 103-104 104-10 s

10-s

10S-106

104

Possible Interpretation

Acceptable count--not a problem. Low countDrepeat tests. Moderate count--possibility of some problem. Slightly high count--great possibility of problems. High count-serious problems. Prepare remedial action. Very high count---extremely serious problems. Initiate remedial action.

Type of BacteriaDAerobic Bottle No. Positive After Five Days 1

Estimated Count Cells/Unit 1-10

10-1

10-102

10-2 10-~ 104

102--103 103-104 104-10 s

10-s

10S-106

Source:Adaptedfrom Ref. [201].

Possible Interpretation

Acceptable count--not a problem. Low count--generally not a problem. Low count--generally not a problem. Moderate count--repeat tests. High count---probable problem. Prepare remedial action. Very high count--problem imminent. Initiate remedial action.

Corrosion a n d Scaling

1323

Corrosion Control Corrosion-related problems can be either prevented or reduced by considering the following i m p o r t a n t factors: • • • • •

material selection design e n v i r o n m e n t a l control corrosion barriers personnel t r a i n i n g

To have an effective corrosion-control program, the following suggestions should be considered: • • • •

Review the previous records of similar situations. Collect a n d analyze as m u c h i n f o r m a t i o n a n d corrosion data as possible. Select compatible materials for the service e n v i r o n m e n t a n d conditions. Maintain a p r o g r a m to m o n i t o r any signs of corrosion problems, a n d keep good records.

Material Selection O n e of the most effective methods of preventing corrosion is the selection of the proper metal or alloy for a particular corrosive service. Once the conditions of service a n d e n v i r o n m e n t have been determined that the equipment must withstand, there are several materials available commercially that can be selected to perform an effective service in a compatible environment. Some of the major problems arise from popular misconceptions; for example, the use of stainless steel. "Stainless" steel is not stainless a n d is not the most corrosion-resistant material. C o m p a t i b i l i t y o f m a t e r i a l with service e n v i r o n m e n t is therefore essential. For example, in a hydrogen sulfide e n v i r o n m e n t , high-strength alloys (i.e., yield strength above 90,000 psi or Rc 20 to 22) should be avoided. In material selection some factors that are i m p o r t a n t to consider are material's physical a n d chemical properties, economics a n d availability.

Material Properties. Materials possess various mechanical a n d chemical properties, and, therefore, it is possible to select materials appropriate for severe corrosion conditions. For example, if the e q u i p m e n t is u n d e r cyclic loading, a material with high fatigue strength is desired. Similarly, it is desirable to have corrosion-resistant materials for the corrosive e n v i r o n m e n t s . There are several sources for o b t a i n i n g i n f o r m a t i o n on materials properties. Some are listed in Table 4-173. Once materials have b e e n selected, the next step is to compare the required properties with a large data of material properties that look promising for the application. O n e should then analyze test data (i.e., corrosion test data) to obtain the most suitable material for services. Economics of Material Selection. Cost is an overpowering consideration in material selection. The basic cost of a material d e p e n d s upon:

1324

Drilling and Well Completions

Table 4-173 Some Sources of Material Properties NACA Corrosion Engineer's Reference Book, Treseder, R. S., 2nd Edition, National Association of Corrosion Engineers, Houston, Texas, 1991. Corrosion Control in Petroleum Production, TPC5, National Association of Corrosion Engineers, Houston, Texas, 1984. Engineering Materials Properties and Selection, Budinski, K., 2nd Edition, Reston Publishing Co., Reston, Virginia, 1983. Betz Handbook of Industrial Water Conditioning, Betz LaboratoriesInc., Trevose, Pennsylvania, 1980. 1. scarcity, as d e t e r m i n e d by concentrations of metal in the ore 9. the cost and a m o u n t of energy required to process the material 3. the basic supply and d e m a n d for the material; large-volume-usage materials generally have low prices The more work invested in the processing of a material, the higher the cost (value is added). Increases in properties, such as corrosion resistance and yield strength, beyond the basic material properties, require structural changes. These structural changes occur due to chemical composition change and additional processing steps. For example, the cost goes up as expensive alloying elements are added to the steel or when the steel is heat treated. As the materials used in drilling processes are p r o d u c e d from depletable m i n e r a l resources, there is a continuous upward trend of cost with time. The field engineer must make a detailed cost comparison of materials available within the target cost of the project. The final choice may be a tradeoff between cost and performance. This is because the choice may narrow down to two or more materials with different initial costs and different expected service lives. Transportation costs of selected materials must also be included in the final cost.

Availability of Materials. Availability of the candidate material is a very essential consideration in the decision-making process. There is no sense in specifying the use of a particular material if it cannot be obtained within the time constraints of the project. It is also advisable to select materials that are available from more than one supplier. If p r o p r i e t a r y materials that are only available from one supplier are used, o n e can b e c o m e a captive customer at the mercy of the supplier on cost and delivery. It is very important to consult the available literature p e r t i n e n t to the project. API and NACE a m o n g others publish standards on material selection that should be reviewed before the material is selected.

Design The design of service e q u i p m e n t (i.e., drillstring) is quite often as i m p o r t a n t as the choice of materials for the equipment. The system can be designed to minimize or totally eliminate the factors c o n t r i b u t i n g to corrosion problems. Therefore, when designing, it is very important to consider corrosion along with mechanical and strength requirements. Materials selected for their corrosion resistance vary widely in their characteristics. Therefore, the design of the system should be based on selected materials.

C o r r o s i o n and Scaling

1325

Most drillstem failures can be attributed to corrosion. Therefore, the following discussion will focus on design considerations to minimize drillstem failures. Too1 j o i n t s suffer high wear on the outer surface because of the a b r a s i o n against the hole wall. This abrasive effect worsens with an increase in hole deviation. As the tool joint rotates under high lateral force against the hole wall, its temperature rises and may reach lower critical levels. The tool joint is alternatively heated by friction and quenched by drilling fluid. This leads to formation of small cracks, leading to hard-facing corrosion fatigue or sulfide stress cracking. Hard-facing the

Tension due to hookloads

Bending~ ~ ~Tension Compres 'f 4, Torsion

~r

Tension due to drill collars Figure 4-478. Stress loading on drillstem. (From Ref. [218].)

1326

Drilling and Well Completions

toolzjoint outer surface and keeping the deviation angle (dogleg angle) low can help in reducing wear on the drillstring (Figure 4478). As the drilling progresses and the drillstring is rotated, the drillstring experiences four basic stresses. The four main stresses are tension, compression, bending and torsional stresses (Figure 4-478); a fifth stress, not shown in Figure 4-478, is caused by the vibration of the drillstring. The tension load is caused by the hook load (weight of the pipe) and the weight of the drill collars at the bottom of the assembly. Part of the drillstring is u n d e r compression and the rest is u n d e r tension. The point at which the string changes from tension to compression is called the neutral point. The location of the neutral point on the drillstring depends on the number of drill collars used and the weight of the drilling fluid (the weight adds buoyancy to the drillstring). Drilling with drillpipes u n d e r compression leads to drillpipe failure. Therefore, the drillstring is designed with enough drill collar weight to locate the neutral point in the drill collar section. Bending stresses are caused by drilling deviated holes. Once bent, drill pipes remain weak. The fourth stress is the torsional stress. The drillstring experiences this stress when the bit is cutting into the formation. Torsional yield strength, therefore, has to be considered when designing the drillstring. Finally, there is a fifth stress caused by vibration of the drillstring. It has been discovered that definite benefits can result from damping severe, downhole vibrations. Therefore, the use of vibration dampers or shock subs above the bit in rough drilling areas is strongly recommended. Once the wear of the drillstring and a better control o f stress concentration are achieved, it is possible to reduce corrosion-related failure of the drillstem. In the above discussion only the drillstem was discussed. However, when designing other systems in drilling operation, such as drilling fluid systems and casing design to name a few, the engineer must also consider corrosion prevention.

Environmental Control Environmental control involves reducing the corrosivity of the drilling fluids. Controlling the factors influencing the corrosion rate is a way to reduce the corrosivity of the drilling fluid. These factors are temperature, pressure, velocity and corrodent concentration. Chemical treatment is also used in reducing the corrosivity of the drilling fluid. Corrosion inhibitors, neutralizers, scavengers and scale inhibitors can be used to minimize the corrosivity of the drilling fluids.

Temperature and Pressure. Temperature o f the drilling fluid can be reduced by using cooling towers when drilling through high-temperature zones. Geot h e r m a l drilling is a g o o d example of this situation. A degasser unit can be added to the circulatory system to separate the contaminating gas or gases from the drilling fluid. These units can be added to the surface part of the circulatory system.

Velocity. The velocity of the drilling fluid is a major problem in air and gas drilling operations (see section titled "Air and Gas Drilling"). High gas velocity (i.e., 8,000 f t / m i n ) is maintained during dry gas drilling. The high annular velocities are necessary for dry-gas drilling fluid to function properly. Therefore, alternative drilling fluids should be considered if corrosion problems are severe. Stable foam can perform effectively at reduced annular velocity such as 2,000 f t / m i n or lower.

C o r r o s i o n and Scaling

1327

Corrodent Concentration.

Salt Concentration. T h e most cost-effective m e t h o d of reducing salt concentration levels is to dilute water-base drilling f l u i d with freshwater. Care must be taken to make sure that the makeup water is c o m p a t i b l e with the system. T h e water must not contain high concentrations of undesirable corrodents. Gas Concentration. T h e principal source of oxygen and some carbon dioxide c o n t a m i n a t i o n is the surface p a r t of the circulatory system. Care must be taken to reduce unnecessary a e r a t i o n of the drilling fluid. Makeup water should be a d d e d to the system at the m u d flow-line. This will increase the water temperature by the warm, returning, drilling fluid. T h e increase in water t e m p e r a t u r e reduces the solubility of gases. I n f l u x of f o r m a t i o n fluids can also introduce c o n t a m i n a t i n g gases such as carbon dioxide and hydrogen sulfide. Increasing the m u d weight to the level to prevent influx can minimize this type of contamination. As m e n t i o n e d earlier, a d e g a s s e r unit can be used to degas the drilling fluid. Corrosion Inhibitors. A n inhibitor is any substance that retards or slows down a c h e m i c a l r e a c t i o n . Thus, when a d d e d to t h e e n v i r o n m e n t in small concentrations, inhibitors reduce the rate, or prevent the attack by the environment on the metal. T h e basic mechanisms by which inhibitors function are as follows [209]: 1. They adsorb onto the c o r r o d i n g material as a thin film. 2. They induce f o r m a t i o n of a thick corrosion product, which form a passive layer. 3. They change the characteristics of the e n v i r o n m e n t either by p r o d u c i n g protective precipitates or by removing or inactivating an aggressive constituent of the environment. To be used effectively, the inhibitor must be compatible with the expected environment and also be economical, while c o n t r i b u t i n g the greatest desired effect. Inhibitors can be classed into two main categories, inorganic and organic inhibitors.

Inorganic Inhibitors. Inorganic inhibitors are generally crystalline salts such as s o d i u m chromate, s o d i u m silicate and s o d i u m phosphates, a m o n g others. These salts form ions in solution. T h e positively charged cations (Na ÷) and the negatively charged anions (CrO42-, SiO32-, PO42-). T h e negatively charged anions cause the decrease in the corrosion rate. T h e r e are basically t h r e e main types of inorganic inhibitors used in industry: anodic passivating inhibitors, cathodic inhibitors and cathodic precipitators. Anodic Passivating Inhibitors. T h e r e are basically two types of anodic passivating inhibitors. O x i d i z i n g anions, such as c h r o m a t e , n i t r i t e and n i t r a t e , are capable of passivating the steel in the absence of oxygen. T h e second type is nonoxidizing ions, such as phosphates, tungstate and molybdate, which require the presence of oxygen to passivate the steel. W h e n used in sufficient quantities, the i n h i b i t o r s can be very effective in c o n t r o l l i n g t h e c o r r o s i o n p r o b l e m . However, if used in insufficient concentrations, they may cause pitting and can increase the rate of corrosion. Due to these possibilities, they are sometimes referred to as dangerous inhibitors.

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Drilling and Well C o m p l e t i o n s

Cathodic Inhibitors. C a t h o d i c inhibitors r e t a r d the c o r r o s i o n rate by affecting the reaction at the cathode, as the n a m e suggests. Cathodic inhibitors can be d i v i d e d into several categories according to the way they achieve inhibition by cathodic polarization. T h e t h r e e main types o f these inhibitors are cathodic poisons, c a t h o d i c p r e c i p i t a t e s and oxygen scavengers. C a t h o d i c poisons and c a t h o d i c p r e c i p i t a t e r s a r e n o t u s e d in d r i l l i n g o p e r a t i o n s . T h e r e f o r e , t h e discussion will only focus on oxygen scavengers. Oxygen Scavengers. W h e n c o r r o s i o n o f steel occurs at p H levels o f above 6, it is usually due to the presence o f dissolved oxygen. Dissolved oxygen depolarizes the cathodic reaction and, therefore, increases corrosion. Oxygen scavengers achieve c o r r o s i o n i n h i b i t i o n by p r e v e n t i n g c a t h o d i c d e p o l a r i z a t i o n . O r g a n i c c o r r o s i o n inhibitors are usually a d d e d with oxygen scavengers when oxygen c o n t a m i n a t i o n is suspected. This is b e c a u s e o r g a n i c inhibitors a l o n e r e t a r d general corrosion, but may not prevent pitting d u e to presence o f oxygen. T h e r e are several oxygen scavengers commercially available, such as hydrazine and sulfites, with the most cost-effective being sulfites. Sulfites react with oxygen in the following manner: 2RSO 3 + 02 -~ 2RSO 4 T h e most c o m m o n l y used sulfite is s o d i u m sulfite Na2SOa: 2Na2SO 3 + 0 2 ---) 2Na2SO 4 It is usually a g o o d practice to add a catalyst to the system. Catalysts increase the rate o f oxygen scavenging. T h e most commonly used catalysts are the transition elements in their II oxidation state. Some good examples are Co 2+, Mn 2+, FC + and Ni 2+. Some o t h e r commercially available oxygen scavengers are a m m o n i u m bisulfite, various organic amine sulfites and a c o m b i n a t i o n o f a m i n e - a m m o n i u m bisulfite with an o r g a n o m e t a l l i c catalyst c o m p o n e n t .

Organic Inhibitors. These organic c o m p o u n d s affect the entire surface o f a c o r r o d i n g metal when present in sufficient concentrations. Figure 4-430 shows the effect o f organic i n h i b i t o r c o n c e n t r a t i o n s on the rate o f corrosion. T h e c o r r o s i o n inhibition increases as the inhibitor c o n c e n t r a t i o n increases, a result o f a d s o r p t i o n o f organic inhibitors onto the metal surface. A thin film only a few molecules thick is a d s o r b e d according to the ionic charge o f the inhibitor molecule and the charge onto the metal surface. Cationic inhibitors (positively charged), such as amines, o r anionic inhibitors (negatively charged), such as sulfonates, are adsorbed selectively d e p e n d i n g on the charge, positive o r negative. T h e molecules o f these inhibitors are u n b a l a n c e d with one portion, the tail end, b e i n g oil soluble o r h y d r o p h o b i c (water repelling). T h e o t h e r e n d is the p o l a r head o r hydrophilic (water loving). As only a part o f these inhibitor molecules is polar, they are said to be "semipolar" (Figure 4-479). These molecules adsorb over the metal surface as these p o l a r heads attach to the metal surface. T h e oil-soluble, h y d r o c a r b o n tail a t t r a c t s s o m e oil o r h y d r o c a r b o n c o n s t i t u e n t s flowing past the metal [210]. T h e oil e n m e s h e s in t h e tail, as shown in F i g u r e 4-480, a n d p r o v i d e s a mechanical b a r r i e r to attack o f the aqueous c o r r o d e n t s on the base metal. T h e oily film also increases the resistance to corrosion current flow and, thus, stifles the rate o f corrosion. A n advantage o f using organic f i l m - f o r m i n g inhibitors

Corrosion and Scaling

Oily hydrocarbon chain (R)

Polar amine groups

Figure 4-479. A semipolar molecule. (From Ref. [201].)

WATER n

OIL FILM

OIL-SOLUSLE O. CL (:~ O~ O~ '~ Q O~ CL O. (3.

Figure 4-480. Schematic of film-forming inhibitor. (From Rof. [210].)

1329

1330

Drilling and Well Completions

compared to applied coatings is that the inhibitor films are self-healing, as they are continuously added. However, coatings and linings are p r o n e to mechanical damage, which requires shutdowns for m a i n t e n a n c e and repair. A drawback of using this type of inhibitor is that if insufficient c o n c e n t r a t i o n is used, it may result in accelerated corrosion. The factors c o n t r i b u t i n g to effectiveness of organic inhibitors are: 1. 2. 3. 4. 5.

the molecular size aromaticity a n d / o r conjugated b o n d i n g b o n d i n g strength to the metal substrata type and n u m b e r of b o n d i n g atoms or group in the molecule ability of the layer to become compact, or crosslink

Some examples of organic anionic inhibitors are sodium phosphates, thioureas and sodium MBT phosphionates (mercaptobenzothiazole). Some examples of organic cationic inhibitors are amines, amides, quaternary ammonium salts, and imidazoline.

