Chapter 11. Geopressured Reservoirs

Chapter 11. GEOPRESSURED RESERVOIRS

The composition of the waters in normally pressured reservoirs often differs from the composition of the waters in geopressured or abnormally high-pressured reservoirs. There are several theories concerning the cause of the geopressured zones; many papers have been written about their occurrence and causes (Burst, 1969; Dickey et al., 1968, 1972; Fowler, 1970; Harkins and Baugher, 1969; Hottmann and Johnson, 1965; Jones, 1969; Powers, 1967;Schmidt, 1973;Wallace, 1969). Knowledge of how to locate geopressured zones is important in drilling operations, because if such a zone is drilled into without adequate preparation, the well may blow out, perhaps causing a fire, loss of the well, loss of the drilling rig, or even loss of life. The usual precaution, if the driller knows of a high-pressure zone, is to increase the weight of the drilling mud; however, the continual use of heavyweight mud is much more expensive than drilling with a lighter weight mud. Drilling rig time is worth about $2,000 per day, and it costs about $44,000 per kilometer to drill a well on land. A drilling barge in the bay can cost from $4,000 to $lO,O.OOper day while a drilling ship plus a full crew costs about $25,000 per day. Considering.the foregoing costs plus the cost for a special crew t o extinguish a fire at an ignited blowing well can be very expensive because the initial fee for the fire extinguishing personnel is about $25,000. Steps, therefore, are taken by the drilling company to assure that an adequate drilling rig is used, that the optimum size borehole is drilled, that the correct weight drilling mud is pumped down, that strong enough casing is inserted into the well, and that blow-out preventers are operative. Geopressure Dickinson (1953)defined abnormally high pressure (geopressure) as any pressure exceeding the hydrostatic head of a column of water (extending from the subsurface tapped stratum to the land surface) containing 80,000 mg/l of dissolved solids. Formations with equal or less pressures are considered normal or subnormal. In the Gulf Coast area the normal pressure gradient is about 0.107 kg m-l, or about equal to 0.21 g cm-3 of drilling mud (Harkins and Baugher, 1969). Normal pressure in the Rocky Mountain region has a gradient of 0.100 kg m-', although excep tions occur in western Montana, the Denver Basin, the Powder River Basin, and the San Juan Basin, mostly in Cretaceous rocks (Finch, 1969). (A gradient of 0.118 kg m-l is normal in the Williston Basin in North

344

GEOPRESSURED RESERVOIRS

Dakota.) Normal pressure is that which is normal for the particular area involved and is related t o the salinity of the reservoir water, rock types, and geologic setting, but in general, it is that pressure exerted by a column of water from the surface t o the observed subsurface formation, which is equal to and will balance the subsurface formation pressure. Abnormally high pressures are those which exceed this normal hydrostatic head. Geostatic ratio Abnormal pressures can be expressed in terms of a “geostatic ratio,” which is the ratio of the observed fluid pressure in a subsurface formation t o the overburden pressure of the overlying sediments. This load at a given m down t o depths of more than depth is approximately 0.231 kg 6,100 m, because the density of rocks changes slowly with depth (Pennebaker, 1968). Any abnormal pressure will therefore have a geostatic ratio in the Gulf Coast area and between between 0.0327 and 0.0703 kg in the Rocky Mountain area. 0.0304 and 0.0703 kg Compaction model The compaction concept was demonstrated using a model consisting of perforated metal plate separated by metal springs in water and enclosed in a cylindrical tube (Terzaghi and Peck, 1948). The springs were used to simulate communication between deposited particles and with the initial pressure upon the upper plate, the springs d o not move because all of the pressure is supported by the water, assuming that water does not escape from the system. Relating the fluid pressure (FP) t o the total pressure (TP) one can derive an equation X=FP/TP to record various formation pressures (X)t o determine the geostatic ratio using the model.

