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The Main Environmental Factors Influencing Corrosion
CHAPTER
The Main Environmental Factors Influencing Corrosion
4
4.1 Introduction Chapter 3 discusses the nature of materials and how their properties influence the corrosion tendency and the rate. This chapter discusses the influence of environmental factors on corrosion. The rate at which corrosion takes place depends on several environmental factors including flow, pressure, temperature, oil phase composition, aqueous phase composition (salts and organic acids), gas phase composition (CO2, H2S, O2), solids, microbes, and mercury. Table 4.1 presents the oil and gas sectors in which these factors predominantly influence corrosion. Other factors might have additional effect on the corrosion type and corrosion rate and should be considered in a given operating environment.
4.2 Flow To transport hydrocarbons, the oil and gas industry uses pipes and pipelines operated under pressure. The pressure is the force that moves the hydrocarbons. An important consideration in designing and operating piping and pipeline is to estimate the amount of pressure required to transport the hydrocarbons. Bernoulli’s equation explains the pressure of a pipeline,1 according to which: Static Pressure þ Dynamic Pressure ¼ Constant:
(Eqn. 4.1)
Static pressure is the pressure exerted by a column of standing fluid. Dynamic pressure is the pressure exerted by a moving fluid. Figure 4.1 illustrates Bernoulli’s principle. Fluid velocity is lower in Sections A and C than that in Section B. Therefore the static pressure is higher in Sections A and C than in Section B. It should be noted that the velocities (distance travelled per unit time) of fluids in various sections are different, but the mass transferred per unit time is the same in all sections. The pressure is often indicated in the oil and gas industry by the term ‘head’ (H). This represents the pressure exerted by a column of liquid. A one foot high column of water exerts a pressure of 0.433 psi. In other words, the pressure measured as 1 psi is equivalent to the pressure exerted by a column of water of 2.31 feet high, i.e.: 1 psi=0:433 psi=ft ¼ 2:31 ft of head of water (Eqn. 4.2)
Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00004-2 Copyright Ó 2014 Elsevier Inc. All rights reserved.
179
180
Table 4.1 Environmental Factors Influencing Corrosion Environmental Factors
Component
Flow
Oil
Water
CO2
H2S
O2
Solid
Microbe
Pressure
Temperature
pH
acid
Hg
Production
Drill Pipe
No
No
Yes
Yes
Yes
No
Yes
No
No
Yes
No
No
No3
Casing Pipe
No
No
Yes
Yes
Yes
No
No
Yes
Yes
Yes
Yes
No
No
Downhole Tubular
Yes
Yes
Yes
Yes
Yes
No1
Yes
Yes
Yes
Yes
Yes
No
No3
Acidizing Pipe
Yes
No
Yes
No
No
No1
No
No
No
Yes
Yes
No
No
Water Generators
Yes
No
Yes
No
No
No
No
Yes
No
Yes
Yes
No
No
Gas Generators
Yes
No
Yes
No
No
No1
No
No
Yes
Yes
No
No
No
Open Mining
No
No
Yes
No
No
No
Yes
No
No
Yes
No
No
No
In situ Production
Yes
Yes
Yes
Yes
Yes
No1
Yes
No
Yes
Yes
Yes
Yes
No3
Wellhead
No1
Yes
Yes
Yes
Yes
No1
Yes
No
Yes
Yes
Yes
Yes
No3
No
1
Yes
Yes
Yes
Yes
Yes
Yes
No3
No
1
Yes
Yes
No
Yes
No
Yes
No3
Production Pipelines Heavy Crude Oil
Yes
Yes
Yes
Yes
Yes
Yes
Yes
1
No
No
1
1
Yes
Yes
Yes
No2
No2
No1
Yes
No
Yes
Yes
Yes
Yes
No3
No
Yes
Yes
Yes
Yes
No1
No
Yes
No
Yes
Yes
Yes
No3
1
No
No
No
Yes
Yes
No
No3
No
Pipelines Hydrotransport Pipelines Separators Gas Dehydration
No
No
Yes
yes
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
Yes
No3
Facilities Recovery Centers (Extraction) Upgraders
See refinery section
Waste Water Pipelines
Yes
No
Yes
No
No
No1
Yes
No
No
No
Yes
No
No
Tailing Pipelines
Yes
No
Yes
No
No
No1
Yes
No
No
No
Yes
No
No
Lease Tanks
No
Yes
No4
No
No
No
No4
No4
No
No
No
No
No
Transmission-
Transmission Pipelines
Yes
Yes
No4
No
No
No1
No4
No4
Yes
Yes
No
No
No
pipeline
(Midstream Pipelines)
TransportationTanker
Compressor Stations
Yes
No
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No3
Pump Stations
Yes
Yes
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No3
Pipeline Accessories
Yes
Yes
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No3
Ships
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Org. Sector
Storage
Refineries
LNG Tanks
No
No
No4
No
No
No1
No4
No4
No
No
No
No
No
Railcars
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
Other modes
No
No
No4
No
No
No1
No4
No4
No
No
No
No
No
Gas Storage
No
No
No4
No
No
No
No4
No4
No
No
No
No
No
Oil Storage
No
Yes
No4
No
Yes
No
No4
No4
No
No
No
No
No
Desalter
Yes
Yes
Yes
No
No
No
Yes
No
Yes
Yes
Yes
Yes
No
Atmospheric
No
Yes
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Vacuum distillation
No
Yes
Yes
No
Yes
No
No
No
No
Yes
No
Yes
No
Hydrotreating
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No3
Catalytic reforming
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No3
Visbreaker
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Coker
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Alkylation
No
Yes
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Gas treating
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Sour water stripper
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Hydrodesulfurization
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Sulfur recovery
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Heat exchanger
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Product Pipelines
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
Terminals
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
1
4
No4
No
No
No
No
No
distillation
Distribution
City Gates and Local
4
No
No
No
No
No
No1
No4
No4
No
No
No
No
No
No
No
No
1
4
No4
No
No
No
No
No
No
No
No
No
No
No4
No
Distribution CNG Tanks Special
4
No
No
Yes
No
CO2 Pipelines
No
No
Yes5
Yes5
Yes5
Yes5
No4
No4
Yes
Yes
No
No
No
Biofuel Infrastructure
Yes
Yes6
No4
No
No
No1
No
No4
No
Yes
No
Yes
No
High Vapor Pressure
No
No
No4
No
No
No1
No4
No4
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
No
No
No
Pipelines Hydrogen Pipelines 1
Unless operational deficiency accidentally lets them inside the system though may present the influence is minimal due to the influence of other components 3 only affect aluminum components 4 unless operational deficiency lets them accumulate at the bottom for prolonged duration 5 if intentionally left in the stream 6 in the form of biofuel
4.2 Flow
Diluent Pipelines
2
181
182
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.1 Bernoulli Principle.4 Reproduced with permission from PennWell Corporation.
The head of other liquids is estimated by dividing the head of water by the specific gravity of that liquid. Thus:2 H¼
2:31:P SG
(Eqn. 4.3)
where H is the head in feet, P is the pressure in psi, and SG is the specific gravity. H¼
P 9:7928:SG
(Eqn. 4.4)
where H is the head in meters and P is the pressure in kPa. In order to fully understand the effect of flow on corrosion, four parameters should be understood: pressure drop, flow regime, water accumulation, and critical flow rate.
4.2.1 Pressure drop One of the important calculations in designing and operating infrastructure is to determine the pressure drop. This is a combination of the static pressure (static head) due to the difference in elevation between the upstream and downstream locations and the dynamic pressure (dynamic head) due to energy loss from the flow of liquid. The static pressure remains constant once the infrastructure is constructed, but the dynamic pressure varies constantly because the type of phases (oil, water, and gas), number of phases (single, two, and multi), and volumes of different phases change constantly during operation. The combined pressure drop (caused by both static and dynamic heads) is typically represented by a System Head Curve (SHC). Figure 4.2 presents a typical SHC.3 Infrastructures operate over a wide range of SHCs. Appropriate pumps or compressors are selected on the basis of the anticipated SHCs over the entire operating life of the infrastructure. Methods to calculate the pressure drop in various types of flow are described in the following sections.
4.2 Flow
183
FIGURE 4.2 Typical System Head Curve.3 Reproduced with permission from ASME.
4.2.1a Single phase liquid Single phase flow may be laminar flow or turbulent. In general, the Reynolds number is used to differentiate laminar and turbulent flows. If the Reynolds number (Re) is less than 2,000 the flow is laminar, and if it is above 2,000 the flow is turbulent. Sometimes the flow between Re 2,000 and 4,000 is considered as transitional flow, and above 4,000 it is considered as turbulent. Re is defined as: Re ¼
3160 U di $v
(Eqn. 4.5)
where U is the liquid flow rate (gallons per minute [gpm]), di is the inner pipe diameter (inch), and n is the kinematic viscosity (centistokes). Kinematic viscosity, in stokes, is calculated using Eqn. 4.6: v¼
hl $10000 rl
(Eqn. 4.6)
where hl is the liquid viscosity in kg/ms and rl is the liquid density in kg/m3. The downstream pressure, Pd (psi), of a laminar flow with no elevation change, is calculated as: Pd ¼ Pu 0:0134
f $L$SG$U 2 di 5
(Eqn. 4.7)
where Pu is the upstream pressure (psi), f is the friction factor (dimensionless), L is the length of the pipe (ft), SG is the specific gravity of liquid relative to water, U is the liquid flow rate (gpm), and di is the inner pipe diameter (in).
184
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
The friction factor, f, is dimensionless and is calculated using either Eqn. 4.8 (smooth surface) or Eqn. 4.9 (rough surface): 64 (Eqn. 4.8) f ¼ Re εpipe 1=3 (Eqn. 4.9) f ¼ 0:0055 þ 0:15 di where εpipe is the surface roughness (m) and di is the inner pipe diameter (m). The friction factor, pipe roughness, pipe diameter, and Reynolds number are interrelated. Moody diagram is commonly used to indicate this relationship (Figure 4.3).4 If the elevation of the pipeline changes, then Eqn. 4.10 is used to calculate the downstream pressure (Pd, kPa) of a laminar flow. U$L$SG$n Pd ¼ Pu DPE;L (Eqn. 4.10) C3 $di4 where Pu is the upstream pressure (kPa), U is the flow rate (m3/hr), L is the length of the pipe (km), SG is the specific gravity of liquid relative to water (dimensionless), n is the kinematic viscosity (centistokes), C3 is a conversion constant (8.61E06), and di is the inner pipe diameter (mm), and DPE,L is the difference in pressure due to elevation change and is calculated using Eqn. 4.11. DPE;L ¼ CE $SG$ Hd Hu (Eqn. 4.11) where CE is the conversion constant to convert the result to kPa/m (0.0999); SG is the specific gravity of liquid relative to water (dimensionless); Hd is the downstream elevation (m); and Hu is the upstream elevation (m). For heavy crude with viscosity higher than 1,000 cP flowing in the laminar region the pressure drop can be determined as:4,5 " # Cu U 2 f CHead ðHd Hu Þ Pd ¼ Pu SG:DLpipe þ (Eqn. 4.12) DLpipe di5 where Pu is the pressure at the upstream end of the segment; Pd is the pressure at the downstream end of the segment; DLpipe is the length of the segment; f is the friction factor; di is the internal diameter of the pipe; SG is the liquid specific gravity; Hu is the elevation at the upstream end of the segment; Hd is the elevation at the downstream end of the segment; Cu is the flow conversion constant; and CHead is the head conversion constant. The downstream pressure of a turbulent liquid flow, Pd in kPa is calculated as: Pd ¼ Pu DPE;L
f $L$SG$U 2 C42 $di5
(Eqn. 4.13)
where Pu is the upstream pressure (kPa); DPE,L the pressure drop due to elevation change (kPa), L is the length of the pipe (km), U is the liquid flow rate (m3/hr); C4 is a conversion constant (19.8072E06), and di is the inner pipe diameter (mm). For liquid pipelines, the velocity and density do not change significantly along the length of a given pipeline if diameter and temperature are constant. Therefore the pressure loss per length is first
Values of (Vd) for water at 60°F (velocity. ft/s = diameter. m) 0.1
0.2
0.4 0.6 0.8 1
2
4
6 8 10
20
40
60 80 100
200
400 600 800 1000
Values of (Vd) for atmospheric air at 60°F 2
0.10
20
Laminar Critical flow zone Transition zone
40
60 100
200
400 600 800 1000 2000
4000
80,000 8000 6000 10,000 20,000 40,000 60,000 100,000
Complete turbulence, rough pipes
0.05 0.04
0.07 0.06
0.03 Lam
ε
2
(
h
L V d 2g
Friction factor ƒ =
flow 64
ƒ = Re
0.04
0.02 0.015
inar
)
0.05
0.01 0.008 0.006
0.03 0.025
0.004
Recr
0.002 0.001 0.0008 0.0006 0.0004
0.02
Sm
0.015
oo
th
0.0002
pip
es
0.0001 0.000,05
0.01 0.009 103 2(103) 3
4 5 6
8
104 2(104) 3
4 5 6
8
105 2(105) 3
4 5 6
Reynolds number Re =
8
106 2(106) 3
Vd v
4 5 6
8
107 2(107)
ε = 0.000,001 d
3
4 5 6
0.000,01 108
8
ε = 0.000,005 d
4.2 Flow
0.008
d
0.08
5 8 10
8000 4000 6000 10,000
Relative roughness
0.09
4
2000
FIGURE 4.3 Moody Diagram.4
185
Reproduced with permission from ASME.
186
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
calculated, and multiplying this value by the total length produces the total pressure drop for the entire length. When two or more products of different densities and viscosities are transmitted in the pipeline, the weighted average of the densities and viscosities are first calculated. The weighted average values are then used in Eqn. 4.13 to calculate the pressure drop.
4.2.1b Single phase gas The downstream pressure of a single gas pipeline, P2 (psi), is calculated as: !0:5 Ub 2 $Pb 2 $Zave $Tave $SGgas $L 2 . DPE Pd ¼ P u CSPG 2 $Tb 2 $1 f $di5
(Eqn. 4.14)
where Pd is the downstream pressure (psi), Pu is the upstream pressure (psi), Ub is the gas flow rate at base conditions (SCF/d), Pb is the pressure under base conditions (14.7 psi), Zave is the average compressibility factor (dimensionless (see section 4.2.1b.i)), Tave is the average temperature ( R), SGgas is the gas gravity (dimensionless), L is the length of the pipe (miles), CSPG is a constant 38.774, Tb is the temperature at base condition (520 R), 1/f is the transmission factor (dimensionless (see section 4.2.1b.iii)), di is the inner pipe diameter (inches), and DPE is the difference in pressure due to elevation change (see section 4.2.1b.ii).
i. Calculation of Zave Gases are compressible. Therefore the calculation of a pressure drop in the gas phase includes a correction for the compressibility. For an ideal gas, the molecules can be treated as point particles with no interaction between them. For an ideal gas, the relationship between pressure, volume, and temperature is given as: PV ¼ nRT
(Eqn. 4.15)
where P is the pressure, V is the volume, n is the number of moles, R is the constant, and T is the temperature. Under standard pressure and temperature conditions most of the real gases follow Eqn. 4.15, but not at higher pressure and higher temperature. At higher pressures, the gas molecules frequently collide with one another as well as with the walls of the container, and at higher temperatures the molecules move faster. As a consequence, under high pressure and high temperature the molecules interact (attract or repel each other). This behavior can be accounted for by the compressibility factor, Zgas: Zgas ¼
PV nRT
(Eqn. 4.16)
The value of Zgas generally increases with pressure and decreases with temperature. Figures 4.4 and 4.5 present typical values of Zgas for some commonly used gases.6,7 The value of Zgas is a function of the reduced pressure, Pr and the reduced temperature Tr. The reduced pressure is the ratio of the actual pressure to the critical pressure, Pcrit. Similarly, the reduced temperature is the ratio of the actual temperature to the critical temperature, Tcrit. The critical pressure is the minimum pressure required to compress a gas into liquid at its critical temperature, and the critical temperature is the temperature beyond which a gas cannot be compressed into a liquid. Figure 4.6 presents a commonly used graph to
4.2 Flow
187
Pseudo reduced pressure 1
0
2
3
1.1
4
5
6
7
Pseudo reduced temperature 3.0 2.8 2.6 2.4 2.2 2.0 1.9 1.8
1.0
0.9
8 1.1 1.05 1.0 1.2 0.95
1.5
1.7
1.1
1.4 05 1. 1 1.
1.6 0.8
1.3
1.5
1.7
1.45
1.35
1.6 3
1.
1.3 4
0.6
1.
1.25
1.5 1.6 1.7
1.2 0.5
1.8 1.9 2.0 2.2
5
1.1 0.4
2.4
1.1
1.5
1.4
Compressibility factor Z
Compressibility factor Z
2
1.
1.4
0.7
1.3
2.6 3.0
0.3
1.2
5
1.0
0.25 2.8
1.1
3.0
1.1
2.6 2.4 2.2 2.0 1.9 1.8
1.0
1.1 1.05
1.2
1.0 January 1, 1941
1.7 1.6
0.9
1.4 1.3
7
8
9
10
11
12
13
14
0.9 15
Pseudo reduced pressure
FIGURE 4.4 Compressibility Factors for Natural Gases.6 Reproduced with permission from McGraw-Hill.
correlate Zgas with Pr and Tr.8 Table 4.2 presents critical temperatures and pressures of some hydrocarbons.9 The average compressibility factor, Zave is then calculated from the percentages of various gases and their respective compressibility factors (Table 4.2): Zave ¼
Pave :V nR:Tave
(Eqn. 4.17)
188
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
0.9
0.8
Z
0.7
0.6 800 psia 1150 psia 1350 psia 1675 psia 2140 psia
0.5
0.4
0
5
10
15
20
25
30
35
40
Ethane, mole %
FIGURE 4.5 Compressibility Factors for Mixed Gases.7 Reproduced with permission from NOVA Chemicals.
where Pave is the average pressure and Tave is the average temperature, which are calculated using Eqns. 4.18 and 4.19 respectively: Pave ¼ Pca :Ya þ Pcb :Yb þ Pcc :Yc þ :::
(Eqn. 4.18)
Tave ¼ Tca :Ya þ Tcb :Yb þ Tcc :Yc þ :::
(Eqn. 4.19)
where Ya, Yb, etc. are the percentages of gases and Pca , Pcb, etc. and Tca, Tcb, etc. are the critical pressures and critical temperatures of the corresponding gases, respectively.
ii. Calculation of potential energy Potential energy, DPE,G, i.e., the pressure drop due to elevation change in single phase gas flow, is calculated as: 0:0375SGgas $ Hd Hu $P2ave DPE;G ¼ (Eqn. 4.20) Tave $Zave where SGgas is the gas gravity (dimensionless); Hd is the downstream elevation (ft); Hu is the upstream elevation (ft); Pave is the average pressure (psi); Tave is the average temperature ( R); and Zave is the average compressibility factor. Alternatively some constant values of DPE are assumed. Some commonly used approximate values of DPE are:10 1 for new pipe with no bends, fittings, or pipe diameter changes; 0.95 for very good operating conditions, typically for the first 12–28 months; 0.92 for average operating conditions; and 0.85 for unfavorable operating conditions.
4.2 Flow
189
1.125 ture, Tr
Reduced Tempera
4 3 2.6 2.2 2.1 2.0 1.9 1.8 1.7 1.6
1.000
1.55 1.50 1.45
0.750
1.40
5 1.3 0 1.3 5 1.2 0 1.2 5 1.1
0.625
1. 1. 00 05
Supercompressibility Factor, Z
0.875
0.500
P Reduced Pressure, Pr = — Pc
0.375
T Reduced Temperature, Tr = — Tc 0.250
0.125 1
2
3
4
5
6
7
8
9
Reduced Pressure, Pr
FIGURE 4.6 Correlation between Compressibility Factors and Critical Pressure and Critical Temperature.8 Reproduced with permission from Taylor & Francis.
iii. Calculation of transmission factor Table 4.3 presents four common methods for calculating transmission factors. The Weymouth method is used for high flow-rate, large diameter, and high pressure pipelines; the Panhandle A method is used for medium to relatively large diameter pipeline with moderate flow rate, operating under medium to high pressure; the Panhandle B method is used for high flow rate, large diameter (i.e. larger than NPS 24), high pressure pipelines; and the American Gas Association (AGA) Fully Turbulent method is used for high pressure, high flow rate, medium to large diameter pipelines.
4.2.1c Two-phase liquid-gas In two-phase liquid-gas flow, the volume occupied by the gas is physically negligible due to its compressibility. Therefore, the two-phase liquid-gas calculation is only used when the gas flow rate is greater than 3,500,00 ft3/d(w100,000 m3/d). Below this gas production rate, either the single phase liquid (see section 4.2.1a) or single phase gas calculation (see section 4.2.1b) is used depending on the production rates of liquid and gas. Several methods can be used to calculate the pressure drop in a two-phase liquid-gas flow. Only the simple approach is described in this section. In this approach the pressure drop in a
190
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Table 4.2 Critical Properties of Certain Gases9
Gas Methane Ethane Propane Isobutane n-butane Hydrogen n-pentane n-hexane n-heptane n-ocatane n-nonane n-c10 n-c11 n-c12 Air Nitrogen Oxygen CO2 H2S He
Molecular Weight (lbm/mole) 16.04 30.07 44.09 58.12 58.12 2.02 72.15 86.18 100.21 114.23 128.26 142.29 156.30 170.34 29 28.02 32.0 44.01 34.08 4.00
Critical Temperature, Tcri ( R)
K
343.3 549.8 666.0 734.7 765.3 60 845.6 913 972 1,024 1,070 1,112 1,150 1,185 238.4 226.9 277.0 547.7 672 9
Critical Pressure, Pcrit MPa
Psi
191 305 370 408 425
4.6 4.88 4.25 3.65 3.8
470 507 540 569 595 618 639 658 132 126 155 304 373 5
3.37 3.01 2.74 2.49 2.29 2.10 1.97 1.82 3.77 3.4 5.04 7.38 8.96 0.23
673.1 708.3 617.4 529.1 550.7 189.0 489.5 437 397 361 332 305 285 264 547.0 492.0 730.0 1073.0 1,300 33
Table 4.3 Transmission Factors Transmission Factor
Formulae
Weymouth
pffiffiffiffiffiffiffi 1=6 1=f ¼ 11:19di pffiffiffiffiffiffiffi Ug SGgas 0:07305 1=f ¼ 7:211 di Where Ug is the flow rate of gas (ft3/h)
Panhandle A
Panhandle B
pffiffiffiffiffiffiffi Ug SGgas 0:01961 1=f ¼ 16:70 di
AGA fully turbulent
pffiffiffiffiffiffiffi 3:7di 1=f ¼ 4log Ke Where Ke is the effective roughness (in.)
Compressibility Factor, Zgas 0.290 0.285 0.277 0.283 0.274 0.304 0.269
e 0.291 0.292 0.274
4.2 Flow
191
two-phase liquid-gas flow (DPLG) can be determined based on the pressure drop in a single phase gas flow as:11 DPLG ¼ DPG 42
(Eqn. 4.21)
where 4 is the two-phase flow modulus. The values of 4 depend on Lockhart-Martinelli two-phase modulus XLM, which is defined as: vffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi !0:2ffi u 1:8 u U r h g l XLM ¼ t $ l $ (Eqn. 4.22) Ug rl hg where Ul is the liquid flow rate (lb/h), Ug is the gas flow rate (lb/h), rg is the gas density (lb/ft3), rl is the liquid density (lb/ft3), hl is the viscosity of liquid (centipoise), and hg is the viscosity of gas (centipoise). The relationship between 4 and XLM depends on the flow regime. For annular, annular mist, and wispy flow (see section 4.2.2 for flow regimes): 0:3430:021di 4 ¼ 4:8 0:3125di XLM
(Eqn. 4.23)
where di is inner pipe diameter in inches. For bubble flow: 14:2X 0:75 4 ¼ . LM 0:1 Ul A
(Eqn. 4.24)
where A is the cross sectional surface area of the pipe (ft2). For plug flow: 27315X 0:855 4 ¼ . LM 0:17 Ul A
(Eqn. 4.25)
1190X 0:815 4 ¼ . LM 0:5 Ul A
(Eqn. 4.26)
15400XLM 4 ¼ . 0:3 Ul A
(Eqn. 4.27)
For slug, churn, and oscillator flows:
For stratified flow:
For dispersed flow: 4 3 2 42 ¼ 0:00003:XLM þ 0:0048:XLM 0:2415:XLM þ 7:6125:XLM þ 6:5734
(Eqn. 4.28)
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.2.1d Two-phase liquid-liquid When two immiscible liquids, e.g., oil and water, are transported, the pressure drop is calculated as per section 4.2.1a, except that the mixed viscosity is used in Eqns. 4.6 and 4.10. The mixed viscosity is calculated as: Vo :ho þ Vw :hw hl ¼ (Eqn. 4.29) V o þ VW where hl is the viscosity of liquid, ho and hw are viscosities of oil and of water respectively, and Vo and Vw are the volumes of oil and water respectively.
4.2.1e Two-phase liquid-solid The solid content in most of the oil and gas industry infrastructure, except hydrotransport pipelines, is relatively low. Therefore the effect of solid on the pressure drop may conveniently be neglected. The head loss due to slurry flow in hydrotransport pipelines compared with water flow at the same flow velocity is expressed as:12 ! DPsolid DPL fdi rs ¼f : 1 (Eqn. 4.30) ½SolidDPL Ul2 rl where DPSolid is the pressure drop in the liquid containing solids (e.g., hydrotransport pipeline); DPL is the pressure drop in liquid flow (see section 4.2.1a); [Solid] concentration of solids; f is the friction factor; di is the internal diameter of pipe; Ul is the liquid flow rate; rs is the density of solids; and rl is the density of liquid.
4.2.1f Two-phase gas-solid The solids present in a gaseous flow may include corrosion products, e.g., iron sulfides, sands, debris, and other impurities. The solid content in gas pipelines is relatively low in most cases, and hence its effect on the pressure drop may conveniently be neglected. The pressure drop in gas-solid flow is therefore calculated using the equations presented in section 4.2.1b.
4.2.1g Three-phase liquid-liquid-gas Multiphase pipelines may transport oil, water, and gas. Very little information is available on threephase flow. The pressure drop in three-phase liquid-liquid-gas flow can be calculated by considering oil and water as one phase, and calculating the viscosity of this phase using Eqn. 4.29. With this consideration, the two-phase liquid-gas equation (see section 4.2.1c) is used to calculate the pressure drop in three-phase flow.
4.2.1h Series pipeline The pressure drop of a pipeline in series with different diameters (Figure 4.7)13 can be calculated by calculating the pressure drop in adjacent sections individually as: nPD P21;S P22;S ¼ k1;S Ub;S
(Eqn. 4.31)
nPD P22;S P23;S ¼ k2;S Ub;S
(Eqn. 4.32)
nPD P23;S P24;S ¼ k3;S Ub;S
(Eqn. 4.33)
4.2 Flow
k1,S Ub
P1
k2,S Ub
P2
193
k3,S Ub
P3
P4
FIGURE 4.7 Pipeline in Series.13
Then the pressure drop across the entire section is given as: nPD nPD P21;S P24;S ¼ kT;S Ub;S ¼ k1;S þ k2;S þ k3;S :Ub;S kS ¼ RPD :L
(Eqn. 4.34) (Eqn. 4.35)
where P1,S, P2,S, P3,S and P4,S are respectively the pressure drops at segments 1, 2, 3, and 4 of pipeline in series; k1,S, k2,S, k3,S and kT,S are the pipeline resistance in segments 1, 2, 3, and total respectively; RPD is the resistance per foot of pipeline; L is the length of pipeline in feet; Ub is the gas flow rate at base conditions; and nPD is the flow exponent (value ranges between 1.74 and 2.00). Equation 4.36 presents a simple equation to calculate RPD; several more complicated and more accurate equations are also available:13 Tf RPD ¼ 4:82 104 5 $SG0:855 (Eqn. 4.36) g di where Tf is the temperature constant and is equal to 520 R and SGg is specific gravity of gas.
4.2.1i Parallel pipelines Flow in the pipeline is diverted into two parallel lines (i.e., looped pipeline) to reduce resistance to flow. Figure 4.8 presents an example of looped pipeline.14 The pressure drop in each segment can be calculated as: nPD P21;P P22;P ¼ k1;P Ub1
(Eqn. 4.37)
nPD P21;P P22;P ¼ k2;P Ub2
(Eqn. 4.38)
k1;P :k2;P nPD kT;P ¼ 1=nPD 1=n k1;P þ k2;P PD
(Eqn. 4.39)
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Ub,1 K1 P P1,P P2,P
Ub
Ub
K2 P
Ub,2
FIGURE 4.8 Pipeline in Parallel.14
where P1,P and P2,P are the pressure drops in parallel pipeline segments 1 and 2 respectively; k1,P, k2,P, and kT,P are the pipeline resistance in segments 1, 2, and total respectively; Ub is the gas flow rate at base conditions; and nPD is the flow exponent (value ranges between 1.74 and 2.00). By calculating the resistance to flow in individual segments using Eqn. 4.35, the total resistance (kT,P) in the entire loop is calculated. Then the pressure drop at the exit point of the looped segment can be calculated.
4.2.1j Expansion of cross-section15 If the cross-section of a pipe is suddenly enlarged, the fluid stream separates from the wall and flows as a jet into the enlarged section. The fluid then expands to fill the entire cross-section of the larger conduit (Figure 4.9). Considerable friction is generated in the space between the expanding jet (smaller pipe) and the larger pipe completely filled with fluid. The pressure drop from a sudden expansion of cross-section is given as: 2 dup;Ex 2 2 Uup;Ex (Eqn. 4.40) PEx ¼ 1 ddown;Ex 2g where PEx is the pressure drop at pipeline expansion, ft; dup,Ex is the diameter of pipeline upstream to expansion; ddown,Ex is the diameter of pipeline downstream to expansion; Uup,Ex is the flow velocity in
Va
Sa
Vb
Sb
Direction of flow
FIGURE 4.9 Pipeline with Sudden Expansion.15 Reproduced with permission from Taylor & Francis.
4.2 Flow
195
the smaller (upstream) pipeline segment before expansion, ft/s; and g is the acceleration of gravity (32.2 ft/s2).
4.2.1k Contraction of cross-section15 When the cross-section of the pipe is suddenly reduced, the fluid jet expands downstream from the point of contraction and then establishes a normal velocity distribution. The pressure drop from the sudden contraction may be given as: 2 ddown;Con Udown;Con (Eqn. 4.41) PCon ¼ 0:4 1 dup:Con 2g where Pcon is the pressure drop at pipeline contraction, ft, ddown,Con is the diameter of pipeline downstream of the contraction; dup,Con is the diameter of pipeline upstream to contraction; Udown, Con is the velocity in the smaller (downstream) pipe, ft/s; and g is the acceleration of gravity (32.2 ft/s2). It is important to note that the pressure drop depends on the velocity in the smaller pipe: at expansion it is proportional to the upstream flow, and at contraction it is proportional to the downstream flow. These calculations (discussed in sections 4.2.1j and 4.2.1k) are applicable to turbulent liquid flow only, but not to laminar (the effect of expansion or contraction is negligible) or gaseous flow.