Selection of Corrosion Inhibitors. When selecting inhibitors for use, it is always i m p o r t a n t to consider the following useful suggestions: • Consult an outside consultant specializing in the use of inhibitors. • Review available literature on the use of the inhibitor in question for a particular e n v i r o n m e n t . • Conduct in-house inhibitor tests to d e t e r m i n e which inhibitor and at what c o n c e n t r a t i o n to use. The tests must be conducted following the recomm e n d e d practices of NACE or ASTM. ASTM (American Society for Testing and Materials) and NACE (National Association of Corrosion Engineers) publish standards for such tests. • The inhibitors must be readily available, and cost effective. • Consideration should be given to the inhibitor's effects on drilling fluid properties, other than corrosivity.

Inhibitor Efficiency. The value of corrosion inhibitors can be compared on the basis of inhibitor efficiency. Inhibitor efficiency indicates the percentage that corrosion is lowered in the presence of the inhibitor as compared to that in its absence. Inhibitor efficiency can be calculated by using the formula

E= ( R°- R~ )100 )

(4-368)

where E = inhibitor efficiency R0 = rate of corrosion in the absence of an inhibitor R i = rate of corrosion in the presence of an inhibitor

Application of Corrosion Inhibitors. There are basically two main techniques used to apply corrosion inhibitors in drilling operations. In the first m e t h o d inhibitors are added to the drilling fluid system either by mixing the additives through the rig's chemical h o p p e r or through additions into the m u d pit. The treatment can be achieved in two ways, batch treatment or continuous treatment. In some cases it may be necessary to use both types of treatment simultaneously. The second technique of applying is directly coating the corrosion inhibitors on the drillpipe.

Corrosion and Scaling

1331

Batch Treatment. This treatment is accomplished by p u m p i n g manufacturer's r e c o m m e n d e d volume (with c o n c e n t r a t i o n up to 10,000 p p m or according to the manufacturer's r e c o m m e n d a t i o n s for prevailing conditions) to "batch" down the drillpipe initially. Once the film is formed, the inhibitor c o n c e n t r a t i o n can be lowered for batch treatment at regular p r e d e t e r m i n e d intervals. Continuous Treatment. C o n t i n u o u s treatment involves introducing a corrosion inhibitor on a regular basis to maintain the specified concentrations of inhibitors in the system. D e p e n d i n g on the prevailing c o n d i t i o n s a n d m a n u f a c t u r e r ' s r e c o m m e n d a t i o n , the c o n c e n t r a t i o n may vary from a few parts per million to 50 p p m or more.

Direct Treatment. A l t h o u g h batch and c o n t i n u o u s t r e a t m e n t are both quite effective, there is a problem with inhibitor waste. W h e n corrosion inhibitors contact the circulating drilling fluid, they are likely to coat the solids in the f l u i d system (cuttings or other solids). By applying the c o r r o s i o n i n h i b i t o r directly to drillstem c o m p o n e n t s before they are r u n in the hole, the corrosion inhibitor is the first thing that contacts the exposed metal surface. There are two methods for this type of corrosion inhibitor treatment.

Spray or Painting Application. The corrosion inhibitor is either sprayed (Figure 4-481) or painted (by paint brush) on the drillstem components, before they are r u n in the hole. The application process also takes place while tripping into the hole. Spray application systems can be m o u n t e d on brackets just above and a r o u n d a bell nipple. A 1-in. circular pipe with one closed e n d and the other connected to an air-powered spray-application system is used. Three spray nozzles pointing inward and slightly downward into the wellhead are used to deliver the spray. The spray system is activated by a foot pedal situated near the driller's console as the drillstem is lowered into the borehole. Batch treatment for the inside of the drillstem and general c o n d i t i o n i n g should also be carried out at regular intervals (i.e., every 5 to 10 stands) [211,212].

Dipping Application. T r e a t m e n t by d i p p i n g consists of d i p p i n g a j o i n t of drillpipe into an "extra mouse hole" (Figure 4-482). The extra mouse hole may be located half way between the V-door and the rig's "working" mouse hole on the rig floor. The mouse hole can be constructed from a large-diameter casing (i.e., 9 ~ in. diameter), cut to about 28 ft in length with the bottom sealed closed. The hole is filled with corrosion inhibitor and drained out into storage containers through a bottom valve (Figure 4-482) when not in use. The exposed part of the drillstem component is treated by inhibitor coating using a regular paint brush. Whatever m e t h o d of i n h i b i t o r application is used, care must be taken to m a i n t a i n o p t i m u m c o n c e n t r a t i o n of the corrosion inhibitor. In the event of addition of makeup water or untreated reserve fluids to maintain other fluid properties, care must be taken to ensure the addition of the correct amounts of corrosion inhibitors. Inhibitor Concentration. Corrosion inhibitors are commercially available in solid or liquid form. Liquid inhibitors are usually preferred as they are easier to transport, measure and use. Corrosion inhibitors are dissolved in appropriate solvents and mixed with property enhancers to achieve the desired properties. The prepared mixture of liquid inhibitors is sold by the gallon. The a m o u n t of the inhibitor present in the mixture is expressed as percent active. For example, a gallon of inhibitor which is 25% active contains 25% by weight of inhibitor.

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Drilling and Well C o m p l e t i o n s

i

ll

l e g ~ e ~ n u d li~, ~ V ares r j m ~ m

~lne

f

Fl-

ii¢~tau~

7"='i=" I[ Figure 4-481. Inhibitor spraying equipment. (From Ref. [212].) Inhibitor concentrations are generally expressed as parts per million (ppm). Solid inhibitors are expressed on a weight basis, such as pounds or kilograms o f inhibitor per million pounds or kilograms o f fluid. Liquid inhibitors are expressed in volumes used, such as liters o f inhibitor per million liters o f fluid. To find the quantity o f inhibitor required for a given system, the following formula can be used: Q= (v×

10 -6)× p p m

(4-369)

where Q = quantity o f inhibitor r e q u i r e d V = amount o f f l u i d to be inhibited p p m = c o n c e n t r a t i o n o f inhibitor in parts p e r million T h e quantity o f inhibitor Q is always in the same units as those used for the a m o u n t o f f l u i d to be inhibited V.

Neutralizers. To m a i n t a i n p H levels in a l k a l i n e regions, it is n e c e s s a r y to n e u t r a l i z e the acidic c o m p o n e n t s o f the c o r r o s i v e m e d i u m . Water-soluble, alkaline materials, such as s o d i u m hydroxide (NaOH), a m m o n i u m hydroxide (NH4OH) and calcium hydroxide [Ca(OH)2], can be used to obtain p H levels a r o u n d 9.6. However, care must be taken to avoid reaching p H levels that are

Corrosion and Scaling

1333

J /

T

~4~ge~

m ~

Figure 4-482. Drillpipe dipping treatment. (From Ref. [212].) high enough to cause scale formation of calcium and magnesium salts. The neutralizing materials can be added to the drilling fluid circulation system directly or to the mud pits.

Scale Inhibitors. When scaling conditions exist, scale inhibitors can be used to control the scaling tendencies, and keep metal surfaces free of scale deposits. Scale inhibitors are chemicals that interrupt and deform the normal crystalline growth pattern of carbonate scales. The three most commonly used classes of scale-inhibiting chemicals used in drilling fluid are [191,197]: 1. amino-phosphonates 2. phosphate esters of amino-alcohols 3. sodium polyacrylate polymers These chemicals are generally marketed as water solutions (20 to 30% active). Alcohols are usually added to lower the freezing point and keep the inhibitor chemical in solution.

Hydrogen Sulfide Scavengers. Hydrogen sulfide (H~S) can be neutralized by using sodium hydroxide (NaOH) and calcium hydroxide [Ca(OH) z] [213,214]. The reaction is

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Drilling a n d Well Completions

H2S + OH- ---) H20 + HSHS- + OH-

---) H20

+ S2-

The n e u t r a l i z a t i o n is essentially c o m p l e t e at pH levels higher t h a n 9.5; however, if the pH levels drop below 9.5, H2S is released. As H2S neutralization may reverse by change in pH, neutralization does not provide the degree of security required in H2S control. Thus, special scavenging c o m p o u n d s are used to remove the H2S from the drilling fluids. H2S scavenging is a form of irreversible treatment at operating conditions. There are two types of scavengers available to the drilling industry, zinc-base scavengers a n d iron-base scavengers. Soluble sulfides (i.e., H2S, HS- and S2-, with sulfur at minus two oxidation state) are chemically very reactive. The two general types of soluble-sulfide reactions may be identified as precipitation reaction (type A) and redox reaction (type B). In type A reaction soluble sulfide ions c o m b i n e with metal ions to form a precipitate of insoluble metal sulfide. Sulfur's oxidation state of minus two does not change in this reaction. The reaction is Zn 2÷ + S2- ~ ZnS ,1, This reaction occurs over a wide range of drilling fluid conditions. Type B (redox) r e a c t i o n s are more complex. Sulfide in this r e a c t i o n is converted into some other oxidation state of sulfur. For example, sulfides can be converted to a zero oxidation state of elemental sulfur by oxygen: 02 + 2H2S ~ 2S 0 + 2H20 In this way sulfides may disappear from circulating m u d when muds contact air during circulation.

Zinc-Base Scavengers. T h e r e are two types of zinc-base scavengers available. These are: 1. Slightly water-soluble inorganic compounds, zinc carbonate being the most common. Zinc carbonate is only slightly soluble in the middle range of the pH scale (i.e., 8 through 11). Commercial compounds of zinc carbonate are not the same as the mineral smithsonite, ZnCO 3. The manufactured commercial compound has an approximate formula 3Zn(OH)22ZnCO3. This commercialgrade c o m p o u n d contains 55 to 58 wt% zinc and about 20 wt% carbonate. The type A reaction that occurs between the zinc ion a n d sulfate ion is Zn 2÷ + S2- "--> ZnS ,l, ZnS is stable and will not revert to H2S unless the pH level drops below 3. It is highly unlikely for drilling muds to drop to pH levels below 3; generally the drilling mud pH is maintained around pH of 9.5. The slightly soluble, zinc-base scavenger can dissolve completely at high pH levels above pH of 11. This is because at high pH levels zincate ions are formed as high concentration of hydroxal ions (OH-) combine with the zinc ions as shown below. Zn 2÷ + 3OH- --) Zn(OH)-s Zn(OH)-s + OH- ~ Zn(OH)42-

C o r r o s i o n a n d Scaling

1335

This results in h i g h c o n c e n t r a t i o n s of zincate ions t h a t are effective scavengers. However, high concentrations of zincate can lead to p r o b l e m s related to m u d p e r f o r m a n c e . . T h e s e c o n d t y p e of zinc-base scavenger, utilizes highly water-soluble, organic, zinc-chelate c o m p o u n d s . T h e metal ions are b o n d e d with organic compounds, f o r m i n g "metal chelates" that are highly soluble in water. This high solubility enables their use in clear drilling fluids; whereas, a lesssoluble scavenger can settle out a n d b e c o m e ineffective. A n o t h e r advantage of using zinc chelates is that they are effective over a wide r a n g e of pH.

Iron-Base Scavengers. T h e r e is only one iron c o m p o u n d that is commercially available as a sulfide scavenger for drilling fluids. T h e p r o d u c t is a synthetic, high-surface-area magnetite, F%O 4. F%O 4 is often used in low-pH muds, where sulfides in the m u d exist largely as acidic m o l e c u l a r H2S. This is because reactions of F%O 4 in n o r m a l a l k a l i n e - m u d p H r a n g e s p r o c e e d at a slow rate. Consequently, a soluble sulfide may coexist with unreacted F%O 4 for undesirably long p e r i o d s of time. T h e scavenging reaction of H2S by F%O 4 proceeds according to the following equation by type A reaction: F%O 4 + 6H2S ~ 3FeS 2 ,l, + 4H20 + 2H 2 1" T h e reaction efficiency a n d p r o d u c t s f o r m e d d e p e n d on d o w n h o l e variables. T h e most i m p o r t a n t variables are pH, temperature, reaction time, post-reaction aging time, a n d mud-shear conditions. A n advantage of using F%O 4 over o t h e r chemicals is that large quantities of insoluble material can be a d d e d without affecting the drilling fluid properties. U n d e r o p t i m u m conditions with adequate F%O 4 surface area exposed, the p r o d u c t may remove up to 2,000 m g / L sulfides for 1 l b m / b b l (2.85 k g / m 3) F%O 4 treatment. F%O 4 is often used as a pretreatm e n t to reduce the threat to drilling tools a n d health of the drilling crew, which may r e s u l t f r o m a kick of gas c o n t a i n i n g h i g h H2S content. A l t h o u g h the chemical c o m p o s i t i o n is the same as magnetite, F%O 4, it is not very m a g n e t i c and, therefore, does not cling to d r i l l p i p e or casing.

M|crobiocides. T h e r e are several m i c r o b i o c i d e s available c o m m e r c i a l l y that can p e r f o r m an effective f u n c t i o n in controlling m i c r o b i a l activity. Some of these chemicals are inorganic, such as chlorine, s o d i u m hypochlorite, calcium hypochlorite, h y d r o g e n peroxide, chromates a n d c o m p o u n d s of m e r c u r y a n d silver. However, the organic chemicals f i n d the highest use as microbiocides. Some examples of these organic c o m p o u n d s are peracetic acid, p a r a f o r m a l d e hyde, p o l y c h l o r o p h e n o l s a n d q u a t e r n a r y a m m o n i u m derivatives, to n a m e a few [208]. Microbiocides may be toxic to humans; therefore, care must be taken when used. W h e n selecting the microbiocide, the field e n g i n e e r can obtain p e r t i n e n t i n f o r m a t i o n on chemicals from the service c o m p a n y p r o v i d i n g the chemicals. T h e m i c r o b i o c i d e selected must be c o m p a t i b l e with the system in which it is b e i n g used. Some chemicals such as quaternary amines have dual functions; one as microbiocides a n d the other as film-forming corrosion inhibitors. Insufficient concentrations of this type of chemical may not be enough to coat the whole surface of metal and can cause pitting corrosion. T h e selection must also d e p e n d on chemicals that can p r o d u c e the desired control in m i n i m u m time limits a n d

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Drilling a n d Well Completions

m i n i m u m cost. Commercially available microbiocides generally contain one or more chemical compounds. The amount of chemical present that has the microbiocidal property is expressed as percent active ingredient.

Microbiocidal Treatment. Once the microbial activity reaches a high enough level to cause problems, physical a n d chemical methods may be used to control the problem. In drilling o p e r a t i o n s , the most effective m e t h o d is chemical t r e a t m e n t - t h e use of microbiocides [184,208]. To select a microbiocide one should consider its compatibility with the system. Some chemicals may affect the performance of the drilling fluids a n d lead to other problems. For example, quats, amines, a n d chlorinated phenols may cause clay flocculation of the drilling fluid if present in sufficient quantities. Therefore, the effect of the microbiocide on the drilling fluid properties must be thoroughly tested a n d u n d e r s t o o d before the chemical is used. Once the microbiocide is selected, a m e t h o d of application should be considered. The chemical can be introduced to the system by either batch treatment, continuous treatment or by a c o m b i n a t i o n of both. For batch treatment, NACE provides an equation given below. This equation can be used to d e t e r m i n e the c o n c e n t r a t i o n of chemical at any time d u r i n g the eight h o u r period. The equation is C = 10.7 - 10.7e -2"3'

(4-370)

where C = c o n c e n t r a t i o n of the microbiocide in l b / 3 0 0 bbl t = time in hr C * ( 9 ) = parts per million (ppm) The frequency of the batch treatment, or slug treatment, depends on the actual field response. The continuous m e t h o d of treatment is relatively more expensive a n d can be four times as expensive as the batch treatment. This is one of the most i m p o r t a n t factors in alleviating microbial problems. A decrease in microbial activity after treatment indicates a positive response to the microbiocidal treatment. C o n t i n u o u s m o n i t o r i n g is imperative for effective control.

Oil Muds. Oil-base muds can be used effectively to minimize the corrosionrelated problems in drilling operations. These fluids are composed of a continuous oil phase in which water is emulsified. The performance of oil-base mud is very competitive with that of water-base muds, a n d is superior u n d e r some adverse conditions. However, as pointed out earlier, they are only used in special cases due to their high costs a n d e n v i r o n m e n t a l restrictions. Nevertheless, they are the most effective m e t h o d to avoid corrosion-related problems. For the corrosion process to proceed, the corrosion cell must contain an anode, a cathode, an electrolyte a n d an electronic conductor. W h e n a properly prepared a n d c o n d i t i o n e d m u d is used, it causes preferential oil wetting on the metal. As the metal is completely enveloped a n d wet by an oil e n v i r o n m e n t that is electrically nonconductive, corrosion does not occur. This is because the electric circuit of the corrosion cell is interrupted by the absence of an electrolyte. Excess calcium hydroxide [Ca(OH)2 ] is added as it reacts with hydrogen sulfide a n d carbon dioxide if they are present. The protective layer of oil film on the metal is not readily removed by the oil-wet solids as the fluid circulates through the hole.