Origin of abnormal pressures Abnormally high pressures in a formation can be caused by compaction. Factors which may cause them are, according to Hottmann and Johnson (1965),“the ratio of shale t o sand thickness, the mean formation permeability, the elapsed time since deposition, the rate of deposition, and the amount of overburden.” These parameters are interrelated in compaction, which is the controlling factor in fluid pressures within subsurface sedimentary environments (Harkins and Baugher, 1969). Dickinson (1953)reports that the fluid pressures within sediments are predominately controlled by two factors; namely: (1)the compression as a result of compaction; and (2)the resistance t o expulsion of water. Compaction begins with sedimentation and deposition of soft muds composed of up to 90% water (Wallace, 1969). In an environment where deposition continues, gradual compaction occurs whereby the muds become clay

ORIGIN OF ABNORMAL PRESSURES

345

minerals and shales. The shales are primarily clay minerals with flat or tabular grain shapes; with additional overburden, the pressure packs the grains closer together, with a resultant expulsion of water from the intervening spaces. In the early stages of compaction, the shale possesses high porosity and permeability, and the expelled water always flows to areas of least resistance and pressure (often porous sand). As the overburden increases, the porosity and permeability of the shale decrease until equilibrium is approached and the pressure in all directions is equal. A t this point, expulsion of additional water is limited. Tectonics, of course, could alter the subsurface environment. Deposition and sedimentation of sand are somewhat different because the sand grains are in contact in the first stage and sand compaction is about complete with deposition. However, reduction of porosity can occur by: (1) solution of the sand grains at contact points; and (2) rearrangement of the grains because of very high pressures. Clay beds separating aquifers are often referred to as semipermeable membranes. Such beds can separate aquifers containing waters of different salinities, causing a hydrostatic head in the direction of the more saline water.

Fig. 11.1. Sand dikes in the Simpson Sand formed by the actiqn of highly pressured subsurface waters forcing the lighter colored sand intrusively into the primary sandstone. The primary sand was formed from white beach sands during Ordovician time.

346

GEOPRESSURED RESERVOIRS

Osmotic pressure can develop, which is dependent upon osmotic efficiency of the clay bed and the differences in salinities of the two aquifers (Young and Low, 1965).According to Jones (1969),stepwise increments of osmotic pressure may develop wiih depth through a series of bedded sands and clays acting as a multistage pump, thus producing the high reservoir pressures in the northern Gulf of Mexico basin. Fertl and Timko (1972)discuss 17 possible causes of abnormally high pressures. They are rate of sedimentation, tectonic activities, potentiometric surface levels, reservoir structures, areal salt deposition, shallow-reservoir repressuring, paleopressures, mud volcanoes, secondary precipitation of cementation constituents, diagenesis of volcanic ash, rehydration of anhydrite, diagenesis of clays, osmosis, permafrost, earthquakes, chemical, thermal chemical, and biochemical effects, and tidal disturbances. Fig. 11.1 illustrates one type of action that results from high pressures, where sand dikes formed by the action of highly pressured subsurface waters forcing the lighter colored sand intrusively into the primary sandstone. The primary sandstone was formed from white beach sands during Ordovician time. Abnormal pressures in the Gulf Coast area In the Gulf Coast area, the abnormal pressure seems t o be related t o rapid deposition of sediments and low regional transmissibility. Fluid pressures are near hydrostatic where there is continuity with normally pressured aquifers and where the sands are sufficiently permeable to dissipate the expelled water from the compacting fine-grained rock. In some of the deep oil and gas wells of the Gulf Coast, the pressure of the interstitial fluids (oil, gas, or water) in kilograms per square centimeter is normally the depth in meters multiplied by 0.107.This is slightly more than the pressure required t o sustain a column of water to the surface. At great depths where the geological section is mostly shale, fluids at abnormally high pressures are found. Sometimes the pressures are very high, approaching 0.2 kg cme2 m-l. Often the increase in fluid pressure is abrupt, taking place in a vertical interval of 30 m or less. In other areas, the increase in pressure is more gradual, extending over 300 m of vertical section. The depth at which the pressure starts t o increase ranges over a wide interval. Abnormal pressures are found at depths as shallow as 1,000m in some offshore fields, and wells in some areas have been drilled deeper than 7,000 m without encountering abnormal pressures. Forty-one formation water samples from gasfields in southwestern Louisiana were obtained and analyzed to determine the relationships of the chemical composition of the waters to normal and abnormally pressured geologic zones (Dickey et al., 1972).The concentration of dissolved solids in the waters from the overpressured zones is generally less than in the normal pressure zones, and this knowledge is significant in electric log interpretation.