4.2.1l Accessories Valves and fittings also contribute to overall pressure loss. When the ratio of pipeline length to pipe diameter is equal or greater than 1,000 to 1 (e.g., transmission pipelines) with a standard number of fittings and valves, the effect of pressure drop through valves and fittings may be considered as negligible. But in a pumping station, refinery piping, and process piping, where many valves exist over relatively short distances, pressure loss due to valves and fittings is important. Obtaining the pressure drop of every size and type of valve and pipe fitting is difficult. a practical approach is to use the equivalent length method, in which the pressure drop through a valve, fitting, miter elbow, or any component is assumed to be equivalent to the pressure drop of an equivalent length of straight, round pipe. Table 4.4 presents the equivalent length values; it should be noted that these values apply only to single phase, non-compressible liquids in turbulent flow in steel and iron pipe.
Table 4.4 Head Loss in Terms of Equivalent Length (L)16 Type of Bend
Radius
U-bend Z-bend U-bend Z-bend
Short Short Long Long
L/di Ratio 30 30 20 20
Equation Lequivalent Lequivalent Lequivalent Lequivalent
¼ ¼ ¼ ¼
2Haccessories 2Haccessories 2Haccessories 2Haccessories
þ116 di þ 174 di þ 74 di þ 111 di
where Lequivalent is the equivalent length of accessories to calculate pressure drop; Haccessories is the height (or, if horizontal, the width) of the loop, feet; and di is the internal diameter of pipe in feet. These equivalent lengths are based on Lequivalent /di ratio of 30 for short-radius elbows and 20 for long-radius elbows
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.2.1m Annular space17 Sometimes the fluids are transported in the annular space between the pipelines, typically between tubing and casing (see Chapter 2). The pressure drop of flow in the annular space may be calculated as follows: For laminar flow: 0:1 di;casing 6 7:95 10 hl LUl d 2 i;casing do;tubing PAnn:Lam ¼ (Eqn. 4.42) 2 di;casing do;tubing di;casing 2 do;tubing 2 1þ 1:5eecc 2 For turbulent flow: PAnn:Tur ¼
11:46 106 SGl :f :Ul2 L 2 di;casing ðdi;casing do;tubing Þ di;casing 2 do;tubing 2 d d i;casing
o;tubing
0:1 2
1þ 1:5eecc 2
0:25
(Eqn. 4.43) where PAnn.Lam is the pressure drop, psi of laminar flow in the annular space; PAnn.Tur is the pressure drop, psi of turbulent flow in the annular space; hl is the viscosity of liquid, cp; L is the length of annulus, ft; Ul is the flow rate, barrel per day; di,casing is the internal diameter of the casing, in.; do,tubing is the outer diameter of the tubing, in.; eecc is the eccentricity of tubes (defined in Eqn. 4.44); SGl is the specific gravity of liquid; and f is the friction factor. Eccentricity of tube, eecc is defined as: 2:dtube:off (Eqn. 4.44) eecc ¼ di;casing do;tubing where dtub.off is the distance tubing is off the center, in.
4.2.1n Transient flow Normally transmission pipelines operate under steady-state conditions when supply and demand are stable. However such ideal situations seldom occur. The flow rate in the pipelines fluctuates on a daily, weekly, monthly, and annual basis. In addition to seasonal variations, large variations in the flow rate may occur during commissioning, during normal operation (e.g., air purging and loading of pipeline and pigging operations) and abnormal operation (e.g., failure of a component). The duration of a transient flow situation and the extent of deviation from steady-state conditions should be analyzed to determine appropriate corrosion factors.
4.2.2 Flow regimes Most of the flow in the oil and gas pipelines involves two or more phases. The two-phase flows may be liquid-gas, liquid-liquid, liquid-solid, or gas-solid. Because the physical properties (density and viscosity) of the phases involved are different, their rates of flow are different. Consequently, multiphase flow can take an infinite number of patterns. Fortunately these patterns can be delineated on the basis of the interfacial distribution between various phases. The delineated patterns are commonly known as flow regimes. The flow regime depends on the position of the pipe (i.e., vertical, inclined, or horizontal), flow rate, flow directions (i.e., upward or downward), and fluid properties (density and viscosity).
4.2 Flow
197
Baker parameter, Bx 105
10–1
1
10
102
103
104
Dispersed
Baker parameter, By
Wave
Bubble or froth
Annular
104
Slug Stratified 103
Plug 102
FIGURE 4.10 Baker Flow Regime Map.18 Reproduced with permission from Taylor & Francis.
4.2.2a Two-phase liquid-gas The flow regime map for gas-liquid flow in a horizontal pipe was first developed by Baker in 1954. Although various other flow regime maps have been developed, the Baker flow regime (Figure 4.10) is still widely used in the oil and gas industry. A Baker flow regime map uses two empirically developed parameters lGLflow and jGLflow defined as:18,19 r r 1=2 g l lGLflow ¼ (Eqn. 4.45) 1:2 1000 " #1=3 0:073 hl 1000 2 (Eqn. 4.46) jGLflow ¼ 103 g rl where rg is the gas density; rl is the liquid density; hl is the liquid viscosity; and g is the surface tension.
i. Vertical upward flow regimes Figures 4.11, 4.12, and 4.13 present flow regimes of vertical upward flow, inclined upward flow (inclination angle up to 10 ), and inclined upward flow (inclination angle between 10 and 45 ) respectively. Common flow regimes of vertical flow are described in the following paragraphs.20–22
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
104
Annular Wispy Annular
PG(UG)2 kg m-1 s-2
103
102 Churn Bubble Flow with Developing Structure 10 Plug 1
0.1 1
10
10 10 PL(UL)2 kg m-1 s-2
10
10
FIGURE 4.11 Vertical Upward Flow Regimes.20 Reproduced with permission from Taylor & Francis.
FIGURE 4.12 Inclined Upward Flow Regimes (Inclination Angle up to 10 ).21 (DB Dispersed bubble flow and A is the annular flow). Reproduced with permission from Taylor & Francis.
4.2 Flow
199
FIGURE 4.13 Inclined Upward Flow Regimes (Inclination Angle between 10 and 45 ).22 Reproduced with permission from Taylor & Francis.
Churn flow: This flow occurs at low liquid and gas velocity in which the liquid moves upward and downward creating large bubbles of gas phase surrounded by liquid phase. With increasing flow velocity the bubbles break down leading to an unstable flow regime. Plug flow: At higher liquid flow rates, the bubbles coalesce and eventually the bubble diameter approaches that of the pipe. When this occurs, large, characteristically bullet-shaped bubbles are formed, which may be separated by regions containing dispersions of smaller bubbles. Typically this liquid phase flows down the outside of the large bubbles in the form of a falling liquid film, but because of higher fluid velocity the net flow of both liquid and gas is upwards. In plug flow, falling films may exist if the gas velocity is relatively low. As the gas flow increases, the flow undergoes a series of changes from falling to flooding, upward-downward and finally to upward. On the other hand, when the gas flow decreases the liquid begins to creep and this process is normally known as creeping. Bubble flow: At higher liquid flow conditions (higher than the plug flow) the liquid phase is continuous and a dispersion of bubbles flows within the liquid continuum. In bubble flow, the bubbles undergo random motions which pass through the channel, and from time to time, bubbles coalesce to form larger ones, leading to plug flow. The collision frequency increases with increasing void fraction. As a rule of thumb, a 30% void fraction may be taken as the limit of bubble flow. Bubble flow may exist at higher void fraction in the presence of contaminants that prevent coalescence or at very high flow velocities that prevent the growth of bubbles. Annular flow: At high gas flow rate and relatively small volume of liquid flow, the liquid flows on the wall of the pipe as a film, and the gas phase flows in the center. Usually some liquid is entrained as small droplets in the gas core.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Wispy annular flow: Under annular flow conditions, if the liquid flow rate increases, the concentration of liquid droplets in the gas core increases. Ultimately the liquid droplets coalesce in the gas core in the center to large lumps or streaks (wisps) of liquid. Froth flow: Some authors describe froth flow regimes as being an emulsion-type flow without noticeable structure. However, high-speed analysis of this flow regime indicates that it is indeed bubble to annular flow, depending on the gas flow rate.
ii. Vertical downward flow regimes Figures 4.14 and 4.15 present the flow regimes of vertical downward and inclined downward flow (inclination angle up to 10 ), respectively. Vertical downward flow regimes are different from those for upward flow. Not much work has been done for this flow regime. The main characteristic of flow is the dominance of the annular flow regime. It should be noted that annular flow can, in effect, occur at zero gas flow in the form of a falling film on the wall.23,24
iii. Horizontal flow regimes Figure 4.16 presents the flow regimes of horizontal flow.25 These are more complex than those in vertical flow, mainly because of the asymmetry in the flow caused by gravitational force. This acts
FIGURE 4.14 Vertical Downward Flow Regimes.23 Reproduced with permission from Taylor & Francis.
4.2 Flow
201
FIGURE 4.15 Inclined Downward Flow Regimes (Inclination Angle up to 10 ).24 (DB is dispersed bubble, S is stratified, and A is annular). Reproduced with permission from Taylor & Francis.
FIGURE 4.16 Horizontal Flow Regimes.25 Reproduced with permission from Taylor & Francis.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
normal to the direction of horizontal flow, whereas as it acts parallel to flow in vertical flow. As a consequence, the heavier phase tends to accumulate at the bottom of the pipe in horizontal flow. Stratified flow: When the flow rates are small, the gravitational force separates the two phases completely. As a result the liquid flows at the bottom and the gas flows at the top of the pipe. Stratified-wavy flow: As the gas velocity increases in stratified flow, waves are formed at the gasliquid interface, producing the stratified-wavy or wavy flow regime. Annular-annular mist (dispersed) flow: This pattern is similar to that of vertical flow and occurs at very high gas flow rates. However the film thickness is non-uniform, with the film at the bottom of the pipe being thicker than that on the top of the pipe. Further, most of the liquid may be entrained in the gas core. Bubble flow: Characteristic bullet-shaped bubbles are formed which normally move near the top of the pipe. In some flow regime descriptions, this flow pattern may be identified as plug flow. Slug flow: At relatively moderate gas and liquid flow rates, slugs are intermittently created. The slug contains continuous liquid phase but with large amounts of entrained gas bubbles. The presence of slugs produces sudden pressure pulses causing vibrations in the pipe. Dispersed flow: At high liquid flow rates the bubbles are dispersed in a liquid continuum. The bubbles tend to congregate near the top of the pipe. At high liquid velocities the bubbles may be more uniformly distributed and may appear as froth.
4.2.2b Two-phase liquid-liquid Liquid-liquid flow occurs in the oil and gas industry when oil and water are transported simultaneously. The oil and water may flow either in the emulsion (oil-in-water or water-in-oil) form or in the stratified form. Due to their non-ionic nature, hydrocarbons cannot dissolve ionic water. However at low water concentrations, hydrocarbons can form an emulsion with the water. The type of emulsion and its stability depends on the type of hydrocarbon, presence of surfactants (e.g., corrosion inhibitors), the ionic content of the water, as well as the pressure, temperature, and flow rate (see section 4.3 for more information on emulsions). At high concentrations of water, oil and water exist as two distinct phases and different flow regimes can exist under these conditions. Figures 4.17 and 4.18 present typical flow regimes of oil and water mixture in horizontal pipe and Figure 4.19 presents typical flow regimes in vertical pipe.26–28 Typically, the density of oil is less than that of water, and as a result stratification occurs (Figure 4.18). When the density of oil (e.g., heavy oil) is similar to that of water the oil moves as a central core with water flowing in the annulus space (Figure 4.17).
4.2.2c Two-phase liquid-solid Liquid-solid flow occurs mainly in hydrotransport pipelines (see section 2.12), but it can also occur in liquid pipelines containing corrosion products and scales. Liquid-solid flow may exist in different flow regimes depending on the flow rate, particle size, and density difference between the solid and liquid (Figure 4.20).29 Below a minimum flow velocity in a horizontal pipeline (or below critical angles in inclined pipelines), solid particles in the fluid can form a bed on the bottom of the line. As the sand is produced, a sand bed will build up until the increased velocity above the bed is large enough to transport the particles further down the pipeline, where the particles settle again, resulting in an increase in the length of the sand bed. Deposition of the solids can lead to partial or complete blockage of flowlines,
4.2 Flow
Flow pattern
203
Superficial oil velocity V0 (ft s-1) 1.95
Water drops in oil 1.11 Oil in water concentric 0.682 Oil slugs in water 0.200 Oil globules in water Superficial water velocity
Vw = 0.682 ft s-1
FIGURE 4.17 Flow Regimes of Oil and Water Mixture in a Horizontal Pipeline. (Densities of Oil and Water are almost Same).26 Reproduced with permission from Taylor & Francis.
0.491 Stratified 0.290 0.149
0.043 Oil globules in water Superficial water velocity Vw = 0.287 ft s-1 Superficial oil velocity ft/s
FIGURE 4.18 Flow Regimes of Oil and Water Mixture in a Horizontal Pipeline. (Densities of Oil and Water are Different).27 Reproduced with permission from Taylor & Francis.
underdeposit corrosion, microbiologically influenced corrosion (caused by sessile bacteria), and trapping of pigs. In sour media, the presence of solid sulfur enhances corrosion. As the flow rate increases, the sand may move in dune patterns. In a moving dunes pattern the sand will move along the pipeline at low velocities. All particles will be transported through the pipe under these conditions. As the flow rate further increases, the pattern changes to scouring. In a scouring
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Superficial oil velocity V0 (ft s-1) 0.015
0.06
0.18
0.55 1.2
3.0
9.0
Superficial water velocity Vw = 0.1 ft s-1
FIGURE 4.19 Flow Regimes of Oil and Water Mixture in a Vertical Pipeline.28 Reproduced with permission from Taylor & Francis.
FIGURE 4.20 Flow regimes of Liquid-Solid Flow.
pattern, the particles will move at the liquid velocity close to the pipe wall. At a sufficiently high velocity, a dispersed pattern will be established, in which the sand particles will move at the velocity of the bulk liquid phase. The transition between the various regimes is somewhat gradual with no sharp boundary. Depending on service conditions, any of the transitions between these regimes may be critical. For oil transportation, the transition between scouring and moving dunes may be critical. The flow velocity at this transition point will be lower than the velocity required to keep the sand suspended in oil but high enough to transport the sand through the pipeline. This flow velocity is often known as the critical velocity, Ucrit,SM and it is calculated using a general formula: Ucrit:SM ¼ a:Vsand dsand DDos di
(Eqn. 4.47)
where a is a constant, Vsand is the solid volume; dp diameter of solid or sand particles; DDo–s difference in density between oil and solid phases; and di is the pipe internal diameter.
4.2 Flow
205
4.2.2d Two-phase gas-solid When gas is used as a conveying medium then the process is known as a pneumatic process. Gassolid flow occurs either in suspended or non-suspended forms. Suspended flow occurs when the volume of solid is small and when the velocity of gas is high. Non-suspended flow occurs when the volume of solid is larger and when the velocity of gas is low. Pneumatic conveying of solids is frequently used to transport coal and minerals, grains, foodstuffs, chemicals, and plastics, but is not a common method of transportation in the oil and gas industry. Gas-solid flow may occur in a gas pipeline containing corrosion products, frequently iron sulfide black powders. However, such a solid is assumed to have little effect on the gas flow due to the relatively small percentages occuring in most conditions.
4.2.3 Water accumulation Internal corrosion occurs in oil and gas infrastructure only when water accumulates on metallic surfaces. Many oil and gas infrastructures, e.g., oil transmission and gas transmission pipelines operate under conditions of extremely low water content (typically less than 0.5% by weight). Determining the locations where water may accumulate in those infrastructures is critical. The accumulation of water depends on oil, water, and gas characteristics, the inclination of the pipe, the flow velocity, and the cleanliness of the pipeline. Several methodologies and rules of thumb are available to determine the likelihood of water accumulation, leading to the establishment of corrosion conditions. Every methodology has its advantages and limitations, therefore in using a particular methodology, its characteristics and limitations should be understood. Some methodologies are described in this section. In order to predict the locations of water accumulation, three broad categories are established: single phase oil, single phase gas, and multi phase. Flow is considered as single phase oil when 95% of the products it transmits are oil, i.e.: P:R:oil > 0:95 (Eqn. 4.48) P:R:oil þ P:R:water þ P:R:gas The flow is considered as a single phase gas when the water content is less than 7 mmscf and the gas to liquid production rate ratio is higher than 5,000, i.e.: P:R:gas > 5; 000 (Eqn. 4.49) P:R:oil þ P:R:water where P.R.gas, P.R.oil, and P.R.water are the production rates of gas, oil, and water, respectively. The flow is considered to be multiphase when it does not meet the conditions of Eqns. 4.48 or 4.49.
4.2.3a Single phase oil Based on field experience, it is commonly assumed that if the oil flow rate is higher than 1 m/s and if the water content is less than 20% water does not accumulate.30,31 Field experience has also indicated that water accumulation depends on the nature of the oil, and in some cases an 0.5 m/s oil flow rate is sufficient to avoid any accumulation of water. A parameter known as the Froude number (Fr) is used to predict the water accumulation tendency in a single phase oil pipeline. Several definitions of the
206
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Froude number are available, and most of them for single phase flow takes the form presented in Eqn. 4.50:32–37 Fr ¼
Doil VL DDow gdpipe
(Eqn. 4.50)
where Fr is the Froude number, Doil is the density of oil, DDo-w is the density difference between oil and water, g is the acceleration due to gravity, dpipe is the hydraulic diameter of pipe, and VL is the velocity of the liquid. In most situations, the critical Froude number for water accumulation is assumed to be approximately 0.65; above this value, water does not accumulate and below this value water is likely to accumulate. The critical Froude number is found to be inversely proportional to the inclination angle of the pipeline.38 Standards providing guidelines for calculating the accumulation of water in single phase oil pipelines include: •
NACE SP0208, ‘Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines’
4.2.3b Single phase gas In normally dry gas transmission pipelines the flow is single phase. When water accidently enters into the system, it may be carried as droplets in the gas flow, or accumulates in localized regions along the pipeline. To determine the locations where water may accumulate, two parameters are determined: inclination angle of the pipeline based on field topography, and the critical angle above which the flow cannot carry the water through. In the locations of the pipe where the inclination angle is greater than the critical angle water accumulation occurs. The critical angle is determined as:33 !1:091 rg Ug 2 qCA ¼ arcsin 0:675$ $ (Eqn. 4.51) rl rg g$di where qCA is the critical angle; rg is the density of gas (kg/m3); rl is the density of liquid (kg/m3); Ug is the gas flow rate (m/s); g is the acceleration due to gravity (9.81 m/s2); and di is the inner pipe diameter (m). The flow rate of gas (Ug) cannot be calculated directly from the production rate of gas because this is measured at standard temperature and pressure (STP). Hence, the production rate of gas at STP is converted into the production rate of gas at pipeline operating temperatures and pressures, using either the compressibility factor (Zgas) (Eqn. 4.52) or Van der Waal’s real gas equation (Eqn. 4.53). From Eqn. 4.16: Pstp Vstp PV ¼ RTstp ZRT
an2 p þ 2 V nb ¼ RT V
(Eqn. 4.52) (Eqn. 4.53)
4.2 Flow
207
Table 4.5 Comparison of Results Using Compressibility Factor (Z) versus Van der Waal’s Equation39 Parameter Gas Velocity (m/s) Critical Angle, degrees
Result from Compressibility Factor
Result from Van der Waal’s Equation
% Difference between the Two Approaches
6.6 5.9
5.9 4.4
11.8 28.0
The calculations were performed for 100% methane gas using the following values: ll ¼ 1.0 g/cm3, g ¼ 9.81m/s2, di ¼ 0.745 m, P ¼ 35.05 atm, T ¼ 298K, VSTP ¼ 4.13 x 108 L/h, TSTP ¼ 273K, PSTP ¼ 1.000 atm, R ¼ 0.08206 L atm/mol K, AVan ¼ 2.25 L2atm/mol2, bVan ¼ 0.0428 L/mol
where P is the pressure; PSTP is the pressure at STP; V is the volume; VSTP is the volume at STP; TSTP is the temperature at STP; R is the gas constant; and T is the temperature; and aVan and BVan are Van der Waal’s constants. Van der Waal’s equation Eqn. 4.53 is similar to using the compressibility factor, in that it is a modification of the ideal gas law to simulate non-ideal gas behavior. Unlike the compressibility factor method, Van der Waal’s equation contains two constants which change with the gas being simulated, and Van der Waal’s equation is cubic in form, which is better for simulating a non-ideal system. The advantage of using this method is increased accuracy, the disadvantage is the complicated mathematics involved in cubic equations.39 Table 4.5 shows the difference in results obtained by using compressibility factor and Van der Waal’s equation. Standards providing guidelines for calculating the accumulation of water in single phase gas pipelines include: •
NACE SP0206, ‘Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Gas (DG-ICDA)’
4.2.3c Multiphase When two phases are transported in a pipe, the flow velocity is frequently inadequate to uniformly transport both phases at the same rate. As a result, the gas flows faster than the liquid and there is a hold-up of liquid. This means that the volume of liquid in some areas along the pipeline is higher than the normal liquid to gas ratio. The amount of liquid hold-up depends on gravity, the inclination of the pipe, and the flow velocity. Numerous equations and commercial software are available to calculate liquid hold-up.
i. Two-phase The rate of deposition of liquid from the gas phase may be calculated as:40 mD ¼ kd $Cw
(Eqn. 4.54)
where mD is the rate of deposition (mass per unit peripheral area per unit time); kd is the deposition mass transfer coefficient; and Cw is the concentration of droplets in the gas core (mass per unit volume calculated on a homogeneous basis).
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
The value of kd is calculated as: kd ¼
Vc) :87
sffiffiffiffiffiffiffiffiffiffiffi h2l DsrL
(Eqn. 4.55)
where VC) is the core friction velocity (defined in Eqn. 4.56); hl is the liquid phase viscosity; di is the internal diameter of pipe, m; s is the surface tension kg/s2; and rl is the liquid phase density (kg/m3). rffiffiffiffiffi si (Eqn. 4.56) VC) ¼ rg where si is the interfacial shear stress in the absence of interface mass transfer, N/m2 and rg is the gas density, kg/m3.
ii. Three-phase When oil, water, and gas phases are involved the liquid fraction, l, is first calculated as: l¼
P:R:oil þ P:R:water P:R:oil þ P:R:water þ P:R:gas
(Eqn. 4.57)
where P.R.oil is the oil volumetric flow rate (m3/d); P.R.water is the water volumetric flow rate (m3/d), and P.R.gas is the gas volumetric flow rate (m3/d). Then the modified Froude number for multiphase flow is calculated as: ! ! rl rg g$di $ $sinðqÞ (Eqn. 4.58) Fr ¼ rg Vg 2 where rl is the liquid density (kg/m3); rg is the gas density (kg/m3); g is the gravity constant (9.81 m/s2); di is the inner pipe diameter (m); Vg is the gas flow rate (m/s); and q is the angle of pipe inclination. Based on the liquid fraction (Eqn. 4.57), modified Froude number (Eqn. 4.58), and flow regimes (section 4.2.2) the liquid hold-up (HL) is then calculated using the formulae presented in Table 4.6.41,42 The same calculations may also be used for two-phase flow by deleting the flow rate of oil or water as appropriate from Eqn. 4.57, and replacing the liquid density with the appropriate density of oil or water in Eqn. 4.58.
4.2.4 Effect of flow on corrosion In addition to determining the pressure drop, flow regimes, and locations where corrosion may take place (i.e., where water accumulates), the flow may directly affect corrosion in three ways: mass transfer, momentum transfer, and phase transfer. A complete understanding of the effect of flow on corrosion should also include heat transfer; however heat transfer in most oil and gas infrastructure (production, transmission, and product pipelines) is not sufficient to affect the corrosion. Heat transfer effect may be important in the refinery operating conditions (see section 2.31) and top-of-the line corrosion (see section 5.24).
4.2.4a Mass transfer Flow may influence corrosion by bringing corrosive species (e.g., dissolved oxygen) towards the metal surface or moving corrosion products away from the metal surface. Flow may decrease corrosion rate
4.2 Flow
209
Table 4.6 Liquid Hold-Up Calculation41,42 Pipe Orientation
Flow Regime
Incline
• • • • • • •
Incline
Horizontal
Wave Annular Stratified Annular Mist Annular Wispy Annular Annular Mist
Liquid Hold-up Equation HLð1Þ ¼
0:98$l0:4846 Fr 0:0868
• Slug • Churn, Plug • Oscillatory
HLð2Þ ¼
0:845$l0:5351 Fr 0:0172
• Dispersed • Bubble • Slug
HLð3Þ ¼
1:065$l0:5825 Fr 0:0609
by removing corrosive species from the metal surface; a mass transfer coefficient is used to represent this effect. The mass transfer coefficient is the rate at which the reactants (or products) are transferred to the surface (or removed from it). The mass transfer in various geometries is assumed to be similar if the mass transfer coefficients are equal. The mass transfer coefficient, kcoeff is expressed as:43 Di kcoeff ¼ Sh$ L
(Eqn. 4.59)
where Sh is the Sherwood number (see Eqn. 4.60); Di is the diffusivity of species i, m2/s; and L is characteristic length, e.g., diameter of pipe, m. Sh ¼
0:62048Sc1=3 Re1=2 1 þ 0:2980Sc1=3 þ 0:14514Sc2=3
(Eqn. 4.60)
where Sc is the Schmidt number, dimensionless (see Eqn. 4.61) and Re is the Reynolds number (see Eqn. 4.5) h Sc ¼ (Eqn. 4.61) rDi
4.2.4b Momentum transfer An increase in corrosion due to momentum transfer is commonly known as flow-induced localized corrosion (FILC), and the wall shear stress is used to represent its effect. FILC occurs due to increasing turbulence intensity and mass transfer as a result of flow over a surface and is different from erosioncorrosion (see section 4.2.4c).44 The wall shear stress is a measure of the viscous energy loss within the turbulent boundary layer and is related to the intensity of turbulence in the fluid acting on the wall. Wall shear stress and mass transfer are intimately linked and their individual contributions to flowaccelerated corrosion cannot be delineated either experimentally or mathematically. Changes to flow that affect the mass transfer coefficient will affect the wall shear stress, and vice versa.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Wall shear stress is the force per unit area on the pipe due to fluid friction. The wall shear stress, Wss, in Pascal, can be calculated as: fU 2 r (Eqn. 4.62) 2 where f is the friction factor (dimensionless); U is the flow rate (m/s); and r is the density (kg/m3). Alternatively the wall shear stress may also be determined experimentally as: DP di (Eqn. 4.63) Wss ¼ 4 DLpipe Wss ¼
where DP is the pressure drop over a specific length (DL) of pipe of specific diameter (di).
4.2.4c Phase transfer In the presence of a second phase, flow may affect corrosion in two ways: erosion-corrosion and underdeposit corrosion. The second phase may be gas, liquid, or solid and the primary phase is mostly liquid, but it can also be gas. Under high flow conditions, the flow impinges the second phase (e.g., sand or liquid) on the surface, causing erosion-corrosion (see sections 5.11 and 6.6) or collapses the second phase (e.g., gas) causing cavitation corrosion (see section 5.10):45 Under low flow conditions, the second phase (mostly sand or other solid particles) deposits in localized areas, causing under-deposit corrosion and blocking access of the inhibitor to the surface. These locations are susceptible to localized corrosion in the form of pits. Guidelines to predict critical flow below which solid deposition occurs have been established on the basis of laboratory experiments. In horizontal pipes solid deposition occurs if the flow rate is less than the following value:46 5:305 106 ð314:96di þ 20Þ ðdi =2Þ2
m=s
(Eqn. 4.64)
where di is the internal diameter of pipe in meters. Solid deposition does not occur in pipes inclined downwards. In pipes inclined upwards, solid deposition depends on flow rate, inclination angle, and pipe diameter. For an incline of less than 40 , deposition occurs if the flow rate is less than the following value: 5:305 106 ð314:96di þ 16Þ ðdi =2Þ2
m=s
(Eqn. 4.65)
For an incline of greater than 40 , deposition occurs if the following relationship holds: 2 di þ 8ð39:4di 2Þ < ½ð 0:5qÞ53:3 ½U þ 8ð39:4:di 260000pU 2
(Eqn. 4.66)
where U is flow rate in m/s and q is the angle of inclination in rad. Eqns. 4.64 through 4.66 are only applicable over the range of parameters analyzed in tests.46 The density and size of solids, the density and viscosity of liquids, the pipe diameters evaluated, and the
4.3 Oil phase
211
relative length/diameter of the flow loop used in these investigations influence the solid deposition. Other methodologies for determining locations for solids to deposit are presented in: •
NACE Standard Practice SP0208–08, Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines (LP-ICDA)
These methodologies have been found to be reliable for solid deposition from light oil. However, for heavy oil, it has been found that solids deposit downstream of over-bends.47 A computational fluid dynamics (CFD) study of a representative segment of a transmission pipeline suggests that the main reason for the observed solids deposition downstream of over-bends in pipelines carrying heavy crude oil is that the wall boundary layer is thicker for heavy oil than for light oil. This thicker boundary layer leads to lower near-wall velocities than for the light oil case. This effect is especially pronounced for heavy oils downstream of over-bends, where the boundary layer is even thicker and near-wall velocities even slower. Extremely slow velocity makes the particles susceptible to becoming trapped in existing corrosion pits or stationary solid deposits. Conversely, it was found that, for light oil, even though the particles fall quickly to the pipe floor, the relatively rapid near-wall velocity keeps them moving.48
4.3 Oil phase Crude oils are corrosive at the higher temperatures prevailing in the refinery (see section 3.31), but are non-corrosive at lower temperatures. At lower temperatures, crude oils have low conductivity, i.e., they are poor electrolytes (see section 5.2 for details), preventing electrochemical reactions from occuring.49–53 However at lower temperatures crude oils may influence the corrosivity of an aqueous phase with which they are in contact. The corrosivity of crudes depends on their chemical and physical constituents, emulsion type, wettability, and partition of chemicals between oil and aqueous phase.
4.3.1 Chemical and physical constituents Chemical constituents affect corrosion only at temperatures high enough to liberate them but low enough for water to exist as liquid. Such conditions normally occur in certain parts of the refineries (see section 3.31). On the other hand, constituents such as solids or paraffins may affect the corrosivity of the water phase which is in contact with crude oils at lower temperatures (typically below 158 F (70 C)). The influence of specific chemicals on the corrosivity of crude oils is discussed in this section.