C o r r o s i o n and Scaling

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Oil muds are relatively resistant to contaminants generally e n c o u n t e r e d during drilling. Ca(OH)~ + H~S ---) 2H~O + CaS Ca(OH)~ + CO s ---) H~O + CaCO s However, these two reactions result in an increase in the total solid content of the mud, affecting the m u d p e r f o r m a n c e . W h e n using oil-base mud, care must be taken to prevent water b e c o m i n g free. Water is always present in oil-base m u d whether a d d e d intentionally through the surface e q u i p m e n t or from the d r i l l e d formations. API RP 7G r e c o m m e n d s the following factors to be m o n i t o r e d when oil-base muds are in use [181]: * Electrical stability: T h e test measures the voltage required to cause c u r r e n t

flow between two electrodes i m m e r s e d in an oil-base mud. T h e higher the voltage, the greater the stability and, consequently, the greater the drillpipe p r o t e c t i o n (see API RP 13B for m o r e details [206]). • A l k a l i n i t y : Acidic gases may contaminate the oil muds a n d lower the p H to an u n d e s i r a b l e range. • Corrosion test coupons: As m e n t i o n e d before, these coupons p r o v i d e very i m p o r t a n t i n f o r m a t i o n on the c o r r o s i v e n e s s o f the d r i l l i n g f l u i d s (see section on c o r r o s i o n coupons in this text and API RP 13B for m o r e details [206]).

Corrosion Barrier Plastic-Coated Drillpipes. C o r r o s i o n can b e p r e v e n t e d by s e p a r a t i n g the corrosive e n v i r o n m e n t from the metal. Plastic coating provides this s e p a r a t i o n when it is u n d a m a g e d . T h e drill-pipe can only be coated internally. T h e outside surface of the pipe experiences high wear with the hole wall. W h i l e internal coatings r e d u c e i n t e r n a l c o r r o s i o n of the d r i l l p i p e , the c o r r o s i v e a t t a c k is transferred to the outside surface of the drillpipe. Such occurrences suggest that coating alone cannot control corrosion. Therefore, they must be used in conj u n c t i o n with o t h e r control measures that reduce the overall corrosivity of the drilling fluid. O n e of the serious problems is that it is very difficult to obtain holiday-free coating. Holidays (discontinuities) are areas of d a m a g e d coating where the metal is e x p o s e d to corrosive environments. This can either be the result of p o o r b o n d i n g or of mechanical damage. Holidays can completely nullify the beneficial effects of a coating. Therefore, it is essential that the internally coated drillpipes be free of holidays [211]. Plastic coating of d r i l l p i p e has e x t e n d e d its service life greatly. T h e drawback of coatings is that they can be damaged. Coatings can be d a m a g e d locally when tools such as wirelines, hole d e v i a t i o n tools, etc., are r u n down the drill pipe. Overtorque and i m p r o p e r handling may also contribute to coating damage. Quite often, the d a m a g e is in or n e a r the tool j o i n t area where c o r r o s i o n fatigue failures are m o r e c o m m o n . T h e r e are several plastic coatings available commercially, some being m o r e effective than others. However, the selected plastic coating must possess flexibility, resistance against impact, chemical attack, flow of galvanic currents a n d

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p e r m e a t i o n by moisture. The coating must have g o o d adhesion, cohesion a n d h i g h - t e m p e r a t u r e serviceability. Plastic coatings are c o m p o s e d o f t h r e e basic c o m p o n e n t s : pigment, b i n d e r a n d solvent.

Pigments. Pigments i n t r o d u c e s t r e n g t h a n d color to the coating. T h e y are d e s i g n e d to be corrosion a n d abrasion resistant. Pigments reduce water vapor transmission and prolong coating life. They are usually composed o f inert inorganic compounds that interlock among themselves to provide strength to the coating. Often zinc may be a d d e d to the pigment for greater corrosion resistance. Other compounds that may be used in this way are red-lead, zinc-chromate a n d basic lead silicochromate. Binders. Binders are organic resins that are composed o f high-molecular-weight polymers that p r o v i d e specific p r o p e r t i e s to the coatings. Epoxies a n d phenolics are g o o d examples o f these binders.

Solvents. Solvents are only present in the m a n u f a c t u r i n g stage o f the coating process. They are not present in the f i n i s h e d product. As the coating is baked, the solvent evaporates, polymerization occurs a n d the resin adheres to the base surface.

Personnel Training Most often c o r r o s i o n failures can be t r a c e d back to a lack o f u n d e r s t a n d i n g a n d neglect on the p a r t o f personnel. Therefore, the success o f a c o r r o s i o n control p r o g r a m is d e p e n d e n t on the knowledge a n d efficiency o f the personnel involved. After all, they are the p e o p l e who may carry out the c o r r o s i o n control p r o g r a m . T h e r e f o r e , it is essential that they u n d e r s t a n d the i m p o r t a n c e o f their responsibilities a n d c a r r y t h e m out efficiently. Personnel involved in drilling o p e r a t i o n s must have a basic knowledge o f principles o f c o r r o s i o n control. Thus, training p r o g r a m s for drilling personnel must be developed. The p r o g r a m must present current technology in a m a n n e r conducive to learning a n d offering a w e l l - r o u n d e d e d u c a t i o n . T r a i n i n g b e n e f i t s can i n c l u d e m o r e p r o d u c t i v e employees, lesser down time and, perhaps, a b e t t e r c o o p e r a t i o n between personnel. In o t h e r words, m o r e efficient o p e r a t i o n s can result from an effective training p r o g r a m .

Corrosion Control in Arctic and Geothermal Drilling Arctic Drilling. C o r r o s i o n p r o b l e m s e n c o u n t e r e d in arctic area drilling are no d i f f e r e n t f r o m p r o b l e m s faced in o t h e r areas o f the world. It is a g e n e r a l m i s c o n c e p t i o n that d u r i n g arctic drilling corrosion-related p r o b l e m s are either not very severe or totally absent due to low temperatures. Cool t e m p e r a t u r e s may slow down the corrosion process. However, they also increase the solubility o f oxygen, carbon dioxide a n d hydrogen sulfide. Therefore, the net result can be an increase in the rate o f corrosion. While cold t e m p e r a t u r e s may cause problems, the t e m p e r a t u r e f l u c t u a t i o n c o m m o n in arctic e n v i r o n m e n t s can be a m o r e severe source o f corrosion-related p r o b l e m s [215]. The severity o f weather in arctic regions, especially in winter months, presents difficulties. They can be in m o n i t o r i n g c o r r o s i o n , i n s p e c t i o n o f e q u i p m e n t ,

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mobility o f personnel, t r a n s p o r t a t i o n delays o f materials, accurate o p e r a t i o n o f electronic and o t h e r instruments. The storage and use o f chemicals used to c o m b a t corrosion is also a p r o b l e m in these conditions. Chemicals packaged in warm and h u m i d areas o f the world may be difficult to a d d to the circulatory system until t h e c o n d e n s e d a n d frozen m o i s t u r e in t h e bay is thawed. As m e n t i o n e d earlier, t r a n s p o r t a t i o n to and from the drilling site is very slow and d e p e n d s on the weather conditions. "Three-day blows" and "whiteouts" are very c o m m o n and result in t r a n s p o r t a t i o n "blackout." T r a n s p o r t a t i o n "blackouts" are total cessation o f t r a n s p o r t activity. T h e distances between major d i s t r i b u t i o n points and drilling sites are generally very large. Therefore, the deliveries can be f u r t h e r slowed down. S u m m e r months in these areas may not necessarily be any better. In view o f these problems, it is very i m p o r t a n t to consider all aspects o f o p e r a t i o n before embarking on the project. Therefore, before starting a drilling project, corrosion control must also be considered. Steps should be taken to ensure r u n n i n g an effective c o r r o s i o n control p r o g r a m .

Geothermal Drilling. G e o t h e r m a l drilling presents one o f the most challenging environments for corrosion control. During g e o t h e r m a l drilling the b o t t o m h o l e t e m p e r a t u r e s can reach a r o u n d 480°F (250°C). Therefore, drilling fluids and c h e m i c a l additives, such as c o r r o s i o n i n h i b i t o r s , must w i t h s t a n d high temp e r a t u r e s (480°F) and pressures a r o u n d 4,000 psi. High temperatures, coupled with corrosive fluids encountered in the formation, result in increased corrosion rates. Water and oil-based drilling muds can d a m a g e the p r o d u c i n g zones. To minimize this f o r m a t i o n damage, a e r a t e d muds and gaseous drilling fluids are used. However, t h e s e d r i l l i n g f l u i d s i n c r e a s e the p o t e n t i a l for a c c e l e r a t e d corrosion o f drilling equipment. This is because o f high concentrations o f oxygen in fluids and increased fluid velocities over the metal surface. A n o t h e r p r o b l e m that can arise d u r i n g drilling a g e o t h e r m a l well is lost circulation. Lost circulation can occur while drilling through highly f r a c t u r e d formations. This leads to a displacement i n f l u x o f corrosive agents into the wellbore. It also results in loss o f e x p e n s i v e d r i l l i n g f l u i d a n d c h e m i c a l additives, such as c o r r o s i o n inhibitors. W h e n f l u i d losses occur, a e r a t e d or gaseous drilling techniques can be used. With these techniques, hydrostatic head can be adjusted (i.e., lightened) to balance the f o r m a t i o n pressure and, consequently, reduce fluid losses to the formation. A n o t h e r m e t h o d sometimes used is b l i n d drilling or dry drilling. In b l i n d drilling, the drilling f l u i d is slowly p u m p e d down the d r i l l p i p e without it r e t u r n i n g to the surface. In this p r o c e d u r e drill cuttings are expected to be c a r r i e d with drilling fluids into the host circulation zone. However, it is important to pick up the drillstem at regular intervals o f short distances. This will reduce the chance o f drill cuttings stacking up or accumulating in the annular c h a m b e r space above the bit, leading to a stuck drillstem. Quite often these cuttings will plug the lost circulation zone, and the drilling f l u i d circulates back to the surface. This m e t h o d o f drilling is extremely expensive as the drilling rates are r e d u c e d and drilling fluids are lost. T h e technique does not provide any means o f protecting the external surface o f the d r i l l p i p e from corrosive e n v i r o n m e n t . Therefore, if possible a e r a t e d m u d or gaseous drilling should be c o n s i d e r e d over the technique o f b l i n d drilling. N i t r o g e n can be used to aerate the drilling f l u i d to reduce c o r r o s i o n problems. It can also substitute for air in gaseous d r i l l i n g to m i n i m i z e c o r r o s i o n p r o b l e m s if e c o n o m i c a l l y feasible [216].

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Recommended Practices Equipment failure due to corrosion is one problem that inevitably rears its ugly head during drilling operations. Corrosion control is an essential factor in any engineering design and must be considered as early as the initial phase of the operation. An effective and most cost-efficient corrosion control p r o g r a m is imperative for a successful drilling operation. Some recommended practices are as follows [202,203,217-222]:

General Operation 1. Utilize drillpipe corresponding to C-75 tubing or casing specification set in API Specification 5AC [178]; the specification calls for certain chemical requirements. Heat treatment by normalizing and tempering at a minimum 1,150°F (621°C) after cold working. Yield strength from 75,000 psi to a maximum of 90,000 psi. Some grade E can be used: however, all grade D drillpipe can be used. 2. Avoid the use of shrink-type tool joints on drillpipes and drill collars (connectors, in this case). Flash-welded tool joints for drillpipes and integral drill-collar joints should be used. 3. Reduce the stress levels in the pin by utilizing makeup torque on tool joints at the low end of the r e c o m m e n d e d torque range. 4. Use internally, plastic-coated drillpipe at all times. The coating must be holiday-free to be effective. 5. Consider the use of heavy-wall (thick wall) drillpipe in severely corrosive conditions. Heavy walls reduce stress levels and extend the service life of drill pipe. 6. Materials used for tool joints are generally 4137 or 4140 steel. They are heat treated by quenching and tempering at temperatures equal to or above 1,150°F to hardness of Rc 30 to Rc 37 and yield strength ranging from 120,000 psi to 135,000 psi. The above specifications do not meet the requirements corresponding to C-75 specifications. One solution is to use smaller, nonstandard bore and larger outside diameter to achieve heavy-wall effects. 7. Most drill collars are also made with materials used for tool joints. Here again, heavy walls are used to reduce stress levels. 8. Limit exposure time of the drillstem to the corrosive environment during drillstem tests. A maximum of one hour is recommended. 9. Sustained exposure of drillpipe to operating temperatures above 300°F (149°C) must be limited to a maximum of 10 hr. 10. Run enough drill collars to keep all drillpipe in tension in order to reduce wear and stress on tool joints. 11. Minimize opportunities of corrodent contamination of drilling fluids.

Transportation 1. Drillpipes and drill collars should be tied down with suitable chains at the bolsters when being transported. 2. Load with all couplings on the same end of the truck. 3. Use thread protectors on tool joints when moving or racking pipes. 4. Avoid chafing of tooljoint shoulders on adjacent joints.

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5. Keep load b i n d i n g chains tight at all times. 6. Avoid d a m a g i n g coatings as well as the p i p e itself.

Storage 1. To clean, wash down p i p e in d e r r i c k with freshwater. 2. Clean the pin a n d box threads and shoulders thoroughly, and inspect for any damage. 3. Inspect each j o i n t for any damage or crack, and inspect internal coating for holidays. 4. Apply a p p r o p r i a t e film-forming inhibitors to reduce atmospheric corrosion d u r i n g storage and transit. 5. Do not store p i p e directly on ground, rails, steel or concrete floors. A m i n i m u m of 18 in. clearance should be present b e t w e e n the g r o u n d and the first tier of pipe. 6. To help in inspection and handling, do not stack pipes higher than five tiers at the rig.

Handling 1. 2. 3. 4. 5.

Before unloading, make sure that the thread protectors are tightly in place. Avoid rough handling that can damage the p i p e in any way. T h e pipe must not be d r o p p e d at any time. U n l o a d one j o i n t at a time. W h e n rolling down skids, roll p i p e parallel to the stack. Do not let the p i p e g a t h e r any m o m e n t u m and strike the ends. This can damage threads even when the protectors are in place. 6. Avoid creating knicks or notches on the drillpipe.

Chemical Additives 1. W h e n high t e m p e r a t u r e s above 300°F are expected, do not use sulfurcontaining c o m p o u n d s as drilling fluid additives. In general, avoid using chemical additives that can at o p e r a t i n g temperatures. 2. Use only chemical additives that are c o m p a t i b l e with drilling f l u i d s in circulatory systems. 3. Avoid using c o p p e r - b a s e d c o m p o u n d s such as c o p p e r carbonate. C o p p e r can "plate out" on steel a n d set up galvanic c o r r o s i o n cells, resulting in accelerated c o r r o s i o n of the steel. 4. Maintain the p H level of the drilling fluid a r o u n d 9.5 to reduce corrosion. However, when aluminum drillpipes are in use, the p H must be maintained between 9.5 and 7. 5. Avoid using c o n c e n t r a t i o n s h i g h e n o u g h to l e a d to t h e loss o f o t h e r desirable characteristics of the drilling fluid. 6. Unless unavoidable, do not let salt contents exceed 180,000 ppm. 7. Caustics should be dissolved in water before being added. T h e mixture should be mixed well with mud guns in the pit prior to p u m p i n g into the hole.

Chemical Treatment Dosage Chemical treatment of drilling fluids has to be c a r r i e d out with great care. T h e c h e m i c a l s u s e d m u s t be a p p r o p r i a t e a n d in p r o p e r q u a n t i t i e s . If t h e

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chemicals are not compatible with the e n v i r o n m e n t or if their concentrations are not sufficient, they can actually accelerate corrosion. The concentrations, the type and frequency of the treatment will vary with different e n v i r o n m e n t s and desired level of corrosion control. However, it should be noted that excesses of certain chemicals may alter the desirable characteristics of the drilling fluids. Most commercially available inhibitors are mixtures of various chemicals. The c o n c e n t r a t i o n of active ingredients varies. Before use, the manufacturers and suppliers of these chemicals must be consulted. R e c o m m e n d e d procedures, m e t h o d of treatment and dosage should be followed. Some general guidelines are presented in this section for treatment. These r e c o m m e n d a t i o n s are by no means absolute. The treatment must be designed for prevailing conditions.

Oxygen Scavengers. Oxygen scavengers such as sodium sulfite should be added to the m u d system, premixed in water solution with r e c o m m e n d e d catalyst. The solution should be injected into the pump-suction line. It can also be added to the circulatory system through a submerged drip line. The drip line is usually a r u b b e r hose with one e n d connected to the chemical barrel and the other e n d 1 or 2 ft below the mud surface in the suction pit near the p u m p suction. The scavenger solution must not be added to the system t h r o u g h the m u d hopper. In fact, the solution must not be exposed to air longer than necessary. I n i t i a l t r e a t m e n t should r a n g e from a b o u t 300 m g / L of scavenger, a n d injection rates should be as high as the p u m p will allow. Treatment has to be adjusted to achieve from 100 to 300 m g / L sulfite residual at the flowline. Organic Inhibitors. D u r i n g drilling operations organic inhibitors can be used in two ways. They can be sprayed or brushed o n directly to the external surface of the drillstem. Secondly, are "batch" treatment down the drillstem at regular intervals. For direct treatment, a mixture is prepared by mixing film-forming amine and diesel oil in a 1:1 ratio. "Batch" treatment is carried out by p u m p i n g 3 to 4 gal of corrosion i n h i b i t o r down the drillstem. Frequency of "batch" treatment should be every 5 to 10 stands while tripping into the hole.