ABNORMAL PRESSURES IN THE GULF COAST AREA

347

Fig. 11.2. Slash lines showing the general area in Louisiana where the samples were obtained.

Previous work in the area suggested that the abnormally fresh waters were found in the same part of the section as were the abnormally high pressures (Dickey et al., 1968). The general locations of the wells are shown in Fig. 11.2. They were from the South Lewisburg, Church Point, Branch, South BOSCO,North Duson, Duson, Ridge, and Andrew fields, all in Acadia, and Lafayette Parishes, Louisiana. The water samples were analyzed chemically by using the procedures published by the American Petroleum Institute (1968). The analytical data are summarized in Table 11.1. A subsurface cross section, Fig. 11.3, was constructed in a general northsouth direction showing the stratigraphy and structure across seven oilfields in the area of study (Fajardo, 1968). The initial pressures of the shallower reservoirs are normal. However, below 2,450 m many reservoirs contain fluids with abnormally high pressures. The 4.9-m amplified normal curve was used to recognize the first appearance of abnormal pressures in the shale section. The fluid pressure gradients were estimated following the method described by Hottmann and Johnson (1965). Shale resistivity and fluid pressure gradient versus depth were plotted for 50 wells in different fields of the study area, and of these, 22 are included in the cross section. All of the 41 waters belong t o the chloride-calcium class of Sulin (1946), and none has the composition of meteoric water. The principal cation is sodium, although the concentration of calcium is always high. In some of the more concentrated brines, the calcium concentration is nearly 40,000 mg/l and constitutes over half the reacting value of the sodium. Magnesium is variable in amount, and in two samples it is absent. Chloride is the predominant anion, amounting always t o more than 49.5% of the total reacting values. Sulfate usually is absent and never is present in concentrations greater than 0.5% of the total reacting value. In Fig. 11.3, the top of the section is 2,100 m below sea level. The electric logs indicate the lithology, which is quite sandy down t o a depth of 2,700 m

TABLE 11.I Formation-waters sample locations, constituents found in the waters, shale resistivity (SR),and fluid pressure gradients (FPG) Sample Location o f number of well (S-Twp-R)

1*I 2’1 3*’ 4’1 5*1

6

7 8 9 10

73-105-34E 2l-lOS-03E 2*lOSFo3E 20-10S-aE 17-10S43E O8-lOS43E 25-07S43E 25-07603E

11

12 13 14 15 16 17** 18 19 20 21 22*’ 23 24*’ 25” 26 27 28 29 30 31 32 33*’ 3483 35*3 36” 37 38 39*3 40 41*3

*’ Abnormal pressure.

Depth (m)

Zone

Specific gravity

Concentration (mg/l)

(60°/600F) CI

4,66+4,664 3,643-3,645 3,625-3,627 3.613-3,615 4,060-4,063 3,047-3.049 3,325-3,327 3.293-3.296

1.035 1.062 1.057 L. Camerina 1.059 U. Camerina 1.085 Bolivina-mex Discorbis 1.045 1.060 U. Tweedel 1.069 L. Tweedel U. Nodosaria 1.083 Daigle 1.051 1.065 U. Nodosaria 1.069 Tweedel 1.062 Tweedel 1.128 Struma Frio 1.061 Nodosaria 1.149 Klumpp D 1.090 Frio 1.058 Frio 1.058 Frio 1.057 1.144 Frio 1.090 U. Texana U.Texana 1.092 1.220 Frio 1.202 Frio l.lS3 Frio 1.139 Nodosaria 1.070 Marg howei 1.144 Homeseeker 1.145 Nodosaria A Horn-eker D‘-4 1.088 1.055 Klumpp E 1.089 Brookshire Brookshire 1.089 Brookshire 1.082 Brookshire 1.089 Nodosaria 1.140 Homeseeker 2-D 1.120 1.069 Marg tex 1.082 U. Moicene 1.050 Marginulina Bolivina-mex