4.3.1a Inorganic salts Analyses of crudes indicate that over 2,000 mg/L (70 LB/100BBL) of inorganic salts can be extracted from corrosive crudes and about 20 times less from non-corrosive crudes.54 The chloride content is usually referred to as total salt. The total salt may sometimes be used as an index of corrosivity. It should be noted that only salts that produce hydrogen chloride [HCl] at high temperatures are corrosive. In general, the total amount of HCl liberated is proportional to the salt content. A direct estimate of HCl provides a measure of the corrosivity of the crudes. Factors affecting the amount of HCl liberated at high temperatures typically occurring in the refinery operation conditions
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
include ratio of calcium (Ca) and magnesium (Mg) to sodium (Na) and pH. If about 10% of chlorides are present in the form of Ca and Mg salts and the pH is alkaline, less HCl is liberated; on the other hand, if the Ca and Mg salts are about 20% and if the brine pH is acidic, the amount of HCl liberated is high.55
4.3.1b Sulfur content It has been known for many years that the greatest single cause of crude oil corrosion at higher temperatures occurring in the refinery operating conditions is the presence of sulfur compounds, but there is no direct correlation between sulfur content and corrosivity.56,57 The controlling factor with respect to corrosion is not the sulfur content, but the degree to which the sulfur compounds decompose to form more corrosive constituents such as H2S and HCl. The sulfur content of crude oil is usually less than 1%.58 The sulfur contents of heavier crudes may be in the range 2.0–3.5%. A McConomy curve is used to predict the corrosivity of crude oil based on its sulfur content. Figure 4.21 presents two versions of the McConomy curve.59 However it should be noted that only those sulfur compounds that liberate H2S at high temperatures are important. The total sulfur of certain crudes may be lower (less than 1%), but the H2S liberated may be higher (typically 60–450 mg/L [20–150 LB/1000 BBL]). Sulfur compounds may provide corrosion protection when stable sulfide layers form on the metal surface.
4.3.1c Organic acids Of the organic acids, naphthenic acid is most important with respect to the corrosivity of crude oil at higher temperatures. Naphthenic acids cause corrosion in vacuum units of refineries operating between 428 and 700 F (220 and 370 C). No corrosion occurs at temperatures above 752 F (400 C) due to the decomposition of naphthenic acids. No corrosion product is formed in the presence of naphthenic acid. In addition to carbon steel, stainless steels (12% Cr, 316 SS, 317 SS, and 6% Mo) are also susceptible to naphthenic acid. One study has indicated that the product of the organic nitrogen and naphthenic acid content is inversely proportional to the corrosion rate of steel at lower temperatures (less than 70 C).60 In addition to naphthenic acid, other organic acids including formic, acetic, and propionic acids may also influence the corrosivity of the crude oils at lower temperatures.61 These acids influence the corrosivity of aqueous phase in contact with crude oil by supplying hydrogen ions which undergo cathodic reactions during the corrosion of metals (see section 5.2): Formic acid : Acetic acid : Propionic acid :
HCOOH/Hþ þ HCOO
(Eqn. 4.67)
CH3 COOH/Hþ þ CH3 COO
(Eqn. 4.68)
(Eqn. 4.69)
CH3 CH2
COOH/Hþ
þ CH3 CH2 COO
4.3.1d Dissolved gases62–66 Oxygen, carbon dioxide and hydrogen sulfide are the main corrosive gases. H2S is more soluble in hydrocarbons than in water. The ratio of the concentration of H2S in hydrocarbon to that in water is 1.7 at 32 C (90 F); 1.67 at 29 C (84 F) for mineral oil; 5.95 at 31 C (88 F) for benzene; 2.4 at 31 C (88 F) in kerosene; and 2.65 at 31 C (88 F) for iso-octane. The saturation concentration of H2S in crude oil is 5,000 ppm, whereas normal concentrations are found to be in the range of 100–200 ppm. The solubility of CO2 and oxygen in hydrocarbons is also higher than they are in water.
4.3 Oil phase
Corrosion rate multiplier
100 50 20 10 5 2 1 0.5
213
Carbon Steel 1 – 3Cr
4 – 6Cr
9Cr
0.2 12Cr 0.1 0.05 18/8 Sulfur content:.0.6wt% 0.02 0.01 450 500 550 600 650 700 750 800 Tempature F
Modified McConomy Curve [1]
Sulfer content, wt%
10 5 2 1 0.5 0.2 0.1 0.05 0.02 0.01 0.4
0.8 1.2 1.6 Corrosion rate multipiler
2.0
Correction curve for sulfur content [1]
FIGURE 4.21 McConomy Curve to Predict the Effect of Sulfur Content in Crude Oils on High-Temperature Corrosion Rate.59
4.3.1e Solids Crudes may contain solids and sediments as finely divided particles of siliceous matter.67 At high velocities the solids may be swept along with the flow while at low velocities they settle at the bottom of the pipe. When they settle, they shield the pipe and facilitate the occurrence of corrosion beneath them (underdeposit corrosion). The extent of corrosion depends on the amount and composition of solids.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.3.1f Paraffin Paraffin is a mixture of aliphatic and aromatic hydrocarbons, asphalts, resins, and naphthenes. Crude oils contain paraffin as suspensions of 1–100 mm (0.04–4 mil). The paraffin layer on the pipe wall protects it, but when the layer entraps water localized corrosion may take place.
4.3.2 Emulsion type Because of their non-polar nature, crude oils cannot dissolve ionic water. However, at low concentrations of water, crude oil can form an emulsion with water. The type of emulsion and its stability depends on the type of crude oil, composition of water, presence of surfactants, operating pressure, temperature, and flow rate. There are two kinds of emulsion: water-in-oil and oil-in-water. In water-in-oil emulsions, the nonionic (non-conducting) oil is the continuous phase in which the ionic water is dispersed. Therefore, corrosion does not occur in the presence of a water-in-oil emulsion; since oil is a non-conducting electrolyte, corrosion does not take place. On the other hand, in oil-in-water emulsions the ionic (conducting) water forms the continuous phase in which the non-ionic oil is dispersed. Therefore, corrosion occurs in the presence of oil-in-water emulsions. The water-cut at which a water-in-oil emulsion inverts into an oil-in-water emulsion is known as the ‘emulsion inversion point’ (EIP) (Figure 4.22).68,69 By measuring the conductivity of the emulsion under flowing conditions the type of emulsion can be determined.70 Standard providing guidelines to measure EIP include: •
ASTM G205, ‘Standard Guide for Determining Corrosivity of Crude Oils’
FIGURE 4.22 Schematic Diagram of the Experimental Section of Emulsion Inversion Point Apparatus.70 Reproduced with permission from ASTM.
4.3 Oil phase
215
4.3.3 Wettability The probability of corrosion in the presence of an oil-in-water emulsion or free water depends on the wettability. When the oil phase preferentially wets the surface (oil-wet), corrosion is negligible; but when the water phase preferentially wets the surface (water-wet), corrosion does take place; and when no phase preferentially wets the surface (mixed-wet), corrosion may or may not take place. It should be pointed out that emulsion and wettability are two different properties. The emulsion depends on the interaction between two phases: water phase and oil phase, whereas the wettability depends on three phases: water phase, oil phase, and solid phase (e.g., pipeline steel). A crude oil may have high EIP, i.e., it may hold water in the water-in-oil phase, but as soon as the EIP is reached water drops out and wets the surface. On the other hand, the crude oil may have a low EIP, i.e., water drops out even when present in low concentration, but the surface may continue to be oil-wet, reducing the possibility of corrosion. The wettability can be estimated by considering the relative surface energies of all the interfaces involved. A water-steel interface will be replaced by an oil-steel interface if the energy of the system decreases as a result of this action (that is, the tendency of oil to displace water from steel). The difference in surface energy (Dwo) between a steel-oil and a steel-water interface can be calculated from measured values of the contact angle (qCaw) and the water-oil interfacial tension (gwo) as: Dwo ¼ gwo $cos qCaw
(Eqn. 4.70)
It follows that displacement of water by oil should be expected when qCaw is between 90 and 180 ; on the other hand, displacement of oil by water would be expected when qCaw is between 0 and 90 (Figure 4.23). The contact angle method is extensively used to determine the wettability of different surfaces. The oil and water may be added in two sequences: oil-first water-next sequence or water-first, oil-next sequence. The first sequence represents the case of oil transmission pipelines, but measuring the contact angle using this sequence is relatively difficult. Due to the dark background of the oil, the wo
so
Caw
sw
FIGURE 4.23 Principle behind Determining Wettability using Contact Angle Measurement.70 Reproduced with permission from ASTM.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.24 Schematic Diagram of Apparatus to Determine Wettability using Spread Method.70 Reproduced with permission from ASTM.
apparatus should be illuminated. For this reason, the contact angle is normally measured in a waterfirst, oil-next sequence. However, this sequence does not truly represent the oil transmission pipeline operating conditions. The spreading method overcomes these difficulties. This method measures the conductivity across a series of 20 steel pins imbedded in non-conducting material (Figure 4.24). The conductivity is measured between a central reference pin and series of outer test pins. Based on how many measurements exhibit high resistance (low conductivity), the crude oil is classified as: • • •
Oil-wet (less than five of the 20 pins exhibit high conductivity) Mixed-wet (between five and 15 of the 20 pins exhibit high conductivity) Water-wet (more than 15 of the 20 pins exhibit high conductivity)
Although this apparatus can be operated at elevated pressures, the boundary for differentiating different wettabilities is arbitrary. Standard providing guidelines to measure wettability include: •
ASTM G205, ‘Standard Guide for Determining Corrosivity of Crude Oils’
4.3.4 Partition of chemicals between oil and water phases In the presence of an oil-in-water emulsion or free water phase on a water-wet surface; corrosion may take place. The crude oil phase surrounding the water phase may influence corrosion by partitioning water-soluble species into it. If the water-soluble species are corrosive in nature, the corrosivity of the aqueous phase would increase and be greater than that observed without an oil phase. On the other hand, if water-soluble species are inhibitive in nature, the corrosivity of the aqueous phase would decrease and be less than that observed without an oil phase. In order to understand the influence of an oil phase on the corrosivity of a water phase, tests should be performed using both oil and water phases
4.4 Water (Brine or Aqueous) phase
217
No Corrosion
W/O Emulsion O/W
Oil-Wet Wettability
No Corrosion
Mixed-Wet Water-Wet
Less then 0.01 mpy (Preventive Hydrocarbon)
Corrosivity of Brine in the Presence of Hydrocarbon
No Corrosion
Less then Absence of Hydrocarbons (Inhibitive Hydrocarbon)
Reduced Corrosion
No Change (Neutral Hydrocarbon)
Aqueous Corrosion
Higher then Absence of Hydrocarbons (Corrosive Hydrocarbon)
Accelerated Corrosion
FIGURE 4.25 Classification of Crude Oil (Hydrocarbons) based on Corrosivity (ASTM G205).70 Reproduced with permission from ASTM.
in a laboratory methodology (see section 8.2.2a). Based on the results, the overall corrosivity of oil may be established (Figure 4.25).
4.4 Water (Brine or Aqueous) phase The water phase may also be identified as brine solution, brine, or aqueous phase. The source and composition of the water used in various sectors of the oil and gas industry vary considerably. The water phase sustains corrosion by being a good electrolytic conductor (‘E’ in the ACME; see section 5.2). Deionized water does not contain ionic species, is a poor-conductor, and hence does not support corrosion. As the concentration of ions increases, the corrosivity of water increases. The ionic species influence the corrosivity of water in several ways: they increase conductivity of water, participate in electrochemical corrosion reactions (e.g., oxygen, by forming hydroxyl ion, may undergo cathodic reduction reaction), and change the properties of surface layers (e.g., chloride ions destroy many oxide surface layers leading to localized corrosion). The corrosivity of water depends on the nature as well as the concentrations of both anions and cations.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.4.1 Effect of anions The dominant anions affecting corrosion are halide ions, of which chloride ion is the most significant. Figure 4.26 presents the variation in corrosion rate of iron in air-saturated distilled water at room temperature as a function of Cl ion concentration (added in the form of NaCl). The corrosion rate increases as a function of NaCl concentration up to 3% NaCl. The concentration of oxygen is highest in pure distilled water, but its solution resistance is also high (i.e., the solution conductivity is low), so the corrosion rate is low. Addition of NaCl increases the solution’s conductivity, so the corrosion rate increases. At around 3% NaCl the solution conductivity reaches levels sufficient for the oxygen effect to become dominant. As the NaCl concentration increases above 3%, the dissolved oxygen content decreases; consequently the corrosion rate decreases. At about 26% NaCl the corrosion rate is as low as that in distilled water. The most prominent effect of chloride is, however, in initiating localized corrosion of metals. One study found that the tendency to initiate pits increases with increase in chloride ion concentration in the range 10,000 to 120,000 ppm, and that the effect of chloride ion depends on the presence of other ionic species.72 Depending on other factors, the presence of 5% chloride ion may increase localized pitting corrosion rate by 100 mpy.73 The chloride ion increases the susceptibility of metal to localized pitting corrosion by penetrating and destroying the oxide or other surface layers that are otherwise protective. Other halides may also initiate pitting corrosion, but the effect decreases in the order chloride > bromide > iodide > fluoride. Sulfate, bicarbonate, and phosphate ions in general decrease the susceptibility to pitting corrosion. In the presence of phosphate ions, the susceptibility to pit 2 3 initiation decreases in the order: H2PO 4 > HPO4 > PO4 .
3
Relative Corrosion Rate
3% NaCl
2
1
0 0
5
10
15 20 Concentration of NaCl (wt. %)
25
30
FIGURE 4.26 Corrosion Rate of Iron in Aerated Solution at Room Temperature as a Function of NaCl.71
35
4.4 Water (Brine or Aqueous) phase
219
4.4.2 Effect of cations74,75 Studies indicate that most of the univalent cations (Liþ, Naþ, Kþ, and Rbþ) increase susceptibility to pitting corrosion in various metals; the effect increases with the size of the ion. The bivalent cation Zn2þ may also increase the susceptibility of metals to pitting corrosion, initiating pitting by hydrolysis of the zinc salt. However most bivalent cations, such as Mg2þ, Ca2þ, Ba2þ, Sr2þ and Mo2þ, decrease susceptibility to pitting corrosion.
4.4.3 The combined effect of anions and cations In order to maintain the charge balance, equal amounts of anions and cations exist in solution. Therefore the combined effect of anions and cations needs to be understood. The cations and anions may combine to form a salt that may precipitate as scale. Formation of scale may plug pipes and equipment, and may lead to underdeposit corrosion. The tendency to form scale depends on the solubility. Solubility is a measure of maximum amount of solute (e.g., NaCl) which can be dissolved in a solvent (e.g., water phase), and this depends on pressure, temperature, and pH. Although several types of scales can form calcium carbonate (CaCO3) (commonly known as calcite), calcium sulfate (CaSO4), barium sulfate (BaSO4), and strontium sulfate (SrSO4) scales are all common in the oil and gas industry. Calcium carbonate scale forms by the reaction between calcium with carbonate (Eqn. 4.71) or bicarbonate (Eqn. 4.72) ions: Ca2þ þ CO3 2 > CaCO3
(Eqn. 4.71)
Ca2þ þ 2HCO3 > CaCO3 þ CO2 þ H2 O
(Eqn. 4.72)
Normally, calcium carbonate scale forms in downhole tubulars due to release of CO2 when the pressure drops. Calcium sulfate scale forms when calcium ions combine with sulfate ions: Ca2þ þ SO4 2 > CaSO4
(Eqn. 4.73)
Calcium sulfate scale may be anhydrous (CaSO4) or hydrated (CaSO4.2H2O) (commonly known as gypsum). Normally, calcium sulfate scale forms in seawater because this contains high sulfate concentrations. In addition, barium sulfate (Eqn. 4.74) and strontium sulfate (Eqn. 4.75) scales, and to a smaller extent calcium fluoride scale, also form in the oil and gas production sector: Ba2þ þ SO4 2 > BaSO4
(Eqn. 4.74)
Sr2þ þ SO4 2 > SrSO4
(Eqn. 4.75)
The tendency to form scale is determined using saturation index (SI): SI ¼ log10 ðSRÞ
(Eqn. 4.76)
where SR is the saturation ratio; it is the ratio of the ionic product at a given concentration to that under saturation conditions. For example, for calcium carbonate the saturation ratio is defined as: 2þ 2 Ca : CO3 (Eqn. 4.77) SR ¼ 2þ ½Ca satn: :½CO2 3 satn:
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
where [Ca2þ] is the concentration of calcium ion in solution; [CO2 3 ] is the concentration of carbonate in solution; [Ca2þ]satn. and [CO23 ]satn. are the respective concentrations at the saturation point. For a given solution, if SR is unity, the solution is saturated with CaCO3 and scale can potentially form; if SR less than unity, the solution is undersaturated with CaCO3 and scale will not form; and SR is greater than unity the solution is supersaturated with CaCO3 and scale can form (precipitation is a kinetic driven process, so we may not see scale even when SR is greater than unity).
4.5 CO2 In the 1950s, corrosion was encountered in high pressure sweet oil wells, which, at that time, were thought to be non-corrosive. Based on a statistical analysis of data from several companies, the NACE TP-1C76 committee found that: general pitting-type corrosion occurs frequently in oil-producing pipe lines; corrosion starts once the wells begin producing water; pitting frequency varies with thickness of the pipe and the number of pits is higher at points of maximum wall thickness; and unique and unexplained scale conditions obscure the interpretation of caliper surveys (see section 8.4.9). An economic analysis at that time indicated that $1,500,000 must be spent within the next four years because of corrosion in 150 wells concentrated in a small geographic area located in SouthEastern Louisiana.77 Since the 1950s, several groups have studied the corrosion of carbon steel in CO2 solution. Carbon dioxide is soluble in the aqueous phase; concentrations of CO2 increase with a decrease in temperature. Normal solution CO2 concentrations are in the range 265–320 ppm at 80 C (176 F), and 1125–1720 ppm at 20 C (68 F).78 CO2 dissolved in water hydrates to become carbonic acid (H2CO3).79–82 This hydration reaction is a slow process; hence, only a small fraction of aqueous CO2 exists as H2CO3. The dissociation of H2CO3 produces carbonate (CO2 3 ) and bicarbonate (HCO3 ) 2 ions. Within the pH range 6 to 10, HCO3 exists predominantly and above pH 10, CO3 predominates. Accordingly, the corrosion of carbon steel produces both Fe(HCO3)2 (below pH 10) and FeCO3 (above pH 10), but in practice only FeCO3 is observed. Thus the overall corrosion of carbon steel in CO2 environment may be written as:83 Fe þ H2 CO3 /FeCO3 þ H2
(Eqn. 4.78)
Corrosion takes place without a corrosion layer if the Fe2þ and CO2 3 concentrations are below exceed the solubility limit, the solubility limit. When the concentrations of Fe2þ and CO2 3 corrosion layers form.84 Sometimes a FeCO3 surface layer does not form until the solution concentrations of Fe2þ and CO2 3 are five to ten times more than the values obtained from thermodynamic calculations. A solution is considered as supersaturated when the concentrations of Fe2þ and CO2 3 in it exceed values from thermodynamic calculations. The extent to which the solution is in the supersaturated condition (before FeCO3 surface layer formation) depends on pH, surface-volume ratio, and temperature. The supersaturation stage occurs because the precipitation rate of FeCO3 is slow.85,86 When the surface layer is formed, the corrosion rate decreases, and the extent of decrease depends on temperature, velocity, pH, H2S, and steel type. Several other mechanisms have been proposed for the formation of FeCO3. Irrespective of the mechanisms by which they form, an intact FeCO3 surface layer reduces corrosion and when FeCO3 is broken, localized pitting corrosion occurs.
4.5 CO2
221
4.5.1 Effect of temperature87–89 In general, corrosion rate increases with increase of temperature until reaching a maximum. Many studies indicate that formation of a FeCO3 surface layer is difficult at temperatures below 70 F (w20 C); surface layers formed between temperatures 70 and 100 F (w20 and 40 C) are not adherent and may be removed by wiping with a cloth; surface layers formed between 100 and 140 F (40 and 60 C) are non-protective; and surface layers form between 140 and 300 F (60 and 150 C) are hard, adherent, and protective. Figure 4.27 presents the distribution of pit densities on carbon steel exposed for 100 hours in CO2 solution as determined by laser profilometer.90 At 70 F (20 C); the pit density (i.e., number of pits per unit area) is higher but the pits are shallower – indicating a non-uniform, fragile surface layer. Between 70 and 175 F (20 and 75 C), as the temperature increases, the pit density decreases but the pits are deeper, indicating insufficient amounts of adherent surface layer; and between 170 and 250 F (75 and 120 C), as temperature increases both pit density and pit depth decrease, indicating the formation of adherent and protective surface layers.
4.5.2 Effect of velocity91–94 Velocity may facilitate the formation of a FeCO3 layer by promoting the dissolution of CO2 in the solution and by transporting of reactants to the surface. On the other hand, velocity may delay formation of a FeCO3 layer by transporting reaction products away from the surface, or it may completely prevent the formation of surface layer. Depending on the flow conditions, different forms of corrosion can take place in solutions containing CO2: pitting, mesa attack, FILC, and general corrosion. The boundary between these forms is not sharp, and depends on several factors including flow rate (single phase or multi phase), type of steel, pH, CO2 partial pressure, temperature, and the presence of other species (e.g., H2S). Pitting corrosion occurs under stagnant to low flow conditions, and is characterized by loss of metal in discrete areas of the surface, with surrounding areas remaining essentially unaffected or subject to general corrosion. These discrete areas may exist as circular depressions (pits) or slits (sometimes referred to as knife lines). Stepped depressions with flat-bottom and sharp-vertical side geometry, often referred to as mesa corrosion, occur at medium flow rate conditions (Figure 4.28).95 This type normally occurs when stable, hard, but non-adherent surface layers are exposed to moderate flow conditions. At very high flow velocities, the corrosion feature may take the form of parallel grooves extending in the flow direction; this phenomenon is known as FILC. FILC may start from pits or mesa corrosion above a critical flow velocity. The pits and mesa type corrosion features disturb the flow pattern and create local turbulence. This turbulence and stresses inherent in the surface layer may destroy and remove the surface layers, and the flow also prevents re-formation of a surface layer on the exposed metal. The velocity at which the surface layer is completely removed, or prevented from forming, is known as the critical velocity. Various studies indicate that the critical velocity varies between 4 and 6.5 feet/s (1.25 and 2 m/s).
4.5.3 Effect of microstructure96–102 In general, microstructural elements (e.g., pearlite, normalization) which promote anchoring of the surface layer decrease the corrosion rate, whereas elements (e.g., ferrite and cementite) which promote
222
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Profiles of the Outer Surface
Temperature oC
20
50
75
FIGURE 4.27 Distribution of Pits (as Determined by Laser Profilometer) on Carbon Steel in CO2 Atmosphere as a Function of Temperature.90 Reproduced with permission from NACE International.
4.5 CO2
223
90
120
FIGURE 4.27 (continued ).
FIGURE 4.28 Example of Mesa Type of Corrosion.95 Reproduced with permission from NACE International.
224
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Table 4.7 Characteristics of Surface Layers in Sweet Environment Characteristics
Magnetite
Cementite
Siderite
Name Chemical formula Color
Iron Oxide Fe3O4 Black
Metastable carbide Fe3C
Hardness Physical stat
5.5e6.5 Crystal
e Brittle
Iron Carbonate FeCO3 Gray, yellow, yellowish brown, greenishbrown, reddish brown and brown 3.5e4.5 Crystal
galvanic corrosion increase the corrosion rate. Table 4.7 presents the characteristics of surface layers. When iron corrodes away, leaving pearlite behind, cavities between pearlite facilitate an increase in the concentration of ferrous ions. Local flow stagnation and the higher local Fe2þ concentrations in the cavities allow the formation of an iron carbonate scale between the pearlite platelets. In addition, the pearlite helps to anchor the layer. This mechanism explains why adherent surface layers are formed on steel with a normalized microstructure rather than on steel with a quenched, tempered microstructure. When ferrite (a-Fe) microstructure preferentially corrodes, leaving cementite (Fe3C) behind, surface layer formation is hindered. Fe3C is a good electrical conductor; therefore the cathodic reaction occurs readily on Fe3C. This leads to galvanic coupling between the steel substrate and the Fe3C layer, promoting and sustaining corrosion. The effect of microstructure is evident at temperatures up to 60 C but diminishes above this. The FeCO3 surface layer makes the role of the underlying steel microstructure less pronounced.
4.5.4 Effect of pH103–108 A minimum pH is required for the formation and for the stability of surface layers. This minimum pH may vary between 4.2 and 6.0 depending on several other parameters including temperature, chemical species (CO2, carbonate, and bicarbonate), and flow rate.
4.5.5 Effect of H2S109–110 Small amounts of H2S may have some inhibitory effect on CO2 corrosion of steel, due to the formation of more protective iron sulfide (FeS). When the pCO2/pH2S ratio is above 5,000, sweet corrosion (controlled by FeCO3 surface layer) occurs. This ratio, however, may vary with temperature and pH.
4.6 H2S111–125 A historic test that is directly relevant to the understanding of iron and steel corrosion by elemental sulfur was conducted by Nemery in 1700. He mixed equal parts of iron filings and sulfur with water to form dough and buried it underground. This dough fermented and caught fire. The vigorous reaction lifted the soil, and this phenomenon led Nemery to the postulate that earthquakes occur due to similar reactions. This test indicated that iron reacts vigorously with sulfur in the presence of water.
4.6 H2S
225
Two-hundred and fifty years after Nemery’s test, Farrer and Wormwell patented the use of suspensions of sulfur in water as an etching medium for iron and steel. They found that such a suspension was corrosive to steel. They used this solution to assess the porosity of non-ferrous coatings on a ferrous base material. In the oil and gas industry, environments containing H2S are commonly known as sour environments. Sour environments cause two types of failures: sour corrosion and sulfide-stress cracking (SSC). Industry first experienced both these failures in the 1950s. Sour corrosion was first experienced in oil production fields in the USA, and SSC was first experienced in Western Canadian oil fields. Sour corrosion frequently caused – in some cases within 30 days of installation – broken sucker rods and perforated tubing. To control sour corrosion, 942 (about 26%) of the 3,618 wells operating in one location in 1950s were treated with corrosion inhibitors. (Section 5.18.4 discusses SSC in detail). Similar to CO2, H2S dissolved in water is a weak acid. In the absence of buffering ions, water equilibrated with H2S at atmospheric pressure reaches a pH value of about 4. Under higher pressures, the pH value can become as low as 3.114 Sulfur and H2S may occur naturally or may be generated by sulfate reducing bacteria (see section 4.9). At high pressure, sulfanes (the acid form of a polysulfide) are formed in the gas phase by the dissolution of elemental sulfur. As the pressure reduces (e.g., in production pipelines), the sulfanes in the gas phase dissociate to form elemental sulfur and, in the presence of water, sulfanes dissociate into H2S and elemental sulfur. Elemental sulfur may also be formed by the oxidation of H2S by air or by oxides (for example, iron oxides): 2H2 S þ O2 /2H2 O þ 2S
(Eqn. 4.79)
3H2 S þ 2FeOðOHÞ/2FeS þ S þ 4H2 O
(Eqn. 4.80)
This oxidation is detrimental for two reasons: it produces elemental sulfur, which causes severe sulfur corrosion, and further it produces water which makes dry and non-corrosive H2S becoming wet and corrosive. The solubility of sulfur in water increases with temperature (w10 ppm to 20 ppm at 77 F (25 C) to w50 ppm at 122 F (50 C)). The dissolution of sulfur in water produces H2S and sulfuric acid: 4S þ 4H2 O/3H2 S þ H2 SO4
(Eqn. 4.81)
This reaction is very slow at ambient temperatures, yet it occurs and produces enough H2S. Carbon steel or iron corrodes in the presence of H2S to produce FeS: Fe þ H2 S/FeS þ H2
(Eqn. 4.82)
The production of hydrogen atoms on the metal surface, as precursor to molecular hydrogen (Eqn. 4.82) leads to SSC (see section 5.18.4). Corrosion is however less severe in the presence of H2S than in the presence CO2 because the kinetics of formation of FeS is faster than those of FeCO3. Consequently, the surface layer of FeS is formed relatively quickly. However FeS is an electron-conductor; therefore it provides site for cathodic reactions to occur. Therefore a surface not fully covered by FeS may undergo severe localized corrosion. Iron sulfides may exist in different forms. Table 4.8 presents characteristics of these forms. The term kansite was used first in 1953–1955 for a corrosion product found in steel tubing in a Kansas oil well. In 1958, kansite Fe9S8 was described as a new iron sulfide, formed by action of H2S on steel. Based on very similar properties, to avoid confusion, the name kansite was dropped and the name
226
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Table 4.8 Common Species of Iron Sulphide123,124 Name
Stability
Chemical Formula
Pyrrhotite Trolite Mackinawite
Meta stable Stable Various degree
Marcasite Pyrite Greigite
Meta stable Stable (sulfide mineral) Metastable
Fe1-xS (e.g., Fe7S8) FeS Fe1þxS (x ¼ 0 to 0.1, e.g., Fe9S8)) FeS2 FeS2 Fe3S4
)
may be identified as kansite
Mackinawite was approved by the International Committee on Mineral Names. Since then many corrosion products of sour corrosion have been identified as Mackinawite.
4.6.1 Effect of temperature126–129 In general, at constant concentrations of H2S, the corrosion rate increases with temperature in the range 40 to 140 F (5 to 60 C). Temperature has no significant effect on corrosion rate in the range between 190 and 300 F (w90 and 150 C). At 302 F (w150 C), the surface layer is very hard and adherent. At 425 F (w220 C), the surface layer predominately consists of pyrrhotite, with small amounts of pyrite and trolite, which reduces the corrosion rate. High temperature (above 500 F [260 C]) corrosion of carbon steel may occur in the presence of H2S in reforming and desulfurizing units of refineries.
4.6.2 Effect of velocity130 Iron sulfides have low solubility (precipitation as surface layer is fast), good adherence onto steel, and good mechanical properties. For these reasons, velocity effects are generally not encountered in sour systems at velocities up to 30 m/s (100 ft/s).
4.6.3 Effect of microstructure131–132 Any microstructural changes (e.g., cold-working) that promote the formation of FeS on the surface decrease corrosion. On the other hand, any microstructural changes that promote galvanic corrosion increase corrosion. For example, the presence of a cementite phase acts as a cathode with respect to ferrite, and promotes dissolution of the ferritic phase. FeS is preferentially formed on cementite phases (which continues to act as cathode) further sustaining corrosion in the ferrite phase, leading to grooves on the metal surface.
4.6.4 Effect of pH133 In the pH range 1.7 to 2.7, iron continues to corrode and ferrous ion continues to dissolve without forming any FeS surface layer. The FeS layer starts to form at pH 2.8. Figure 4.29 presents the general variation of sour corrosion of carbon steel with pH.
4.7 O2
227
FIGURE 4.29 Variation of Corrosion Rate in H2S Medium with pH.133
4.6.5 Effect of CO2134–135 When the pCO2/pH2S ratio is below 5,000, sour corrosion (controlled by the FeS surface layer) occurs. This ratio, however, may vary with temperature and pH.
4.7 O2136 Although oxygen is not normally present at depths greater than approximately 100 m (330 ft) below the surface and is not intentionally added, it is nevertheless responsible for some corrosion encountered in the oil and gas industry. Oxygen is soluble in water. The solubility of oxygen in water increases with decreasing temperature (Figure 4.30).137–139 Even trace amounts of oxygen are sufficient to cause corrosion. Figure 4.31 provides a comparison of corrosion rates in oxygen, H2S, and CO2 atmospheres.140 The kinetics of oxygen reduction on steel is relatively fast. In the presence of oxygen, depending on the pH, two types cathodic reaction can take place: In acidic solution: O2 þ 4Hþ þ 4e /2H2 O
(Eqn. 4.83)
1=2 O2 þ H2 O þ 2e /2 OH
(Eqn. 4.84)
In neutral or alkaline solution:
228
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
OVERALL CORROSION RATE OF CARBON STEEL MPY
FIGURE 4.30 Dissolution of Oxygen in Aqueous Solution as a Function of Temperature.