Hydrogen Sulfide Scavengers. Hydrogen sulfide scavengers are very effective in controlling hydrogen sulfide, H2S, contamination. The most c o m m o n H2S scavengers used in drilling operations are zinc carbonate (ZnCO3) and iron oxide (F%O,). Zinc carbonate and iron oxides can be used either individually or in c o m b i n a t i o n d e p e n d i n g on e n v i r o n m e n t a l conditions. The c o n c e n t r a t i o n will, of course, vary according to the conditions. At least 5 lb of iron oxide per barrel should be added to the system. Large quantities of iron oxide in the system do not affect the drilling fluid properties. However, zinc carbonate in excess of 5 l b / b b l can affect the drilling f l u i d properties, especially when temperatures reach above 250°F (120°C). Therefore, when zinc-based scavengers are used, mud properties must be closely monitored for adverse effects. About 1 l b / b b l (2.85 kg/ m 3) of zinc-based scavengers (10 to 20 wt% active) should be sufficient for 100 to 200 m g / L of sulfide contamination. Scale Inhibitor. About 3 to 5 gal (20 to 30% active) of scale inhibitor per day should be sufficient for scale inhibition. The treatment can be reduced to 1 to 3 gal per day once the scale formation is u n d e r control. The chemical can be introduced to the system by injecting it into the p u m p suction line.

Neutralizers. Sodium hydroxide, calcium hydroxide and a m m o n i u m hydroxide are used to neutralize the acidic c o m p o n e n t s of drilling fluids. Neutralizers are

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a d d e d to the system to maintain the desired p H levels. Normally, p H o f a r o u n d 9.5 is m a i n t a i n e d d u r i n g drilling operations.

Microbiocides. For a general g u i d e l i n e about 100 m g / L o f the m i c r o b i o c i d e with at least 50 wt% active ingredient should be added to the drilling fluid. Exact dosage a n d treatment frequency has to be estimated based on the severity o f the problem. ENVIRONMENTAL CONSIDERATIONS Introduction T h e key role o f the e n g i n e e r is the design o f facilities a n d their operations. In designing a new o p e r a t i o n or u p g r a d i n g an old one, the e n g i n e e r must be aware o f e n v i r o n m e n t a l concerns such as air emissions, water discharges a n d hazardous waste generation. T h e e n g i n e e r needs an in-depth u n d e r s t a n d i n g o f the impact o f the o p e r a t i o n on the environment, a n d how considerations m a d e p r i o r to i m p l e m e n t a t i o n o f t h e p r o j e c t may m i n i m i z e t h e s e i m p a c t s . T h e e n g i n e e r must also be aware o f the regulations involved so that designs are legally feasible and p e r m i t t i n g is a c c o m p l i s h e d in a timely manner. In drilling, p l a n n i n g should include e n v i r o n m e n t a l considerations. Environmental m a n a g e m e n t at the wellsite involves thoughtful p l a n n i n g at the onset o f e x p l o r a t i o n or d e v e l o p m e n t . In today's world o f h e i g h t e n e d e n v i r o n m e n t a l concern, a project may be p o s t p o n e d or t e r m i n a t e d due to these issues. T h e p r e s p u d m e e t i n g in a d d i t i o n to discussion o f well depth, casing points, a n d rig selection, should include topics p e r t i n e n t to the e n v i r o n m e n t a l m a n a g e m e n t o f the drilling a n d c o m p l e t i o n o p e r a t i o n . Regulating agencies are most c o n c e r n e d with these issues. A site will have particulars imminently a p p a r e n t a n d those perhaps not so a p p a r e n t except to groups e x h i b i t i n g a certain interest. It is the role o f t h e r e g u l a t i n g a g e n c y to p r o t e c t t h e p u b l i c a n d p u b l i c d o m a i n from d e t r i m e n t a l effects caused by industrial o p e r a t i o n s . C o m p l i a n c e o f the r e g u l a t o r ' s r e q u i r e m e n t s is usually simple in nature. T h e r e q u i r e m e n t s are d o c u m e n t e d a n d follow a p a r t i c u l a r order. C o n c e r n s d i s s e m i n a t e d by special interest groups are often unexpected. In an attempt to forego stalling o f a project by these parties, public disclosure o f a p r o j e c t should be m a d e as early as possible, even if it is p e n d i n g . A well-informed public disclosure s t a t e m e n t r e l e a s e d to t h e i m m e d i a t e c o m m u n i t y may in many instances p r e c l u d e any future surprises. In p l a n n i n g a drilling o p e r a t i o n , the location a n d access are primarily keyed to e n v i r o n m e n t a l decisions. T h e access a n d location must be able to maintain the traffic load, a n d also mitigate any impact on local resources such as flora, fauna, c u l t u r a l a n d a e s t h e t i c . In c e r t a i n instances, t h e p r e p a r a t i o n o f an e n v i r o n m e n t a l assessment followed by a e n v i r o n m e n t a l impact statement may be considered w a r r a n t e d due to proximate: • • • •

wildlife refuges historic or cultural resources recreation areas l a n d containing t h r e a t e n e d o r e n d a n g e r e d species

In the U n i t e d States d r i l l i n g plans are s u b m i t t e d to t h e Bureau o f L a n d Management or state oil and gas commission in the form o f an APD (application

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for p e r m i t to drill) d e p e n d i n g o n o w n e r s h i p o f m i n e r a l resources. O t h e r countries have similar requirements. In a d d i t i o n to these agencies, o t h e r appropriate surface m a n a g e m e n t agencies may have to be considered. These include, but are not limited to, the BLM, National Park Service, Tribal Authorities, State E n v i r o n m e n t a l P r o g r a m a n d County E n v i r o n m e n t a l P r o g r a m . In accessing the r e s p o n s i b l e a u t h o r i t i e s involved, t h e p e r m i t t e e s h o u l d c o n t a c t t h e p r i m a r y responsible p e r m i t t i n g agency a n d follow their guidelines for contact o f interested parties. In the permitting process, it is important to have the entire o p e r a t i o n planned. In fact it is a necessary c o m p o n e n t o f most APDs. In a federal APD, the 13point surface use plan must address, p r i o r to approval: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.

location o f site a n d existing roads p l a n n e d access roads location o f existing wells location o f existing o r p r o p o s e d p r o d u c t i o n facilities location a n d type o f water supply source o f construction materials m e t h o d s o f h a n d l i n g waste disposal ancillary facilities wellsite layout plans for restoration o f the surface surface ownership other information such as proximity to water, inhabited dwellings, archeological, historic o r cultural sites 13. certification o f liability

Details o f the actual drilling p r o g r a m are not c o n s i d e r e d in detail in an APD except for the casing a n d c e m e n t i n g p r o g r a m a n d how they are d e s i g n e d to protect any u n d e r g r o u n d sources o f d r i n k i n g water (USDW). T h e bulk o f the APD p e r m i t is d e s i g n e d to address the impact on surface resources a n d the mitigating p r o c e d u r e s the o p e r a t o r plans to take to lessen these impacts [223]. Site Assessment and Construction Access and Pad T h e r o a d to the wellpad should be constructed to prevent erosion a n d be o f d i m e n s i o n s suitable for traffic. A 16-ft t o p - r u n n i n g width with a 35-ft b o t t o m width has shown to sustain typical oilfield traffic. T h e r o a d should be crowned to facilitate d r a i n a g e a n d culverts placed at intersections o f major r u n o f f (see Figure 4-483). Before the p a d a n d access is surveyed for final layout, preliminary routes should be studied a n d walked out. Trained p e r s o n n e l should note any significant attributes o f the area such as archeological finds, plants a n d animals. As a result o f this survey, the most favorable access is d e s i g n a t e d weighing economics with the e n v i r o n m e n t a l regulations. T h e p a d size a n d a r r a n g e m e n t are functions o f the d r i l l i n g o p e r a t i o n itself a n d primarily linked to: • drilling fluid program • periodic operations • completions

Environmental Considerations

1345

Figure 4-483. Typical oilfield access dimensions.

T h e rig selection will dictate the basic layout of the pad. Based o n the necessary area n e e d e d to s u p p o r t its functions, ancillary e q u i p m e n t may be added in space conservative measures. In addition to the placement of various stationary rig site components, other operations such as logging, trucking and subsequent c o m p l e t i o n o p e r a t i o n s must be provided for. The most environmentally sensitive design will impact the least a m o u n t of area, and in that it will be the most economic. Potential pad sites and access routes should be laid out on a topographic map prior to the actual survey. At this time, construction costs can be estimated and compared. Figure 4-484 shows such a layout. The cost of building a location includes the cost of reclamation such as any remediation,

SS

Figure 4-484. Topographic layout of proposed access and pad.

1346

Drilling a n d Well C o m p l e t i o n s

r e c o n t o u r i n g and reseeding o f native plants. In the event o f a p r o d u c i n g well, only that area n e e d e d to s u p p o r t the p r o d u c t i o n o p e r a t i o n s is left in place. The reserve pit a n d all outlying areas are reclaimed.

Rig Considerations A rig layout d i a g r a m , p r o v i d e d from the contractor, will give the dimensions necessary to begin planning the drillsite. Figure 4-485 depicts a layout for a ]0,000-ft mobile drilling rig. The main c o m p o n e n t s to the rig are drive-in unit, substructure, m u d pits, pumps, lightplant, catwalk, piperacks, lightplant and fuel supply. This type o f rig, with a telescoping derrick, may be laid on less than 0.37 acre. The o u t s t a n d i n g area is taken by the p o s i t i o n i n g o f the deadmen. The deadmen, to which the guywires are connected, are specified through safety c o n s i d e r a t i o n s for each rig model. Smaller mobile drilling units with less than 2,000-ft-depth capacity may be guyless and as such n e e d less o f an area on which to operate. A s t a n d a r d drilling rig with a ]0,000-ft capacity will have a longer laydown side, as it is m e a s u r e d from the well center. Here, d u r i n g rig up, the derrick is assembled on the g r o u n d and then lifted onto the A legs. The laydown side o f the site must allow for this o p e r a t i o n . As depicted in Figure 4-486, the s t a n d a r d rig exceeds the overall areal dimensions o f the mobile rig at 0.41 acre with a laydown d i m e n s i o n o f 130 ft as c o m p a r e d to 90 ft for the telescoping mast unit. A s t a n d a r d drilling rig with a 20,000-ft capacity may run a laydown o f 185 ft, with all o t h e r dimensions p r o p o r t i o n a t e l y increased. With the basic rig layout defined, the ancillary equipment may be d e t e r m i n e d and laid out adjacent to the structures in place. Usually the access is d e t e r m i n e d where casing, m u d a n d o t h e r e q u i p m e n t may be delivered without disturbance o f the infrastructure. In the case where a c r a n e (or forklift) is used, this may

! pumps

0

I

mud pit

unit

substructu~

catwalk

]

90 ft water tank

doghouse

t-.

a.

pipe racks

t-

r

D--

deadman

.__=

180 ft Figure 4-485. Basic mobile l O,O00-ft drilling rig layout.

~C

E n v i r o n m e n t a l Considerations

1347

pit side mud pit derrick

~

pump

rear 90 ft

S

ructure

laydown

t

water tank d°gh°u'¢

=

working side

pipe racks

2 0 0 ft

w

Figure 4-486. Basic layout for drilling rig with standard derrick. m e a n a simple loop from the rear to the laydown on the working side of the location. A loop is the optimum arrangement whereby multiple-truck interference may be avoided. In the event a crane is not available, extra space is n e e d e d to accommodate the activity of gin trucks positioning the materials. Figure 4-487 shows an overall location view.

Drilling Fluid Considerations The drilling fluid p r o g r a m will define to some extent a major p o r t i o n of the pad i n c l u d i n g reserve pit, blow pit and e q u i p m e n t space. The p r o g r a m may include a closed system or a conventional one. The fluids can be oil-base mud, air, foam, water or other media. While the basic rig layout considers most m u d drilling activities, it does not figure in m u d storage, additional water storage, or air drilling systems. The overall layout may even be reduced in some cases. A closed m u d system or air d r i l l i n g e l i m i n a t e s the r e q u i r e m e n t for a large reserve pit.

Air Drilling. In the event of air drilling, the blooie line will exit from u n d e r the substructure and away from the rig. Depending on the nature of the payzone, the blooie line will extend different lengths from the rig. For example, a well, p r o d u c i n g 20 MMcfd in addition to the injection of 2,000 cfm air, will require an extension of at least 150 ft, due to heat a n d dust accumulation. The blow pit with b e r m will often extend a n o t h e r 40 ft b e y o n d that to include both the

1348

Drilling and Well Completions

reserve pit il pile porta~ ~[1

~

~

~

tructun_.j

__

I water,=nltIdoghoJse pipe racks

/

~

i

O01pusher [ I CO. man ~

'

~

Figure 4-487. Overall location plan. blow pit and berm. The blow pit is then connected to a reserve pit. This allows the transfer of any injected or produced fluid to a storage area away from the blow pit. The blow pit and berm should be designed with considerable contingency. During operations, the well may be producing oil a n d / o r natural gas. In the case of oil, the well will have to be mudded up, once the well is under control. In the process of getting the well under control the oil may be sprayed a great distance if the blow pit and berm are not properly constructed. If natural gas is encountered, drilling is usually advanced with a flare in place. The pit and berm then must be able to protect the surrounding area from fire plus sustain the impact from a steady bombardment of drilling particles. 30 ft should be allowed from the end of the blooie line to the edge of the berm, with only 5 ft of depth needed at the pit sloping towards the reserve pit built to maintain a flowing velocity of 2 fps. The berm itself should be 20 ft high and composed primarily of 1 ft and larger diameter stones on the face and backed with a soil having poor permeability (see Figure 4-488). A lip should overhang from the top of the berm whereby the ejected materials are diverted back to the pit. The air compressors and boosters are typically located at the rear of the location, with the air piped from that point to the standpipe. This equipment should reside as close as possible to the standpipe to alleviate additional piping. Figure 4-489 shows an air drilling layout. Note that the location may be compacted somewhat due to the reduced reserve pit.

Mud Drilling. The conventional drillsite includes mud pits, mud cleaning equipment, water storage, mud storage, pumps and mixing facilities. Often the reserve pit associated with the conventional mud system is as large as the leveled

Environmental

Considerations

I

bkx~ie !!he

I

air

_ _

flow

Figure 4-488.

1349

l

!f~'~

S i d e v i e w of b l o w pit.

blooie~e

blowpit \

~' ~" 1 b~ rese~e~ "t

~

rrf

tra~in~ ~ ~r ,doghi~se : -4~'=-''k portepottias~'I~t -~ p'p.e ~IooIpusher I Ico.m a n access

Figure 4-489. Air drilling pad.

l o c a t i o n . A l a r g e r e s e r v e pit allows f o r c o n t i n g e n c y , b u t also i n c r e a s e s c o s t o f r e c l a m a t i o n a n d c o n s t r u c t i o n . G e n e r a l l y a 3-ft f r e e b o a r d is m a i n t a i n e d for safety a n d m a y also b e r e l i e d o n f o r c o n t i n g e n c y . A g o o d f i e l d e s t i m a t e for a r e s e r v e p i t size n e e d e d f o r a c o n v e n t i o n a l o p e r a t i o n is V r = 2(V s + V i + Vp) + 2 8 1 D d + 1 6 . 8 4 M V + 3 W L

(4-371)

1350

Drilling a n d Well C o m p l e t i o n s

WL = V--'-z-~ H

(4-372)

where V = volume o f reserve pit in ft s V r = volume o f surface hole (ft 3) = volume o f i n t e r m e d i a t e hole fit s) V p = volume o f p r o d u c t i o n hole (ft 3) D d = forcasted drilling time in days MV = m u d pit volume in bbl L = pit length: 0.5-0.75 length o f location in ft W = pit width: 0.25-0.50 length o f pit in ft H = pit depth: < 10 ft Equation 4-371 assumes that for each o p e r a t i o n a volume o f cuttings is put into the reserve pit plus a m u d volume equivalent to the circulation system. T h e additional volumes are a t t r i b u t e d to m u d d i l u t i o n a n d maintenance. A n additional contingency is a d d e d t h r o u g h 3 ft o f freeboard. T h e reserve pit should b e l o c a t e d in an area where capacity may be i n c r e a s e d in an e m e r g e n c y or a d d i t i o n a l f l u i d trucked away.

Closed Mud System. T h e closed m u d system presents today's solution to an environmentally sensitive drilling o p e r a t i o n . T h e circulation system on the rig is fully self-supporting, requiring only the discharge o f drill cuttings. O n a simple system this may only necessitate the a d d i t i o n o f a m u d cleaner or centrifuge to the d r i l l i n g r i g ' s c o n v e n t i o n a l m u d system. A b i d p a c k a g e to the d r i l l i n g contractor may stipulate a closed system a n d the requirements, thus letting the b u r d e n o f design fall to the contractor, although the liability still rests on the operator. With a closed system, a d d i t i o n a l area is sometimes n e e d e d within the basic layout for m u d cleaning e q u i p m e n t a n d m u d storage. A trench located at the pit side o f the m u d pits may b e allowed t h e n for cutting disposal. In the event o f oil-base mud, the cuttings may be collected in a sloped container, where residual f l u i d is allowed to d r a i n from the cuttings before disposal.

Periodic Operations Periodic o p e r a t i o n s include cementing, r u n n i n g casing a n d logging. Room must be allocated for the storage o f casing. Running 10,000 ft o f range 3, 5 ½-in casing requires a 40 × 115 ft area. T h e casing may be stacked, but never in excess o f t h r e e layers a n d p r e f e r a b l y only two. C e m e n t i n g o p e r a t i o n s may include p l a c e m e n t o f bulk tanks in a d d i t i o n to p u m p trucks a n d bulk trailers. These are usually located near the water source a n d rig floor. Laying down d r i l l p i p e a n d logging b o t h necessitate approximately 30 ft o f space in front o f the catwalk.