U. Camerina

39,000 55,600 56,600 50,000 72.800 33,300 51,700 58,000 50,900 45,300 45,600 57,900 52,600 116,000 50,900 135,000 79,300 46,600 47,900 45,800 125,000 84.500 80,300 201,000 184,000 111,000 119,000 61,600 100,000 109,000 80,000 44,400 77,500 78,000 72,300 75,400 129,000 120,500 55,500 74,400 49,700

HCO3

387 541 826 630 448 503 180 363 507 545 574 586 579 322 330 92 334 741 788 694 135 419 363 0 0 112 76 550 66 73 270 244 171 206 234 203 80 240 539 249 482

SO,

0 407 234 38 tr. 50 0 tr. 33 0 tr. tr. 0 0 67 223 0 60 72 ND 0 122 tr. 352 tr. ti. 0 0 0

SR at B

49 62 62 37 43 32 18 26 35 28 29 26 34 38 23 52 48 46 48 44 47 40 45 75 67 42 52 67 42 0 39 77 34 130 36 0 18 0 18 0 33 0 18 0 41 0 43 102 52 0 26 8 8 43

Mg

Br

1

Na

Ca

35 61 52 57 81 37 21 41 70 38 35 56 45 128 43 154 169 40 52 47 64 20 62 213 204 94 117

18 22 21 21 19 16 15 18 23 18

17,800 32,300 34,200 29,500 41,100 19.200 34,800 34,400 27,500

1,070 78 2,210 369 1,380 213 1,380 194 3,850 583 1,390 224 2,730 544 2,020 194 3,050 719 2,310 167 2,950 447 2,660 389 1,570 0 21,600 2.180 1,890 408 15,200 1,270 2,950 447 2,660 1,010 2,180 303 ND ND 15,700 159 7,390 565 3,300 972 38,800 2,140 33,200 5,770 14,300 428 18,400 1,200 3.610 17 18,300 1,090 14,400 700 2,760 35 1,510 447 836 3,530 3,270 972 3,270 564 3,370 894 4.560 0 5,610 564 3,210 136 2,950 855 1,780 141

14

201 71 110 70 81 82 58 162 174 134 40 79 60

22

25 20 26 18 24 74 23 21 22

23 22 20 18 19 24 28 5 21 21 34 30 21 19 18 19 24 38 26 18 35

26,000

24,900 33,300 31,700 49,600 29,600 66,800 46,400 24,700 26,600 ND 61,900 45,800 45,800 80,600 68,900 53,600 52,700 35,200 40,600 51,800 47,800 25,800 44,200 44,400 41,200 42,600 77,800 68,800 32,500 42,800 29,600

*’ Abnormal pressure. but normal chemically. * 3 Samples 33-36 are from the Abheville field or the south and of the area sampled and appear to be in a different chemical family, S-Twp-R = section-township-range; ND = not determined.

K

Li

Sr

518 247 200 204 267 85 208 230 162 134 262 in1 192 427 31 5 813 427 172 166 157 830 324 376 782 640 798 771 137 1,150 631 392 166 236 235 294 232 ND 375 176 264 71

10 7 6 6 6 3 4 5 6 4 4 4 5 9 9 9 10

ND ND ND ND ND P:D ND ND ND ND ND ND ND ND ND ND

6

5 4 15 7 9 17 17 12 18 5 17 15 10 5 2 2 3 2 ND 5 5 2

2

Ba

ND ND ND YD ND ND ND ND ND ND ND ND ND ND ND ND 0 50 0 5 0 5 0 8 0 19 ND ND 0 33 ND ND ND ND ND ND ND ND ND ND N D l ND ND ND 0 110 ND ND 140 97 128 109 265 41 171 102 ND ND ND ND 0 7 195 85 0 4

NH4 organic acid as acetic 246 295 238 650 178 200

538 301 362 279 210 254 364 218 230 250 202 377 206 96 243 110 142 294 282 295 279 180 222 368 349 195 219 214 258 306 152 295 179 167 160

84 48 96 72 96 120 24 76 24 96 72 96 120 144 48 24 144 120 96 72 48 96 144 48 120 48 24 168 72 96 24 12 96 624 144 48 ND 96 192 432 312

FPG spl. depth (kg cm-2

6’)