O2
25
20 CO2
15
10 H2S
5
O2 1
2
3
4
5
6
7
8
H2S 100 200 300 400 500 600 700 800 CO2 50 100 150 200 250 300 350 400 DISSOLVED GAS CONCENTRATION IN WATER PHASE (PPM)
FIGURE 4.31 General Corrosion of Carbon Steel in the Presence of Oxygen, CO2 and H2S.140
4.7 O2
229
The overall reaction taking place during the corrosion of iron in the presence of oxygen is given by: Fe þ H2 O þ 1=2O2 /FeðOHÞ2
(Eqn. 4.85)
Ferrous hydroxide [Fe(OH)2], or hydrous ferrous oxide [FeO.nH2O] initially dissolves in the solution, saturates it, and finally forms a porous layer on the surface (green/blue). Fe(OH)2 is further oxidized to hydrous ferric oxide (reddish brown in color): FeðOHÞ2 þ 1=2H2 O þ 1=4O2 /FeðOHÞ3
(Eqn. 4.86)
A solution saturated with hydrous ferrous oxide has a pH of about 9.5. A solution saturated with hydrous ferric oxide has a neutral pH. Hydrous ferric oxide often turns black due to the formation of an intermediate hydrous ferrous-ferrite oxide (Fe2O3.FeO.nH2O or Fe3O4.nH2O). Thus, the surface layers of iron may consist of three or more forms of iron oxide, depending on the extent of oxidation and hydration (Table 4.9). Depending on environmental conditions, the oxide surface layers can be porous and non-protective, or compact and protective.141–154 The surface layers of iron oxides are stable even at higher temperatures. An adherent and protective magnetite has been observed even at 310 C.155
4.7.1 Effect of temperature It is generally accepted that, in the presence of oxygen, the corrosion rate of carbon steel doubles for every 30 C (90 F) increase in temperature (when compared to chemical reactions that in general, double in rate for every 10 C (50 F) increase of temperature) (see also section 4.11). In an open system, the corrosion rate drops at the boiling point due to the evaporation of water (disappearance of dissolved oxygen). On the other hand, in a closed system, the corrosion rate continues to increase with temperature (Figure 4.32).156
4.7.2 Effect of velocity157 In general, the surface layer thickness is large in stagnant systems and decreases progressively with increasing flow rate, until eventually all surface layers are removed. The effect of flow rate on corrosion in the presence of oxygen depends on the solution composition. For example, in the presence of chloride ions the corrosion rate increases with flow (Figure 4.33),158 but in the absence of chlorides, corrosion rate decreases with flow rate.
Table 4.9 Common Oxides of Iron Formula
Color
Oxidation State 2þ
Fe(OH)2 or FeO.nH2O FeO Fe(OH)3 or Fe2O3.nH2O
blue/green black red brown
Fe Fe2þ Fe3þ
Fe3O4 or Fe2O3.FeO.nH2O
black
Fe2þ/3þ
Name Ferrous oxide (hydrated) Ferrous oxide (unhydrated) Ferric oxide (hydrated) or Hematite (common rust) Ferrous-ferric oxide or Magnetite
230
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.32 Effect of Temperature on Corrosion of Iron in Water containing Dissolved Oxygen.156 Reproduced with permission from McGraw-Hill.
4.7.3 Effect of microstructure The influence of microstructure on the corrosion rate of steels in oxygen solution or in air is minimal in neutral solutions; only large amounts of chromium (more than 12%, e.g., stainless steel), silicon, or nickel decreases the corrosion rate. In acid solution, both composition and microstructure influence corrosion. Many alloying elements, such as carbon, nitrogen, sulfur, and phosphorous, increase both the general and pitting corrosion rates. Table 4.10 presents the general influence of alloying elements on the corrosion rate of iron.
FIGURE 4.33 Effect of Velocity on the Corrosion of Iron.158 Reproduced with permission from Wiley.
4.8 Sand and solids
231
Table 4.10 Effect of Alloying Elements on the Corrosion of Iron in Acid Media159 Element
Formula
Carbon
C
Phosphorous Sulphur
Concentration, %
Influence on Corrosion
Remarks
0.1 to 0.8
Slight increase in corrosion
Fe3C (cementite) acting as effective cathode increases galvanic corrosion
P S
0.02 0.015
Increases corrosion Increases corrosion
Copper
Cu
1
Moderately Increases corrosion rate
Chromium
Cr
12
Arsenic Manganese
As Mn
0.1 0.1
Nickel
Ni
5
Drastically decreases corrosion by forming effective oxide layer Increases corrosion Decreases corrosion; MnS, if present, may become location for pit initiation
Sulfur acts as anodic site, facilitating localized corrosion But in the presence of phosphorous and sulfur counteracts their accelerating effect Stainless steel
MnS inclusion has low electrical conductivity compared to FeS. It decreases the solubility of sulfur in iron
Decreases corrosion; may promote localized corrosion
4.7.4 Effect of pH Figure 4.34 presents the effect of pH on the corrosion rate of iron. Below pH 4, no surface layer is formed and the corrosion rate is independent of oxygen concentration; between pH 4 and 10, the corrosion rate increases with increase in oxygen concentration; and above pH 10 the corrosion rate decreases due to increased stability and compactness of surface layers. In many practical situations in the oil and gas industry, the pH is between 4 and 10, and under these conditions the corrosion rate increases with oxygen concentration.
4.8 Sand and solids161–163 Analyses of reservoir and rock mechanics of formations that have a relatively low strength (less than 2,000 psi (13.8 MPa)) and the availability of large amounts of oilsands indicate that the presence of sand in certain parts of the oil and gas industry is inevitable. Table 4.11 presents common types of solid and the most common cause of their formation.161 Both particle size distribution and concentration depend mostly on the formation rock and sand control technologies used. In most production facilities, sand control techniques are used to prevent the entry of sand into the downhole production tubulars. However, even with best sand control techniques,
232
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.34 Effect of pH on Corrosion of Iron in Aerated Soft water, Room Temperature.160 Reproduced with permission from the American Chemical Society.
Table 4.11 Common Types of Solids and Their Formation Mechanisms161 Solid Type
Typical Cause
Sand Oilsand Iron oxide, iron sulfide, iron carbonate and sulfur (generically referred to as ‘black powders’)
• Sand produced naturally from normal production wells • Sand naturally socked with oil • Direct chemical reaction of transported fluid components with pipe material • Ineffective removal of mill-scale from new pipe during pre-commissioning • Improper dewatering, drying and/or lay-up of pipe during pre-commissioning or remedial works. • Temperature and pressure change during the transportation of aqueous fluids; some inorganic scales (e.g., calcium carbonate, calcium sulfate, barium sulfate, and strontium sulfate) are deposited. • Comingling of incompatible aqueous fluids • Temperature and pressure change during the transportation of hydrocarbon fluids some organic molecules (e.g., asphaltene and wax) are deposited • Decrease of temperature (below dew point) and increased pressure during the transportation of wet (water containing) natural gas
Inorganic scales
Organic solids) Hydrates)
)
These solids, though cause operational difficulties for flow-assurance team, they do not normally accelerate corrosion
4.8 Sand and solids
233
sand will enter into the tubulars. Depending on the composition of the material being transported and the efficiency of the sand control techniques used, different types of sand or solid contamination may occur. Two unique pipelines of the oilsand sector of the industry are hydrotransport pipelines and tailing pipelines. Oilsands are transported from the mining area either by conveyer belt or by hydrotransport. Hydrotransport has been used since 2005. In this process, oilsands and water are mixed together to make a slurry, which is transported in pipeline from the mine to a bitumen-extraction facility. While the mixture of oil sands and water flow through the pipeline, large lumps of oil sands are broken down and bitumen is separated from the oil sands in the form of tiny droplets. The benefits of hydrotransport include lower energy consumption, lower operating temperature, and flexibility of transportation. However, the degradation of pipelines, due to erosion and corrosion caused by sand and water, is a major challenge (see section 2.13). Fine tailings are by-products of the oilsand extraction process. They are a mixture of water, sand, silt, and fine clay particles, and they are transported to tailing ponds via tailing pipelines. Similar to hydrotransport pipelines, tailing pipelines also suffer from erosion and corrosion (see section 2.20). Solids may form due to corrosion of steel exposed to wet-gas. Typical solids include iron oxides, iron sulfides, iron carbonates, and sulfur, and these are collectively known as black powders. Gas transmission pipelines may contain several types of solids including sand, sludges, biomass (containing microbial species), inorganic scales (e.g., calcium carbonate, barium carbonate), organic scales (e.g., paraffins and asphaltenes) and corrosion products. Some dissolved solids carried by entrained liquids may also drop out and accumulate under favorable conditions. The presence of black powder affects gas transmission pipelines in several ways. These black powders may be hygroscopic or deliquescent, and they increase corrosion rates by retaining water, by establishing environments under them (i.e., underdeposit corrosion), and by sustaining microbial growth. Black powders may decrease the corrosion rate if they form an adherent surface layer on the pipe’s surface. When water from different sources is mixed, inorganic scales can be formed (see section 4.4.3). When the temperature of pipelines transporting extra-heavy crude oil is low, some long-chain (typically containing more than 20 carbon atoms, e.g., C20H42) paraffinic components (asphaltenes and wax) may deposit as hard solids. The majority of crude oils with API 20 or less (i.e., heavy and extra-heavy crude oils) contain significant amounts of paraffinic wax. As temperature reduces, wax will start to precipitate out. The wax may deposit in the form of an oil-gel containing some entrapped oil. As the temperature decreases the wax solidifies, eventually stopping the flow of crude oil. The temperature at which oil stops moving is known as the crude pour point temperature. To avoid wax formation, several measures are taken, including thermally insulating the pipe, using cleaning pigs, and adding chemicals. Asphaltenes are organic fractions of crude oils that are soluble in benzene and toluene, but not in alkanes (n-pentane and n-hexane). As the temperature decreases, asphaltene precipitates as a solid. Similar to wax formation, asphaltene formation may block the flow, but unlike wax they do not melt on heating. To remove asphaltene the pipeline is mechanically cleaned (using pigging and wireline cutting), or chemical solvents are used to dissolve it. Chemical inhibitors are also used to prevent the precipitation of asphaltenes in the first place. In wet-gas and multiphase pipelines, gas hydrates may form at low temperatures. Gas hydrate is formed when gas molecules are trapped in a cage of water molecules under certain pressure and temperature conditions. Generally, methane hydrate is formed in the presence of water, when the temperature is below 40 F (4 C) and pressure is above 170 psi (1,172 kPa). Decreasing temperatures and increasing pressures further favor hydrate formation. In addition to methane hydrate, ethane,
Very high
Dispersed sand flow Liquid/solid impingment erosion
Dispersed sand flow Solid/liquid impingment erosion
Dispersed sand flow Solid impingment erosion
High
Flow Rate
Liquid impingment erosion
Flow induced localized corrosion
Dispersed sand flow Corrosion influenced erosion
Scouring sand flow Corrosion influenced erosion
Scouring sand flow Corrosion influenced erosion
Medium
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Flow assisted pitting corrosion
Scouring sand flow Erosion influenced corrosion
Sand dunes Erosion influenced corrosion
Sand dunes Erosion influenced corrosion
Low
234
General and pitting corrosion
Sand dunes Pitting corrosion
Sand deposits Pitting corrosion
Sand deposits Underdeposit corrosion
No
Small
Medium
Large
Sand Level FIGURE 4.35 Effect of Sand on Corrosion and Erosion.
propane, CO2 and H2S hydrates may also form. These hydrates form as solids or semi-solids, and they slow or even completely block the gas flow. Several measures are taken to avoid hydrate formation in gas pipelines, including removal of water, keeping the temperature above hydrate formation temperature, maintaining the pressure below hydrate formation pressure, and by injecting chemicals (hydrate inhibitors). The formation of these solids, i.e., asphaltene deposits, wax deposits, and hydrate normally decrease the corrosion rate. But they create operational difficulties, e.g., pressure drop and, in extreme situation, stoppage of flow; therefore their formation is avoided. The presence of solids may result in corrosion under sand beds (underdeposit corrosion), erosioninfluenced corrosion (EIC), corrosion-influenced erosion (CIE), and erosion. Figure 4.35 presents various types of corrosion and the conditions in which they will probably occur. However the boundary conditions between these types of corrosion are not well established.
4.9 Microorganisms165–168 When some microbiological species are present, they may influence corrosion. The corrosion influenced by microbiological activities is known as microbiologically influenced corrosion (MIC).164 Microorganisms do not produce unique types of corrosion. For this reason, it is accepted by international community that the term is microbiologically ‘influenced’ corrosion, rather than microbiologically ‘induced’ corrosion. The presence and activities of microorganisms may cause pitting, crevice corrosion, selective dealloying, and differential aeration cells (see section 5.14).
4.9 Microorganisms
235
There are several types of microorganisms present in air, water, and attached to solid materials. The microorganisms floating freely in a liquid are commonly referred to as ‘planktonic’ organisms. Microorganisms that are attached to a surface are commonly known as ‘sessile’ organisms. The microorganisms may be classified as bacteria (0.2 to 2 mm), fungi (2 to 20 mm), and algae (2 to 20 mm). All these microorganisms can be present in diversified environments of various pH, oxygen content, temperature, and food sources. Table 4.12 presents some of their characteristics. When conditions are conducive, they multiply rapidly, with growth as high as 1 million/ml within 24 hours. Of the various microorganisms, sulphate-reducing bacteria (SRB), acid-producing bacteria (APB), iron-oxidizing bacteria (IOB) and iron-reducing bacteria (IRB) are known to cause MIC. SRB constitute a diverse group of anaerobic bacteria which have several morphologies and nutritional requirements. They reduce sulfate to hydrogen sulfide. Common SRBs include Desulfovibrio, Desulfobacter and Desulfotomaculum. Since the discovery of SRBs by the Dutch microbiologist Wilhelm Bijerninck in 1905, they have been considered as the dominant bacteria associated with MIC.169 Despite the recognition that the most severe MIC occurs in the presence of consortia of bacteria, SRB are most often considered as the primary cause, because they are ubiquitous; in sulfate-containing environments they produce hydrogen sulfide; and they convert sweet production to sour production (containing hydrogen sulfide).
Table 4.12 Characteristics of Microorganisms Properties
Definition
Bacteria
Fungi
Algae
Nucleus
Procaryote (i.e., it does not have any nucleus) eucaryote (i.e., they have nucleus)
Procaryote
Eucaryote
Eucaryote
0.2 to 2 No 3 to 9
2 to 20 No 3 to 5
2 to 20 Yes 7 to 8
Yes
Yes
Yes
Yes Yes Yes Yes
No e e Yes
No e e Yes
Yes
e
e
Yes
e
e
e Yes
e e
Yes e
Yes
e
e
Typical size, mm Chlorophyll Typical pH range of activity Aerobic Anaerobic Anaerobic-Obligate Anaerobic-Faculative Psychrophiles Mesophiles Thermophiles Phototrophs Lithotrophs Heterotrophs
Requires light to grow
Presence of oxygen required for growth Oxygen is not required for growth Can not tolerate oxygen Can tolerate oxygen Active in the temperature range 20 to 20 C Active in the temperature range 20 to 45 C Active in the temperature range above 45 C Light is the source of energy Inorganic matters are the source of energy Organic matters are the source of energy
236
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Section 5.14 discusses the mechanism of MIC, section 6.7.6 presents comprehensive model for MIC, and section 8.2.4 presents methods for monitoring MIC.
4.10 Pressure As discussed in section 4.2, pressure is the force that moves the hydrocarbons. Therefore an important consideration in designing and operating the piping and pipeline is to estimate the amount of pressure required to transport the hydrocarbons. Many oil and gas facilities are operated at elevated pressure. The effect of pressure on corrosion depends on the partial pressures of acid gases (H2S and CO2), other chemical species (bicarbonate, acetate, and calcite), the pH and temperature. Higher pressure (or partial pressures of acid gases H2S and CO2), may increase corrosion if it increases the dissolution of corrosive species into the solution, or increases the dissolution of the surface layer from the metal surface. On the other hand, higher pressure may decrease corrosion if it facilitates the formation of a compact surface layer.
4.11 Temperature In general, the relationship between temperature and chemical reactions is provided by the Arrhenius equation. According to this equation, the rate of a chemical reaction increases with an increase in temperature. The Arrhenius equation also applies to corrosion reactions taking place by electrochemical mechanisms (see section 5.2). Depending on the material, environment, and temperature, the corrosion rate doubles for every 10 or 30 C increase in temperature. However, the Arrhenius equation applies only in the range of temperature in which the corrosion mechanism remains the same. Above and below this temperature range, the relationship between corrosion rate and temperature may be different. Sections 4.5.1, 4.6.1, and 4.7.1 respectively present the effect of temperature in CO2, H2S, and O2 systems. In some cases, an increase in temperature decreases corrosion. The dew point is the temperature below which water condenses. When the temperature is above the dew point water does not condense. Because water is required for electrochemical corrosion to take place, above the dew point the corrosion rate decreases. Most of the gas wells and gas pipelines are operated above the dew point to avoid condensation of water, and hence corrosion. On the other hand, in some cases, a decrease in temperature decreases corrosion; this normally happens when solids such as asphaltene, wax, and hydrates form (see section 4.8). However, the formation of these solids causes other operational difficulties and hence this is avoided. At high temperatures, typically above 840 F (w450 C), another form of corrosion known as ‘high temperature corrosion’ takes place (see section 5.15).
4.12 pH The pH of the waters in the oil and gas industry depends on the partial pressures of the acid gases (H2S and CO2), concentrations of buffering species (bicarbonate and acetate ions), the concentration of scale-forming species (calcium carbonate), temperature, and organic acids (acetic acid). Table 4.13
4.13 Organic acids
237
Table 4.13 Influence of Parameters on pH (Experimental Data)170 Parameter
Parameter Range
pH Range
CO2 H2S CO2 and H2S
10 to 80 psi 10 to 80 psi 80 psi each
4.5 to 5.5 4.8 to 5.5 4.0 to 5.0
Temperature NaHCO3
30 and 50 C 4,000 ppm
4.4 to 4.8 6.0
CH3COONa
4,000 ppm
6.0
CH3COOH A mixture of NaHCO3 and CH3COONa
4,000 ppm 4,000 ppm each
4.0 6.0
Effect of Increasing Value of the Parameter on pH Decreases Decreases Same as for individual acid gases Slightly increases Increases and stabilizes (buffering) Increases and stabilizes (buffering) Decreases Stabilizes (buffering)
summarizes the influence of some parameters on the pH. Sections 4.5.4, 4.6.4, and 4.7.4 respectively discuss the influence of pH in sweet, sour, and oxygen containing environments. Determination of pH at the point where corrosion occurs provides valuable information; however such measurement is not routinely carried out. In many instances, the pH of the solution is measured under atmospheric pressure, immediately upon withdrawal from the system. This pH may not necessarily be the pH of the water within the system, because of the loss of acid gases, such as H2S and CO2, through pressure reduction and exposure of the fluid to atmosphere. Alternatively the in situ pH is estimated.171–175 The use of handheld devices facilitates estimation of in situ pH quickly. Equation 4.87 provides a simple method to quickly estimate pH in sweet environment: 1 pH ¼ 4:08 þ Log pffiffiffiffiffiffiffiffiffiffiffi WCO2
(Eqn. 4.87)
where WCO2 is the weight of CO2 in grams dissolved per liter of water.
4.13 Organic acids Organic acids include a broad range of compounds containing a carboxylic group, i.e., –COOH. Depending on the hydrocarbon molecule to which this carboxylic group is attached the organic acids can be broadly classified into: • • •
aliphatic acids (Ali.COOH) where the hydrocarbon molecule may be a straight or branched hydrocarbon, e.g., CH3– (acetic acid), C2H5– (propionic acid), etc; aromatic acids (Ar.COOH) where the hydrocarbon molecule may be benzene or substituted benzene ring; and naphthenic acids (Nap.COOH) where the hydrocarbon molecule may be a saturated cyclic ring, e.g., cyclopentane, cyclohexane, etc. The term ‘naphthenic acid’ as used in the oil and gas industry actually refers to many organic acids present in crude oil.
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Section 4.3.1c briefly discusses the influence on organic acids present in crude oils. The organic acids influence corrosion as: Fe þ 2RCOOH/FeðCOORÞ2 þ H2
(Eqn. 4.88)
where R’ is an aliphatic, aromatic, or naphthenic group. Depending on the type of organic acid, the reaction product, Fe(COOR’)2, is soluble in crude oil or in the aqueous phase. For this reason, corrosion by organic acids does not leave any product layers on the metal surface. Corrosion by aliphatic acids normally occurs at temperatures as low as 140 F (60 C) due to their low volatility. On the other hand, corrosion by naphthenic acids normally occurs at temperatures above 430 F (w220 C); the corrosion rate increases with increase of temperature up to between 500 and 700 F (260 and 370 C), and drops above 700–750 F (370–400 C) due to the decomposition of the acids. Aromatic acids are not normally corrosive.
4.13.1 Aliphatic acids The presence of acetic acid in oilfield brines can significantly increase the rate of corrosion of carbon steel, even if the bulk pH is high due to the presence of bicarbonate ions. Although the presence of acetic acid affects the corrosion rate, it does not necessarily affect the corrosion mechanism (see section 5.24). The species increases the corrosion rate by locally decreasing the pH and dissolving the iron carbonate surface layer. As a result, the thickness of the iron carbonate surface layer is locally reduced. Acetic acid also interferes with the chemical analysis of bicarbonate ions resulting in overestimation of the concentration of bicarbonate ions. For these reasons, the effect of acetic acid is commonly known as a ‘double whammy effect’; i.e., acetate ions lead to overestimation of the concentration of bicarbonate ions (thus underestimation of sweet corrosion rate) and itself increases corrosion rate.176
4.13.2 Naphthenic acids Corrosion by naphthenic acids normally occurs at temperatures above 430 F (w220 C) during refinery processing. For this reason, the concentration of naphthenic acids in crude oil is routinely determined before processing. The crude oil is titrated with potassium hydroxide (KOH) and the resultant value is known as ‘neutralizing number’ or ‘acid number’ or total acid number (TAN). The TAN is expressed as milligrams of KOH required to neutralize the acidity of one gram oil. Standards providing procedures to determine the naphthenic acid content of crude oils include: • •
ASTM D664, ‘Standard Test Method for Acid Number of Petroleum Products by Potentiometric Titration’ ASTM D974, ‘Standard Test Method for Acid and Base Number by Color-Indicator Titration’
As a rule of thumb, crude oils with TAN values greater than 0.5 and refined fractions with TAN values greater than 1.5 are considered corrosive.177 However, the corrosivity of different oils with same acid number may not be the same. Corrosivity also depends on other parameters including temperature,
4.14 Mercury
239
type of acid and the presence of other chemicals, e.g., sulfide. Depending on the presence of a sulfide surface layer, naphthenic acid corrosion may be classified into three types: • • •
Pure naphthenic acid corrosion with no or little effect of sulfur compounds. Sulfidation corrosion, i.e., accelerated corrosion due to the destruction of a sulfide surface layer by naphthenic acid. Inhibited naphthenic acid corrosion, i.e., inhibition of naphthenic acid corrosion due to the presence of a sulfide surface layer.
This property is utilized during refining crudes with higher TAN and high sulfur contents. The highTAN crudes and high sulfur crudes are often blended together to control corrosion. The forms of sulfur involved in this process and the threshold amounts have not been established.
4.14 Mercury Mercury (Hg) in natural gas streams was first recognized in gas fields in Asia. Since then production of Hg in natural gas has been observed in many fields. Though handling of Hg is a health concern, from the perspective of corrosion, liquid metal embrittlement (LME) is of concern. Mercury forms amalgams (liquid solutions) with many metals including aluminum, tin, gold, silver, and zinc. In general, aluminum oxide protects Al. When Hg contacts an Al surface, it breaks the aluminum oxide, wets the surface and forms an amalgam. As a consequence of the amalgam, the mechanical strength of the metal is lost. The Al amalgam also reacts with moisture, producing aluminum hydroxide and regenerating Hg. The aluminum hydroxide grows as a characteristic tree-like structure. As a consequence of this self propagation, the corrosion rate of Al can be as high as 40 inch/y (w1 meter/y), with corrosion products appearing on the surface dramatically and rapidly. Table 4.14 presents the interaction of Hg with other metals.178
Table 4.14 Effect of Mercury on Metals178 Metal
Effect of Hg
Remarks
Carbon and low alloy steel
No effect
Type 304 SS
Sensitization
Carbon steel piping and vessels are used in the presence of Hg without loss of integrity The fracture surface of the sensitized material exhibits intergranular regions
Type 316 SS Type 316L SS Type 321 SS Alloy 800 13% Cr SS Ti Grade 2 alloy Alloy 600 Monel 400
No effect
Sensitization LME
Exhibits intergranular cracking
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114. Schmitt G, Bruckhoff W. Inhibition of Low and High Alloy Steels in the System Brine/Elemental Sulfur/H2S. Corrosion 89, Paper #620. Houston, TX: NACE; 1989. 115. Dillon P. Dissolved Sulfur in Sour Aqueous Environments. MP; April 1997. 72. 116. Al-Hajji JN, Reda MR. Corrosion Behavior of Low-Residual Carbon Steels in a Sour Environment. Corrosion May 1993;49(5):363–71. 117. Dean SW. Velocity – Accelerated Corrosion Testing and Predictions. Materials Performance September 1990:61–7. 118. Bolmer PW. Polarization of Iron in H2S-NaHS Buffers. Corrosion, NACE March 1965;21(3):69–75. 119. Schutt HU, Rhodes PR. Corrosion in an Aqueous Hydrogen Sulfide Ammonia, and Oxygen System. Corrosion December 1996;52(12):947–52. 120. Cheng XL, Ma HY, Zhang JP, Chen X, Chen SH, Yang HQ. Corrosion of Iron in Acid Solutions with Hydrogen Sulfide. Corrosion May 1998;54(5):369–76. 121. Martin RL, Annand RR. Accelerated Corrosion of Steel by Suspended Iron Sulfides in Brine. Corrosion, NACE May 1981;36(5):297–301. 122. Jayalakshmi M, Muralidharan VS. Influence of Sulfur on Passivation of Iron in Alkali Solutions. Corrosion November 1992;48(11):918–23. 123. Smith JS, Miller JDA. Nature of Sulphides and their Corrosive Effect on Ferrous Metals: A Review. Br. Corros. J. 1975;10:136–43. No 3. 124. Sun W, Nesic S, Papavinasam S. Kinetics of Corrosion Layer Formation. Part 2: Iron Sulfide/Carbonate Layers in Carbon dioxide/Hydrogen Sulphide Corrosion. Corrosion 2008;64(7):586–99. 125. Milton C. Kansite: Mackinawite, FeS. Corrosion July 1966;22(7):191–3. 126. Bond DC, Marsh GA. Corrosion of Wet Steel By Hydrogen Sulfide-Air Mixtures. Corrosion, NACE January 1950:22–8. 127. Crowe DC, Tromans D. High-Temperature Polarization Behavior of Carbon Steel in Alkaline Sulfide Solution. Corrosion, NACE March 1988;44(3):142–8. 128. Vedage H, Ramanarayanan TA, Mumford JD, Smith SN. Electrochemical Growth of Iron Sulfide Films in H2S-Saturated Chloride Media. Corrosion February 1993;49(2):114–21. 129. Sorell G, Hoyt WB. Collection and Correlation of High Temperature Hydrogen Sulfide Corrosion Data. Corrosion, NACE May 1956:213t–34t. 130. Dougherty JA. Corrosion Inhibition of Wet, Sour Gas Lines Carrying Elemental Sulfur. Corrosion 92, Paper #2. Houston, TX: NACE; 1992. 131. Huang H, Shaw WJD. Electrochemical Aspects of Cold Work Effect on Corrosion of Mild Steel in Sour Gas Environments. Corrosion November 1992;48(11):931–9. 132. Huang HH, Tsai WT, Lee JT. Electrochemical Behavior of A516 Carbon Steel in Solutions Containing Hydrogen Sulfide. Corrosion, 52 (9): 708–13. 133. Ewing SP. Electrochemical Studies of the Hydrogen Sulfide Corrosion Mechanism. Corrosion, NACE November 1955:497t–501t. 134. Hausler RH, Stegmann DW, Cruz CI, Tjandroso D. Laboratory Studies on Flow Induced Localized Corrosion in CO2/H2S Environments, II. Parametric Study on the Effects of H2S, Condensate, Metallurgy, and Flowrate. Corrosion 90, Paper # 6. Houston, TX: NACE; 1990. 135. Ogundele GI, White WE. Some observations on the corrosion of Carbon Steel in Sour Gas Environments: effects of H2S and H2S/CO2/CH4/C3H8 Mixtures. Corrosion, NACE July 1986;42(7):398–408. 136. Slusser JW, Dean SW, Watkins WR. CO Inhibition of Wet CO2 Corrosion of Carbon Steel. Materials Performance January 1997:40–5. 137. Atkins PW. Physical Chemistry. 6th ed. Oxford University Press; 1998. Henry’s law constant for oxygen Table 7.1 on page 174.