Completions If a well proves productive, the ensuing c o m p l e t i o n o p e r a t i o n may require an area in excess o f the drilling area. This may mean allocations for frac tank placement, blenders, p u m p trucks, bulk trucks a n d n i t r o g e n trucks. In today's e c o n o m i c climate, the o p e r a t o r should weigh the probability o f success, Bayes t h e o r e m (Equation 4-373), with the cost o f c o n s t r u c t i n g a n d r e c l a i m i n g an a d d i t i o n a l area n e e d e d for stimulation (Equation 4-374). Plans such as these

E n v i r o n m e n t a l Considerations

1351

s h o u l d be c o n s i d e r e d a n d p r o p o s e d in the APD. The o p e r a t o r may t h e n construct the additional space without a p e r m i t t i n g delay. Thus, Ps = P R ( E / R ) =

PR(E)PR(R/E) PR(E)PR(R/E) + PR(not E)PR(R/not E)

PsCb < Ca where P PR(E/R) Cb C

= = = =

(4-373) (4-374)

probability of success probability of event E given i n f o r m a t i o n R construction cost of additional space before drilling in $ construction cost of additional space after drilling in $

Pad Construction Once access and size of pad have b e e n determined, they may be physically flagged to further reduce the a m o u n t of dirt moved. I m p o r t a n t features of the area should be noted at this time, including: • • • • •

depth of water table n a t u r a l drainage patterns vegetation types and a b u n d a n c e surface water proximate structures

These features are quantified, as well as testing for c o n t a m i n a t i o n in both soil and water to prevent unnecessary litigation over previous pollution. In construction of the pad, b r u s h and trees are pushed to one area. Top soil is then removed from the site and stockpiled for respreading during subsequent seeding operations. The leveled pad is slightly crowned to move fluids collected on the pad to the perimeter where drainage ditches divert this fluid to the reserve pit. In the event a subsurface pit is not possible, the drainage will r u n to a small sump. This sump is used as a holding tank for p u m p i n g of collected fluids to an elevated reserve pit. W h e n possible, the reserve pit is placed on the low side of the location to reduce dirt removal. In this event, the pit wall should be keyed into the earth and the s u m m a t i o n of forces and m o m e n t s on the retaining wall calculated to prevent failure. Pits most often fail due to leaking liners u n d e r c u t t i n g the retaining wall and sliding out. A m i n i m u m horizontal-to-vertical slope of 2 is r e c o m m e n d e d for e a r t h e n dams [224]. The pit bottom should be soft filled to prevent liner tears. O t h e r key factors of the loc'ation provided for the drainage of all precipitation away from the location. This prevents the operator from unduly m a n a g i n g it as a waste product. Any water l a n d i n g on the location must be diverted to the reserve pit. A new scheme for location m a n a g e m e n t has developed whereby wastes are diverted to separate holding facilities according to the hazard imposed by the waste. Separate pits are created to hold rig washing and precipitation wastes, solid wastes and drilling fluids [225]. The waste is then reused, disposed on site, or hauled away for offsite treatment. The system reduces c o n t a m i n a t i o n of less hazardous materials with the more hazardous materials, thereby reducing disposal costs.

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E n v i r o n m e n t a l Considerations

1353

Table 4-174 Cation Exchange Capacity of Various Materials Encountered in Drilling [225]. Material

meq/lO0 gmmoisture free

Wyoming Bentonite Soft Shale Kaolinite Drilled Cuttings

75 45 10 8

i~ k - ( N a X ) C ( M ) (MX)(Na) c

(4-375)

where NaX = sodium on the shale in meq M = multivalent cation in meq c = charge of multivalent cation MB MBC = M,h~e m

CEC,h~e

(4-376)

where MBC = methylene blue capacity in m e q / 1 0 0 g MB = methylene blue in meq M ha~e = weight of shale in 100 g There are a variety of chemicals that are toxic and used in the drilling fluid makeup. Chromates and asbestos were once commonly used and are now off the market. A mud inventory should be kept for all drilling additives. Included in the inventory are the material safety data sheets (MSDS) that describe each material's p e r t i n e n t characteristics. The chemicals found on the MSDS sheet should be compared with the priority pollutants and any material should be eliminated if a match is found. The chemicals should also be checked on arrival for breakage and returned to the vendor if defective packaging is found. All mud additives should be housed in a dry area and properly cared for to prevent waste. Chemicals should always be mixed in packaged proportions. Wasted chemicals, ejected to the reserve pit by untrained personnel, can present future liabilities to the operator.

Rig Practice. All drilling fluids should be contained in the m u d pits or reserve pit. The cellar should have a c o n d u i t linking it to the reserve pit such that accumulation of m u d from connections does not spread over the location. In the case of toxic mud, a bell should be located beneath the rotary table to direct such fluids back into the drilling nipple or into the m u d pit in the case of a rotating head. The use of a m u d bucket is also r e c o m m e n d e d in situations where the pipe can not be shook dry. Many operators are now requiring that absorbent or catch pans be placed beneath the drilling rig. Oil and grease leaks/spillage are c o m m o n to the drilling rig operation. Even if the drilling rig is new, leaks and spills are inevitable. Fuel and oil racks should provide a spill-resistant pour device for direct placement of the l u b r i c a n t / f u e l into equipment. Oil changed on location must be caught in barrels and recycled by the contractor. Pipe dope should be environ-mentally sound a n d not a metal type. T h r e a d cleaning on casing is now frequently done with machines that catch the solvent for reuse on subsequent operations.

1354

Drilling and Well Completions

Drilling contractors should be advised prior to the operations on what is trying to be accomplished environmentally on location. Contractors know that the standard practices of throwing dope buckets and everything else into the reserve pit is no longer acceptable, but an occasional drilling crew may not take the directives serious. Because of this, drilling contracts should line item the liabilities associated with imprudent practices.

Completions Inherent to the completion operation are the stimulation fluids used to carry sand or otherwise enhance producing qualities of the well. These stimulation fluids may or may not be toxic in nature. The stimulation fluids, while sometimes batch mixed at the service company's facility, may also be mixed on location. The latter system is preferable unless the service company is willing to let from the operator any liability c o m m o n to the fluid in the case of excess. Currently many frac jobs are minifraced before the actual operation and the design criteria established before the actual frac j o b is accomplished. The method helps prevent the screening out of the well beforehand. A screened-out well causes potential problems not only in productivity but also in waste management. The unused mixed chemicals, such as KC1 makeup water in frac tanks leftover due to the screenout, must be properly disposed. An alternative to this is the mixing of chemicals on the fly instead of preblending and stocking in frac tanks. Some chemicals, such as KC1 in water, must be mixed well in advance on location to attain heightened concentrations. In these instances, a properly designed frac job, based on the minifrac, will allow for some certainty in getting the designed j o b away. Frac flow back may be introduced to the reserve pit after separation from any hydrocarbons. Current frac fluids are composed primarily of natural organics such as guar gum but may contain other components that may be harmful to the environment. Containment of flowback in a lined reserve pit prior to disposal is a prudent practice. Acid jobs may also be designed according to prior investigation although most service companies will accept unused acid back into their facilities. Spent acid flow back may be introduced to the lined reserve pit with little consequence. Often the residual contains salts such as CaC12 previously introduced to the pit. Live acid is occasionally flowed backed to surface. This acid may be flowed to the lined pit given acceptance of the liner material for low pH. The buffer capacity of most drilling fluids is significant, thus it is able to assimilate the excess hydrogen ions introduced to the system. The buffer capacity of the fluid may be calculated from Equations 4-377 and 4-378 [229]. From a water analysis, pH and alkalinity are determined and the remaining parameters may then be calculated. dC 13 = dpH

(4-377)

] _ [ O H _ ] + [ H + ] ) ( [ H + ] +(K~K~)[ H+] + 4 K ~ ) = 2 . 3 I 0tI([ALK

K:(1+ E-ffS; 2K'2)

+ [ H + ] + [ O H -]

(4-378)

Environmental Considerations [ALK] = [HCO;]+2[CO;~]+[OH-]-[H

+]

1355 (4-379)

[Ct] = [ H 2 C O ; ] + [ H C O ~ ] + 2[CO~ ~]

(4-380)

K~ = 7 [ H C O ; ] ( H + ) [H2CO;]

(4-381)

K2' =

]t4[C0~2](H+)

(4-382)

7[ HCO~ ]

1 + ( H ~ ) + (H+------~)

K;

AzE l where [3 = C = [ALK] = K = 7 = I = Z = A = D = T =

()= []=

(4-383)

(4-384)

buffer capacity, ( e q u i v a l e n t s / u n i t p H change) equivalents of buffer available--assumed equal to [ALK] equivalents of alkalinity equilibrium coefficients the monovalent activity coefficient the ionic strength the charge of the species of interest 1.82 x 106 (DT) -1"5 the dielectric constant for water, 78.3 at 25°C oK activity of the ion c o n c e n t r a t i o n of the ion

T h e buffer capacity of the pit f l u i d is equal to the change in alkalinity of the system p e r unit change of pH. Figure 4-491 shows the b u f f e r intensity (capacity) of a 0.1 M carbonate pit fluid. Calculating the initial buffer capacity of the pit f l u i d allows for p r e d i c t i o n of the p H change u p o n i n t r o d u c t i o n of live acid and also any a d d i t i o n of buffer, such as s o d i u m bicarbonate, r e q u i r e d to neutralize the excess hydrogen ions. Care should be taken in every stimulation circumstance to allow fluids to drain to the reserve pit. In the c o m p l e t i o n o p e r a t i o n it is exceedingly difficult to accomplish this due to traffic. Because of this, the service c o m p a n y should p r o v i d e leak free hoses, lines, and connections. U p o n c o m p l e t i o n of j o b , the hoses should be d r a i n e d to a c o m m o n area for h o l d i n g subsequent to introduction to the reserve pit. Every precaution should be taken to prevent accumulation of fluids on the p a d proper, thereby posing a potential risk to groundwater a n d r u n o f f of location. As with the d r i l l i n g o p e r a t i o n , the e q u i p m e n t on l o c a t i o n p r o v i d i n g the completion service may leak oil. T h e use of absorbents and catch pans is advised.

1356

Drilling and Well Completions

0.1000

0.0750 "Ii

i 0.0~!

0.0250

0.00t~ 2

3

4

$

6

7

pH

Figure 4-491, Nonideal buffer characteristics of a 0.10 M carbonate reserve pit fluid [228]. In the case of produced liquid hydrocarbons and other chemicals spilled during operations, subsequent remediation may be necessary. This section as well as Chapter 6, Environmental Considerations, details some remediation techniques currently employed.

Reclamatlon of the Drillsite In the event of a dryhole, the reserve pit water usage should be maximized to prepare the mud spacers between plugs. Water in excess of this may be p u m p e d into the hole, including solids. All USDW's must be protected in this event. Once the hole has been properly plugged and the drilling rig removed, the mousehole and rathole should be backed filled immediately to preclude any accidents. Trash is removed from the location and adjacent areas and is hauled to permitted facilities.

Reserve Pit Closure The reserve pit commonly holds all fluids introduced to the wellbore during drilling and completion operations. This includes both the drilling and completion fluids in the event the well is stimulated for production and those cuttings produced during the drilling operation. The reserve pit, u p o n completion of the initial rig site activities must be reclaimed. Upon removal of the drilling rig, the reserve pit is fenced to prevent wildlife and livestock from watering. The fence is then removed u p o n initiation of reclaimation.

E n v i r o n m e n t a l Considerations

1357

T h e fluids from the reserve pit may be hauled away from location for disposal, reclaimed insitu, or p u m p e d into the wellbore given a dryhole. T h e o p e r a t o r of the wellsite is responsible for the t r a n s p o r t a t i o n offsite of the drilling fluids. T h e fluids may be considered hazardous in nature due to the toxic characteristics of most drilling and c o m p l e t i o n fluids.

Evaporation. E v a p o r a t i o n of the water held in the pit is often the first step in reserve pit r e m e d i a t i o n , due to economic considerations over trucking and disposal. T h e e v a p o r a t i o n may be mechanically driven or take place naturally. N a t u r a l e v a p o r a t i o n is very effective in the s e m i a r i d r e g i o n s . T h e Meyer Equation 4-385 as derived from Dalton's law may be used to estimate the local n a t u r a l e v a p o r a t i o n [224]. These are, E = C(e w - e ) V

(4-385)

~t = 1 + 0.1w

(4-386)

where E = e v a p o r a t i o n rate ( i n / 3 0 days) C = empirical coefficient, equal to 15 for small shallow pools a n d 11 for large deep reservoirs e w = saturation vapor pressure c o r r e s p o n d i n g to the monthly mean temp e r a t u r e of air for small bodies a n d the monthly mean t e m p e r a t u r e of water for reservoirs (inHg) e = actual vapor pressure corresponding to the monthly mean temperature of air and relative humidity 30 ft above the body of water (inHg) V = wind factor w = monthly mean wind velocity m e a s u r e d at 30 ft above body of water (mi/hr) Some mechanically driven systems include heated vessels or spraying of the water to enhance the n a t u r a l e v a p o r a t i o n rate. In heating, the energy n e e d e d to evaporate the water is equal to that n e e d e d to bring the water to the temp e r a t u r e of vaporization plus that energy required for the evaporation, where for constant volume this is AE = C p d T + AHwp

(4-387)

T h e heat capacity and AHva of pure water at 14.7 psia are commonly taken as 1 b t u / I b m (°F) and 970 b t ~ / I b m [230]. Ionic content in the pit fluid raises the energy necessary to evaporate the fluid. Figure 4-492 shows this relationship for b r i n e water containing p r e d o m i n a t e l y NaC1. In field evaporative units utilizing natural gas as the fuel source, the p r i m a r y driving force is the heat supplied to the water. T h e theoretical evaporation rate for these units may be expressed as HcQg AEpw = Qe~P where H = Q~= 9w -Q~wp =

natural gas heating value ( b t u / m c f ) natural gas flow rate to b u r n e r (mcfpd) density of water (ppg) e v a p o r a t i o n rate (gpd)

(4-388)

1358

Drilling a n d Well Completions

100

E 90

8. ~> W

80

"6 60 5o 40

,

0

Figure

I

I

I

,

I

,

I

:

',

:

',

20 40 60 80 100 120 Total Dissolved Solids (ppm x 1000)

"

140

4-492. Maximum limit of evaporation as defined by TDS (NaCI) [228].

Mechanical efficiency may range from 25-75% of the theoretical evaporation rate. Efficiencies may be raised with the application of multieffect or vapor compression evaporators. The more complicated efficient systems can seldom be warranted due to the short service offered. Spray systems rely on forming minuscule droplets of water a n d allowing the vaporization thereof while in suspension over the reserve pit. Allowance for wind carriage of the droplets beyond the pit must be made to prevent salting damage to the s u r r o u n d i n g area. T h e shear force e x t e n d e d u p o n each d r o p l e t in c o m b i n a t i o n with the relative h u m i d i t y p r o v i d e the d r i v i n g force for the operation. Neglecting the shear component, driving force is actual and saturation vapor pressure differential. A derivation of Fick's law may be used to express the molar flux of water in air. Na =

DA dgp 1000RT dx

where Na D A Vp R x

= = = -= --

(4-389)

mols of water diffused to the air (mol/sec) diffusivity of water in air (0.256 cm2/sec-25°C, 1 atm) the area p e r p e n d i c u l a r to the flux (cm 2) vapor pressure of water in air (atm) gas law constant (0.0821 a t m L / m o l ° K ) the thickness of the film where dV exists (cm) P

Environmental C o n s i d e r a t i o n s

1359

Inspection of Equation 4-389 shows that increasing the area of the active water surface will allow for greater evaporation rates. In the case of the spray systems, the e v a p o r a t i o n from n bubbles is Na = 0. 01256 nD d g p RT dx

(4-390)

Because of the difficulties in d e t e r m i n i n g x, the thickness of the film between the two vapor pressures, an overall transfer coefficient is introduced. Based on the two film theory, the overall transfer coefficient is used. In the case of water e v a p o r a t i o n , t h e gas f i l m is t h e c o n t r o l l i n g m e c h a n i s m a n d t h e r e s u l t i n g equation is Na = Kga (Vpsat _ Vp~ct) RT

(4-391)

where Kga = the overall mass transfer coefficient (t-'). Service companies offering e v a p o r a t i o n services can supply the o p e r a t o r with values of Kga b a s e d on their e x p e r i e n c e in the area. The values of Kga may be used comparitively between all the systems for economic analysis. Example: Using the Meyer Equation 4-385, the e v a p o r a t i o n rate from a 5000 ft ~ pit is estimated. T h e average t e m p e r a t u r e in an area in the winter is 40°F, the c o r r e s p o n d i n g saturated vapor pressure is 0.26 i n H g with the actual average 'vapor pressure residing at 0.19 inHg. W i n d velocity reaches a peak at 40 m p h with a time weighted m e a n velocity of 5 mph, such that the e v a p o r a t i o n rate may be estimated as E = 15(0.26 - 0.19)(1 + .1(5)) = 1.58 i n / m o or 111 b b l / m o (0.00083 molsec -I) Given this e v a p o r a t i o n rate, the overall mass transfer coefficient may t h e n be calculated from Equation 4-391, Kga =

NaRT = 7.94 sec-' (Vp~ - V pac~)

Fixation of Reserve Pit Water and Solids. A n o t h e r m e t h o d of reclaiming the reserve pit involves c o m b i n i n g water absorbing materials to the water and mud. Usually, t h e pit c o n t e n t s are p u m p e d t h r o u g h tanks w h e r e t h e s o r b a n t is c o m b i n e d with the pit fluid a n d solids. T h e mixture is d r i e d and subsequently buried. Care must be taken with this m e t h o d whereby any harmful contaminant is immobilized to prevent contamination to the surroundings. Studies have shown that for muds, once the majority of the water has b e e n e v a p o r a t e d or p u l l e d from the pit, the r e m a i n d e r may be solidified in o r d e r to comply with existing regulations. This may be d o n e with cement, flyash, pozzalin, or any n u m b e r of absorbents. Polymers have b e e n d e v e l o p e d to h a n d l e high pH, salt, a n d oil contents, where t h e p r e v i o u s m i x t u r e s have fell short. T h e m i x t u r e is t h e n allowed to dry and the bulk mass is then buried. This m e t h o d requires forethought on pit construction whereby c o m p l e t e mixing of the slurry is accomplished. If p r i m a r i l y b e n t o n i t e a n d water are used, e v i d e n c e has shown m i n o r o r no m i g r a t i o n from the pit [235]. This is

1360

Drilling and Well Completions (4-392)

W = ~ M ...... Rwi .... where W = water available in pit (bbls) M = Mass of absorbent (lbm) RW= water required by absorbent ( b b l / l b m )

Even though materials such as bentonite will absorb tremendous amounts of water, they will not solidify to an extent that the pit may be reclaimed. In most instances, a dozer must be able to walk out to the center of the pit u n d e r a load of pushed dirt. In the event the pit materials are wet, the dozer may become mired and unable to complete the work. Thus it is often better to pick an sorbant that will harden sufficiently for this purpose.