0.77 0.59 0.62 ND 0.38 1.1

ND ND 1.02 0.83 0.97 ND ND 0.90 ND ND 0.60 0.84 ND 1.o

0.94 0.35 0.70 0.50 0.35 1.4 1.o

0.38 1 .o ND ND 0.83 ND ND ND ND 0.95 0.92 0.65 ND 0.57

0.185 0.159 0.157 ND 0.195 0.107 ND ND 0.107 0.107 0.107 ND

ND

0.107 ND ND 0.157 0.107 ND 0.107 0.107

0.191 0.131 0.191 0.203 0.107 0.107 0.193 0.107 ND ND 0.107 ND ND ND ND 0.107 0.107

0.152 ND 0.16X

ABNORMAL PRESSURES IN THE GULF COAST AREA

?6 *33a34

4.5

il

30

I

I

50

40

1

60

I 70

I

80

357

KEY X AbnzDressure Normal pressure

I

90

I

100

1

I

120

110

I D

CHLORIDE, g / l

Fig. 11.4. Plot of the depth of the wells versus concentrations of chloride in the formation waters.

-‘-I 2.5

c

0

,

33.

/ KEY X Abnormal pressure/ ?‘Normal presauro

3p

034

0.5 BICARBONATE, p/l

Fig. 11.5. Plot of the depth of the wells versus concentrations of bicarbonate in the formation waters.

GEOPRESSURED RESERVOIRS

358

in the north to 3,050 m in the south. Below this depth, the sands become less abundant and less widespread. The first abnormal pressure as calculated from shale resistivity is indicated by an arrow. The location of a producing horizon from which a water sample was taken is shown by the sample number in a circle. When the water sample was taken from a nearby well, not shown on the section, it was projected onto the section and shown as the sample number inside a square in Fig. 11.3. There is a general tendency for the dissolved salt concentration of the water samples t o increase with depth. This is shown in Fig. 11.4, which shows chloride plotted against depth. Since chloride is the predominant

I

KEY )< Abnormal pressure 0 Normal pressure

25

K

27

\

I

10

X

24

\

I

CALCIUM, g/l

Fig. 11.6. Plot of the depth of the wells versus concentrations of calcium in the formation waters.

359

ABNORMAL PRESSURES IN THE GULF COAST AREA

anion, it serves as an indication of the degree of concentration. The samples of water from abnormally pressured sands are shown as circles in x'es. All of them except 17, 22, 24, and 25 fall below the average concentration line, that is, they are less concentrated than they should be for their depth of burial. Sample 1 especially is much too weak. Bicarbonate, while occurring in much smaller quantities, shows the reverse relation, decreasing in amount with depth, as shown in Fig. 11.5. The waters from horizons with abnormal pressures have more bicarbonate than they should, considering their depth of burial. Calcium increases with depth, as shown in Fig. 11.6. It would be more correct t o say that there are two types of water. Type 1includes waters with less than 5,000 mg/l calcium, all of which are shallower than 3,800 m; type 2 is water with more than 5,000 mg/l calcium, most of which is deeper than 3,500 m. The only minor constituent that indicated a significant change with depth was potassium, and it appears to increase relative to sodium. The abnormally pressured waters seem deficient in potassium for their depth.

Normal pressure x

Abnormal pressu&e-Solution

o N o r m a l pressure- A l t e r e d relict bittern

100 -

O\&o

0% '0

a0 -

0

\

0

"\

"

\

O \

-

\ 0

60-

\ "\ .\O 0

A 0

0

0 SODIUM, g/l

Fig. 11.7. Comparison of some brines of a bittern type from the Michigan Basin with some brines from some normal and abnormally pressured reservoirs in Louisiana.

GEOPRESSURED RESERVOIRS

36 0 I50

Normal pressure x Abnormal pressure

I25

I00

/

\

2 5-

.

75 X

0

0

In 50

X

- x

25 X*

Sodium’=mg/l

0

I

0.05

Na

+ 40 mg/l

I

010 BROMIDE,

Ca

I

0.15

I

0.20

!5

g/l

Fig. 11.8. Plot of Na’ versus Br from some brines from normal and abnormal pressured reservoirs in Louisiana.