246
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
138. Lewis ME. Chapter 6.2: Dissolved Oxygen. In: Handbooks for Water-Resources Investigation. National Field Manual for the Collection of Water-Quality Data, TWRI Book 9; 2008. U.S. Geological Survey, 12201 Sunrise Valley Drive Mail Stop 412, Reston, VA 20192. 139. White AF, Peterson ML, Solbau RD. Measurement and interpretation of low levels of dissolved oxygen in ground water. Ground Water 1990;28(4):584–90. 140. Obeyesekere Nihal. Personal communication, Based on Presentation at Oil Sands Water Usage Workshop; February 24, 2004. 141. Okada H, Hosoi Y, Naito H. Technical note: Electrochemical Reduction of Thick Rust Layers Formed on Steel Surfaces. Corrosion, N.A.C.E Oct 1970;26(10). 142. Gurry RW. Determination of the Amount of Oxide on the Surface of Iron and Steel by Reduction. Corrosion, N.A.C.E Feb 1970;26(2). 143. Feigenbaum C, Gal-Or L, Yahalom J. Microstructure and Chemical Composition of Natural Scale Layers. Corrosion Feb 1978;34(2). 144. Bornak WE. Chemistry of Iron and its Corrosion Products in Boiler Systems. Corrosion, N.A.C.E March 1988;44(3):154–8. 145. Keiser JT, Brown CW, Heidersbach RH. The oxidation of Fe3O4 on Iron and Steel Surfaces. Corrosion July 1982;38(7):357–60. 146. Lorenz WJ, Mansfeld F. Influence of iron Metal Oxides on Corrosion in Oxygenated Neutral Solutions. Washington: 164th meeting of the Electrochemical Society; 1983. 147. Long GG, Kruger J, Black DR, Kuriyama M. Structure of Passive Films on Iron Using a New Surface-Exafs Technique. J. Electroanal. Chem. 1983;150:603–10. 148. Nishimura R, Araki M, Kudo K. Breakdown of Passive Film on Iron. Corrosion Sept 1984;40(9):465–70. 149. Beavers JA, Thompson NG. Effect of Pit Wall Reactivity on Pit Propagation in Carbon Steel. Corrosion, N.A.C.E Mar 1987;43(3):185–8. 150. Raman A, Kuban B. Infrared Spectroscopic Analysis of Phase Transformation Processes in Rust Layers Formed on Weathering Steels in Bridge Spans. Corrosion, N.A.C.E July 1988;44(7):483–8. 151. Mabuchi K, Horii Y, Takahashi H, Nagayama M. Effect of Temperature and Dissolved Oxygen on the Corrosion Behavior of Carbon Steel in High-Temperature Water. Corrosion July 1991;47(7):500–8. 152. Nasrazadani S, Raman A. Formation and Transformation of Magnetite (Fe3O4) on Steel Surfaces Under Continuous and Cyclic Water Fog Testing. Corrosion April 1993;49(4):294–300. 153. Okada H, Shimada H. Relation Between Manganese Sulfides and Rust Initiation. Corrosion, N.A.C.E March 1974;30(3):97–101. 154. Jelinik J, Neufeld P. Kinetics of Hydrogen Formation from Mild Steel in Water under Anaerobic Conditions. Corrosion, N.A.C.E Feb 1982;38(2):98–104. 155. Gadiyar HS, Elayathu NSD. Corrosion and Magnetite Growth on Carbon Steels in Water at 310 C – Effect of Dissolved Oxygen, pH, and EDTA Addition. Corrosion, N.A.C.E June 1980;36(6). 156. Revie RW, Uhlig HH. Corrosion and Corrosion Control. Figure 7.2, p. 121. J. Wiley and Sons; 2008. ISBN: 978–0-471–73279–2. 157. Matsudaira M, Suzuki M, Sato Y. Investigation of Carbon Steel Passivation Behavior in Deionized Water by Ellipsometry. Corrosion 1981;36(5):267. 158. Revie RW, Uhlig HH. 978–0-471–73279–2. Figure 7.9, p. 130, Corrosion and Corrosion Control. J. Wiley and Sons; 2008. ISBN. 159. Revie RW, Uhlig HH. Corrosion and Corrosion Control. Section 7.3.2., p. 139. J. Wiley and Sons; 2008. ISBN: 978–0-471–73279–2. 160. Whitman W, Russell R, Altieri V. Ind. Eng. Chem 1924;16:665, American Chemical Society. 161. Arrigton S. Pipeline Debris Removal Requires Extensive Planning. Pipeline and Gas Journal 2006; 233(11):77.
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162. McLaury BS, Shirazi SA, Shadley JR, Rybicki EF. How Operating and Environmental Conditions Affect Erosion. Corrosion/1999, Paper No. 34. Houston, TX: NACE; 1999. 163. Rincon H, Chen J, Shadley J. Erosion Corrosion Phenomena of 13Cr Alloy in Flows Containing Sand Particles. Corrosion/2002, Paper No. 02493. Houston, TX: NACE; 2002. 164. Little BJ, Ray RI, Pope RK. Relationship between corrosion and the biological sulfur cycle: A Review. Corrosion 2000;56(4):433. 165. Jack TR, Rogoz E, Bramhill B, Roberge PR. The Characterisation of Sulfate Reducing Bacteria in Heavy Oil Waterflood Operations. In: Kearns JR, Little BJ, editors. Microbiologically Influenced Corrosion Testing. PA: ASTM: West Conshohocken; 1994. p. 108. 166. Videla HA. Manual of Biocorrosion. New York: CRC Lewis Press; 1996. 273. 167. Edwards, editor. Environmental Monitoring of Bacteria. Totowa: Human Press; 1999. p. 333. 168. Ohata Y, Sumida K, Nakada Y. Purification and properties of a sulfide-oxidizing enzyme from Strptomyces sp. strain SH91. Canadian Journal of Microbiology 1997;43:1097–101. 169. Beijerink MW. Archives of Exact and Natural Sciences (Dutch Journal) Haarlem. Series II 1904:131. 170. Papavinasam S. NACE Corrosion Technology Week 2009, “Sour Corrosion - Technical Information Exchange”, NACE International, Houston, TX: NACE, 2009. 171. Rogers WF. Calculation of the pH of Oil Well Waters. Corrosion December 1956;12:595t–601t. 172. Hefler JR. Determination of Saturation pH by Hand Calculator. Materials Performance April 1983:20–2. 173. Miyasaka A. Thermodynamic Estimation of pH of Sour and Sweet Environments as Influenced by the Effects of Anions and Cations. Corrosion 92, paper #5. 174. Crolet JL, Bonis MR. An Optimized Procedure for Corrosion Testing Under CO2 and H2S Gas Pressure. Materials Performance July 1990:81–6. 175. Staples BR, Holcomb GR, Cramer SD. Calculation of pH for High-Temperature Sulfate Solutions at High Ionic Stengths. Corrosion 1992;48(1):35–41. 176. Hedges B, McVeigh L. The Role of Acetate on CO2 Corrosion: The Double Whammy. Corrosion 1999, Paper #21. Houston, TX: NACE; 1999. 177. Lewis KR, Daane ML, Schelling R. Processing Corrosive Crude Oils. Corrosion 1999, Paper #377. Houston, TX: NACE; 1999. 178. Craig B. Oilfield Metallurgy and Corrosion. 3rd ed.; 2005. Section: Effect of Mercury on Production Equipment, p. 197, MetCorr, 4600 South Ulster Street, Suite 700, Denver, Colorado 80237, ISBN: 0–9760400–0-X.
The Main Environmental Factors Influencing Corrosion
4
4.1 Introduction Chapter 3 discusses the nature of materials and how their properties influence the corrosion tendency and the rate. This chapter discusses the influence of environmental factors on corrosion. The rate at which corrosion takes place depends on several environmental factors including flow, pressure, temperature, oil phase composition, aqueous phase composition (salts and organic acids), gas phase composition (CO2, H2S, O2), solids, microbes, and mercury. Table 4.1 presents the oil and gas sectors in which these factors predominantly influence corrosion. Other factors might have additional effect on the corrosion type and corrosion rate and should be considered in a given operating environment.
4.2 Flow To transport hydrocarbons, the oil and gas industry uses pipes and pipelines operated under pressure. The pressure is the force that moves the hydrocarbons. An important consideration in designing and operating piping and pipeline is to estimate the amount of pressure required to transport the hydrocarbons. Bernoulli’s equation explains the pressure of a pipeline,1 according to which: Static Pressure þ Dynamic Pressure ¼ Constant:
(Eqn. 4.1)
Static pressure is the pressure exerted by a column of standing fluid. Dynamic pressure is the pressure exerted by a moving fluid. Figure 4.1 illustrates Bernoulli’s principle. Fluid velocity is lower in Sections A and C than that in Section B. Therefore the static pressure is higher in Sections A and C than in Section B. It should be noted that the velocities (distance travelled per unit time) of fluids in various sections are different, but the mass transferred per unit time is the same in all sections. The pressure is often indicated in the oil and gas industry by the term ‘head’ (H). This represents the pressure exerted by a column of liquid. A one foot high column of water exerts a pressure of 0.433 psi. In other words, the pressure measured as 1 psi is equivalent to the pressure exerted by a column of water of 2.31 feet high, i.e.: 1 psi=0:433 psi=ft ¼ 2:31 ft of head of water (Eqn. 4.2)
Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00004-2 Copyright Ó 2014 Elsevier Inc. All rights reserved.
179
180
Table 4.1 Environmental Factors Influencing Corrosion Environmental Factors
Component
Flow
Oil
Water
CO2
H2S
O2
Solid
Microbe
Pressure
Temperature
pH
acid
Hg
Production
Drill Pipe
No
No
Yes
Yes
Yes
No
Yes
No
No
Yes
No
No
No3
Casing Pipe
No
No
Yes
Yes
Yes
No
No
Yes
Yes
Yes
Yes
No
No
Downhole Tubular
Yes
Yes
Yes
Yes
Yes
No1
Yes
Yes
Yes
Yes
Yes
No
No3
Acidizing Pipe
Yes
No
Yes
No
No
No1
No
No
No
Yes
Yes
No
No
Water Generators
Yes
No
Yes
No
No
No
No
Yes
No
Yes
Yes
No
No
Gas Generators
Yes
No
Yes
No
No
No1
No
No
Yes
Yes
No
No
No
Open Mining
No
No
Yes
No
No
No
Yes
No
No
Yes
No
No
No
In situ Production
Yes
Yes
Yes
Yes
Yes
No1
Yes
No
Yes
Yes
Yes
Yes
No3
Wellhead
No1
Yes
Yes
Yes
Yes
No1
Yes
No
Yes
Yes
Yes
Yes
No3
No
1
Yes
Yes
Yes
Yes
Yes
Yes
No3
No
1
Yes
Yes
No
Yes
No
Yes
No3
Production Pipelines Heavy Crude Oil
Yes
Yes
Yes
Yes
Yes
Yes
Yes
1
No
No
1
1
Yes
Yes
Yes
No2
No2
No1
Yes
No
Yes
Yes
Yes
Yes
No3
No
Yes
Yes
Yes
Yes
No1
No
Yes
No
Yes
Yes
Yes
No3
1
No
No
No
Yes
Yes
No
No3
No
Pipelines Hydrotransport Pipelines Separators Gas Dehydration
No
No
Yes
yes
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
Yes
No3
Facilities Recovery Centers (Extraction) Upgraders
See refinery section
Waste Water Pipelines
Yes
No
Yes
No
No
No1
Yes
No
No
No
Yes
No
No
Tailing Pipelines
Yes
No
Yes
No
No
No1
Yes
No
No
No
Yes
No
No
Lease Tanks
No
Yes
No4
No
No
No
No4
No4
No
No
No
No
No
Transmission-
Transmission Pipelines
Yes
Yes
No4
No
No
No1
No4
No4
Yes
Yes
No
No
No
pipeline
(Midstream Pipelines)
TransportationTanker
Compressor Stations
Yes
No
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No3
Pump Stations
Yes
Yes
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No3
Pipeline Accessories
Yes
Yes
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No3
Ships
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Org. Sector
Storage
Refineries
LNG Tanks
No
No
No4
No
No
No1
No4
No4
No
No
No
No
No
Railcars
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
Other modes
No
No
No4
No
No
No1
No4
No4
No
No
No
No
No
Gas Storage
No
No
No4
No
No
No
No4
No4
No
No
No
No
No
Oil Storage
No
Yes
No4
No
Yes
No
No4
No4
No
No
No
No
No
Desalter
Yes
Yes
Yes
No
No
No
Yes
No
Yes
Yes
Yes
Yes
No
Atmospheric
No
Yes
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Vacuum distillation
No
Yes
Yes
No
Yes
No
No
No
No
Yes
No
Yes
No
Hydrotreating
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No3
Catalytic reforming
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No3
Visbreaker
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Coker
No
Yes
No
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Alkylation
No
Yes
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Gas treating
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Sour water stripper
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Hydrodesulfurization
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Sulfur recovery
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Heat exchanger
No
No
Yes
No
Yes
No
No
No
Yes
Yes
No
Yes
No
Product Pipelines
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
Terminals
No
Yes
No4
No
No
No1
No4
No4
No
No
No
No
No
1
4
No4
No
No
No
No
No
distillation
Distribution
City Gates and Local
4
No
No
No
No
No
No1
No4
No4
No
No
No
No
No
No
No
No
1
4
No4
No
No
No
No
No
No
No
No
No
No
No4
No
Distribution CNG Tanks Special
4
No
No
Yes
No
CO2 Pipelines
No
No
Yes5
Yes5
Yes5
Yes5
No4
No4
Yes
Yes
No
No
No
Biofuel Infrastructure
Yes
Yes6
No4
No
No
No1
No
No4
No
Yes
No
Yes
No
High Vapor Pressure
No
No
No4
No
No
No1
No4
No4
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
No
No
No
Pipelines Hydrogen Pipelines 1
Unless operational deficiency accidentally lets them inside the system though may present the influence is minimal due to the influence of other components 3 only affect aluminum components 4 unless operational deficiency lets them accumulate at the bottom for prolonged duration 5 if intentionally left in the stream 6 in the form of biofuel
4.2 Flow
Diluent Pipelines
2
181
182
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.1 Bernoulli Principle.4 Reproduced with permission from PennWell Corporation.
The head of other liquids is estimated by dividing the head of water by the specific gravity of that liquid. Thus:2 H¼
2:31:P SG
(Eqn. 4.3)
where H is the head in feet, P is the pressure in psi, and SG is the specific gravity. H¼
P 9:7928:SG
(Eqn. 4.4)
where H is the head in meters and P is the pressure in kPa. In order to fully understand the effect of flow on corrosion, four parameters should be understood: pressure drop, flow regime, water accumulation, and critical flow rate.
4.2.1 Pressure drop One of the important calculations in designing and operating infrastructure is to determine the pressure drop. This is a combination of the static pressure (static head) due to the difference in elevation between the upstream and downstream locations and the dynamic pressure (dynamic head) due to energy loss from the flow of liquid. The static pressure remains constant once the infrastructure is constructed, but the dynamic pressure varies constantly because the type of phases (oil, water, and gas), number of phases (single, two, and multi), and volumes of different phases change constantly during operation. The combined pressure drop (caused by both static and dynamic heads) is typically represented by a System Head Curve (SHC). Figure 4.2 presents a typical SHC.3 Infrastructures operate over a wide range of SHCs. Appropriate pumps or compressors are selected on the basis of the anticipated SHCs over the entire operating life of the infrastructure. Methods to calculate the pressure drop in various types of flow are described in the following sections.
4.2 Flow
183
FIGURE 4.2 Typical System Head Curve.3 Reproduced with permission from ASME.
4.2.1a Single phase liquid Single phase flow may be laminar flow or turbulent. In general, the Reynolds number is used to differentiate laminar and turbulent flows. If the Reynolds number (Re) is less than 2,000 the flow is laminar, and if it is above 2,000 the flow is turbulent. Sometimes the flow between Re 2,000 and 4,000 is considered as transitional flow, and above 4,000 it is considered as turbulent. Re is defined as: Re ¼
3160 U di $v
(Eqn. 4.5)
where U is the liquid flow rate (gallons per minute [gpm]), di is the inner pipe diameter (inch), and n is the kinematic viscosity (centistokes). Kinematic viscosity, in stokes, is calculated using Eqn. 4.6: v¼
hl $10000 rl
(Eqn. 4.6)
where hl is the liquid viscosity in kg/ms and rl is the liquid density in kg/m3. The downstream pressure, Pd (psi), of a laminar flow with no elevation change, is calculated as: Pd ¼ Pu 0:0134
f $L$SG$U 2 di 5
(Eqn. 4.7)
where Pu is the upstream pressure (psi), f is the friction factor (dimensionless), L is the length of the pipe (ft), SG is the specific gravity of liquid relative to water, U is the liquid flow rate (gpm), and di is the inner pipe diameter (in).
184
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
The friction factor, f, is dimensionless and is calculated using either Eqn. 4.8 (smooth surface) or Eqn. 4.9 (rough surface): 64 (Eqn. 4.8) f ¼ Re εpipe 1=3 (Eqn. 4.9) f ¼ 0:0055 þ 0:15 di where εpipe is the surface roughness (m) and di is the inner pipe diameter (m). The friction factor, pipe roughness, pipe diameter, and Reynolds number are interrelated. Moody diagram is commonly used to indicate this relationship (Figure 4.3).4 If the elevation of the pipeline changes, then Eqn. 4.10 is used to calculate the downstream pressure (Pd, kPa) of a laminar flow. U$L$SG$n Pd ¼ Pu DPE;L (Eqn. 4.10) C3 $di4 where Pu is the upstream pressure (kPa), U is the flow rate (m3/hr), L is the length of the pipe (km), SG is the specific gravity of liquid relative to water (dimensionless), n is the kinematic viscosity (centistokes), C3 is a conversion constant (8.61E06), and di is the inner pipe diameter (mm), and DPE,L is the difference in pressure due to elevation change and is calculated using Eqn. 4.11. DPE;L ¼ CE $SG$ Hd Hu (Eqn. 4.11) where CE is the conversion constant to convert the result to kPa/m (0.0999); SG is the specific gravity of liquid relative to water (dimensionless); Hd is the downstream elevation (m); and Hu is the upstream elevation (m). For heavy crude with viscosity higher than 1,000 cP flowing in the laminar region the pressure drop can be determined as:4,5 " # Cu U 2 f CHead ðHd Hu Þ Pd ¼ Pu SG:DLpipe þ (Eqn. 4.12) DLpipe di5 where Pu is the pressure at the upstream end of the segment; Pd is the pressure at the downstream end of the segment; DLpipe is the length of the segment; f is the friction factor; di is the internal diameter of the pipe; SG is the liquid specific gravity; Hu is the elevation at the upstream end of the segment; Hd is the elevation at the downstream end of the segment; Cu is the flow conversion constant; and CHead is the head conversion constant. The downstream pressure of a turbulent liquid flow, Pd in kPa is calculated as: Pd ¼ Pu DPE;L
f $L$SG$U 2 C42 $di5
(Eqn. 4.13)
where Pu is the upstream pressure (kPa); DPE,L the pressure drop due to elevation change (kPa), L is the length of the pipe (km), U is the liquid flow rate (m3/hr); C4 is a conversion constant (19.8072E06), and di is the inner pipe diameter (mm). For liquid pipelines, the velocity and density do not change significantly along the length of a given pipeline if diameter and temperature are constant. Therefore the pressure loss per length is first
Values of (Vd) for water at 60°F (velocity. ft/s = diameter. m) 0.1
0.2
0.4 0.6 0.8 1
2
4
6 8 10
20
40
60 80 100
200
400 600 800 1000
Values of (Vd) for atmospheric air at 60°F 2
0.10
20
Laminar Critical flow zone Transition zone
40
60 100
200
400 600 800 1000 2000
4000
80,000 8000 6000 10,000 20,000 40,000 60,000 100,000
Complete turbulence, rough pipes
0.05 0.04
0.07 0.06
0.03 Lam
ε
2
(
h
L V d 2g
Friction factor ƒ =
flow 64
ƒ = Re
0.04
0.02 0.015
inar
)
0.05
0.01 0.008 0.006
0.03 0.025
0.004
Recr
0.002 0.001 0.0008 0.0006 0.0004
0.02
Sm
0.015
oo
th
0.0002
pip
es
0.0001 0.000,05
0.01 0.009 103 2(103) 3
4 5 6
8
104 2(104) 3
4 5 6
8
105 2(105) 3
4 5 6
Reynolds number Re =
8
106 2(106) 3
Vd v
4 5 6
8
107 2(107)
ε = 0.000,001 d
3
4 5 6
0.000,01 108
8
ε = 0.000,005 d
4.2 Flow
0.008
d
0.08
5 8 10
8000 4000 6000 10,000
Relative roughness
0.09
4
2000
FIGURE 4.3 Moody Diagram.4
185
Reproduced with permission from ASME.
186
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
calculated, and multiplying this value by the total length produces the total pressure drop for the entire length. When two or more products of different densities and viscosities are transmitted in the pipeline, the weighted average of the densities and viscosities are first calculated. The weighted average values are then used in Eqn. 4.13 to calculate the pressure drop.
4.2.1b Single phase gas The downstream pressure of a single gas pipeline, P2 (psi), is calculated as: !0:5 Ub 2 $Pb 2 $Zave $Tave $SGgas $L 2 . DPE Pd ¼ P u CSPG 2 $Tb 2 $1 f $di5
(Eqn. 4.14)
where Pd is the downstream pressure (psi), Pu is the upstream pressure (psi), Ub is the gas flow rate at base conditions (SCF/d), Pb is the pressure under base conditions (14.7 psi), Zave is the average compressibility factor (dimensionless (see section 4.2.1b.i)), Tave is the average temperature ( R), SGgas is the gas gravity (dimensionless), L is the length of the pipe (miles), CSPG is a constant 38.774, Tb is the temperature at base condition (520 R), 1/f is the transmission factor (dimensionless (see section 4.2.1b.iii)), di is the inner pipe diameter (inches), and DPE is the difference in pressure due to elevation change (see section 4.2.1b.ii).
i. Calculation of Zave Gases are compressible. Therefore the calculation of a pressure drop in the gas phase includes a correction for the compressibility. For an ideal gas, the molecules can be treated as point particles with no interaction between them. For an ideal gas, the relationship between pressure, volume, and temperature is given as: PV ¼ nRT
(Eqn. 4.15)
where P is the pressure, V is the volume, n is the number of moles, R is the constant, and T is the temperature. Under standard pressure and temperature conditions most of the real gases follow Eqn. 4.15, but not at higher pressure and higher temperature. At higher pressures, the gas molecules frequently collide with one another as well as with the walls of the container, and at higher temperatures the molecules move faster. As a consequence, under high pressure and high temperature the molecules interact (attract or repel each other). This behavior can be accounted for by the compressibility factor, Zgas: Zgas ¼
PV nRT
(Eqn. 4.16)
The value of Zgas generally increases with pressure and decreases with temperature. Figures 4.4 and 4.5 present typical values of Zgas for some commonly used gases.6,7 The value of Zgas is a function of the reduced pressure, Pr and the reduced temperature Tr. The reduced pressure is the ratio of the actual pressure to the critical pressure, Pcrit. Similarly, the reduced temperature is the ratio of the actual temperature to the critical temperature, Tcrit. The critical pressure is the minimum pressure required to compress a gas into liquid at its critical temperature, and the critical temperature is the temperature beyond which a gas cannot be compressed into a liquid. Figure 4.6 presents a commonly used graph to
4.2 Flow
187
Pseudo reduced pressure 1
0
2
3
1.1
4
5
6
7
Pseudo reduced temperature 3.0 2.8 2.6 2.4 2.2 2.0 1.9 1.8
1.0
0.9
8 1.1 1.05 1.0 1.2 0.95
1.5
1.7
1.1
1.4 05 1. 1 1.
1.6 0.8
1.3
1.5
1.7
1.45
1.35
1.6 3
1.
1.3 4
0.6
1.
1.25
1.5 1.6 1.7
1.2 0.5
1.8 1.9 2.0 2.2
5
1.1 0.4
2.4
1.1
1.5
1.4
Compressibility factor Z
Compressibility factor Z
2
1.
1.4
0.7
1.3
2.6 3.0
0.3
1.2
5
1.0
0.25 2.8
1.1
3.0
1.1
2.6 2.4 2.2 2.0 1.9 1.8
1.0
1.1 1.05
1.2
1.0 January 1, 1941
1.7 1.6
0.9
1.4 1.3
7
8
9
10
11
12
13
14
0.9 15
Pseudo reduced pressure
FIGURE 4.4 Compressibility Factors for Natural Gases.6 Reproduced with permission from McGraw-Hill.
correlate Zgas with Pr and Tr.8 Table 4.2 presents critical temperatures and pressures of some hydrocarbons.9 The average compressibility factor, Zave is then calculated from the percentages of various gases and their respective compressibility factors (Table 4.2): Zave ¼
Pave :V nR:Tave
(Eqn. 4.17)
188
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
0.9
0.8
Z
0.7
0.6 800 psia 1150 psia 1350 psia 1675 psia 2140 psia
0.5
0.4
0
5
10
15
20
25
30
35
40
Ethane, mole %
FIGURE 4.5 Compressibility Factors for Mixed Gases.7 Reproduced with permission from NOVA Chemicals.
where Pave is the average pressure and Tave is the average temperature, which are calculated using Eqns. 4.18 and 4.19 respectively: Pave ¼ Pca :Ya þ Pcb :Yb þ Pcc :Yc þ :::
(Eqn. 4.18)
Tave ¼ Tca :Ya þ Tcb :Yb þ Tcc :Yc þ :::
(Eqn. 4.19)
where Ya, Yb, etc. are the percentages of gases and Pca , Pcb, etc. and Tca, Tcb, etc. are the critical pressures and critical temperatures of the corresponding gases, respectively.
ii. Calculation of potential energy Potential energy, DPE,G, i.e., the pressure drop due to elevation change in single phase gas flow, is calculated as: 0:0375SGgas $ Hd Hu $P2ave DPE;G ¼ (Eqn. 4.20) Tave $Zave where SGgas is the gas gravity (dimensionless); Hd is the downstream elevation (ft); Hu is the upstream elevation (ft); Pave is the average pressure (psi); Tave is the average temperature ( R); and Zave is the average compressibility factor. Alternatively some constant values of DPE are assumed. Some commonly used approximate values of DPE are:10 1 for new pipe with no bends, fittings, or pipe diameter changes; 0.95 for very good operating conditions, typically for the first 12–28 months; 0.92 for average operating conditions; and 0.85 for unfavorable operating conditions.
4.2 Flow
189
1.125 ture, Tr
Reduced Tempera
4 3 2.6 2.2 2.1 2.0 1.9 1.8 1.7 1.6
1.000
1.55 1.50 1.45
0.750
1.40
5 1.3 0 1.3 5 1.2 0 1.2 5 1.1
0.625
1. 1. 00 05
Supercompressibility Factor, Z
0.875
0.500
P Reduced Pressure, Pr = — Pc
0.375
T Reduced Temperature, Tr = — Tc 0.250
0.125 1
2
3
4
5
6
7
8
9
Reduced Pressure, Pr
FIGURE 4.6 Correlation between Compressibility Factors and Critical Pressure and Critical Temperature.8 Reproduced with permission from Taylor & Francis.
iii. Calculation of transmission factor Table 4.3 presents four common methods for calculating transmission factors. The Weymouth method is used for high flow-rate, large diameter, and high pressure pipelines; the Panhandle A method is used for medium to relatively large diameter pipeline with moderate flow rate, operating under medium to high pressure; the Panhandle B method is used for high flow rate, large diameter (i.e. larger than NPS 24), high pressure pipelines; and the American Gas Association (AGA) Fully Turbulent method is used for high pressure, high flow rate, medium to large diameter pipelines.
4.2.1c Two-phase liquid-gas In two-phase liquid-gas flow, the volume occupied by the gas is physically negligible due to its compressibility. Therefore, the two-phase liquid-gas calculation is only used when the gas flow rate is greater than 3,500,00 ft3/d(w100,000 m3/d). Below this gas production rate, either the single phase liquid (see section 4.2.1a) or single phase gas calculation (see section 4.2.1b) is used depending on the production rates of liquid and gas. Several methods can be used to calculate the pressure drop in a two-phase liquid-gas flow. Only the simple approach is described in this section. In this approach the pressure drop in a
190
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Table 4.2 Critical Properties of Certain Gases9
Gas Methane Ethane Propane Isobutane n-butane Hydrogen n-pentane n-hexane n-heptane n-ocatane n-nonane n-c10 n-c11 n-c12 Air Nitrogen Oxygen CO2 H2S He
Molecular Weight (lbm/mole) 16.04 30.07 44.09 58.12 58.12 2.02 72.15 86.18 100.21 114.23 128.26 142.29 156.30 170.34 29 28.02 32.0 44.01 34.08 4.00
Critical Temperature, Tcri ( R)
K
343.3 549.8 666.0 734.7 765.3 60 845.6 913 972 1,024 1,070 1,112 1,150 1,185 238.4 226.9 277.0 547.7 672 9
Critical Pressure, Pcrit MPa
Psi
191 305 370 408 425
4.6 4.88 4.25 3.65 3.8
470 507 540 569 595 618 639 658 132 126 155 304 373 5
3.37 3.01 2.74 2.49 2.29 2.10 1.97 1.82 3.77 3.4 5.04 7.38 8.96 0.23
673.1 708.3 617.4 529.1 550.7 189.0 489.5 437 397 361 332 305 285 264 547.0 492.0 730.0 1073.0 1,300 33
Table 4.3 Transmission Factors Transmission Factor
Formulae
Weymouth
pffiffiffiffiffiffiffi 1=6 1=f ¼ 11:19di pffiffiffiffiffiffiffi Ug SGgas 0:07305 1=f ¼ 7:211 di Where Ug is the flow rate of gas (ft3/h)
Panhandle A
Panhandle B
pffiffiffiffiffiffiffi Ug SGgas 0:01961 1=f ¼ 16:70 di
AGA fully turbulent
pffiffiffiffiffiffiffi 3:7di 1=f ¼ 4log Ke Where Ke is the effective roughness (in.)
Compressibility Factor, Zgas 0.290 0.285 0.277 0.283 0.274 0.304 0.269
e 0.291 0.292 0.274
4.2 Flow
191
two-phase liquid-gas flow (DPLG) can be determined based on the pressure drop in a single phase gas flow as:11 DPLG ¼ DPG 42
(Eqn. 4.21)
where 4 is the two-phase flow modulus. The values of 4 depend on Lockhart-Martinelli two-phase modulus XLM, which is defined as: vffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi !0:2ffi u 1:8 u U r h g l XLM ¼ t $ l $ (Eqn. 4.22) Ug rl hg where Ul is the liquid flow rate (lb/h), Ug is the gas flow rate (lb/h), rg is the gas density (lb/ft3), rl is the liquid density (lb/ft3), hl is the viscosity of liquid (centipoise), and hg is the viscosity of gas (centipoise). The relationship between 4 and XLM depends on the flow regime. For annular, annular mist, and wispy flow (see section 4.2.2 for flow regimes): 0:3430:021di 4 ¼ 4:8 0:3125di XLM
(Eqn. 4.23)
where di is inner pipe diameter in inches. For bubble flow: 14:2X 0:75 4 ¼ . LM 0:1 Ul A
(Eqn. 4.24)
where A is the cross sectional surface area of the pipe (ft2). For plug flow: 27315X 0:855 4 ¼ . LM 0:17 Ul A
(Eqn. 4.25)
1190X 0:815 4 ¼ . LM 0:5 Ul A
(Eqn. 4.26)
15400XLM 4 ¼ . 0:3 Ul A
(Eqn. 4.27)
For slug, churn, and oscillator flows:
For stratified flow:
For dispersed flow: 4 3 2 42 ¼ 0:00003:XLM þ 0:0048:XLM 0:2415:XLM þ 7:6125:XLM þ 6:5734
(Eqn. 4.28)
192
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.2.1d Two-phase liquid-liquid When two immiscible liquids, e.g., oil and water, are transported, the pressure drop is calculated as per section 4.2.1a, except that the mixed viscosity is used in Eqns. 4.6 and 4.10. The mixed viscosity is calculated as: Vo :ho þ Vw :hw hl ¼ (Eqn. 4.29) V o þ VW where hl is the viscosity of liquid, ho and hw are viscosities of oil and of water respectively, and Vo and Vw are the volumes of oil and water respectively.