Final Closure U p o n elimination of the fluids, the liner to the pit is folded over the residual solids in a way to prevent fluid migration. The liner is then buried inplace. The operator may choose to remove the liner contents completely to preclude any future contamination. In the case of a producing well, the location is reclaimed up to the deadmen. The adjacent areas are contoured to provide for drainage away from the production facilities. In the case of a dryhole, the entire location is reclaimed to the initial condition. All of the reclaimed area should be ripped to enhance soil conductivity. The top soil is then spread over the reclaimed area followed by seeding. Local seed mixtures are broadcast to quicken reintroduction of native plants.

Environmental Regulations In the U.S., the E n v i r o n m e n t a l Protection Agency sets policy c o n c e r n i n g environmental regulations. The states are then allowed primacy over jurisdiction of e n v i r o n m e n t a l compliance if their regulations are at least as stringent as the federal regulations. Several bodies of government may be involved in environmental decisions c o n c e r n i n g the wellsite (i.e., California). C o m m o n to most oil and gas producing states, the oil and gas division is allowed to administrate all matters c o n c e r n i n g exploration and development matters. It is primarily their responsibility to protect the integrity of the state's land and water supplies from c o n t a m i n a t i o n due to oil a n d gas activity. The state oil and gas division's e n v i r o n m e n t a l regulation usually m i r r o r closely those provided by the EPA. Congress, in an attempt to promote mineral development in the United States, has exempted most hazardous wastes produced at the wellsite u n d e r the Resource Conservation and Recovery Act (RCRA) Subtitle C regulations. Hazardous wastes are listed due to i n h e r e n t characteristics of: • • • •

Toxicity, Ignitability, Corrosiveness, and Reactivity.

While a n u m b e r of wastes produced at the wellsite are considered characteristic hazardous waste, some wastes fall u n d e r the n o n h a z a r d o u s description. The regulation of these fall u n d e r RCRA Subtitle D. Initially Subtitle "D" wastes were regulated to control d u m p i n g of domestic trash and city runoff. The EPA is considering promulgating regulation of certain oil and gas wastes u n d e r Subtitle "D" [231].

E n v i r o n m e n t a l Considerations

1361

Under the RCRA exemption, wastes intrinsically associated with the exploration and development of oil and gas do not have to follow Subtitle C regulations for disposal. U n d e r Subtitle C, hazardous wastes must follow strict guidelines for storage, treatment, and t r a n s p o r t a t i o n and disposal. The cost of h a n d l i n g materials u n d e r the Subtitle C scenario is overwhelming. U n d e r the exemption, the operator is allowed to dispose of wellsite waste in a p r u d e n t m a n n e r and is not obliged to use licensed hazardous waste transporters and licensed Treatment, Storage, and Disposal Facilities (TSDF). Covered by the exemption are drilling fluids, cuttings, completion fluids, and rigwash. Not covered by the exemption are motor and chain oil wastes, thread cleaning solvents, painting waste, trash and u n u s e d completion fluids. A waste product, whether exempt or not, should always be recycled if economically possible. Oil-based drilling mud typically is purchased back by the vendor for reuse. Unused chemicals are similarly taken back for resale. Arrangements should be made with the mud company for similar arrange for partial drums/sacks of chemical. Muds also may be used on more than one hole. With the advent of closed system drilling, the mud must be moved off location in the event of a producing well. If a waste is generated that is a listed or characteristic, the operator must follow certain guidelines [232]. A listed hazardous waste (i.e., mercury, benzene) is considered hazardous if the concentrations in which they naturally occur are above certain limitations (40 CFR 261.31-261.33). The listed hazardous waste may not be diluted to achieve lesser c o n c e n t r a t i o n s a n d thus b e c o m e nonhazardous. A characteristic hazardous waste (40 CFR 261.21-261.24) may be diluted to a nonhazardous status. Most nonexempt nonacute hazardous waste generated on location is considered a small quantity. In this case, the waste may remain on location for 90 days. At that time, a Department of Transportation licensed motor carrier must transfer the waste to a EPA certified TSDF for disposal. Appropriate d o c u m e n t a t i o n and packaging must be conformed to. The operator continues to be liable for the waste as denoted by the cradle to grave concept [233]. Exempt wastes are usually disposed of on location following permission from the state oil and gas division. Liquid wastes, if not evaporated or fixated on location, are usually injected into Class II injection wells--refer to Chapter 6, E n v i r o n m e n t a l Considerations. Solid wastes, if not acceptable to local landfills, are remediated onsite or b u r i e d in some instances. Table 4-175 shows exempt and n o n e x e m p t waste [234].

Table 4-175 Exempt and Nonexempt Oil and Gas Production Related Wastes Exempt Wastes

Nonexempt Wastes

Produced water

Unused well completion/stimulation fluids

Drilling fluids

Radioactive tracer wastes

Drill cuttings

Painting wastes

Rigwash

Service company wastes such as empty drums, drum rinsate, vacuum truck rinsate, sandblast media, spent solvents, spilled chemicals, and waste acids

Well completion/stimulation fluids

Vacuum truck and drum rinsate containing nonexempt wastes

1362

Drilling and Well Completions

BS&W and other tank bottom material from storage facilities that hold product and exempt waste

Refinery wastes

Accumulated materials such as hydrocarbons, solids, sand, and emulsions from production separators, fluid treating vessels, and production impoundments

Liquid and solid wastes resulting from operations by tank bottom reclaimers

Pit sludges and contaminated bottoms from storage or disposal of exempt waste

Used lubrication oils

Workover wastes

Waste compressor oil, filters, and blowdown

Gas plant dehydration and sweetening waste

Used hydraulic oil

Cooling tower blowdown

Waste solvents

Spent filters, filter media, and backwash involved in the treatment of the product or an exempt waste

Waste in transportation pipeline related pits

Packer fluids

Caustic or acid cleaners

Produced sand

Boiler cleaning wastes

Pipe scale, hydrocarbon solids, hydrates, and other deposits removed from piping and equipment prior to transportation

Boiler refractory bricks

Hydrocarbon bearing soil

Boiler scrubbing fluids, sludges and ash

Pigging wastes

Incinerator ash

Wastes from subsurface gas storage and retrieval

Laboratory wastes

Liquid hydrocarbons removed from the production stream but not from oil refining

Pesticide wastes

Gases from the production stream, such as H2S, CO 2, and volitized hydrocarbons

Gas plant cleaning wastes

Materials ejected from a producing well during blowdown

Drums, insulation, and miscellaneous solids

Waste crude from primary operations and production Light organics volatilized from exempt wastes in reserve pits, impoundments, or production equipment Constituents removed from produced water before it is injected or otherwise disposed of

Offshore Operations

1363

Generally, waste that m u s t be produced to complete the work involved in the exploration and production of oil and gas is considered exempt, allowing the operation the option of disposing of such waste in a prudent matter. A nonexempt waste should be avoided at all costs if possible (i.e., radioactive tracer wastes). These wastes must be disposed of according to federal and state regulations. Because these regulations are becoming more complicated with time, the operator should consult the primary regulator in the event of questionable circumstances.

OFFSHORE OPERATIONS The basic principles of rotary drilling defined for onshore operations are also applicable to offshore operations. The primary difference offshore is that a stable, self-contained platform must be provided for the drilling equipment. Communication with a well through possibly thousands of feet of water provides for mechanical as well as procedural differences, primarily in well control. Onshore technology can be applied to offshore operations in many instances on bottom-supported rigs, but the use of floating vessels has resulted in the development of new technology tailored to the offshore environment.

Drilling Vessels Offshore drilling vessels are classified as either bottom-supported or floatingtype vessels. Water depth is generally the governing factor as to which type of vessel is employed. Bottom-supported vessels consist of drilling platforms, jackup rigs, and drilling barges. A drilling platform is not employed until reserves warranting field development is indicated. Platforms are currently being set in water depths up to 1,000 ft, and also serve as permanent production facilities. A jackup rig (Figure 4-493) is used for drilling in water depths up to about 350 ft. The drilling platform on a jackup can be raised or lowered on the legs of the vessel to allow for use in various water depths. These rigs can also be used alongside production platforms for developmental drilling. Jackup rigs thus provide a mobile, bottom-supported drilling vessel suitable for use in relatively shallow water. Drilling barges, commonly employed in inland waters and marshes, can be used where water depths do not exceed about 25 ft. These self-contained vessels provide the least expensive drilling vessel, but have limited applicability because of water depth limitations. Drillships and semisubmersible rigs are the two types of floating drilling vessels. A drillship (Figure 4-494) provides a drilling platform in waters up to 10,000 ft deep. The rig is kept on location by complex mooring and dynamic positioning systems requiring computer control. A semisubmersible rig (Figure 4-495) can be used in water up to 6,000 ft deep, and provides a drilling platform generally more stable than does a drillship. As on a drillship, a semisubmersible rig is stabilized by a complex mooring and positioning system. Since a major portion of the vessel is submerged, wave action can be minimized. Mooring systems are specifically designed to resist surface forces, and ballast can be preferentially shifted within the vessel to provide stability during rough weather. W h e n choosing an offshore drillsite, the p r i m a r y considerations are the location of shipping lanes, foundation stability (for bottom-supported vessels), and the possible presence of shallow gas. Seismic surveys generally provide

1364

Drilling and Well C o m p l e t i o n s

Figure 4-493. Jack-up drilling rig.

suitable i n f o r m a t i o n on f o u n d a t i o n stability, and can indicate the presence of potentially dangerous shallow gas deposits.

Marine Riser Systems T h e most fundamental difference found between onshore and offshore drilling occurs when the wellhead is located at the seafloor. This c o n f i g u r a t i o n makes c o m m u n i c a t i o n with the well m o r e complex. A m a r i n e riser p r o v i d e s communication and circulation capability between the surface and the seafloor, and is used at some point during most offshore drilling. T h e riser consists of largediameter (17-20) in.) steel pipe joints of approximately 50-ft lengths, with quickconnect couplings. T h e riser can be c o n n e c t e d at the s e a f l o o r to a wellhead or to a subsea blowout preventer stack. A diverter system is usually attached at the

Offshore Operations

~

1365

~r~

Figure 4-494. Drillship. surface. Vertical vessel motion is tolerated by adding a telescoping (slip)joint at the surface. This joint will usually allow up to 30 ft of vertical vessel motion. Lateral m o t i o n is tolerated by use of ball joint connections at the seafloor and surface. T h e riser can be quickly d e t a c h e d f r o m the wellhead or blowout preventer stack to facilitate vessel m o v e m e n t during adverse weather conditions. Figure 4-496 shows two typical drilling configurations with a riser in place, and Figure 4-497 shows in more detail a typical riser system that would be used while drilling the intermediate hole from a floating vessel.

1366

Drilling a n d Well C o m p l e t i o n s

j

.

J

Figure 4-495. Semisubmersible drilling rig.

A m a r i n e riser must be held in tension to prevent the riser from collapsing u n d e r its own weight. This can b e accomplished by a d d i n g buoyant material to the riser p i p e , o r by m e c h a n i c a l t e n s i o n i n g devices (Figures 4-498, 4-499). Tensioning devices are usually required in water depths greater than 250 ft. Many operators drill the conductor hole (approximately 1,000 ft) without using a riser. W h e n drilling with a f l o a t i n g vessel, the shallow p o r t i o n of the surface hole is considered expendable, a n d can easily be a b a n d o n e d in case o f shallow gas flow, d e v i a t i o n difficulties, o r o t h e r shallow-hole p r o b l e m s . D r i l l i n g is accomplished by circulating returns to the sea floor. O n c e the c o n d u c t o r hole is drilled, the m a r i n e riser can b e attached a n d used to drill the r e m a i n d e r of the well. Problems o f l o s t circulation can be avoided through use o f riserless systems. A n o t h e r a d v a n t a g e with riserless d r i l l i n g is t h a t t h e well can be a b a n d o n e d quickly if shallow gas is encountered. Most o p e r a t o r s p r e f e r to vent the gas at the s e a f l o o r r a t h e r than b r i n g i n g it to the surface. T h e disadvantage of the riserless system is in the lack of well control alternatives. T h e dynamic

Offshore Operations

1367

Te4escopi~

Templote

Figure 4-496. Marine riser systems. kill, if attempted rapidly u p o n kick recognition, is the only recourse in attempting to control the well.

Casing Programs Casing programs offshore typically consist of 30-in. structural, 20-in. conductor, 13 ~-in. surface, and 9-~-in. intermediate casing strings. Because seawater is in perfect communication with the sediments, pore pressure is increased by increasing water depth, and the margin between fracture pressure and pore pressure is lessened. Also, abnormal pore pressure is found in many offshore geological environments, forcing fairly stringent casing designs to be used. Several intermediate casing strings or liners are often required to reach the target depth. Most operators prefer to set 7-in. production casing to facilitate larger production tubing and quicker payout.

Well Control Offshore, well control equipment and associated operations present some differences from that seen and used onshore. In some instances o n s h o r e equipment can be employed, but the offshore environment generally dictates a modification of equipment and procedures. There are several different well c o n f i g u r a t i o n s used offshore, often on the same well at different drilling intervals, and each configuration has specific well control procedures that should be followed. A well may be equipped with a surface blowout preventer stack; a subsea blowout preventer stack, riser and diverter system; a riser and diverter system with no blowout preventer; a diverter only; or a riserless system with no well control equipment.

1368

Drilling and Well Completions RIG FLOOR

DIVERTER

DISCHARGE

• SLIP JOINT TO TENSIONERS

~.AaN OSCX

WATER

22_._

BALL JOINT

,up ~ , LINE

l=__.L__J~" ,w. wELL"~D LANDING BASE

Figure 4-497. Marine riser for floating system.

Offshore O p e r a t i o n s

Buoyant Force

1369

Buoyant Force Material

] H ti UL Figure 4-498. Buoyant riser tensioning device.

Surface Blowout Preventer Stacks W h e n a d e v e l o p m e n t platform has b e e n set, wells can b e d r i l l e d with a landtype well design. C o n d u c t o r casing is set from above sea level, through the water, to as much as 1,500 ft subsea. T h e c o n d u c t o r provides for m u d returns, a n d allows the blowout prevention system to exist in the surface environment. This well d e s i g n is essentially i d e n t i c a l to t h a t o n s h o r e , as are t h e well c o n t r o l p r o c e d u r e s that should be employed.

Subsea Blowout Preventer Stacks Due to the n o n p e r m a n e n t nature of exploratory drilling offshore, the o p e r a t o r does not always have the luxury of placing the blowout preventers at the surface. By placing the blowout preventer stack at the s e a f l o o r a n d c o m m u n i c a t i n g with the well through a detachable m a r i n e riser, a well can be shut in at the seafloor. This action removes from the drilling vessel the responsibility of maintaining surface position at all times. Figure 4-500 shows a typical subsurface blowout preventer stack. Note the presence of choke a n d kill lines e x t e n d i n g from the surface to the stack. These lines allow fluids to be p u m p e d out of the well, bypassing the m a r i n e riser, and are the source of the p r o c e d u r a l differences b e t w e e n o n s h o r e a n d offshore well control operations.

1370

Drilling and Well C o m p l e t i o n s

Idler

Sheaves

Wire

Rope

Counterweight

Riser

. . . . . . . .