Four of the waters from high-pressure sands (17, 22, 24, 25) have normal concentrations of dissolved solids for their depth. The other waters from high-pressure sands (1-5, 13, 28, 39, 41) have lower concentrations than normal. They also have less calcium, more bicarbonate, and a higher Cl/K ratio. About 80% of the material in the Gulf Coast shale is clay. Assuming that the waters have reacted with montmorillonite, there should be a direct relationship of calcium t o sodium. Plotting the calcium and sodium data in Table 11.1 plus some data for some brines from the Michigan Basin (as shown in Fig. 11.7) indicate that a relationship of calcium t o sodium does exist in the Gulf Coast waters and that they probably have reacted with montmorillonite. Fig. 11.7 also indicates that the Gulf Coast waters are not an altered relict bittern as are the Michigan Basin brines. In an ion exchange reaction with montmorillonite, 2 moles of sodium are exchanged for 1 mole of calcium, therefore, if salt is redissolved the bromide content in solution should be proportional to the original redissolved solu-

ABNORMAL PRESSURES IN THE GULF COAST AREA

36 1

tion. However, because of the exchange reaction the sodium in solution should be Na + 46/40 Ca or Na'. Fig. 11.8 is a plot of Na' versus Br for the 41 samples. The data scatter to some extent but this can be expected if biogenic derived bromide is present and the presence of iodide indicates that such is the case. Fig. 11.8 indicates that re-solution of salt is a control in these samples. Fig. 11.9 shows further evidence that the Louisiana brines were formed by re-solution of salt. For example, the dashed line in the left portion of Fig. 11.9 is a plot of Na' versus Br of salt dissolved in distilled water, and the solid line just t o the right is a replot of Na' versus Br for the Louisiana brines. The next dashed line t o the right is Na' versus Br for evaporating sea water, and the curved dashed line is Na' versus Br for relict brines from the Michigan Basin. Notable differences in the waters found in the normally and abnormally pressured rocks are evident (Schmidt, 1973). The dissolved solids in the

-Re-solution solt in pure water Southwestern Louisiano brines

\*

I

*\

I

I

I

t

\

*\

\

f *\

I

I

Sodium I=mg/l sodium

I

\

h

9vaporoting seo water

25

\*

.3:

+%mg/l calcium

2 BROMIDE, g/l

3

m>

4

Fig. 11.9. Replot of Na' versus Br of the Louisiana brines (Fig. 11.8);plus data for relict Michigan brines, evaporating sea water, and resolution of salt. Resolution of salt is an important control for the Louisiana brines

362

GEOPRESSURED RESERVOIRS

normally pressured sandstones range from 600 to 180,000 mg/l, while in the geopressured sandstones the range is from 16,000 to 26,000 mg/l. The dissolvedsolids in the water in the pores of the shales adjacent to normally pressured sandstones are lower than the dissolved solids in the water in the sandstones, but the dissolved solids concentrations are similar in the waters of the adjacent high-pressure sandstones and shales. The concentration order in shale pore water is > HC03- > Cl-, and in normally pressured sandstone water it is C1- > HC03- > S 0 4 - 2 . The temperature gradient in the geopressured zone is about O.8l0C/25 m, while in the normally pressured zone it is about 0.44OC/25 m. This change in temperature gradient is believed t o be related t o the porosity, where a greater porosity causes a decreased thermal conductivity (Schmidt, 1973). The clay mineral composition in the geopressured zone is predominantly a nonexpandable type, while in the normally pressured zone montmorillonite, an expandable type, frequently occurs. This change is believed to be related t o the temperature, and the heat allows the release of water from the clays at temperatures of about 93-104OC. This released water will dilute the pore water and cause the dissolved solids to decrease. The total amount of water released by Gulf Coast shales in geopressured zones is about 13%of the total in the system (Schmidt, 1973). This can be a cause of the lower salinity of the waters found in the geopressured zones. Fowler (1970) studied the Chocolate Bayou field in Texas and evaluated the relationships between geopressure and the migration and accumulation of hydrocarbons. He concluded that faults tend t o act as barriers separating fluid systems in the area; however, cross-formational flow occurs with geopressure causing shale ultrafiltration of the waters. The ultrafiltration produces salinity variations in the waters. Hydrocarbon accumulation in the area is controlled by the hydrodynamic flow. According to Fowler (1970), hydrocarbons are trapped in the upper sands because of slight pressure differentials across fault traps in the West Chocolate Bayou field. However, in deeper strata, abnormal pressures have caused hydrodynamic flow and pressures greater than the displacement pressure in the fault, resulting in no trapped hydrocarbons. In essence then, sands with pressure gradients greater than 0.20 kgcm-' m-' in the Chocolate Bayou field do not contain commercial amounts of hydrocarbons. It also appears that the size of the accumulation may decrease with increasing pressure gradients up t o about 0.16 kg cm-* m-'. The accumulation size may increase with pressure gradients in the range of 0.16-0.19 kg cm-2 m-' and then decreases. Detection of abnormal pressures Estimation of formation pressures from electrical surveys is related to the following assumptions, concerning the origin of abnormal pressures (Foster and Whalen, 1966):