4.2.1e Two-phase liquid-solid The solid content in most of the oil and gas industry infrastructure, except hydrotransport pipelines, is relatively low. Therefore the effect of solid on the pressure drop may conveniently be neglected. The head loss due to slurry flow in hydrotransport pipelines compared with water flow at the same flow velocity is expressed as:12 ! DPsolid DPL fdi rs ¼f : 1 (Eqn. 4.30) ½SolidDPL Ul2 rl where DPSolid is the pressure drop in the liquid containing solids (e.g., hydrotransport pipeline); DPL is the pressure drop in liquid flow (see section 4.2.1a); [Solid] concentration of solids; f is the friction factor; di is the internal diameter of pipe; Ul is the liquid flow rate; rs is the density of solids; and rl is the density of liquid.
4.2.1f Two-phase gas-solid The solids present in a gaseous flow may include corrosion products, e.g., iron sulfides, sands, debris, and other impurities. The solid content in gas pipelines is relatively low in most cases, and hence its effect on the pressure drop may conveniently be neglected. The pressure drop in gas-solid flow is therefore calculated using the equations presented in section 4.2.1b.
4.2.1g Three-phase liquid-liquid-gas Multiphase pipelines may transport oil, water, and gas. Very little information is available on threephase flow. The pressure drop in three-phase liquid-liquid-gas flow can be calculated by considering oil and water as one phase, and calculating the viscosity of this phase using Eqn. 4.29. With this consideration, the two-phase liquid-gas equation (see section 4.2.1c) is used to calculate the pressure drop in three-phase flow.
4.2.1h Series pipeline The pressure drop of a pipeline in series with different diameters (Figure 4.7)13 can be calculated by calculating the pressure drop in adjacent sections individually as: nPD P21;S P22;S ¼ k1;S Ub;S
(Eqn. 4.31)
nPD P22;S P23;S ¼ k2;S Ub;S
(Eqn. 4.32)
nPD P23;S P24;S ¼ k3;S Ub;S
(Eqn. 4.33)
4.2 Flow
k1,S Ub
P1
k2,S Ub
P2
193
k3,S Ub
P3
P4
FIGURE 4.7 Pipeline in Series.13
Then the pressure drop across the entire section is given as: nPD nPD P21;S P24;S ¼ kT;S Ub;S ¼ k1;S þ k2;S þ k3;S :Ub;S kS ¼ RPD :L
(Eqn. 4.34) (Eqn. 4.35)
where P1,S, P2,S, P3,S and P4,S are respectively the pressure drops at segments 1, 2, 3, and 4 of pipeline in series; k1,S, k2,S, k3,S and kT,S are the pipeline resistance in segments 1, 2, 3, and total respectively; RPD is the resistance per foot of pipeline; L is the length of pipeline in feet; Ub is the gas flow rate at base conditions; and nPD is the flow exponent (value ranges between 1.74 and 2.00). Equation 4.36 presents a simple equation to calculate RPD; several more complicated and more accurate equations are also available:13 Tf RPD ¼ 4:82 104 5 $SG0:855 (Eqn. 4.36) g di where Tf is the temperature constant and is equal to 520 R and SGg is specific gravity of gas.
4.2.1i Parallel pipelines Flow in the pipeline is diverted into two parallel lines (i.e., looped pipeline) to reduce resistance to flow. Figure 4.8 presents an example of looped pipeline.14 The pressure drop in each segment can be calculated as: nPD P21;P P22;P ¼ k1;P Ub1
(Eqn. 4.37)
nPD P21;P P22;P ¼ k2;P Ub2
(Eqn. 4.38)
k1;P :k2;P nPD kT;P ¼ 1=nPD 1=n k1;P þ k2;P PD
(Eqn. 4.39)
194
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Ub,1 K1 P P1,P P2,P
Ub
Ub
K2 P
Ub,2
FIGURE 4.8 Pipeline in Parallel.14
where P1,P and P2,P are the pressure drops in parallel pipeline segments 1 and 2 respectively; k1,P, k2,P, and kT,P are the pipeline resistance in segments 1, 2, and total respectively; Ub is the gas flow rate at base conditions; and nPD is the flow exponent (value ranges between 1.74 and 2.00). By calculating the resistance to flow in individual segments using Eqn. 4.35, the total resistance (kT,P) in the entire loop is calculated. Then the pressure drop at the exit point of the looped segment can be calculated.
4.2.1j Expansion of cross-section15 If the cross-section of a pipe is suddenly enlarged, the fluid stream separates from the wall and flows as a jet into the enlarged section. The fluid then expands to fill the entire cross-section of the larger conduit (Figure 4.9). Considerable friction is generated in the space between the expanding jet (smaller pipe) and the larger pipe completely filled with fluid. The pressure drop from a sudden expansion of cross-section is given as: 2 dup;Ex 2 2 Uup;Ex (Eqn. 4.40) PEx ¼ 1 ddown;Ex 2g where PEx is the pressure drop at pipeline expansion, ft; dup,Ex is the diameter of pipeline upstream to expansion; ddown,Ex is the diameter of pipeline downstream to expansion; Uup,Ex is the flow velocity in
Va
Sa
Vb
Sb
Direction of flow
FIGURE 4.9 Pipeline with Sudden Expansion.15 Reproduced with permission from Taylor & Francis.
4.2 Flow
195
the smaller (upstream) pipeline segment before expansion, ft/s; and g is the acceleration of gravity (32.2 ft/s2).
4.2.1k Contraction of cross-section15 When the cross-section of the pipe is suddenly reduced, the fluid jet expands downstream from the point of contraction and then establishes a normal velocity distribution. The pressure drop from the sudden contraction may be given as: 2 ddown;Con Udown;Con (Eqn. 4.41) PCon ¼ 0:4 1 dup:Con 2g where Pcon is the pressure drop at pipeline contraction, ft, ddown,Con is the diameter of pipeline downstream of the contraction; dup,Con is the diameter of pipeline upstream to contraction; Udown, Con is the velocity in the smaller (downstream) pipe, ft/s; and g is the acceleration of gravity (32.2 ft/s2). It is important to note that the pressure drop depends on the velocity in the smaller pipe: at expansion it is proportional to the upstream flow, and at contraction it is proportional to the downstream flow. These calculations (discussed in sections 4.2.1j and 4.2.1k) are applicable to turbulent liquid flow only, but not to laminar (the effect of expansion or contraction is negligible) or gaseous flow.
4.2.1l Accessories Valves and fittings also contribute to overall pressure loss. When the ratio of pipeline length to pipe diameter is equal or greater than 1,000 to 1 (e.g., transmission pipelines) with a standard number of fittings and valves, the effect of pressure drop through valves and fittings may be considered as negligible. But in a pumping station, refinery piping, and process piping, where many valves exist over relatively short distances, pressure loss due to valves and fittings is important. Obtaining the pressure drop of every size and type of valve and pipe fitting is difficult. a practical approach is to use the equivalent length method, in which the pressure drop through a valve, fitting, miter elbow, or any component is assumed to be equivalent to the pressure drop of an equivalent length of straight, round pipe. Table 4.4 presents the equivalent length values; it should be noted that these values apply only to single phase, non-compressible liquids in turbulent flow in steel and iron pipe.
Table 4.4 Head Loss in Terms of Equivalent Length (L)16 Type of Bend
Radius
U-bend Z-bend U-bend Z-bend
Short Short Long Long
L/di Ratio 30 30 20 20
Equation Lequivalent Lequivalent Lequivalent Lequivalent
¼ ¼ ¼ ¼
2Haccessories 2Haccessories 2Haccessories 2Haccessories
þ116 di þ 174 di þ 74 di þ 111 di
where Lequivalent is the equivalent length of accessories to calculate pressure drop; Haccessories is the height (or, if horizontal, the width) of the loop, feet; and di is the internal diameter of pipe in feet. These equivalent lengths are based on Lequivalent /di ratio of 30 for short-radius elbows and 20 for long-radius elbows
196
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.2.1m Annular space17 Sometimes the fluids are transported in the annular space between the pipelines, typically between tubing and casing (see Chapter 2). The pressure drop of flow in the annular space may be calculated as follows: For laminar flow: 0:1 di;casing 6 7:95 10 hl LUl d 2 i;casing do;tubing PAnn:Lam ¼ (Eqn. 4.42) 2 di;casing do;tubing di;casing 2 do;tubing 2 1þ 1:5eecc 2 For turbulent flow: PAnn:Tur ¼
11:46 106 SGl :f :Ul2 L 2 di;casing ðdi;casing do;tubing Þ di;casing 2 do;tubing 2 d d i;casing
o;tubing
0:1 2
1þ 1:5eecc 2
0:25
(Eqn. 4.43) where PAnn.Lam is the pressure drop, psi of laminar flow in the annular space; PAnn.Tur is the pressure drop, psi of turbulent flow in the annular space; hl is the viscosity of liquid, cp; L is the length of annulus, ft; Ul is the flow rate, barrel per day; di,casing is the internal diameter of the casing, in.; do,tubing is the outer diameter of the tubing, in.; eecc is the eccentricity of tubes (defined in Eqn. 4.44); SGl is the specific gravity of liquid; and f is the friction factor. Eccentricity of tube, eecc is defined as: 2:dtube:off (Eqn. 4.44) eecc ¼ di;casing do;tubing where dtub.off is the distance tubing is off the center, in.
4.2.1n Transient flow Normally transmission pipelines operate under steady-state conditions when supply and demand are stable. However such ideal situations seldom occur. The flow rate in the pipelines fluctuates on a daily, weekly, monthly, and annual basis. In addition to seasonal variations, large variations in the flow rate may occur during commissioning, during normal operation (e.g., air purging and loading of pipeline and pigging operations) and abnormal operation (e.g., failure of a component). The duration of a transient flow situation and the extent of deviation from steady-state conditions should be analyzed to determine appropriate corrosion factors.
4.2.2 Flow regimes Most of the flow in the oil and gas pipelines involves two or more phases. The two-phase flows may be liquid-gas, liquid-liquid, liquid-solid, or gas-solid. Because the physical properties (density and viscosity) of the phases involved are different, their rates of flow are different. Consequently, multiphase flow can take an infinite number of patterns. Fortunately these patterns can be delineated on the basis of the interfacial distribution between various phases. The delineated patterns are commonly known as flow regimes. The flow regime depends on the position of the pipe (i.e., vertical, inclined, or horizontal), flow rate, flow directions (i.e., upward or downward), and fluid properties (density and viscosity).
4.2 Flow
197
Baker parameter, Bx 105
10–1
1
10
102
103
104
Dispersed
Baker parameter, By
Wave
Bubble or froth
Annular
104
Slug Stratified 103
Plug 102
FIGURE 4.10 Baker Flow Regime Map.18 Reproduced with permission from Taylor & Francis.
4.2.2a Two-phase liquid-gas The flow regime map for gas-liquid flow in a horizontal pipe was first developed by Baker in 1954. Although various other flow regime maps have been developed, the Baker flow regime (Figure 4.10) is still widely used in the oil and gas industry. A Baker flow regime map uses two empirically developed parameters lGLflow and jGLflow defined as:18,19 r r 1=2 g l lGLflow ¼ (Eqn. 4.45) 1:2 1000 " #1=3 0:073 hl 1000 2 (Eqn. 4.46) jGLflow ¼ 103 g rl where rg is the gas density; rl is the liquid density; hl is the liquid viscosity; and g is the surface tension.
i. Vertical upward flow regimes Figures 4.11, 4.12, and 4.13 present flow regimes of vertical upward flow, inclined upward flow (inclination angle up to 10 ), and inclined upward flow (inclination angle between 10 and 45 ) respectively. Common flow regimes of vertical flow are described in the following paragraphs.20–22
198
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
104
Annular Wispy Annular
PG(UG)2 kg m-1 s-2
103
102 Churn Bubble Flow with Developing Structure 10 Plug 1
0.1 1
10
10 10 PL(UL)2 kg m-1 s-2
10
10
FIGURE 4.11 Vertical Upward Flow Regimes.20 Reproduced with permission from Taylor & Francis.
FIGURE 4.12 Inclined Upward Flow Regimes (Inclination Angle up to 10 ).21 (DB Dispersed bubble flow and A is the annular flow). Reproduced with permission from Taylor & Francis.
4.2 Flow
199
FIGURE 4.13 Inclined Upward Flow Regimes (Inclination Angle between 10 and 45 ).22 Reproduced with permission from Taylor & Francis.
Churn flow: This flow occurs at low liquid and gas velocity in which the liquid moves upward and downward creating large bubbles of gas phase surrounded by liquid phase. With increasing flow velocity the bubbles break down leading to an unstable flow regime. Plug flow: At higher liquid flow rates, the bubbles coalesce and eventually the bubble diameter approaches that of the pipe. When this occurs, large, characteristically bullet-shaped bubbles are formed, which may be separated by regions containing dispersions of smaller bubbles. Typically this liquid phase flows down the outside of the large bubbles in the form of a falling liquid film, but because of higher fluid velocity the net flow of both liquid and gas is upwards. In plug flow, falling films may exist if the gas velocity is relatively low. As the gas flow increases, the flow undergoes a series of changes from falling to flooding, upward-downward and finally to upward. On the other hand, when the gas flow decreases the liquid begins to creep and this process is normally known as creeping. Bubble flow: At higher liquid flow conditions (higher than the plug flow) the liquid phase is continuous and a dispersion of bubbles flows within the liquid continuum. In bubble flow, the bubbles undergo random motions which pass through the channel, and from time to time, bubbles coalesce to form larger ones, leading to plug flow. The collision frequency increases with increasing void fraction. As a rule of thumb, a 30% void fraction may be taken as the limit of bubble flow. Bubble flow may exist at higher void fraction in the presence of contaminants that prevent coalescence or at very high flow velocities that prevent the growth of bubbles. Annular flow: At high gas flow rate and relatively small volume of liquid flow, the liquid flows on the wall of the pipe as a film, and the gas phase flows in the center. Usually some liquid is entrained as small droplets in the gas core.
200
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Wispy annular flow: Under annular flow conditions, if the liquid flow rate increases, the concentration of liquid droplets in the gas core increases. Ultimately the liquid droplets coalesce in the gas core in the center to large lumps or streaks (wisps) of liquid. Froth flow: Some authors describe froth flow regimes as being an emulsion-type flow without noticeable structure. However, high-speed analysis of this flow regime indicates that it is indeed bubble to annular flow, depending on the gas flow rate.
ii. Vertical downward flow regimes Figures 4.14 and 4.15 present the flow regimes of vertical downward and inclined downward flow (inclination angle up to 10 ), respectively. Vertical downward flow regimes are different from those for upward flow. Not much work has been done for this flow regime. The main characteristic of flow is the dominance of the annular flow regime. It should be noted that annular flow can, in effect, occur at zero gas flow in the form of a falling film on the wall.23,24
iii. Horizontal flow regimes Figure 4.16 presents the flow regimes of horizontal flow.25 These are more complex than those in vertical flow, mainly because of the asymmetry in the flow caused by gravitational force. This acts
FIGURE 4.14 Vertical Downward Flow Regimes.23 Reproduced with permission from Taylor & Francis.
4.2 Flow
201
FIGURE 4.15 Inclined Downward Flow Regimes (Inclination Angle up to 10 ).24 (DB is dispersed bubble, S is stratified, and A is annular). Reproduced with permission from Taylor & Francis.
FIGURE 4.16 Horizontal Flow Regimes.25 Reproduced with permission from Taylor & Francis.
202
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
normal to the direction of horizontal flow, whereas as it acts parallel to flow in vertical flow. As a consequence, the heavier phase tends to accumulate at the bottom of the pipe in horizontal flow. Stratified flow: When the flow rates are small, the gravitational force separates the two phases completely. As a result the liquid flows at the bottom and the gas flows at the top of the pipe. Stratified-wavy flow: As the gas velocity increases in stratified flow, waves are formed at the gasliquid interface, producing the stratified-wavy or wavy flow regime. Annular-annular mist (dispersed) flow: This pattern is similar to that of vertical flow and occurs at very high gas flow rates. However the film thickness is non-uniform, with the film at the bottom of the pipe being thicker than that on the top of the pipe. Further, most of the liquid may be entrained in the gas core. Bubble flow: Characteristic bullet-shaped bubbles are formed which normally move near the top of the pipe. In some flow regime descriptions, this flow pattern may be identified as plug flow. Slug flow: At relatively moderate gas and liquid flow rates, slugs are intermittently created. The slug contains continuous liquid phase but with large amounts of entrained gas bubbles. The presence of slugs produces sudden pressure pulses causing vibrations in the pipe. Dispersed flow: At high liquid flow rates the bubbles are dispersed in a liquid continuum. The bubbles tend to congregate near the top of the pipe. At high liquid velocities the bubbles may be more uniformly distributed and may appear as froth.
4.2.2b Two-phase liquid-liquid Liquid-liquid flow occurs in the oil and gas industry when oil and water are transported simultaneously. The oil and water may flow either in the emulsion (oil-in-water or water-in-oil) form or in the stratified form. Due to their non-ionic nature, hydrocarbons cannot dissolve ionic water. However at low water concentrations, hydrocarbons can form an emulsion with the water. The type of emulsion and its stability depends on the type of hydrocarbon, presence of surfactants (e.g., corrosion inhibitors), the ionic content of the water, as well as the pressure, temperature, and flow rate (see section 4.3 for more information on emulsions). At high concentrations of water, oil and water exist as two distinct phases and different flow regimes can exist under these conditions. Figures 4.17 and 4.18 present typical flow regimes of oil and water mixture in horizontal pipe and Figure 4.19 presents typical flow regimes in vertical pipe.26–28 Typically, the density of oil is less than that of water, and as a result stratification occurs (Figure 4.18). When the density of oil (e.g., heavy oil) is similar to that of water the oil moves as a central core with water flowing in the annulus space (Figure 4.17).
4.2.2c Two-phase liquid-solid Liquid-solid flow occurs mainly in hydrotransport pipelines (see section 2.12), but it can also occur in liquid pipelines containing corrosion products and scales. Liquid-solid flow may exist in different flow regimes depending on the flow rate, particle size, and density difference between the solid and liquid (Figure 4.20).29 Below a minimum flow velocity in a horizontal pipeline (or below critical angles in inclined pipelines), solid particles in the fluid can form a bed on the bottom of the line. As the sand is produced, a sand bed will build up until the increased velocity above the bed is large enough to transport the particles further down the pipeline, where the particles settle again, resulting in an increase in the length of the sand bed. Deposition of the solids can lead to partial or complete blockage of flowlines,
4.2 Flow
Flow pattern
203
Superficial oil velocity V0 (ft s-1) 1.95
Water drops in oil 1.11 Oil in water concentric 0.682 Oil slugs in water 0.200 Oil globules in water Superficial water velocity
Vw = 0.682 ft s-1
FIGURE 4.17 Flow Regimes of Oil and Water Mixture in a Horizontal Pipeline. (Densities of Oil and Water are almost Same).26 Reproduced with permission from Taylor & Francis.
0.491 Stratified 0.290 0.149
0.043 Oil globules in water Superficial water velocity Vw = 0.287 ft s-1 Superficial oil velocity ft/s
FIGURE 4.18 Flow Regimes of Oil and Water Mixture in a Horizontal Pipeline. (Densities of Oil and Water are Different).27 Reproduced with permission from Taylor & Francis.
underdeposit corrosion, microbiologically influenced corrosion (caused by sessile bacteria), and trapping of pigs. In sour media, the presence of solid sulfur enhances corrosion. As the flow rate increases, the sand may move in dune patterns. In a moving dunes pattern the sand will move along the pipeline at low velocities. All particles will be transported through the pipe under these conditions. As the flow rate further increases, the pattern changes to scouring. In a scouring
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Superficial oil velocity V0 (ft s-1) 0.015
0.06
0.18
0.55 1.2
3.0
9.0
Superficial water velocity Vw = 0.1 ft s-1
FIGURE 4.19 Flow Regimes of Oil and Water Mixture in a Vertical Pipeline.28 Reproduced with permission from Taylor & Francis.
FIGURE 4.20 Flow regimes of Liquid-Solid Flow.
pattern, the particles will move at the liquid velocity close to the pipe wall. At a sufficiently high velocity, a dispersed pattern will be established, in which the sand particles will move at the velocity of the bulk liquid phase. The transition between the various regimes is somewhat gradual with no sharp boundary. Depending on service conditions, any of the transitions between these regimes may be critical. For oil transportation, the transition between scouring and moving dunes may be critical. The flow velocity at this transition point will be lower than the velocity required to keep the sand suspended in oil but high enough to transport the sand through the pipeline. This flow velocity is often known as the critical velocity, Ucrit,SM and it is calculated using a general formula: Ucrit:SM ¼ a:Vsand dsand DDos di
(Eqn. 4.47)
where a is a constant, Vsand is the solid volume; dp diameter of solid or sand particles; DDo–s difference in density between oil and solid phases; and di is the pipe internal diameter.
4.2 Flow
205
4.2.2d Two-phase gas-solid When gas is used as a conveying medium then the process is known as a pneumatic process. Gassolid flow occurs either in suspended or non-suspended forms. Suspended flow occurs when the volume of solid is small and when the velocity of gas is high. Non-suspended flow occurs when the volume of solid is larger and when the velocity of gas is low. Pneumatic conveying of solids is frequently used to transport coal and minerals, grains, foodstuffs, chemicals, and plastics, but is not a common method of transportation in the oil and gas industry. Gas-solid flow may occur in a gas pipeline containing corrosion products, frequently iron sulfide black powders. However, such a solid is assumed to have little effect on the gas flow due to the relatively small percentages occuring in most conditions.
4.2.3 Water accumulation Internal corrosion occurs in oil and gas infrastructure only when water accumulates on metallic surfaces. Many oil and gas infrastructures, e.g., oil transmission and gas transmission pipelines operate under conditions of extremely low water content (typically less than 0.5% by weight). Determining the locations where water may accumulate in those infrastructures is critical. The accumulation of water depends on oil, water, and gas characteristics, the inclination of the pipe, the flow velocity, and the cleanliness of the pipeline. Several methodologies and rules of thumb are available to determine the likelihood of water accumulation, leading to the establishment of corrosion conditions. Every methodology has its advantages and limitations, therefore in using a particular methodology, its characteristics and limitations should be understood. Some methodologies are described in this section. In order to predict the locations of water accumulation, three broad categories are established: single phase oil, single phase gas, and multi phase. Flow is considered as single phase oil when 95% of the products it transmits are oil, i.e.: P:R:oil > 0:95 (Eqn. 4.48) P:R:oil þ P:R:water þ P:R:gas The flow is considered as a single phase gas when the water content is less than 7 mmscf and the gas to liquid production rate ratio is higher than 5,000, i.e.: P:R:gas > 5; 000 (Eqn. 4.49) P:R:oil þ P:R:water where P.R.gas, P.R.oil, and P.R.water are the production rates of gas, oil, and water, respectively. The flow is considered to be multiphase when it does not meet the conditions of Eqns. 4.48 or 4.49.
4.2.3a Single phase oil Based on field experience, it is commonly assumed that if the oil flow rate is higher than 1 m/s and if the water content is less than 20% water does not accumulate.30,31 Field experience has also indicated that water accumulation depends on the nature of the oil, and in some cases an 0.5 m/s oil flow rate is sufficient to avoid any accumulation of water. A parameter known as the Froude number (Fr) is used to predict the water accumulation tendency in a single phase oil pipeline. Several definitions of the
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Froude number are available, and most of them for single phase flow takes the form presented in Eqn. 4.50:32–37 Fr ¼
Doil VL DDow gdpipe
(Eqn. 4.50)
where Fr is the Froude number, Doil is the density of oil, DDo-w is the density difference between oil and water, g is the acceleration due to gravity, dpipe is the hydraulic diameter of pipe, and VL is the velocity of the liquid. In most situations, the critical Froude number for water accumulation is assumed to be approximately 0.65; above this value, water does not accumulate and below this value water is likely to accumulate. The critical Froude number is found to be inversely proportional to the inclination angle of the pipeline.38 Standards providing guidelines for calculating the accumulation of water in single phase oil pipelines include: •
NACE SP0208, ‘Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines’
4.2.3b Single phase gas In normally dry gas transmission pipelines the flow is single phase. When water accidently enters into the system, it may be carried as droplets in the gas flow, or accumulates in localized regions along the pipeline. To determine the locations where water may accumulate, two parameters are determined: inclination angle of the pipeline based on field topography, and the critical angle above which the flow cannot carry the water through. In the locations of the pipe where the inclination angle is greater than the critical angle water accumulation occurs. The critical angle is determined as:33 !1:091 rg Ug 2 qCA ¼ arcsin 0:675$ $ (Eqn. 4.51) rl rg g$di where qCA is the critical angle; rg is the density of gas (kg/m3); rl is the density of liquid (kg/m3); Ug is the gas flow rate (m/s); g is the acceleration due to gravity (9.81 m/s2); and di is the inner pipe diameter (m). The flow rate of gas (Ug) cannot be calculated directly from the production rate of gas because this is measured at standard temperature and pressure (STP). Hence, the production rate of gas at STP is converted into the production rate of gas at pipeline operating temperatures and pressures, using either the compressibility factor (Zgas) (Eqn. 4.52) or Van der Waal’s real gas equation (Eqn. 4.53). From Eqn. 4.16: Pstp Vstp PV ¼ RTstp ZRT
an2 p þ 2 V nb ¼ RT V
(Eqn. 4.52) (Eqn. 4.53)
4.2 Flow
207
Table 4.5 Comparison of Results Using Compressibility Factor (Z) versus Van der Waal’s Equation39 Parameter Gas Velocity (m/s) Critical Angle, degrees
Result from Compressibility Factor
Result from Van der Waal’s Equation
% Difference between the Two Approaches
6.6 5.9
5.9 4.4
11.8 28.0
The calculations were performed for 100% methane gas using the following values: ll ¼ 1.0 g/cm3, g ¼ 9.81m/s2, di ¼ 0.745 m, P ¼ 35.05 atm, T ¼ 298K, VSTP ¼ 4.13 x 108 L/h, TSTP ¼ 273K, PSTP ¼ 1.000 atm, R ¼ 0.08206 L atm/mol K, AVan ¼ 2.25 L2atm/mol2, bVan ¼ 0.0428 L/mol
where P is the pressure; PSTP is the pressure at STP; V is the volume; VSTP is the volume at STP; TSTP is the temperature at STP; R is the gas constant; and T is the temperature; and aVan and BVan are Van der Waal’s constants. Van der Waal’s equation Eqn. 4.53 is similar to using the compressibility factor, in that it is a modification of the ideal gas law to simulate non-ideal gas behavior. Unlike the compressibility factor method, Van der Waal’s equation contains two constants which change with the gas being simulated, and Van der Waal’s equation is cubic in form, which is better for simulating a non-ideal system. The advantage of using this method is increased accuracy, the disadvantage is the complicated mathematics involved in cubic equations.39 Table 4.5 shows the difference in results obtained by using compressibility factor and Van der Waal’s equation. Standards providing guidelines for calculating the accumulation of water in single phase gas pipelines include: •
NACE SP0206, ‘Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Gas (DG-ICDA)’
4.2.3c Multiphase When two phases are transported in a pipe, the flow velocity is frequently inadequate to uniformly transport both phases at the same rate. As a result, the gas flows faster than the liquid and there is a hold-up of liquid. This means that the volume of liquid in some areas along the pipeline is higher than the normal liquid to gas ratio. The amount of liquid hold-up depends on gravity, the inclination of the pipe, and the flow velocity. Numerous equations and commercial software are available to calculate liquid hold-up.
i. Two-phase The rate of deposition of liquid from the gas phase may be calculated as:40 mD ¼ kd $Cw
(Eqn. 4.54)
where mD is the rate of deposition (mass per unit peripheral area per unit time); kd is the deposition mass transfer coefficient; and Cw is the concentration of droplets in the gas core (mass per unit volume calculated on a homogeneous basis).
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
The value of kd is calculated as: kd ¼
Vc) :87
sffiffiffiffiffiffiffiffiffiffiffi h2l DsrL
(Eqn. 4.55)
where VC) is the core friction velocity (defined in Eqn. 4.56); hl is the liquid phase viscosity; di is the internal diameter of pipe, m; s is the surface tension kg/s2; and rl is the liquid phase density (kg/m3). rffiffiffiffiffi si (Eqn. 4.56) VC) ¼ rg where si is the interfacial shear stress in the absence of interface mass transfer, N/m2 and rg is the gas density, kg/m3.
ii. Three-phase When oil, water, and gas phases are involved the liquid fraction, l, is first calculated as: l¼
P:R:oil þ P:R:water P:R:oil þ P:R:water þ P:R:gas
(Eqn. 4.57)
where P.R.oil is the oil volumetric flow rate (m3/d); P.R.water is the water volumetric flow rate (m3/d), and P.R.gas is the gas volumetric flow rate (m3/d). Then the modified Froude number for multiphase flow is calculated as: ! ! rl rg g$di $ $sinðqÞ (Eqn. 4.58) Fr ¼ rg Vg 2 where rl is the liquid density (kg/m3); rg is the gas density (kg/m3); g is the gravity constant (9.81 m/s2); di is the inner pipe diameter (m); Vg is the gas flow rate (m/s); and q is the angle of pipe inclination. Based on the liquid fraction (Eqn. 4.57), modified Froude number (Eqn. 4.58), and flow regimes (section 4.2.2) the liquid hold-up (HL) is then calculated using the formulae presented in Table 4.6.41,42 The same calculations may also be used for two-phase flow by deleting the flow rate of oil or water as appropriate from Eqn. 4.57, and replacing the liquid density with the appropriate density of oil or water in Eqn. 4.58.
4.2.4 Effect of flow on corrosion In addition to determining the pressure drop, flow regimes, and locations where corrosion may take place (i.e., where water accumulates), the flow may directly affect corrosion in three ways: mass transfer, momentum transfer, and phase transfer. A complete understanding of the effect of flow on corrosion should also include heat transfer; however heat transfer in most oil and gas infrastructure (production, transmission, and product pipelines) is not sufficient to affect the corrosion. Heat transfer effect may be important in the refinery operating conditions (see section 2.31) and top-of-the line corrosion (see section 5.24).