~,

Figure 4-499. Mechanical riser tensioning device. Well Control Procedures T h e r e are several m e c h a n i c a l d i f f e r e n c e s b e t w e e n o n s h o r e a n d o f f s h o r e e q u i p m e n t that lead to p r o c e d u r a l differences in well control. W h e n a well is shut in by a subsea blowout preventer, f l u i d s must be circulated down the drillstring, up the casing annulus, a n d up the choke line to the surface. T h e m a r i n e r i s e r / d r i l l s t r i n g annulus is thus bypassed. Because the choke line is of small d i a m e t e r ( 3 - 4 in.) and, d e p e n d i n g on water d e p t h , may be very long, frictional pressure d r o p in the choke line may be very large. W h e n p r e p l a n n i n g for well control operations, the kill rate circulating pressure must be o b t a i n e d by circulating the well through the choke line. Neglecting choke line friction in calculations can cause excessive backpressure to be placed on the casing shoe. Choke line friction is c o n s i d e r e d when calculating the p u m p pressure startup schedule. If the circulating pressure has been m e a s u r e d by circulating through the choke line, the r e m a i n d e r of the calculations are p r e f o r m e d as for a surface stack. Choke line friction can be r e d u c e d by using larger choke lines, o r by circulating the well through both the choke a n d kill lines. W h e n the well is circulated through the choke line, a r a p i d loss in hydrostatic pressure is seen when the kick f l u i d begins to enter the choke line. Hydrostatic pressure is lost because low density gas is displacing the drilling m u d from the small volume o f choke line. Small kick volumes can result in l o n g columns of gas in the choke line. Surface choke response must be r a p i d enough to prevent new kick f l u i d f r o m e n t e r i n g the well d u e to the r e d u c t i o n in b o t t o m h o l e

References

1371

RISER

ADAPTER

BALL JOINT

HYDRIL "G L" W Z

Z I -J

_.1 .-I -J

RISER

CONNECTOR

v

5M

HYDRIL "GL"

BLIND/SHEAR RAMS PIPE

RAM

PIPE

RAM

PIPE

RAM

WELL HEAD CONNECTOR 163/4 '' - i 0 , 0 0 0

psi - B . O . R

STACK

F i g u r e 4-500. Subsea blowout preventer stack.

pressure. Also, when kill fluid enters the choke line and begins to displace the kick fluid, hydrostatic pressure will increase rapidly, thus increasing bottomhole pressure. Slow response by the choke operator can fracture the casing shoe. A choke operator is faced with an unusually demanding job when pumping out a kick through a subsurface blowout preventer.

1372

Drilling a n d Well Completions

In deep water, it is c o m m o n to find kick fluids t r a p p e d above the blowout preventer stack when the well is shut in. These fluids must be vented through the diverter system.

DiverterSystems It is c o m m o n in many offshore areas to encounter a shallow gas hazard. Quite often, these hazards can be spotted on seismic, and a surface location is chosen to avoid the hazard. However, there is always a risk of e n c o u n t e r i n g a shallow gas flow with insufficient casing in the well to allow a shut-in. In this instance a diverter system is called on as a safety measure. The ideal f u n c t i o n of the diverter system is to allow the well to flow a n d subside by natural means. In many cases the diverter system simply provides enough time to evacuate the rig. Figure 4-501 shows a typical diverter system setup. The c o m p o n e n t s of the system are the a n n u l a r preventer, vent lines, the control system, a n d the conductor or structural casing. The major operational consideration when using a diverter system is to be certain that the valves on the vent lines are fully o p e n before the a n n u l a r preventers are closed. W h e n drilling the conductor or surface hole, it is generally accepted that shutting in the well will cause a subsurface blowout that is likely to broach to the surface. This cannot be tolerated when drilling from a bottomsupported vessel. Experience has shown that the diverter operations can also cause a subsurface blowout. Large-diameter vent lines free from turns or bends generally lower the backpressure placed on the well by the diverter system, therefore reducing the risk of a subsurface blowout. The lack of bends in the lines greatly reduces the erosion potential of the flow. Sufficient conductor casing

DIVERTER ,=] I

TO

SHALE S HAKER AREA

L

SPOOL

"-dQ\ ,o I I~

TELESCOPIJOI C NT

Figure4-501.Divertersystem.

References

1373

depth is also very important in preventing a subsurface blowout. Conductor depths as much as 1,500 ft are sometimes required to prevent subsurface blowouts. The Minerals Management Service requires a minimum 6-in.-diameter diverter vent line, but many operators are now using as large as 12-in.-diameter vent lines. While a bottom-supported vessel must divert when shallow gas is encountered, a floating vessel has the additional option of simply abandoning the well. This option has led to the use of riserless systems when drilling the surface hole. However, a dynamic kill provides the only means of controlling the well. A dynamic kill makes use of annular friction as well as a heavier mud to hold backpressure on the formation. If very short wellbores are involved, the dynamic kill rates are usually to large to be practical. A well being drilled with a riserless system is very likely to be lost if shallow gas is encountered.

REFERENCES Derricks and Portable Masts 1. McCray, A. W., and F. W. Cole, Oil Well Drilling Technology, University of Oklahoma Press, Norman, Oklahoma, 1959. 2. API Standard 4A, Sixteenth Edition: "API Specification for Steel Derricks," (American Petroleum Institute), Dallas, April 1967. 3. API Standard 4D, Sixth Edition: "API Specification for Portable Masts," API, Dallas, March 1967. 4. API Standard 4E, Second Edition: "API Specification for Drilling and Well Servicing Structures," API, Dallas, March 1974. 5. API Standard 4F, First Edition: "API Specification for Drilling and Well Servicing Structures," API, Dallas, May 1985. 6. Rossel, Henry E., and Lawrence B. Chapman (eds.), Principles of Naval Architecture, The Society of Naval Architects and Marine Engineers, New York, 1939. 7. Bourgoyne, A. T., et al., Applied Drilling Engineering, SPE, Richardson, Texas, 1986. 8. C. Gatlin, Petroleum Engineering, Drilling and Well Completions, Prentice-Hall, Englewood Cliffs, New Jersey, 1960.

Hoisting Systems 9. API Specification 8A, Eleventh Edition: "API Specification for Drilling and Production Hoisting Equipment." API, Dallas, May 1, 1985. 10. API Recommended Practice 8B, Fourth Edition: "Recommended Practice for Hoisting Tool Inspection and Maintenance Procedures," API, Dallas, April 1979. 11. API Recommended Practice 9B, Ninth Edition: "Recommended Practice on Application, Care, and Use of Wire Rope for Oilfield Service," API, Dallas, May 30, 1986. 12. APT Specification 9A, "API Specification for Wire Rope," APT, Dallas, May 28, 1984.

Rotary Equipment 13. APT Specification 7: "APT Specification for Rotary Drilling Equipment," API, Dallas, December 1981.

1374

Drilling and Well Completions

14. API Specification 5B: "API Specification for Threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads," API, Dallas, March 1979. 15. International Association of Drilling Contractors, Drilling Manual, Tenth Edition, 1982. 16. Lynch, Phillip F., Rig Equipment: A Primer in Drilling and Production Equipment, Vol. 2, Gulf Publishing Co., Houston, 1978.

Mud Pumps 17. Hughes Tool Company, Hughes Practical Hydraulics, Houston, 1976. 18. API Bulletin D10, Second Edition: "Procedure for Selecting Rotary Drilling Equipment," API, Dallas, January 1982. 19. American Association of Drilling Contractors, Tool Pusher's Manua~ API, Dallas, 1955. 20. Fullerton, H. B., Constant Energy Drilling System Well Programmin~ Sii Smith Tool, p. 6, Irvine, (adapted from original work by Hal B. Fullerton, Jr., United Drilling Services). 21. Lummus, James L., "Drilling in the Seventies, Part II: Analysis of MudHydraulics Interaction," Petroleum Engineer, February 1974. 22. Randal, B. V., "Optimum Hydraulics in the Oil Patch," Petroleum Engineer, September, 1975.

Drilling Muds and Completion Fluids 23. API Bulletin, RP-13B: "Standard Procedures for Field Testing drilling Fluid," API, Dallas, May 1, 1985. 24. M-I Drilling Fluids Co., Drilling Fluid Engineering Manual, Houston, 1991. 25. NL Baroid/NL Industries, Inc., Manual of Drilling Fluid Technology; Mud Testing-Tools and Techniques, Houston, 1979. 26. NL Baroid/NL Industries, Inc., Manual of Drilling Fluids Technology; Calculations, Charts and Tables for Mud Engineerin~ Houston, 1979. 27. API Bulletin 13A: "Oil Well Drilling Fluid Materials," API, Dallas, 1983. 28. Technical Manua~ International Drilling Fluids, Uxbridge, United Kingdom, 1988. 29. Bingham, G., B. Calgle, and C. Grichar, Mud Equipment Manual, Handbook 8: Centrifuges, Gulf Publishing Co., Houston, 1983. 30. International Association of Drilling Contractors, Drilling Manual, Tenth Edition, 1982. 31. Wojtanowicz, A. K., "Environmental control potential of drilling engineering: Overview of existing technologies," SPE/IADC 21954, Proc. 1991 SPE/IADC Drilling Conference, Amsterdam, 11-14 March, 1991. 32. Candler, J., et al., "Source of mercury and cadmium in offshore drilling discharges," SPE Drilling Engineering, December, 1992. 32A. Ayers, R. C., Jr., et al., "The generic mud concept for NPDES permitting of offshore drilling discharges," J Petroleum Engineerin~ March 1985. 33. Hinds, A. A., S. P. T. Smith, and E. K. Morton, "A comparison of the performance, cost and environmental effects of diesel-based and low-toxicity oil mud Systems," SPE 11891, Offshore Europe 1983 Conference, Aberdeen, September, 1983. 34. Moore, P. L., Drilling Practices Manua~ The Petroleum Publishing Co., Tulsa, Oklahoma, 1974.

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35. Imco Services, A Halliburton Company, Pocket Guide For Mud Technology, Catalog No. 05006M 10M, 1981. 36. Tuttle, R. N., and J. H. Bankman, "New nondamaging and acid-degradable drilling and completion fluids," SPE Reprint Series: "Well, completions," SPE, 1978. 37. G. O. Suman, Jr., Sand Control Handbook, Gulf Publishing Co., Houston, 1975.

Drill String: Composition and Design 38. Drilco Drilling Assembly Handbook, Drilco, Division of Smith International, Inc., Houston, 1977. 39. Wilson, G. E., and W. R. Garrett, "How to drill a usable hole," Part 3, World Oi~ October 1976. 40. Dawson, R., and P. R. Paslay, "Drilling pipe buckling in included holes," SPE Paper 11167 (presented at the 57th Annual Fall Technical Conference and Exhibition of the SPE of AIME held in New Orleans, September 26-29, 1983). 41. Lubinski, A., "Maximum permissible dog-legs in rotary boreholes," Journal of Petroleum Technology, February 1961. 42. Rowe, M. E., "'Heavy wall drill pipe, a key member of the drill stem," Publ. No. 45, Drilco, Division of Smith International, Inc., Houston, 19XX. 42A. Timoshenko, S., and D. H. Young, Elements of Strength of Materials, Fifth Edition, D. Van Nostrand Co., New York, 1982.

Rock Bits and Downhole Tools 43. Garrett, W. R., "The effect of a downhole shock absorber on drill bit stem performance," Publ. No. 41, Drilco, Division of Smith International, Inc., Houston, 19XX. 43A. Christensen Diamond Compact Bit Manual, Christensen, Inc., March 1983. 44. Winters, W.J., et al., "Application of the 1987 IADC/roller bit classification system, SPE/DC 16143, Proc. SPE/IADC Drilling Conference, New Orleans, March 15-18, 1987, pp. 819-837. 45. Drilling Manual, Canadian Association of Drilling Contractors, Calgary, 1979. 46. Hampton, S. D., et al., "Application of the 1987 roller bit dull grading system," SPE/IADC 16146, Proc. of 1987 SPE/IADC Drilling Conference, New Orleans, March 15-18, 1987, pp. 859-867. 47. "Engineering essentials of modern drilling," Energy Publication Division of HBJ, Dallas, 1982. 47A. Nicholson, R. W., "Minimize drill pipe damage and hole problems. Follow acceptable dog-leg severity limits," transactions of the 1974 IADC Rotary Drilling Conference. 48. McLean, R. H., "Crossflow and impact under jet bits," Journal of Petroleum Technology, November 1964. 48A. Bringer, D. W., and S. T. Crews, "Using large drill collars successfully,"

Journal of Petroleum Technology, August 1978. 49. Diamond Drill Bit Technology, student manual, Christensen, Inc. 49A. Casner, J. A., "How to design drill strings for deep wells," World Oil, February 1, 1968. 50. Diamond Coring Technology, student manual, Christensen, Inc.

1376

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51. APR Recommended Practice 7G, Fourteenth Edition: "API Recommended Practice for Drill Stem Design and Operation Limits," August 1990. 51A. Wilson, G. E., "How to select bottom-hole drilling assemblies," Part I, Publ. No. 62, Drilco, Division of Smith International, Inc., Houston, 19XX. 52. Offenbacher, L. A., J. D. McDermain, and C. R. Paterson, "PDC bits find applications in Oklahoma drilling," paper presented at the IADC/SPE 1983 Drilling Conference, New Orleans. 52A. "Drilco 1982-83 Composite Catalog," World Oil, Houston. 53. Smith, R., G. Hollingsworth, C. Joiner, and J. Bernard: "Chevron optimizes drilling procedures in the Tuscaloosa trends," Petroleum Engineering International, March 1982. 54. Winters, W. J., and H. H. Doiron, "The 1987 IADC fixed cutter bit classification system," SPE/IADC 1642, Proc. 1987 SPE/IADC Drilling Conference, New Orleans, March 15-18, 1987, pp. 807-817. 55. Clark, D. A., et al., "Application of the new IADC dull grading system for fixed cutter bits," SPE/IADC 1645, Proc. 1987 SPE/IADC Drilling Conference, New Orleans, March 15-18, 1987, pp. 851-858. 56. "Drilco 1986-1987 Products Catalog," Smith International, Inc. 1986-87, Composite Catalog, p. 1751. 57. Christensen, Downhole Tool Technology, student manual. 57A. "Proven drilling performance," Eastman-Christensen 1988-89 General Catalog, pp. 28-29. 58. The Servco Division of Smith International, Inc., SERVCO Data Handbook, Fourth Edition. 58A. Wilson, G. E., "Operators slush deep-drilling costs with RWP TM stabilizers," Publ. No. 83, Smith International, Inc., 1977. 59. "Grant reamer/stabilizers," and "Grant cushion stabilizers," Bulletins 71 and 73, Grant Oil Tool Company, 1981.

Drilling Mud Hydraulics 60. Gatlin, C., Petroleum Engineering: Drilling and Well Completions, Prentice-Hall, Inc., Englewood Cliffs, New Jersey, 1960. 61. Bourgoyne, A. T., and others, Applied Drilling Engineerin~ Society of Petroleum Engineers, Richardson, Texas, 1986. 62. White, F. M., Fluid Mechanics, McGraw-Hill Book Co., New York, 1979. 63. Moore, P. L., and others, Drilling Practices Manua~ PennWell Books, Tulsa, Oklahoma, 1974.

Air and Gas Drilling 64. Lyons, W., Air and Gas Drilling Manua~ Gulf "Publishing Co., Houston, 1984. 65. Angel, R. R., "Volume requirements for air or gas drilling," Petroleum Transactions, Vol. 210, 1957. 66. Angel, R. R., Volume Requirements for Air and Gas Drillin~ Gulf Publishing Co., Houston, 1988. 67. Beyer, A. H., R. S. Millhorne, and R. W. Foote, "Flow behavior of foam as a well circulating fluid," SPE 3986, 1972. 68. Millhorne, R. S., C. A. Haskin, and A. H. Beyer, "Factors affecting foam circulation in oil wells," SPE 4001, 1972. 69. Mitchell, B.J., Viscosity of Foam, Doctoral Thesis, University of Oklahoma, January 1970.

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70. Okpobiri, G. A., C. J. Machado, and C. U. Ikoku, Minimum Volumetric Requirements in Aerated Drilling: A Field Operations Manual, U.S. Department of Energy Report No. DOE/BC/10079-49, December 1982. 71. Poettman, E H., and W. E. Bergman, "Density of drilling muds reduced by air injection," World Oil, August 1, 1955. 72. Murray, S. W., "Parasite tubing method of aeration," Spring Meeting of Rocky Mountain District, Division of Production, American Petroleum Institute, Paper No. 875-22-C, Calgary, Alberta, Canada, May 8-10, 1968. 73. Hook, R. A., L. W. Cooper, and B. R. Payne, "Air, mist and foam drilling: A look at latest techniques," Parts I and II, World Oil, April and May 1977. 74. API Bulletin D13, First Edition: "Installation and Use of Blowout-Preventer Stacks and Accessory Equipment," API, February 1966. 75. "New Mexico occupational health and safety recommended practices for oil and gas well drilling and service operations," State of New Mexico Environmental Improvement Division Report No. EID/OHS-82/2, 1982. 76. Miska, S., "Should we consider air humidity in air drilling operations?," Drill Bit, July 1984. 77. Handbook of Chemistry, McGraw-Hill, New York, 1956. Downhole Motors

78. Cross, C. G., "Turbodrill," U.S. Patent 142,992 (September 1873). 79. Tiraspolsky, W., Hydraulic Downhole Drilling Motors, Gulf Publishing Company, Editions Technip, Houston, 1985. 80. Ioannesion, R. A., OsnoryoTeorii i Tekhnik: Turbinnogo Bureniya (Foundations of Theory and Technology of Turbodrilling), Gostoptekhizdat, Moscow, 1954 (in Russian). 81. Ioannesion, R. A., and Y. V. Vadetsky, "Turbine drilling equipment development in the USSR," Oil and Gas Journal, September 28, 1981. 82. Jurgens, R., and C. Marx, "Neve Bohrmotoren ffir die erd61industrie (New drilling motors for the petroleum industry)", ErdoloErdges Zeitschrift, April 1979 (in German). 83. Lyons, W. C., et al., "Field testing of a downhole pneumatic turbine motor", Geothermal Energy Symposium, ASME/GRC, January 10-13, 1988. 84. Magner, N. J., "Air motor drill," The Petroleum Engineer, October 1960. 85. Downs, H. F., "Application and evaluation of air-hammer drilling in the Permian Basin," API Drilling and Production Practices, 1960. 86. Bourgoyne, A. T., et al., Applied Drilling Engineerin~ SPE Textbook Series, Vol. 2, First Printing, SPE, Richardson, Texas, 1986. 87. Drilling Manual, Ninth Edition, IADC, 1974. 88. Winters, W., and T. M. Warren, "Determining the true weight-on-bit for diamond bits," SPE Paper 11950, presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, October 5-8, 1983. MWD and LWD

89. Reed, P., "Amerada develops special rotary drill stem for simultaneous electrical logging and drilling," Oil and Gas J., pp. 68-70, Nov. 17, 1939. 90. Mills, B., "Simultaneous and continuous electrical logging and drilling achieved," Oil Weekly (now World Oil), January 1, 1940. 91. Arps, J. J., "Continuous logging while drilling; A practical reality," SPE 710, SPE Annual Fall Meeting, New Orleans, October 6-9, 1963.