DETECTION OF ABNORMAL PRESSURES

363

(1) Shale porosity is a function of net overburden pressure and normally decreases with an increase in depth. (2) Shales with abnormal pressure will have a higher porosity than normally pressured shales at the same depth, because of the greater amounts of interstitial fluids. (3) Sand bodies (confined by lensing, faulting, etc.) surrounded by shale will have a pressure similar t o those in the shales. Data from acoustic and resistivity logs can be used to establish a shale transit time or shale resistivity versus depth of normal hydrostatically pressured formations. Deviation from the derived curve is used t o determine abnormal pressures (Hottmann and Johnson, 1965). The acoustic log is a function of porosity and lithology; therefore, in any given shale sequence it is primarily a measure of porosity. The acoustic response in normally pressured shales decreases in travel time (velocity increases) with increasing depth. This is the “normal compacted trend”, and the pressures in the shale are normal, or hydrostatic. Deviation from the “normal compaction trend” indicates an abnormally pressured zone. Relating the difference in the travel time of the observed formation pressure ( A T , ) t o a normal formation pressure (AT,) t o the formation pressure gradient (calculated from known depths and pressures of wells in the area), a pressure gradient (AT, -AT,) can be determined. The reservoir pressure can be found by multiplying this gradient by the depth. Fertl and Timko (1970) discuss several methods, using the theory of “departure from the normal” t o detect abnormally pressured zones. Methods they discuss are as follows: (1) Bulk density -this is a measurement of the intensity of back-scattered electrons produced by gamma-ray bombardment; this intensity varies with the bulk density of the rocks surrounding the borehole. (2) Conductivity measurements - measure of an induction log. Electromotive forces set up a current, which is detected by a receiver and recorded. Overpressured shales are noted by greater-than-normal conductivity reading resulting from higher-than-normal water content and porosity. (3) Borehole temperature - geopressured as usually associated with an increase in temperature. (4)Presence of gas in mud - this is not always a good detector, for gas can evolve from formation cuttings, as they come to the surface. One of the best means of obtaining subsurface information, other than drilling, is the use of the reflection seismograph. This geophysical tool is a measure of time between the earth’s surface and various subsurface reflecting horizons. The differences in interval velocities between these different horizons (formations) can be used to obtain a plot of average interval travel time, which varies exponentially with depth. The degree of departure from a “normal” plot of this travel time versus depth is related t o abnormally pressured reservoirs in the Gulf Coast area (Pennebaker, 1968). This departure is noted as an increase in the normally

364

GEOPRESSURED RESERVOIRS

decreasing travel time with depth, because of the undercompacted formations. To measure the formation pore pressure, plots of equal pore pressure gradients are compared, by an overlay, to the abnormally pressured interval travel time depth plots. Forgotson (1969),by experience with wells in the Gulf of Mexico, noted that the presence of high background gas and high trip gas, together with lower than normal shale density, does not necessarily indicate the proximity of an abnormally pressured reservoir. He believes that a minimum of 200% increase in the shale penetration rate when drilling is the best available means to predict abnormal pressures. A recent series of papers explains how downhole temperatures and pressures can affect drilling (Fertl and Timko, 1972;Timko and Fertl, 1972). Methods of detecting abnormal pressures, compensating for them, and evaluating the hydrocarbon potential of geopressured strata are discussed.