4.2.4a Mass transfer Flow may influence corrosion by bringing corrosive species (e.g., dissolved oxygen) towards the metal surface or moving corrosion products away from the metal surface. Flow may decrease corrosion rate
4.2 Flow
209
Table 4.6 Liquid Hold-Up Calculation41,42 Pipe Orientation
Flow Regime
Incline
• • • • • • •
Incline
Horizontal
Wave Annular Stratified Annular Mist Annular Wispy Annular Annular Mist
Liquid Hold-up Equation HLð1Þ ¼
0:98$l0:4846 Fr 0:0868
• Slug • Churn, Plug • Oscillatory
HLð2Þ ¼
0:845$l0:5351 Fr 0:0172
• Dispersed • Bubble • Slug
HLð3Þ ¼
1:065$l0:5825 Fr 0:0609
by removing corrosive species from the metal surface; a mass transfer coefficient is used to represent this effect. The mass transfer coefficient is the rate at which the reactants (or products) are transferred to the surface (or removed from it). The mass transfer in various geometries is assumed to be similar if the mass transfer coefficients are equal. The mass transfer coefficient, kcoeff is expressed as:43 Di kcoeff ¼ Sh$ L
(Eqn. 4.59)
where Sh is the Sherwood number (see Eqn. 4.60); Di is the diffusivity of species i, m2/s; and L is characteristic length, e.g., diameter of pipe, m. Sh ¼
0:62048Sc1=3 Re1=2 1 þ 0:2980Sc1=3 þ 0:14514Sc2=3
(Eqn. 4.60)
where Sc is the Schmidt number, dimensionless (see Eqn. 4.61) and Re is the Reynolds number (see Eqn. 4.5) h Sc ¼ (Eqn. 4.61) rDi
4.2.4b Momentum transfer An increase in corrosion due to momentum transfer is commonly known as flow-induced localized corrosion (FILC), and the wall shear stress is used to represent its effect. FILC occurs due to increasing turbulence intensity and mass transfer as a result of flow over a surface and is different from erosioncorrosion (see section 4.2.4c).44 The wall shear stress is a measure of the viscous energy loss within the turbulent boundary layer and is related to the intensity of turbulence in the fluid acting on the wall. Wall shear stress and mass transfer are intimately linked and their individual contributions to flowaccelerated corrosion cannot be delineated either experimentally or mathematically. Changes to flow that affect the mass transfer coefficient will affect the wall shear stress, and vice versa.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Wall shear stress is the force per unit area on the pipe due to fluid friction. The wall shear stress, Wss, in Pascal, can be calculated as: fU 2 r (Eqn. 4.62) 2 where f is the friction factor (dimensionless); U is the flow rate (m/s); and r is the density (kg/m3). Alternatively the wall shear stress may also be determined experimentally as: DP di (Eqn. 4.63) Wss ¼ 4 DLpipe Wss ¼
where DP is the pressure drop over a specific length (DL) of pipe of specific diameter (di).
4.2.4c Phase transfer In the presence of a second phase, flow may affect corrosion in two ways: erosion-corrosion and underdeposit corrosion. The second phase may be gas, liquid, or solid and the primary phase is mostly liquid, but it can also be gas. Under high flow conditions, the flow impinges the second phase (e.g., sand or liquid) on the surface, causing erosion-corrosion (see sections 5.11 and 6.6) or collapses the second phase (e.g., gas) causing cavitation corrosion (see section 5.10):45 Under low flow conditions, the second phase (mostly sand or other solid particles) deposits in localized areas, causing under-deposit corrosion and blocking access of the inhibitor to the surface. These locations are susceptible to localized corrosion in the form of pits. Guidelines to predict critical flow below which solid deposition occurs have been established on the basis of laboratory experiments. In horizontal pipes solid deposition occurs if the flow rate is less than the following value:46 5:305 106 ð314:96di þ 20Þ ðdi =2Þ2
m=s
(Eqn. 4.64)
where di is the internal diameter of pipe in meters. Solid deposition does not occur in pipes inclined downwards. In pipes inclined upwards, solid deposition depends on flow rate, inclination angle, and pipe diameter. For an incline of less than 40 , deposition occurs if the flow rate is less than the following value: 5:305 106 ð314:96di þ 16Þ ðdi =2Þ2
m=s
(Eqn. 4.65)
For an incline of greater than 40 , deposition occurs if the following relationship holds: 2 di þ 8ð39:4di 2Þ < ½ð 0:5qÞ53:3 ½U þ 8ð39:4:di 260000pU 2
(Eqn. 4.66)
where U is flow rate in m/s and q is the angle of inclination in rad. Eqns. 4.64 through 4.66 are only applicable over the range of parameters analyzed in tests.46 The density and size of solids, the density and viscosity of liquids, the pipe diameters evaluated, and the
4.3 Oil phase
211
relative length/diameter of the flow loop used in these investigations influence the solid deposition. Other methodologies for determining locations for solids to deposit are presented in: •
NACE Standard Practice SP0208–08, Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines (LP-ICDA)
These methodologies have been found to be reliable for solid deposition from light oil. However, for heavy oil, it has been found that solids deposit downstream of over-bends.47 A computational fluid dynamics (CFD) study of a representative segment of a transmission pipeline suggests that the main reason for the observed solids deposition downstream of over-bends in pipelines carrying heavy crude oil is that the wall boundary layer is thicker for heavy oil than for light oil. This thicker boundary layer leads to lower near-wall velocities than for the light oil case. This effect is especially pronounced for heavy oils downstream of over-bends, where the boundary layer is even thicker and near-wall velocities even slower. Extremely slow velocity makes the particles susceptible to becoming trapped in existing corrosion pits or stationary solid deposits. Conversely, it was found that, for light oil, even though the particles fall quickly to the pipe floor, the relatively rapid near-wall velocity keeps them moving.48
4.3 Oil phase Crude oils are corrosive at the higher temperatures prevailing in the refinery (see section 3.31), but are non-corrosive at lower temperatures. At lower temperatures, crude oils have low conductivity, i.e., they are poor electrolytes (see section 5.2 for details), preventing electrochemical reactions from occuring.49–53 However at lower temperatures crude oils may influence the corrosivity of an aqueous phase with which they are in contact. The corrosivity of crudes depends on their chemical and physical constituents, emulsion type, wettability, and partition of chemicals between oil and aqueous phase.
4.3.1 Chemical and physical constituents Chemical constituents affect corrosion only at temperatures high enough to liberate them but low enough for water to exist as liquid. Such conditions normally occur in certain parts of the refineries (see section 3.31). On the other hand, constituents such as solids or paraffins may affect the corrosivity of the water phase which is in contact with crude oils at lower temperatures (typically below 158 F (70 C)). The influence of specific chemicals on the corrosivity of crude oils is discussed in this section.
4.3.1a Inorganic salts Analyses of crudes indicate that over 2,000 mg/L (70 LB/100BBL) of inorganic salts can be extracted from corrosive crudes and about 20 times less from non-corrosive crudes.54 The chloride content is usually referred to as total salt. The total salt may sometimes be used as an index of corrosivity. It should be noted that only salts that produce hydrogen chloride [HCl] at high temperatures are corrosive. In general, the total amount of HCl liberated is proportional to the salt content. A direct estimate of HCl provides a measure of the corrosivity of the crudes. Factors affecting the amount of HCl liberated at high temperatures typically occurring in the refinery operation conditions
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
include ratio of calcium (Ca) and magnesium (Mg) to sodium (Na) and pH. If about 10% of chlorides are present in the form of Ca and Mg salts and the pH is alkaline, less HCl is liberated; on the other hand, if the Ca and Mg salts are about 20% and if the brine pH is acidic, the amount of HCl liberated is high.55
4.3.1b Sulfur content It has been known for many years that the greatest single cause of crude oil corrosion at higher temperatures occurring in the refinery operating conditions is the presence of sulfur compounds, but there is no direct correlation between sulfur content and corrosivity.56,57 The controlling factor with respect to corrosion is not the sulfur content, but the degree to which the sulfur compounds decompose to form more corrosive constituents such as H2S and HCl. The sulfur content of crude oil is usually less than 1%.58 The sulfur contents of heavier crudes may be in the range 2.0–3.5%. A McConomy curve is used to predict the corrosivity of crude oil based on its sulfur content. Figure 4.21 presents two versions of the McConomy curve.59 However it should be noted that only those sulfur compounds that liberate H2S at high temperatures are important. The total sulfur of certain crudes may be lower (less than 1%), but the H2S liberated may be higher (typically 60–450 mg/L [20–150 LB/1000 BBL]). Sulfur compounds may provide corrosion protection when stable sulfide layers form on the metal surface.
4.3.1c Organic acids Of the organic acids, naphthenic acid is most important with respect to the corrosivity of crude oil at higher temperatures. Naphthenic acids cause corrosion in vacuum units of refineries operating between 428 and 700 F (220 and 370 C). No corrosion occurs at temperatures above 752 F (400 C) due to the decomposition of naphthenic acids. No corrosion product is formed in the presence of naphthenic acid. In addition to carbon steel, stainless steels (12% Cr, 316 SS, 317 SS, and 6% Mo) are also susceptible to naphthenic acid. One study has indicated that the product of the organic nitrogen and naphthenic acid content is inversely proportional to the corrosion rate of steel at lower temperatures (less than 70 C).60 In addition to naphthenic acid, other organic acids including formic, acetic, and propionic acids may also influence the corrosivity of the crude oils at lower temperatures.61 These acids influence the corrosivity of aqueous phase in contact with crude oil by supplying hydrogen ions which undergo cathodic reactions during the corrosion of metals (see section 5.2): Formic acid : Acetic acid : Propionic acid :
HCOOH/Hþ þ HCOO
(Eqn. 4.67)
CH3 COOH/Hþ þ CH3 COO
(Eqn. 4.68)
(Eqn. 4.69)
CH3 CH2
COOH/Hþ
þ CH3 CH2 COO
4.3.1d Dissolved gases62–66 Oxygen, carbon dioxide and hydrogen sulfide are the main corrosive gases. H2S is more soluble in hydrocarbons than in water. The ratio of the concentration of H2S in hydrocarbon to that in water is 1.7 at 32 C (90 F); 1.67 at 29 C (84 F) for mineral oil; 5.95 at 31 C (88 F) for benzene; 2.4 at 31 C (88 F) in kerosene; and 2.65 at 31 C (88 F) for iso-octane. The saturation concentration of H2S in crude oil is 5,000 ppm, whereas normal concentrations are found to be in the range of 100–200 ppm. The solubility of CO2 and oxygen in hydrocarbons is also higher than they are in water.
4.3 Oil phase
Corrosion rate multiplier
100 50 20 10 5 2 1 0.5
213
Carbon Steel 1 – 3Cr
4 – 6Cr
9Cr
0.2 12Cr 0.1 0.05 18/8 Sulfur content:.0.6wt% 0.02 0.01 450 500 550 600 650 700 750 800 Tempature F
Modified McConomy Curve [1]
Sulfer content, wt%
10 5 2 1 0.5 0.2 0.1 0.05 0.02 0.01 0.4
0.8 1.2 1.6 Corrosion rate multipiler
2.0
Correction curve for sulfur content [1]
FIGURE 4.21 McConomy Curve to Predict the Effect of Sulfur Content in Crude Oils on High-Temperature Corrosion Rate.59
4.3.1e Solids Crudes may contain solids and sediments as finely divided particles of siliceous matter.67 At high velocities the solids may be swept along with the flow while at low velocities they settle at the bottom of the pipe. When they settle, they shield the pipe and facilitate the occurrence of corrosion beneath them (underdeposit corrosion). The extent of corrosion depends on the amount and composition of solids.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.3.1f Paraffin Paraffin is a mixture of aliphatic and aromatic hydrocarbons, asphalts, resins, and naphthenes. Crude oils contain paraffin as suspensions of 1–100 mm (0.04–4 mil). The paraffin layer on the pipe wall protects it, but when the layer entraps water localized corrosion may take place.
4.3.2 Emulsion type Because of their non-polar nature, crude oils cannot dissolve ionic water. However, at low concentrations of water, crude oil can form an emulsion with water. The type of emulsion and its stability depends on the type of crude oil, composition of water, presence of surfactants, operating pressure, temperature, and flow rate. There are two kinds of emulsion: water-in-oil and oil-in-water. In water-in-oil emulsions, the nonionic (non-conducting) oil is the continuous phase in which the ionic water is dispersed. Therefore, corrosion does not occur in the presence of a water-in-oil emulsion; since oil is a non-conducting electrolyte, corrosion does not take place. On the other hand, in oil-in-water emulsions the ionic (conducting) water forms the continuous phase in which the non-ionic oil is dispersed. Therefore, corrosion occurs in the presence of oil-in-water emulsions. The water-cut at which a water-in-oil emulsion inverts into an oil-in-water emulsion is known as the ‘emulsion inversion point’ (EIP) (Figure 4.22).68,69 By measuring the conductivity of the emulsion under flowing conditions the type of emulsion can be determined.70 Standard providing guidelines to measure EIP include: •
ASTM G205, ‘Standard Guide for Determining Corrosivity of Crude Oils’
FIGURE 4.22 Schematic Diagram of the Experimental Section of Emulsion Inversion Point Apparatus.70 Reproduced with permission from ASTM.
4.3 Oil phase
215
4.3.3 Wettability The probability of corrosion in the presence of an oil-in-water emulsion or free water depends on the wettability. When the oil phase preferentially wets the surface (oil-wet), corrosion is negligible; but when the water phase preferentially wets the surface (water-wet), corrosion does take place; and when no phase preferentially wets the surface (mixed-wet), corrosion may or may not take place. It should be pointed out that emulsion and wettability are two different properties. The emulsion depends on the interaction between two phases: water phase and oil phase, whereas the wettability depends on three phases: water phase, oil phase, and solid phase (e.g., pipeline steel). A crude oil may have high EIP, i.e., it may hold water in the water-in-oil phase, but as soon as the EIP is reached water drops out and wets the surface. On the other hand, the crude oil may have a low EIP, i.e., water drops out even when present in low concentration, but the surface may continue to be oil-wet, reducing the possibility of corrosion. The wettability can be estimated by considering the relative surface energies of all the interfaces involved. A water-steel interface will be replaced by an oil-steel interface if the energy of the system decreases as a result of this action (that is, the tendency of oil to displace water from steel). The difference in surface energy (Dwo) between a steel-oil and a steel-water interface can be calculated from measured values of the contact angle (qCaw) and the water-oil interfacial tension (gwo) as: Dwo ¼ gwo $cos qCaw
(Eqn. 4.70)
It follows that displacement of water by oil should be expected when qCaw is between 90 and 180 ; on the other hand, displacement of oil by water would be expected when qCaw is between 0 and 90 (Figure 4.23). The contact angle method is extensively used to determine the wettability of different surfaces. The oil and water may be added in two sequences: oil-first water-next sequence or water-first, oil-next sequence. The first sequence represents the case of oil transmission pipelines, but measuring the contact angle using this sequence is relatively difficult. Due to the dark background of the oil, the wo
so
Caw
sw
FIGURE 4.23 Principle behind Determining Wettability using Contact Angle Measurement.70 Reproduced with permission from ASTM.
216
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.24 Schematic Diagram of Apparatus to Determine Wettability using Spread Method.70 Reproduced with permission from ASTM.
apparatus should be illuminated. For this reason, the contact angle is normally measured in a waterfirst, oil-next sequence. However, this sequence does not truly represent the oil transmission pipeline operating conditions. The spreading method overcomes these difficulties. This method measures the conductivity across a series of 20 steel pins imbedded in non-conducting material (Figure 4.24). The conductivity is measured between a central reference pin and series of outer test pins. Based on how many measurements exhibit high resistance (low conductivity), the crude oil is classified as: • • •
Oil-wet (less than five of the 20 pins exhibit high conductivity) Mixed-wet (between five and 15 of the 20 pins exhibit high conductivity) Water-wet (more than 15 of the 20 pins exhibit high conductivity)
Although this apparatus can be operated at elevated pressures, the boundary for differentiating different wettabilities is arbitrary. Standard providing guidelines to measure wettability include: •
ASTM G205, ‘Standard Guide for Determining Corrosivity of Crude Oils’
4.3.4 Partition of chemicals between oil and water phases In the presence of an oil-in-water emulsion or free water phase on a water-wet surface; corrosion may take place. The crude oil phase surrounding the water phase may influence corrosion by partitioning water-soluble species into it. If the water-soluble species are corrosive in nature, the corrosivity of the aqueous phase would increase and be greater than that observed without an oil phase. On the other hand, if water-soluble species are inhibitive in nature, the corrosivity of the aqueous phase would decrease and be less than that observed without an oil phase. In order to understand the influence of an oil phase on the corrosivity of a water phase, tests should be performed using both oil and water phases
4.4 Water (Brine or Aqueous) phase
217
No Corrosion
W/O Emulsion O/W
Oil-Wet Wettability
No Corrosion
Mixed-Wet Water-Wet
Less then 0.01 mpy (Preventive Hydrocarbon)
Corrosivity of Brine in the Presence of Hydrocarbon
No Corrosion
Less then Absence of Hydrocarbons (Inhibitive Hydrocarbon)
Reduced Corrosion
No Change (Neutral Hydrocarbon)
Aqueous Corrosion
Higher then Absence of Hydrocarbons (Corrosive Hydrocarbon)
Accelerated Corrosion
FIGURE 4.25 Classification of Crude Oil (Hydrocarbons) based on Corrosivity (ASTM G205).70 Reproduced with permission from ASTM.
in a laboratory methodology (see section 8.2.2a). Based on the results, the overall corrosivity of oil may be established (Figure 4.25).
4.4 Water (Brine or Aqueous) phase The water phase may also be identified as brine solution, brine, or aqueous phase. The source and composition of the water used in various sectors of the oil and gas industry vary considerably. The water phase sustains corrosion by being a good electrolytic conductor (‘E’ in the ACME; see section 5.2). Deionized water does not contain ionic species, is a poor-conductor, and hence does not support corrosion. As the concentration of ions increases, the corrosivity of water increases. The ionic species influence the corrosivity of water in several ways: they increase conductivity of water, participate in electrochemical corrosion reactions (e.g., oxygen, by forming hydroxyl ion, may undergo cathodic reduction reaction), and change the properties of surface layers (e.g., chloride ions destroy many oxide surface layers leading to localized corrosion). The corrosivity of water depends on the nature as well as the concentrations of both anions and cations.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
4.4.1 Effect of anions The dominant anions affecting corrosion are halide ions, of which chloride ion is the most significant. Figure 4.26 presents the variation in corrosion rate of iron in air-saturated distilled water at room temperature as a function of Cl ion concentration (added in the form of NaCl). The corrosion rate increases as a function of NaCl concentration up to 3% NaCl. The concentration of oxygen is highest in pure distilled water, but its solution resistance is also high (i.e., the solution conductivity is low), so the corrosion rate is low. Addition of NaCl increases the solution’s conductivity, so the corrosion rate increases. At around 3% NaCl the solution conductivity reaches levels sufficient for the oxygen effect to become dominant. As the NaCl concentration increases above 3%, the dissolved oxygen content decreases; consequently the corrosion rate decreases. At about 26% NaCl the corrosion rate is as low as that in distilled water. The most prominent effect of chloride is, however, in initiating localized corrosion of metals. One study found that the tendency to initiate pits increases with increase in chloride ion concentration in the range 10,000 to 120,000 ppm, and that the effect of chloride ion depends on the presence of other ionic species.72 Depending on other factors, the presence of 5% chloride ion may increase localized pitting corrosion rate by 100 mpy.73 The chloride ion increases the susceptibility of metal to localized pitting corrosion by penetrating and destroying the oxide or other surface layers that are otherwise protective. Other halides may also initiate pitting corrosion, but the effect decreases in the order chloride > bromide > iodide > fluoride. Sulfate, bicarbonate, and phosphate ions in general decrease the susceptibility to pitting corrosion. In the presence of phosphate ions, the susceptibility to pit 2 3 initiation decreases in the order: H2PO 4 > HPO4 > PO4 .
3
Relative Corrosion Rate
3% NaCl
2
1
0 0
5
10
15 20 Concentration of NaCl (wt. %)
25
30
FIGURE 4.26 Corrosion Rate of Iron in Aerated Solution at Room Temperature as a Function of NaCl.71
35
4.4 Water (Brine or Aqueous) phase
219
4.4.2 Effect of cations74,75 Studies indicate that most of the univalent cations (Liþ, Naþ, Kþ, and Rbþ) increase susceptibility to pitting corrosion in various metals; the effect increases with the size of the ion. The bivalent cation Zn2þ may also increase the susceptibility of metals to pitting corrosion, initiating pitting by hydrolysis of the zinc salt. However most bivalent cations, such as Mg2þ, Ca2þ, Ba2þ, Sr2þ and Mo2þ, decrease susceptibility to pitting corrosion.
4.4.3 The combined effect of anions and cations In order to maintain the charge balance, equal amounts of anions and cations exist in solution. Therefore the combined effect of anions and cations needs to be understood. The cations and anions may combine to form a salt that may precipitate as scale. Formation of scale may plug pipes and equipment, and may lead to underdeposit corrosion. The tendency to form scale depends on the solubility. Solubility is a measure of maximum amount of solute (e.g., NaCl) which can be dissolved in a solvent (e.g., water phase), and this depends on pressure, temperature, and pH. Although several types of scales can form calcium carbonate (CaCO3) (commonly known as calcite), calcium sulfate (CaSO4), barium sulfate (BaSO4), and strontium sulfate (SrSO4) scales are all common in the oil and gas industry. Calcium carbonate scale forms by the reaction between calcium with carbonate (Eqn. 4.71) or bicarbonate (Eqn. 4.72) ions: Ca2þ þ CO3 2 > CaCO3
(Eqn. 4.71)
Ca2þ þ 2HCO3 > CaCO3 þ CO2 þ H2 O
(Eqn. 4.72)
Normally, calcium carbonate scale forms in downhole tubulars due to release of CO2 when the pressure drops. Calcium sulfate scale forms when calcium ions combine with sulfate ions: Ca2þ þ SO4 2 > CaSO4
(Eqn. 4.73)
Calcium sulfate scale may be anhydrous (CaSO4) or hydrated (CaSO4.2H2O) (commonly known as gypsum). Normally, calcium sulfate scale forms in seawater because this contains high sulfate concentrations. In addition, barium sulfate (Eqn. 4.74) and strontium sulfate (Eqn. 4.75) scales, and to a smaller extent calcium fluoride scale, also form in the oil and gas production sector: Ba2þ þ SO4 2 > BaSO4
(Eqn. 4.74)
Sr2þ þ SO4 2 > SrSO4
(Eqn. 4.75)
The tendency to form scale is determined using saturation index (SI): SI ¼ log10 ðSRÞ
(Eqn. 4.76)
where SR is the saturation ratio; it is the ratio of the ionic product at a given concentration to that under saturation conditions. For example, for calcium carbonate the saturation ratio is defined as: 2þ 2 Ca : CO3 (Eqn. 4.77) SR ¼ 2þ ½Ca satn: :½CO2 3 satn:
220
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
where [Ca2þ] is the concentration of calcium ion in solution; [CO2 3 ] is the concentration of carbonate in solution; [Ca2þ]satn. and [CO23 ]satn. are the respective concentrations at the saturation point. For a given solution, if SR is unity, the solution is saturated with CaCO3 and scale can potentially form; if SR less than unity, the solution is undersaturated with CaCO3 and scale will not form; and SR is greater than unity the solution is supersaturated with CaCO3 and scale can form (precipitation is a kinetic driven process, so we may not see scale even when SR is greater than unity).
4.5 CO2 In the 1950s, corrosion was encountered in high pressure sweet oil wells, which, at that time, were thought to be non-corrosive. Based on a statistical analysis of data from several companies, the NACE TP-1C76 committee found that: general pitting-type corrosion occurs frequently in oil-producing pipe lines; corrosion starts once the wells begin producing water; pitting frequency varies with thickness of the pipe and the number of pits is higher at points of maximum wall thickness; and unique and unexplained scale conditions obscure the interpretation of caliper surveys (see section 8.4.9). An economic analysis at that time indicated that $1,500,000 must be spent within the next four years because of corrosion in 150 wells concentrated in a small geographic area located in SouthEastern Louisiana.77 Since the 1950s, several groups have studied the corrosion of carbon steel in CO2 solution. Carbon dioxide is soluble in the aqueous phase; concentrations of CO2 increase with a decrease in temperature. Normal solution CO2 concentrations are in the range 265–320 ppm at 80 C (176 F), and 1125–1720 ppm at 20 C (68 F).78 CO2 dissolved in water hydrates to become carbonic acid (H2CO3).79–82 This hydration reaction is a slow process; hence, only a small fraction of aqueous CO2 exists as H2CO3. The dissociation of H2CO3 produces carbonate (CO2 3 ) and bicarbonate (HCO3 ) 2 ions. Within the pH range 6 to 10, HCO3 exists predominantly and above pH 10, CO3 predominates. Accordingly, the corrosion of carbon steel produces both Fe(HCO3)2 (below pH 10) and FeCO3 (above pH 10), but in practice only FeCO3 is observed. Thus the overall corrosion of carbon steel in CO2 environment may be written as:83 Fe þ H2 CO3 /FeCO3 þ H2
(Eqn. 4.78)
Corrosion takes place without a corrosion layer if the Fe2þ and CO2 3 concentrations are below exceed the solubility limit, the solubility limit. When the concentrations of Fe2þ and CO2 3 corrosion layers form.84 Sometimes a FeCO3 surface layer does not form until the solution concentrations of Fe2þ and CO2 3 are five to ten times more than the values obtained from thermodynamic calculations. A solution is considered as supersaturated when the concentrations of Fe2þ and CO2 3 in it exceed values from thermodynamic calculations. The extent to which the solution is in the supersaturated condition (before FeCO3 surface layer formation) depends on pH, surface-volume ratio, and temperature. The supersaturation stage occurs because the precipitation rate of FeCO3 is slow.85,86 When the surface layer is formed, the corrosion rate decreases, and the extent of decrease depends on temperature, velocity, pH, H2S, and steel type. Several other mechanisms have been proposed for the formation of FeCO3. Irrespective of the mechanisms by which they form, an intact FeCO3 surface layer reduces corrosion and when FeCO3 is broken, localized pitting corrosion occurs.
4.5 CO2
221
4.5.1 Effect of temperature87–89 In general, corrosion rate increases with increase of temperature until reaching a maximum. Many studies indicate that formation of a FeCO3 surface layer is difficult at temperatures below 70 F (w20 C); surface layers formed between temperatures 70 and 100 F (w20 and 40 C) are not adherent and may be removed by wiping with a cloth; surface layers formed between 100 and 140 F (40 and 60 C) are non-protective; and surface layers form between 140 and 300 F (60 and 150 C) are hard, adherent, and protective. Figure 4.27 presents the distribution of pit densities on carbon steel exposed for 100 hours in CO2 solution as determined by laser profilometer.90 At 70 F (20 C); the pit density (i.e., number of pits per unit area) is higher but the pits are shallower – indicating a non-uniform, fragile surface layer. Between 70 and 175 F (20 and 75 C), as the temperature increases, the pit density decreases but the pits are deeper, indicating insufficient amounts of adherent surface layer; and between 170 and 250 F (75 and 120 C), as temperature increases both pit density and pit depth decrease, indicating the formation of adherent and protective surface layers.
4.5.2 Effect of velocity91–94 Velocity may facilitate the formation of a FeCO3 layer by promoting the dissolution of CO2 in the solution and by transporting of reactants to the surface. On the other hand, velocity may delay formation of a FeCO3 layer by transporting reaction products away from the surface, or it may completely prevent the formation of surface layer. Depending on the flow conditions, different forms of corrosion can take place in solutions containing CO2: pitting, mesa attack, FILC, and general corrosion. The boundary between these forms is not sharp, and depends on several factors including flow rate (single phase or multi phase), type of steel, pH, CO2 partial pressure, temperature, and the presence of other species (e.g., H2S). Pitting corrosion occurs under stagnant to low flow conditions, and is characterized by loss of metal in discrete areas of the surface, with surrounding areas remaining essentially unaffected or subject to general corrosion. These discrete areas may exist as circular depressions (pits) or slits (sometimes referred to as knife lines). Stepped depressions with flat-bottom and sharp-vertical side geometry, often referred to as mesa corrosion, occur at medium flow rate conditions (Figure 4.28).95 This type normally occurs when stable, hard, but non-adherent surface layers are exposed to moderate flow conditions. At very high flow velocities, the corrosion feature may take the form of parallel grooves extending in the flow direction; this phenomenon is known as FILC. FILC may start from pits or mesa corrosion above a critical flow velocity. The pits and mesa type corrosion features disturb the flow pattern and create local turbulence. This turbulence and stresses inherent in the surface layer may destroy and remove the surface layers, and the flow also prevents re-formation of a surface layer on the exposed metal. The velocity at which the surface layer is completely removed, or prevented from forming, is known as the critical velocity. Various studies indicate that the critical velocity varies between 4 and 6.5 feet/s (1.25 and 2 m/s).
4.5.3 Effect of microstructure96–102 In general, microstructural elements (e.g., pearlite, normalization) which promote anchoring of the surface layer decrease the corrosion rate, whereas elements (e.g., ferrite and cementite) which promote
222
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Profiles of the Outer Surface
Temperature oC
20
50
75
FIGURE 4.27 Distribution of Pits (as Determined by Laser Profilometer) on Carbon Steel in CO2 Atmosphere as a Function of Temperature.90 Reproduced with permission from NACE International.
4.5 CO2
223
90
120
FIGURE 4.27 (continued ).
FIGURE 4.28 Example of Mesa Type of Corrosion.95 Reproduced with permission from NACE International.
224
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Table 4.7 Characteristics of Surface Layers in Sweet Environment Characteristics
Magnetite
Cementite
Siderite
Name Chemical formula Color
Iron Oxide Fe3O4 Black
Metastable carbide Fe3C
Hardness Physical stat
5.5e6.5 Crystal
e Brittle
Iron Carbonate FeCO3 Gray, yellow, yellowish brown, greenishbrown, reddish brown and brown 3.5e4.5 Crystal
galvanic corrosion increase the corrosion rate. Table 4.7 presents the characteristics of surface layers. When iron corrodes away, leaving pearlite behind, cavities between pearlite facilitate an increase in the concentration of ferrous ions. Local flow stagnation and the higher local Fe2þ concentrations in the cavities allow the formation of an iron carbonate scale between the pearlite platelets. In addition, the pearlite helps to anchor the layer. This mechanism explains why adherent surface layers are formed on steel with a normalized microstructure rather than on steel with a quenched, tempered microstructure. When ferrite (a-Fe) microstructure preferentially corrodes, leaving cementite (Fe3C) behind, surface layer formation is hindered. Fe3C is a good electrical conductor; therefore the cathodic reaction occurs readily on Fe3C. This leads to galvanic coupling between the steel substrate and the Fe3C layer, promoting and sustaining corrosion. The effect of microstructure is evident at temperatures up to 60 C but diminishes above this. The FeCO3 surface layer makes the role of the underlying steel microstructure less pronounced.
4.5.4 Effect of pH103–108 A minimum pH is required for the formation and for the stability of surface layers. This minimum pH may vary between 4.2 and 6.0 depending on several other parameters including temperature, chemical species (CO2, carbonate, and bicarbonate), and flow rate.
4.5.5 Effect of H2S109–110 Small amounts of H2S may have some inhibitory effect on CO2 corrosion of steel, due to the formation of more protective iron sulfide (FeS). When the pCO2/pH2S ratio is above 5,000, sweet corrosion (controlled by FeCO3 surface layer) occurs. This ratio, however, may vary with temperature and pH.
4.6 H2S111–125 A historic test that is directly relevant to the understanding of iron and steel corrosion by elemental sulfur was conducted by Nemery in 1700. He mixed equal parts of iron filings and sulfur with water to form dough and buried it underground. This dough fermented and caught fire. The vigorous reaction lifted the soil, and this phenomenon led Nemery to the postulate that earthquakes occur due to similar reactions. This test indicated that iron reacts vigorously with sulfur in the presence of water.