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92. Arps, J. j., and J. L. Arps, "The subsurface telemetry problem: A practical solution," Journal of Petroleum Engineerin~ May 1964. 93. Roberts, W. F., and Johnson, H. A., "Systems available for measuring hole direction," Oil and Gas J., V. 76, No. 22, pp. 68-70, 1978. 94. Spinner, T. G., and F. A. Stone, "Mud pulse logging while drilling system design, development and demonstration," IADC/CAODC Drilling Technical Conference, Houston, March 6-9, 1978. 95. "MWD: State of the Art," March 27, Vol. 76, No. 13; April 3, Vol. 76, No. 14; April 17, Vol. 76, No. 16; May 1, Vol. 76, No. 18; May 15, Vol. 76, No. 20; May 29, Vol. 76, No. 22; June 12, Vol. 76, No. 24; July 3, Vol. 76, No. 27; July 17, Vol. 76, No. 29; July 31, Vol. 76, No. 31; 1978. 96. Desbrandes, R., "Status report: MWD technology, Part 1: Data acquisition and downhole recording and processing," Petroleum Engineering Internationa~ September 1988. 97. Desbrandes, R., "Status report: MWD technology, Part 2: Data transmission," Petroleum Engineering International, October 1988. 98. Desbrandes, R., "Status report: MWD technology, Part 3: Processing, display and applications," Petroleum Engineering Internationa~ November 1988. 99. Desbrandes, R., "Invasion diameter and supercharging in time-lapse MWD/ LWD logging," ProceedingsMWD Symposium, Louisiana State University, Baton Rouge, February 26-27, 1990. 100. Patton, B.J., et al., "Development and successful testing of a continuos wave, logging-while-drilling telemetry system," Journal of Petroleum Engineering, October 1977. 101. Bourgoyne, A. T., M. E. Chenevert, K. K. Millheim, and F. S. Young, Applied Drilling Engineerin~ SPE Textbook Series, Vol. 2, SPE, 1986. 102. Sunstrand, "Q-flex accelerometers,: brochure, Sundstrand Inc., Redmond, WA, 1985. (Now, a division of Allied Signal Inc., Redmond, WA.) 103. Develco, "Borehole Products," brochure, Develco Inc., Sunnvale, CA, 1985. (Now, a division of Baker-Hughes-Inteq, Houston, TX.) 104. Teledrift, Inc., "Teledrift--Wireless Drift Indicator," Brochure, Teledrift, Inc., Oklahoma City, OK, pp. 4, 1993. 105. "MWD: Measurement-While-Drilling," Inteq-Baker-Hughes, Brochure 602-003, August 1993. 106. "Anadrill Drilling Service Catalog," Anadrill-Schlumberger, AMP-7006, 1993. 107. Holmes, A. B., "Fluidic mud pulser concepts in MWD," Proceedings MWD Symposium, Louisiana State University, Baton Rouge, February 26-27, 1990. 108. Desbrandes, R., A. T. Bourgoyne andJ. A. Carter, "MWD transmission data rate can be optimized," Petroleum Engineering International, June 1987. 109. "Electromagnetic MWD and Directional Drilling Services," Geoservices Brochure, 1994. 110. McCain, W. D. Jr., The Properties of Petroleum Fluids, PennWell Books, Tulsa, OK, 1990. 111. Knox, D. W. J., and J. M. Milne, "Measurement-while-drilling tool performance," SPE 16523, Offshore Europe 1987 Conference, Aberdeen, Proceedings Vol. 1, September 1987. 112. Jan, Y. H., and Harrel, J. w., "MWD directional-focused Gamma Ray-A new tool for formation evaluation and drilling control in horizontal wells," SPWLA 28th Annual Logging Symp., p. A-l-17, 1987. 113. Anadrill-Schlumberger, 1992, Logging While Drillir~ SMP-9160, Sugar Land, TX. 114. Evans, H. B., Brooks, A. G., Meisner, J. E., and Squire, R. E., "A focused current resistivity logging system for MWD," SPE 16757, 62nd SPE Ann. Tech. Conf. & Exhibition, Dallas, TX, Set 27-30, 1987.

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115. Gianzero, S. R., Chemali, R., Lin, Y., and Su, S., "A new resistivity tool for Measurement-While-drilling," SPWLA 26th Ann. Logging Symp., pp. A-1-22, 1985. 116. Aron, J. S. K., Chang, R., Dworak, R., Hsu, K., Lau, T., Masson, J-P., Mayes, J., McDaniel, G., Randall, C., and Plona, T. J., "Sonic compressional measure-ment while drilling," SPWLA 31st Ann. Logging Symp., pp. G-l-21, 1994. 117. Pidcock, G., and J. Daudy, "Gulf Canada improves drilling with MWD techniques," Petroleum Engineering Internationa~ September, Vol. 60, No. 9, 1988. 118. Falconer, I. G., Burgess, T. M., and Sheppard, M. C., "Seaprating Bit and Lithology Effects from Drilling Mechanics data," paper IADC/SPE17191, IADC/SPE Drilling Conf., Dallas, TX, February 1988. 119. Terzaghi, K., 1943, Theoretical Soil Mechanics, John Wiley & Sons, New York, NY. 120. Jorden, J. B., and Shirley, O.J., 1966, "Application of drilling performance data to overpressure detection," J. P. T., v. 18, pp. 1387-1394. 121. Rhem, W. and McClendon, R., "Measurement of formation pressures from drilling data," SPE 3601, 46th Ann. Fall Meet., New Orleans, LA, October 3-5, 1971. 122. Eaton, B. A., "The equation for pressure prediction from well logs," SPE 5544, SPE 50th Ann. Tech. Conf. & Exhibit, Dallas, Tx, September 28October 1, 1975. 123. Hottman, C. E., and Johson, R. K., "Estimation of formation pressure from log-derived shales properties," J. P. T., v. 17, pp. 717-722, 1965. 124. Alixant, J-L.,"Real-time Effective Stress Evaluation in Shale: Pore Pressure and Permeability Estimation," Ph.D. dissertation, Louisiana State University, p. 210, December 1989. 125. Wyllie, M. R.J., Gregory, A. R., and Gartner, L. W., "Elastic wave velocities in heterogeneous and porous media," Geophysics, v. 21, 1, p. 41, 1956. 126. Raymer, L. L., and Hunt, E. R., "An improved sonic transit time-to-porosity transform," SPWLA Ann. Logging Symp., paper P, 1960. 127. Joshi, S. D., Horizontal Well Technology, PennWell Publishing Co., Tulsa, Oklahoma, 1991. 128. Hutchinson, M. W., "Measurement While Drilling and After Drilling by Multiple Service Companies Through Upper Carboniferous Formations at a Borehole Test Facility, Kay County, Oklahoma," SPE 22735, 66th Ann. Techn. Conf., Dallas, TX, October 6-9, pp. 741-753, 1991. 129. Shi, Ying, "A comparison of MWD and open hole logging in sandstone and limestone," Master of Science Thesis, LSU Petroleum Engineering Department, December 1993. 130. Zhao, Donglin, "The Comparison of MWD and Wireline Logs in Sandstone and Limestone Under Various Borehole Conditions," Master of Science Thesis, LSU Petroleum Engineering Department, May 1994.

Directional Drilling 131. Sii DatadriU Directional Drilling Manual, Second Revision, December 1983. 132. Lubinski, A., "How Severe is the Dogleg?," World Oi~ February 1957. 133. Wilson, G. J., "An improved method for computing directional surveys," Journal of Petroleum Technology, August 1968. 134. Leblond, A., "Controlled directional drilling," Ecole Nationale Superieure du Petrole at des Moteurs, Reference 19163, April 1971.

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135. Millheim, K. K., F. H. Gubler, and H. B. Zaremba, "Evaluating and planning directional wells utilizing post analysis techniques and a three dimensional bottom hole assembly program," SPE Paper 8339, presented at the 54th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME held in Las Vegas, September 23-26, 1979. 136. Nicholson, J. T., "Calculator program developed for directional drilling," Oil and Gas Journal, September 28, 1981.

Selection of Drilling Practices 137. Bourgoyne, A. T., Jr., and E S. Young, "A multiple regression approach to optimal drilling and abnormal pressure detection," Society of Petroleum Engineering Journal, August 12974. 138. Fullerton, H. B., "Constant energy drilling system for well programming," Smith Tool, Irvine, California, August 1973. 139. Kendal, H. A., and W. C. Goins, "Design and operation of jet-bit programs for maximum hydraulic housepower impact force or jet velocity," Journal of Petroleum Technology, October 1960. 140. Miska, S., and P. Skalle, "Theoretical description of a new method of optimal hydraulic program design," Society of Petroleum Engineering Journa~ August 1981. 141. Adams, N., "Well Control," The Oil and GasJourna~ October and November 1979. 142. Goins, W. C., Jr., Blowout Prevention, Gulf Publishing Co., Houston, 1969.

Well Pressure Control 143. Miska, S., F. Luis, and A. Schofer-Serini, "Analysis of the inflow and pressure buildup under impending blowout conditions," Journal of Energy Resources Technology, March 1992. 144. Moore, P. L., Drilling Practices Manual, The Petroleum Publishing Co., Tulsa, Oklahoma, 1974. 145. Rehm, B., Pressure Control in Drilling, The Petroleum Publishing Co., Tulsa, Oklahoma, 1976.

Fishing Operations 146. Main, W. C., "Detection of Incipient Drill-pipe Failures," API Drilling and Production Practices, 1949. 147. Moore, E. E., "Fishing and freeing stuck drill pipe," The Petroleum Engineer, April 1956. 148. Gatlin, C., Petroleum Engineering: Drilling and Well Completions, Prentice-Hall, Englewood Cliffs, New Jersey, 1960. 149. Short, J. A., Fishing and Casing Repair, PennWell, 1981. 150. McCray, A. W., and F. W. Cole, Oil Well Drilling Technology, University of Oklahoma Press, Norman, Oklahoma, 1959.

Casing and Casing String Design 151. API Specification 5A, Thirty-Fifth Edition: "API Specification for Casing, Tubing and Drill Pipe," March 1981.

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152. API Bulletin 5C3, Fifth Edition: "API Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe and Line Pipe Properties," July 1989. 153. API Recommended Practice 5A, First Edition: "API Recommended Practice for Field Inspection of New Casing, Tubing, and Plain-end Drill Pipe," April 1983. 154. API Recommended Practice 5B1, "API Recommended Practice for Gauging and Inspection of Casing, Tubing, and Line Pipe Threads," April 1983. 155. API Bulletin 5C2, Twentieth Edition: "API Bulletin on Performance Properties of Casing, Tubing and Drilling Pipe," May 1987. 156. API Recommended Practice, Sixteenth Edition: "API Recommended Practice for Care and Use of Casing and Tubing," May 1988. 157. Adams, N., Well Control Problems and Solutions, Petroleum Publishing Co., Tulsa, Oklahoma, 19XX. 158. Coppes, J., Casing Programmin~ The Norwegian Institute of Technology, Trondheim, 19XX. 159. Craft, B. C., W. R. Holden, and E. D. Graves, Jr., Well Design-Drilling and Production, Prentice-Hall, Englewood Cliffs, New Jersey, 1962.

Well Cementing 160. McCray, A. W., and F. W. Cole, Oil Well Drilling Technology, University of Oklahoma Press, Norman, 1959. 161. Cementing Technology, Dowel Schlumberger Publication. 1984. 162. Smith, D. K., Cementin~ SPE Publications, Second Printing, 1976. 163. Rabia, H., Oilwell Drilling Engineerin~ Principles and Practices, Graham and Trotman Ltd, 1985. 164. API Specification 10: "API Specification for Materials and Testing for Well Cementing," January 1982. 165. ASTM C 150: Standard Specifications for Porland Cement, Book of ASTM Standards, Part 13, ASTM Publication, 1987. 166. API Standard 10A: "API Specifications for Oil-Well Cements and Cement Additives," April 1969. 167. Bourgoyne, A. T., Applied Drilling Engineering, SPE Textbook Series, Vol. 2, 1986. 168. Parker, P. N., B. J. Ladd, W. M. Ross, and W. W. Wahl, "An evaluation of primary cementing technique using low displacement rates," SPE Fall Meeting, 1965, SPE No. 1234. 169. McLean, R. H., C. W. Maury, and W. W. Whitaker, "Displacement mechanics in primary cementing," Journal of Petroleum Technology, February 1967. 170. Allen, T. O., and A. P. Roberts, Production Operations, Well Completions, Workover, and Stimulation, Vol. 1, Oil & Gas Consultants International, Inc., Tulsa, Oklahoma, 1978. 171. Lubinski, A., Developments in Petroleum Engineerin~ edited by Stefan Miska, vol 1: Stability of Tubulars • Deviation Control, Gulf Publishing Co., Houston, 1987. 172. Kastrop, J. E., ed., Oil and Gas Production Handbook, Energy Communications, Inc., Dallas, 1975.

Tubing and Tubing String Design 173. API Specification 5A, Thirty-Fifth Edition, March 1981. 174. API Bulletin 5C2, Twentieth Edition, May 1987. 175. API Recommended Practice, 5C1, Sixteenth Edition, May 1988.

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Corrosion and Scaling 176. API Specification 5C, Thirty-Seventh Edition: "Specifications for Casing, Tubing, and Drill Pipe," May 1984. 177. API Specification 5AX, Thirteenth Edition: "Specifications for High-Strength Casing, Tubing, and Drill Pipe," May 1984. 178. API Specification 5AC, Fourteenth Edition: "Specifications for Restricted Yield Strength Casing and Tubing," May 1984. 179. AP! Specification 6A, Fourteenth Edition: "Specifications for Wellhead Equipment," March 1983. 180. AP! Recommended Practice 53, Second Edition: "Recommended Practice for Blowout Prevention Equipment Systems for Drilling Wells," May 1984. 181. AP! Recommended Practice 7G, Seventh Edition: "Recommended Practice for Drill Stem Design and Operating Limitations," May 1984. 182. API Specification 7, Thirty-Fourth Edition: "Specifications for Rotary Drilling Equipment," May 1984. 183. Fontana, M. G., and N. D. Greene, Corrosion Engineerin~ McGraw-Hill Book Co., New York, 1967. 184. "Corrosion control in petroleum production," TPC5, National Association of Corrosion Engineers, Houston, 1984. 185. Budinski, K., Engineering Materials Properties and Selection, Second Edition, Reston Publishing Co., 1983. 186. Uhlig, H. H., and R. W. Revees, Corrosion and Corrosion Control, Third Edition, John Wiley and Sons Publishing Co., New York, 1985. 187. CorrosionBasics and Introduction, National Association of Corrosion Engineers, Houston, 1984. 188. Shreir, L. L., Corrosion, Vol. 1, John Wiley and Sons Publishing Co., New York, 1963. 189. Benning, M., "Corrosion in drilling operations, causes and treatment," SPE Proceeding of the 13th Annual Southwestern Petroleum Short Course, 1984. 190. Nesbitt, L. E., et al., "Properties of hydrogen sulfide scavengers used in water-based drilling fluids," Proceedings of 36th Annual Technical Meeting of the Petroleum Society, Edmonton, Canada, June 2-5, 1985. 191. Patton, C. C., Applied Water Technology, Campbell Petroleum Series, Norman Oklahoma, 1986. 192. "Material requirements for sulfide stress cracking resistant metallic material for oil field equipment," MR-01-75, National Association of Corrosion Engineers, Houston, 1975. 193. Eeters, L. L., "The Nature of Fatigue," Journal of Petroleum Technology, August 1964. 194. Azar, J. J., "How O, CO, and chlorides affect drill pipe fatigue," Petroleum Engineering International, March 1979. 195. Manual of Drilling Fluids Technology, NL Baroid/NL Industries, Inc., Houston, 1979. 196. Craig, B., "Critical Velocity examined for effects of erosion-corrosion," Oil and Gas Journal, May 27, 1985. 197. Ostroff, A. G., "Introduction to Oilfield Water Technology," National Association of Corrosion Engineers, Houston, 1979. 198. EnDean, H. J., "Avoiding drilling and completion corrosion," Petroleum Engineerin~ September 1977. 199. API Recommended Practice 14E, Fifth Edition: "Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, October 1991.

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