References American Petroleum Institute, 1968. API Recommended Practice f o r Analysis of Oilfield Waters. Subcommittee on Analysis of Oilfield Waters, API, RP 45, 2nd ed., 49 pp. Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation t o petroleum migration. Bull. A m . Assoc. Pet. GeoL, 53:73-93. Dickey, P.A., Collins, A.G. and Fajardo, I., 1972. Chemical composition of deep formation waters in southwestern Louisiana. Bull. Am. Assoc. Pet. GeoL, 56:1530-1533. Dickey, P.A., Shiram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160:609-615. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana, Bull. A m . Assoc. Pet. GeoL, 37:410-432. Fajardo, I., 1968. A Study of the Connate Waters and Clay Mineralogy. M.S. Thesis, University of Tulsa, Tulsa, Okla., 50 pp. Fertl, W.H. and Timko, D.J., 1970. Overpressured formations, 2. How abnormal pressure-detection techniques are applied. Oil Gas J., 68:62-71. Fertl, W.H. and Timko, D.J., 1972. How downhole temperatures, pressures affect drilling. World Oil, 174(7):67-70; 175(1):47-49; 175(2):36-39, 66;175(4):45-50; 176(2): 47-50. Finch, W.D., 1969. Abnormal pressure in the Antelope field, North Dakota. J. Pet. Technol., 21:821-835. Forgotson, J.M., 1969. Indication of proximity of high pressure fluid reservoir, Louisiana and Texas Gulf Coast. Bull Am. Assoc. Pet. GeoL, 53:171-173. Foster, J.B. and Whalen, H.E., 1966. Estimation of formation pressures from electrical surveys - offshore Louisiana. J. Pet. TechnoL, 18:165-171. Fowler, Jr., A.W., 1970. Pressures, hydrocarbon accumulation, and salinities - Chocolate Bayou field, Brazoria County, Texas. J. Pet. TechnoL, 22:411-423. Harkins, K.S. and Baugher, 111, J.W., 1969.Geological significance of abnormal formation pressures. J. Pet. TechnoL, 21:961-966. Hottmann, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from logderived shale properties J. Pet. TechnoL, 17:717-721. Jones, P.H., 1969. Hydrodynamics of geopressure in the North Gulf of Mexico Basin. J. Pet. TechnoL, 21:803-810. Pennebaker, E.S., 1968. Detection of abnormal pressure formations from seismic field records. Presented at API Southern Dist. Meet., San Antonio, Texas, March 6-8, 1968, API Paper, No. 926-13C.

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Perry, D.R., 1969. A Correlation of Reserves and Drive Mechanisms with Reservoir Pressure Gradients on Geopressured Gas Reservoirs in Southwest Louisiana. M.S. Thesis, Southwest Louisiana University, Lafayette, La., 54 pp. Powers, M.C., 1967. Fluid-release mechanisms in compacting marine mudrocks and their importance in oil exploration. Bull. Am. Assoc. Pet. GeoL, 51:1240-1254. Schmidt, G.W., 1973. Interstitial water composition and geochemistry of deep Gulf Coast shales and sandstones. Bull. A m . Assoc. Pet. Geol., 57:321-377. Sulin, V.A., 1946. Waters of Petroleum Formation in the System o f Natural Waters. Gostoptekhizdat, Moscow, 96 pp. Terzaghi, K. and Peck, R.R., 1948. Soil Mechanics in Engineering Practice. John Wiley and Sons, New York, N.Y., 56 pp. Timko, D.J. and Fertl, W.H., 1972. How downhole temperatures, pressures affect drilling. World Oil, 175(5):73-81; 175(6):79-82; 175(7):5*62; 176(1):45-48; 176(4):. 62-65. Wallace, W.E., 1969. Water production from abnormally pressured gas reservoirs in South Louisiana. J. Pet. Technol., 21 :969-982. Young, A. and Low, P.F., 1965. Osmosis in argillaceous rocks. Bull Am. Assoc. Pet. Geol., 49:1004-1008. \