4.6 H2S
225
Two-hundred and fifty years after Nemery’s test, Farrer and Wormwell patented the use of suspensions of sulfur in water as an etching medium for iron and steel. They found that such a suspension was corrosive to steel. They used this solution to assess the porosity of non-ferrous coatings on a ferrous base material. In the oil and gas industry, environments containing H2S are commonly known as sour environments. Sour environments cause two types of failures: sour corrosion and sulfide-stress cracking (SSC). Industry first experienced both these failures in the 1950s. Sour corrosion was first experienced in oil production fields in the USA, and SSC was first experienced in Western Canadian oil fields. Sour corrosion frequently caused – in some cases within 30 days of installation – broken sucker rods and perforated tubing. To control sour corrosion, 942 (about 26%) of the 3,618 wells operating in one location in 1950s were treated with corrosion inhibitors. (Section 5.18.4 discusses SSC in detail). Similar to CO2, H2S dissolved in water is a weak acid. In the absence of buffering ions, water equilibrated with H2S at atmospheric pressure reaches a pH value of about 4. Under higher pressures, the pH value can become as low as 3.114 Sulfur and H2S may occur naturally or may be generated by sulfate reducing bacteria (see section 4.9). At high pressure, sulfanes (the acid form of a polysulfide) are formed in the gas phase by the dissolution of elemental sulfur. As the pressure reduces (e.g., in production pipelines), the sulfanes in the gas phase dissociate to form elemental sulfur and, in the presence of water, sulfanes dissociate into H2S and elemental sulfur. Elemental sulfur may also be formed by the oxidation of H2S by air or by oxides (for example, iron oxides): 2H2 S þ O2 /2H2 O þ 2S
(Eqn. 4.79)
3H2 S þ 2FeOðOHÞ/2FeS þ S þ 4H2 O
(Eqn. 4.80)
This oxidation is detrimental for two reasons: it produces elemental sulfur, which causes severe sulfur corrosion, and further it produces water which makes dry and non-corrosive H2S becoming wet and corrosive. The solubility of sulfur in water increases with temperature (w10 ppm to 20 ppm at 77 F (25 C) to w50 ppm at 122 F (50 C)). The dissolution of sulfur in water produces H2S and sulfuric acid: 4S þ 4H2 O/3H2 S þ H2 SO4
(Eqn. 4.81)
This reaction is very slow at ambient temperatures, yet it occurs and produces enough H2S. Carbon steel or iron corrodes in the presence of H2S to produce FeS: Fe þ H2 S/FeS þ H2
(Eqn. 4.82)
The production of hydrogen atoms on the metal surface, as precursor to molecular hydrogen (Eqn. 4.82) leads to SSC (see section 5.18.4). Corrosion is however less severe in the presence of H2S than in the presence CO2 because the kinetics of formation of FeS is faster than those of FeCO3. Consequently, the surface layer of FeS is formed relatively quickly. However FeS is an electron-conductor; therefore it provides site for cathodic reactions to occur. Therefore a surface not fully covered by FeS may undergo severe localized corrosion. Iron sulfides may exist in different forms. Table 4.8 presents characteristics of these forms. The term kansite was used first in 1953–1955 for a corrosion product found in steel tubing in a Kansas oil well. In 1958, kansite Fe9S8 was described as a new iron sulfide, formed by action of H2S on steel. Based on very similar properties, to avoid confusion, the name kansite was dropped and the name
226
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Table 4.8 Common Species of Iron Sulphide123,124 Name
Stability
Chemical Formula
Pyrrhotite Trolite Mackinawite
Meta stable Stable Various degree
Marcasite Pyrite Greigite
Meta stable Stable (sulfide mineral) Metastable
Fe1-xS (e.g., Fe7S8) FeS Fe1þxS (x ¼ 0 to 0.1, e.g., Fe9S8)) FeS2 FeS2 Fe3S4
)
may be identified as kansite
Mackinawite was approved by the International Committee on Mineral Names. Since then many corrosion products of sour corrosion have been identified as Mackinawite.
4.6.1 Effect of temperature126–129 In general, at constant concentrations of H2S, the corrosion rate increases with temperature in the range 40 to 140 F (5 to 60 C). Temperature has no significant effect on corrosion rate in the range between 190 and 300 F (w90 and 150 C). At 302 F (w150 C), the surface layer is very hard and adherent. At 425 F (w220 C), the surface layer predominately consists of pyrrhotite, with small amounts of pyrite and trolite, which reduces the corrosion rate. High temperature (above 500 F [260 C]) corrosion of carbon steel may occur in the presence of H2S in reforming and desulfurizing units of refineries.
4.6.2 Effect of velocity130 Iron sulfides have low solubility (precipitation as surface layer is fast), good adherence onto steel, and good mechanical properties. For these reasons, velocity effects are generally not encountered in sour systems at velocities up to 30 m/s (100 ft/s).
4.6.3 Effect of microstructure131–132 Any microstructural changes (e.g., cold-working) that promote the formation of FeS on the surface decrease corrosion. On the other hand, any microstructural changes that promote galvanic corrosion increase corrosion. For example, the presence of a cementite phase acts as a cathode with respect to ferrite, and promotes dissolution of the ferritic phase. FeS is preferentially formed on cementite phases (which continues to act as cathode) further sustaining corrosion in the ferrite phase, leading to grooves on the metal surface.
4.6.4 Effect of pH133 In the pH range 1.7 to 2.7, iron continues to corrode and ferrous ion continues to dissolve without forming any FeS surface layer. The FeS layer starts to form at pH 2.8. Figure 4.29 presents the general variation of sour corrosion of carbon steel with pH.
4.7 O2
227
FIGURE 4.29 Variation of Corrosion Rate in H2S Medium with pH.133
4.6.5 Effect of CO2134–135 When the pCO2/pH2S ratio is below 5,000, sour corrosion (controlled by the FeS surface layer) occurs. This ratio, however, may vary with temperature and pH.
4.7 O2136 Although oxygen is not normally present at depths greater than approximately 100 m (330 ft) below the surface and is not intentionally added, it is nevertheless responsible for some corrosion encountered in the oil and gas industry. Oxygen is soluble in water. The solubility of oxygen in water increases with decreasing temperature (Figure 4.30).137–139 Even trace amounts of oxygen are sufficient to cause corrosion. Figure 4.31 provides a comparison of corrosion rates in oxygen, H2S, and CO2 atmospheres.140 The kinetics of oxygen reduction on steel is relatively fast. In the presence of oxygen, depending on the pH, two types cathodic reaction can take place: In acidic solution: O2 þ 4Hþ þ 4e /2H2 O
(Eqn. 4.83)
1=2 O2 þ H2 O þ 2e /2 OH
(Eqn. 4.84)
In neutral or alkaline solution:
228
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
OVERALL CORROSION RATE OF CARBON STEEL MPY
FIGURE 4.30 Dissolution of Oxygen in Aqueous Solution as a Function of Temperature.
O2
25
20 CO2
15
10 H2S
5
O2 1
2
3
4
5
6
7
8
H2S 100 200 300 400 500 600 700 800 CO2 50 100 150 200 250 300 350 400 DISSOLVED GAS CONCENTRATION IN WATER PHASE (PPM)
FIGURE 4.31 General Corrosion of Carbon Steel in the Presence of Oxygen, CO2 and H2S.140
4.7 O2
229
The overall reaction taking place during the corrosion of iron in the presence of oxygen is given by: Fe þ H2 O þ 1=2O2 /FeðOHÞ2
(Eqn. 4.85)
Ferrous hydroxide [Fe(OH)2], or hydrous ferrous oxide [FeO.nH2O] initially dissolves in the solution, saturates it, and finally forms a porous layer on the surface (green/blue). Fe(OH)2 is further oxidized to hydrous ferric oxide (reddish brown in color): FeðOHÞ2 þ 1=2H2 O þ 1=4O2 /FeðOHÞ3
(Eqn. 4.86)
A solution saturated with hydrous ferrous oxide has a pH of about 9.5. A solution saturated with hydrous ferric oxide has a neutral pH. Hydrous ferric oxide often turns black due to the formation of an intermediate hydrous ferrous-ferrite oxide (Fe2O3.FeO.nH2O or Fe3O4.nH2O). Thus, the surface layers of iron may consist of three or more forms of iron oxide, depending on the extent of oxidation and hydration (Table 4.9). Depending on environmental conditions, the oxide surface layers can be porous and non-protective, or compact and protective.141–154 The surface layers of iron oxides are stable even at higher temperatures. An adherent and protective magnetite has been observed even at 310 C.155
4.7.1 Effect of temperature It is generally accepted that, in the presence of oxygen, the corrosion rate of carbon steel doubles for every 30 C (90 F) increase in temperature (when compared to chemical reactions that in general, double in rate for every 10 C (50 F) increase of temperature) (see also section 4.11). In an open system, the corrosion rate drops at the boiling point due to the evaporation of water (disappearance of dissolved oxygen). On the other hand, in a closed system, the corrosion rate continues to increase with temperature (Figure 4.32).156
4.7.2 Effect of velocity157 In general, the surface layer thickness is large in stagnant systems and decreases progressively with increasing flow rate, until eventually all surface layers are removed. The effect of flow rate on corrosion in the presence of oxygen depends on the solution composition. For example, in the presence of chloride ions the corrosion rate increases with flow (Figure 4.33),158 but in the absence of chlorides, corrosion rate decreases with flow rate.
Table 4.9 Common Oxides of Iron Formula
Color
Oxidation State 2þ
Fe(OH)2 or FeO.nH2O FeO Fe(OH)3 or Fe2O3.nH2O
blue/green black red brown
Fe Fe2þ Fe3þ
Fe3O4 or Fe2O3.FeO.nH2O
black
Fe2þ/3þ
Name Ferrous oxide (hydrated) Ferrous oxide (unhydrated) Ferric oxide (hydrated) or Hematite (common rust) Ferrous-ferric oxide or Magnetite
230
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.32 Effect of Temperature on Corrosion of Iron in Water containing Dissolved Oxygen.156 Reproduced with permission from McGraw-Hill.
4.7.3 Effect of microstructure The influence of microstructure on the corrosion rate of steels in oxygen solution or in air is minimal in neutral solutions; only large amounts of chromium (more than 12%, e.g., stainless steel), silicon, or nickel decreases the corrosion rate. In acid solution, both composition and microstructure influence corrosion. Many alloying elements, such as carbon, nitrogen, sulfur, and phosphorous, increase both the general and pitting corrosion rates. Table 4.10 presents the general influence of alloying elements on the corrosion rate of iron.
FIGURE 4.33 Effect of Velocity on the Corrosion of Iron.158 Reproduced with permission from Wiley.
4.8 Sand and solids
231
Table 4.10 Effect of Alloying Elements on the Corrosion of Iron in Acid Media159 Element
Formula
Carbon
C
Phosphorous Sulphur
Concentration, %
Influence on Corrosion
Remarks
0.1 to 0.8
Slight increase in corrosion
Fe3C (cementite) acting as effective cathode increases galvanic corrosion
P S
0.02 0.015
Increases corrosion Increases corrosion
Copper
Cu
1
Moderately Increases corrosion rate
Chromium
Cr
12
Arsenic Manganese
As Mn
0.1 0.1
Nickel
Ni
5
Drastically decreases corrosion by forming effective oxide layer Increases corrosion Decreases corrosion; MnS, if present, may become location for pit initiation
Sulfur acts as anodic site, facilitating localized corrosion But in the presence of phosphorous and sulfur counteracts their accelerating effect Stainless steel
MnS inclusion has low electrical conductivity compared to FeS. It decreases the solubility of sulfur in iron
Decreases corrosion; may promote localized corrosion
4.7.4 Effect of pH Figure 4.34 presents the effect of pH on the corrosion rate of iron. Below pH 4, no surface layer is formed and the corrosion rate is independent of oxygen concentration; between pH 4 and 10, the corrosion rate increases with increase in oxygen concentration; and above pH 10 the corrosion rate decreases due to increased stability and compactness of surface layers. In many practical situations in the oil and gas industry, the pH is between 4 and 10, and under these conditions the corrosion rate increases with oxygen concentration.
4.8 Sand and solids161–163 Analyses of reservoir and rock mechanics of formations that have a relatively low strength (less than 2,000 psi (13.8 MPa)) and the availability of large amounts of oilsands indicate that the presence of sand in certain parts of the oil and gas industry is inevitable. Table 4.11 presents common types of solid and the most common cause of their formation.161 Both particle size distribution and concentration depend mostly on the formation rock and sand control technologies used. In most production facilities, sand control techniques are used to prevent the entry of sand into the downhole production tubulars. However, even with best sand control techniques,
232
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
FIGURE 4.34 Effect of pH on Corrosion of Iron in Aerated Soft water, Room Temperature.160 Reproduced with permission from the American Chemical Society.
Table 4.11 Common Types of Solids and Their Formation Mechanisms161 Solid Type
Typical Cause
Sand Oilsand Iron oxide, iron sulfide, iron carbonate and sulfur (generically referred to as ‘black powders’)
• Sand produced naturally from normal production wells • Sand naturally socked with oil • Direct chemical reaction of transported fluid components with pipe material • Ineffective removal of mill-scale from new pipe during pre-commissioning • Improper dewatering, drying and/or lay-up of pipe during pre-commissioning or remedial works. • Temperature and pressure change during the transportation of aqueous fluids; some inorganic scales (e.g., calcium carbonate, calcium sulfate, barium sulfate, and strontium sulfate) are deposited. • Comingling of incompatible aqueous fluids • Temperature and pressure change during the transportation of hydrocarbon fluids some organic molecules (e.g., asphaltene and wax) are deposited • Decrease of temperature (below dew point) and increased pressure during the transportation of wet (water containing) natural gas
Inorganic scales
Organic solids) Hydrates)
)
These solids, though cause operational difficulties for flow-assurance team, they do not normally accelerate corrosion
4.8 Sand and solids
233
sand will enter into the tubulars. Depending on the composition of the material being transported and the efficiency of the sand control techniques used, different types of sand or solid contamination may occur. Two unique pipelines of the oilsand sector of the industry are hydrotransport pipelines and tailing pipelines. Oilsands are transported from the mining area either by conveyer belt or by hydrotransport. Hydrotransport has been used since 2005. In this process, oilsands and water are mixed together to make a slurry, which is transported in pipeline from the mine to a bitumen-extraction facility. While the mixture of oil sands and water flow through the pipeline, large lumps of oil sands are broken down and bitumen is separated from the oil sands in the form of tiny droplets. The benefits of hydrotransport include lower energy consumption, lower operating temperature, and flexibility of transportation. However, the degradation of pipelines, due to erosion and corrosion caused by sand and water, is a major challenge (see section 2.13). Fine tailings are by-products of the oilsand extraction process. They are a mixture of water, sand, silt, and fine clay particles, and they are transported to tailing ponds via tailing pipelines. Similar to hydrotransport pipelines, tailing pipelines also suffer from erosion and corrosion (see section 2.20). Solids may form due to corrosion of steel exposed to wet-gas. Typical solids include iron oxides, iron sulfides, iron carbonates, and sulfur, and these are collectively known as black powders. Gas transmission pipelines may contain several types of solids including sand, sludges, biomass (containing microbial species), inorganic scales (e.g., calcium carbonate, barium carbonate), organic scales (e.g., paraffins and asphaltenes) and corrosion products. Some dissolved solids carried by entrained liquids may also drop out and accumulate under favorable conditions. The presence of black powder affects gas transmission pipelines in several ways. These black powders may be hygroscopic or deliquescent, and they increase corrosion rates by retaining water, by establishing environments under them (i.e., underdeposit corrosion), and by sustaining microbial growth. Black powders may decrease the corrosion rate if they form an adherent surface layer on the pipe’s surface. When water from different sources is mixed, inorganic scales can be formed (see section 4.4.3). When the temperature of pipelines transporting extra-heavy crude oil is low, some long-chain (typically containing more than 20 carbon atoms, e.g., C20H42) paraffinic components (asphaltenes and wax) may deposit as hard solids. The majority of crude oils with API 20 or less (i.e., heavy and extra-heavy crude oils) contain significant amounts of paraffinic wax. As temperature reduces, wax will start to precipitate out. The wax may deposit in the form of an oil-gel containing some entrapped oil. As the temperature decreases the wax solidifies, eventually stopping the flow of crude oil. The temperature at which oil stops moving is known as the crude pour point temperature. To avoid wax formation, several measures are taken, including thermally insulating the pipe, using cleaning pigs, and adding chemicals. Asphaltenes are organic fractions of crude oils that are soluble in benzene and toluene, but not in alkanes (n-pentane and n-hexane). As the temperature decreases, asphaltene precipitates as a solid. Similar to wax formation, asphaltene formation may block the flow, but unlike wax they do not melt on heating. To remove asphaltene the pipeline is mechanically cleaned (using pigging and wireline cutting), or chemical solvents are used to dissolve it. Chemical inhibitors are also used to prevent the precipitation of asphaltenes in the first place. In wet-gas and multiphase pipelines, gas hydrates may form at low temperatures. Gas hydrate is formed when gas molecules are trapped in a cage of water molecules under certain pressure and temperature conditions. Generally, methane hydrate is formed in the presence of water, when the temperature is below 40 F (4 C) and pressure is above 170 psi (1,172 kPa). Decreasing temperatures and increasing pressures further favor hydrate formation. In addition to methane hydrate, ethane,
Very high
Dispersed sand flow Liquid/solid impingment erosion
Dispersed sand flow Solid/liquid impingment erosion
Dispersed sand flow Solid impingment erosion
High
Flow Rate
Liquid impingment erosion
Flow induced localized corrosion
Dispersed sand flow Corrosion influenced erosion
Scouring sand flow Corrosion influenced erosion
Scouring sand flow Corrosion influenced erosion
Medium
CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Flow assisted pitting corrosion
Scouring sand flow Erosion influenced corrosion
Sand dunes Erosion influenced corrosion
Sand dunes Erosion influenced corrosion
Low
234
General and pitting corrosion
Sand dunes Pitting corrosion
Sand deposits Pitting corrosion
Sand deposits Underdeposit corrosion
No
Small
Medium
Large
Sand Level FIGURE 4.35 Effect of Sand on Corrosion and Erosion.
propane, CO2 and H2S hydrates may also form. These hydrates form as solids or semi-solids, and they slow or even completely block the gas flow. Several measures are taken to avoid hydrate formation in gas pipelines, including removal of water, keeping the temperature above hydrate formation temperature, maintaining the pressure below hydrate formation pressure, and by injecting chemicals (hydrate inhibitors). The formation of these solids, i.e., asphaltene deposits, wax deposits, and hydrate normally decrease the corrosion rate. But they create operational difficulties, e.g., pressure drop and, in extreme situation, stoppage of flow; therefore their formation is avoided. The presence of solids may result in corrosion under sand beds (underdeposit corrosion), erosioninfluenced corrosion (EIC), corrosion-influenced erosion (CIE), and erosion. Figure 4.35 presents various types of corrosion and the conditions in which they will probably occur. However the boundary conditions between these types of corrosion are not well established.
4.9 Microorganisms165–168 When some microbiological species are present, they may influence corrosion. The corrosion influenced by microbiological activities is known as microbiologically influenced corrosion (MIC).164 Microorganisms do not produce unique types of corrosion. For this reason, it is accepted by international community that the term is microbiologically ‘influenced’ corrosion, rather than microbiologically ‘induced’ corrosion. The presence and activities of microorganisms may cause pitting, crevice corrosion, selective dealloying, and differential aeration cells (see section 5.14).
4.9 Microorganisms
235
There are several types of microorganisms present in air, water, and attached to solid materials. The microorganisms floating freely in a liquid are commonly referred to as ‘planktonic’ organisms. Microorganisms that are attached to a surface are commonly known as ‘sessile’ organisms. The microorganisms may be classified as bacteria (0.2 to 2 mm), fungi (2 to 20 mm), and algae (2 to 20 mm). All these microorganisms can be present in diversified environments of various pH, oxygen content, temperature, and food sources. Table 4.12 presents some of their characteristics. When conditions are conducive, they multiply rapidly, with growth as high as 1 million/ml within 24 hours. Of the various microorganisms, sulphate-reducing bacteria (SRB), acid-producing bacteria (APB), iron-oxidizing bacteria (IOB) and iron-reducing bacteria (IRB) are known to cause MIC. SRB constitute a diverse group of anaerobic bacteria which have several morphologies and nutritional requirements. They reduce sulfate to hydrogen sulfide. Common SRBs include Desulfovibrio, Desulfobacter and Desulfotomaculum. Since the discovery of SRBs by the Dutch microbiologist Wilhelm Bijerninck in 1905, they have been considered as the dominant bacteria associated with MIC.169 Despite the recognition that the most severe MIC occurs in the presence of consortia of bacteria, SRB are most often considered as the primary cause, because they are ubiquitous; in sulfate-containing environments they produce hydrogen sulfide; and they convert sweet production to sour production (containing hydrogen sulfide).
Table 4.12 Characteristics of Microorganisms Properties
Definition
Bacteria
Fungi
Algae
Nucleus
Procaryote (i.e., it does not have any nucleus) eucaryote (i.e., they have nucleus)
Procaryote
Eucaryote
Eucaryote
0.2 to 2 No 3 to 9
2 to 20 No 3 to 5
2 to 20 Yes 7 to 8
Yes
Yes
Yes
Yes Yes Yes Yes
No e e Yes
No e e Yes
Yes
e
e
Yes
e
e
e Yes
e e
Yes e
Yes
e
e
Typical size, mm Chlorophyll Typical pH range of activity Aerobic Anaerobic Anaerobic-Obligate Anaerobic-Faculative Psychrophiles Mesophiles Thermophiles Phototrophs Lithotrophs Heterotrophs
Requires light to grow
Presence of oxygen required for growth Oxygen is not required for growth Can not tolerate oxygen Can tolerate oxygen Active in the temperature range 20 to 20 C Active in the temperature range 20 to 45 C Active in the temperature range above 45 C Light is the source of energy Inorganic matters are the source of energy Organic matters are the source of energy
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Section 5.14 discusses the mechanism of MIC, section 6.7.6 presents comprehensive model for MIC, and section 8.2.4 presents methods for monitoring MIC.
4.10 Pressure As discussed in section 4.2, pressure is the force that moves the hydrocarbons. Therefore an important consideration in designing and operating the piping and pipeline is to estimate the amount of pressure required to transport the hydrocarbons. Many oil and gas facilities are operated at elevated pressure. The effect of pressure on corrosion depends on the partial pressures of acid gases (H2S and CO2), other chemical species (bicarbonate, acetate, and calcite), the pH and temperature. Higher pressure (or partial pressures of acid gases H2S and CO2), may increase corrosion if it increases the dissolution of corrosive species into the solution, or increases the dissolution of the surface layer from the metal surface. On the other hand, higher pressure may decrease corrosion if it facilitates the formation of a compact surface layer.
4.11 Temperature In general, the relationship between temperature and chemical reactions is provided by the Arrhenius equation. According to this equation, the rate of a chemical reaction increases with an increase in temperature. The Arrhenius equation also applies to corrosion reactions taking place by electrochemical mechanisms (see section 5.2). Depending on the material, environment, and temperature, the corrosion rate doubles for every 10 or 30 C increase in temperature. However, the Arrhenius equation applies only in the range of temperature in which the corrosion mechanism remains the same. Above and below this temperature range, the relationship between corrosion rate and temperature may be different. Sections 4.5.1, 4.6.1, and 4.7.1 respectively present the effect of temperature in CO2, H2S, and O2 systems. In some cases, an increase in temperature decreases corrosion. The dew point is the temperature below which water condenses. When the temperature is above the dew point water does not condense. Because water is required for electrochemical corrosion to take place, above the dew point the corrosion rate decreases. Most of the gas wells and gas pipelines are operated above the dew point to avoid condensation of water, and hence corrosion. On the other hand, in some cases, a decrease in temperature decreases corrosion; this normally happens when solids such as asphaltene, wax, and hydrates form (see section 4.8). However, the formation of these solids causes other operational difficulties and hence this is avoided. At high temperatures, typically above 840 F (w450 C), another form of corrosion known as ‘high temperature corrosion’ takes place (see section 5.15).
4.12 pH The pH of the waters in the oil and gas industry depends on the partial pressures of the acid gases (H2S and CO2), concentrations of buffering species (bicarbonate and acetate ions), the concentration of scale-forming species (calcium carbonate), temperature, and organic acids (acetic acid). Table 4.13
4.13 Organic acids
237
Table 4.13 Influence of Parameters on pH (Experimental Data)170 Parameter
Parameter Range
pH Range
CO2 H2S CO2 and H2S
10 to 80 psi 10 to 80 psi 80 psi each
4.5 to 5.5 4.8 to 5.5 4.0 to 5.0
Temperature NaHCO3
30 and 50 C 4,000 ppm
4.4 to 4.8 6.0
CH3COONa
4,000 ppm
6.0
CH3COOH A mixture of NaHCO3 and CH3COONa
4,000 ppm 4,000 ppm each
4.0 6.0
Effect of Increasing Value of the Parameter on pH Decreases Decreases Same as for individual acid gases Slightly increases Increases and stabilizes (buffering) Increases and stabilizes (buffering) Decreases Stabilizes (buffering)
summarizes the influence of some parameters on the pH. Sections 4.5.4, 4.6.4, and 4.7.4 respectively discuss the influence of pH in sweet, sour, and oxygen containing environments. Determination of pH at the point where corrosion occurs provides valuable information; however such measurement is not routinely carried out. In many instances, the pH of the solution is measured under atmospheric pressure, immediately upon withdrawal from the system. This pH may not necessarily be the pH of the water within the system, because of the loss of acid gases, such as H2S and CO2, through pressure reduction and exposure of the fluid to atmosphere. Alternatively the in situ pH is estimated.171–175 The use of handheld devices facilitates estimation of in situ pH quickly. Equation 4.87 provides a simple method to quickly estimate pH in sweet environment: 1 pH ¼ 4:08 þ Log pffiffiffiffiffiffiffiffiffiffiffi WCO2
(Eqn. 4.87)
where WCO2 is the weight of CO2 in grams dissolved per liter of water.
4.13 Organic acids Organic acids include a broad range of compounds containing a carboxylic group, i.e., –COOH. Depending on the hydrocarbon molecule to which this carboxylic group is attached the organic acids can be broadly classified into: • • •
aliphatic acids (Ali.COOH) where the hydrocarbon molecule may be a straight or branched hydrocarbon, e.g., CH3– (acetic acid), C2H5– (propionic acid), etc; aromatic acids (Ar.COOH) where the hydrocarbon molecule may be benzene or substituted benzene ring; and naphthenic acids (Nap.COOH) where the hydrocarbon molecule may be a saturated cyclic ring, e.g., cyclopentane, cyclohexane, etc. The term ‘naphthenic acid’ as used in the oil and gas industry actually refers to many organic acids present in crude oil.
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
Section 4.3.1c briefly discusses the influence on organic acids present in crude oils. The organic acids influence corrosion as: Fe þ 2RCOOH/FeðCOORÞ2 þ H2
(Eqn. 4.88)
where R’ is an aliphatic, aromatic, or naphthenic group. Depending on the type of organic acid, the reaction product, Fe(COOR’)2, is soluble in crude oil or in the aqueous phase. For this reason, corrosion by organic acids does not leave any product layers on the metal surface. Corrosion by aliphatic acids normally occurs at temperatures as low as 140 F (60 C) due to their low volatility. On the other hand, corrosion by naphthenic acids normally occurs at temperatures above 430 F (w220 C); the corrosion rate increases with increase of temperature up to between 500 and 700 F (260 and 370 C), and drops above 700–750 F (370–400 C) due to the decomposition of the acids. Aromatic acids are not normally corrosive.
4.13.1 Aliphatic acids The presence of acetic acid in oilfield brines can significantly increase the rate of corrosion of carbon steel, even if the bulk pH is high due to the presence of bicarbonate ions. Although the presence of acetic acid affects the corrosion rate, it does not necessarily affect the corrosion mechanism (see section 5.24). The species increases the corrosion rate by locally decreasing the pH and dissolving the iron carbonate surface layer. As a result, the thickness of the iron carbonate surface layer is locally reduced. Acetic acid also interferes with the chemical analysis of bicarbonate ions resulting in overestimation of the concentration of bicarbonate ions. For these reasons, the effect of acetic acid is commonly known as a ‘double whammy effect’; i.e., acetate ions lead to overestimation of the concentration of bicarbonate ions (thus underestimation of sweet corrosion rate) and itself increases corrosion rate.176
4.13.2 Naphthenic acids Corrosion by naphthenic acids normally occurs at temperatures above 430 F (w220 C) during refinery processing. For this reason, the concentration of naphthenic acids in crude oil is routinely determined before processing. The crude oil is titrated with potassium hydroxide (KOH) and the resultant value is known as ‘neutralizing number’ or ‘acid number’ or total acid number (TAN). The TAN is expressed as milligrams of KOH required to neutralize the acidity of one gram oil. Standards providing procedures to determine the naphthenic acid content of crude oils include: • •
ASTM D664, ‘Standard Test Method for Acid Number of Petroleum Products by Potentiometric Titration’ ASTM D974, ‘Standard Test Method for Acid and Base Number by Color-Indicator Titration’
As a rule of thumb, crude oils with TAN values greater than 0.5 and refined fractions with TAN values greater than 1.5 are considered corrosive.177 However, the corrosivity of different oils with same acid number may not be the same. Corrosivity also depends on other parameters including temperature,
4.14 Mercury
239
type of acid and the presence of other chemicals, e.g., sulfide. Depending on the presence of a sulfide surface layer, naphthenic acid corrosion may be classified into three types: • • •
Pure naphthenic acid corrosion with no or little effect of sulfur compounds. Sulfidation corrosion, i.e., accelerated corrosion due to the destruction of a sulfide surface layer by naphthenic acid. Inhibited naphthenic acid corrosion, i.e., inhibition of naphthenic acid corrosion due to the presence of a sulfide surface layer.
This property is utilized during refining crudes with higher TAN and high sulfur contents. The highTAN crudes and high sulfur crudes are often blended together to control corrosion. The forms of sulfur involved in this process and the threshold amounts have not been established.
4.14 Mercury Mercury (Hg) in natural gas streams was first recognized in gas fields in Asia. Since then production of Hg in natural gas has been observed in many fields. Though handling of Hg is a health concern, from the perspective of corrosion, liquid metal embrittlement (LME) is of concern. Mercury forms amalgams (liquid solutions) with many metals including aluminum, tin, gold, silver, and zinc. In general, aluminum oxide protects Al. When Hg contacts an Al surface, it breaks the aluminum oxide, wets the surface and forms an amalgam. As a consequence of the amalgam, the mechanical strength of the metal is lost. The Al amalgam also reacts with moisture, producing aluminum hydroxide and regenerating Hg. The aluminum hydroxide grows as a characteristic tree-like structure. As a consequence of this self propagation, the corrosion rate of Al can be as high as 40 inch/y (w1 meter/y), with corrosion products appearing on the surface dramatically and rapidly. Table 4.14 presents the interaction of Hg with other metals.178
Table 4.14 Effect of Mercury on Metals178 Metal
Effect of Hg
Remarks
Carbon and low alloy steel
No effect
Type 304 SS
Sensitization
Carbon steel piping and vessels are used in the presence of Hg without loss of integrity The fracture surface of the sensitized material exhibits intergranular regions
Type 316 SS Type 316L SS Type 321 SS Alloy 800 13% Cr SS Ti Grade 2 alloy Alloy 600 Monel 400
No effect
Sensitization LME
Exhibits intergranular cracking
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CHAPTER 4 The Main Environmental Factors Influencing Corrosion
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