Abnormal Pressures in Hydrocarbon Environments

Edited by B.E. Law, G.F. Ulmishek and V.I. Slavin


Abnormal pressures, pressures above or below hydrostatic pressures, occur on all continents in a wide range of geological conditions. According to a survey of published literature on abnormal pressures, compaction disequilibrium and hydrocarbon generation are the two most commonly cited causes of abnormally high pressure in petroleum provinces. In young (Tertiary) deltaic sequences, compaction disequilibrium is the dominant cause of abnormal pressure. In older (pre-Tertiary) lithified rocks, hydrocarbon generation, aquathermal expansion, and tectonics are most often cited as the causes of abnormal pressure.

The association of abnormal pressures with hydrocarbon accumulations is statistically significant. Within abnormally pressured reservoirs, empirical evidence indicates that the bulk of economically recoverable oil and gas occurs in reservoirs with pressure gradients less than 0.75 psi/ft (17.4 kPa/m) and there is very little production potential from reservoirs that exceed 0.85 psi/ft (19.6 kPa/m). Abnormally pressured rocks are also commonly associated with unconventional gas accumulations where the pressuring phase is gas of either a thermal or microbial origin. In underpressured, thermally mature rocks, the affected reservoirs have most often experienced a significant cooling history and probably evolved from an originally overpressured system.

  1. Page 1

    Abnormal pressures, pressures above or below hydrostatic pressures, occur on all continents in a wide range of geological conditions. According to a survey of published literature on abnormal pressures, compaction disequilibrium and hydrocarbon generation are the two most commonly cited causes of abnormally high pressure in petroleum provinces. In young (Tertiary) deltaic sequences, compaction disequilibrium is the dominant cause of abnormal pressure. In older (pre-Tertiary) lithified rocks, hydrocarbon generation, aquathermal expansion, and tectonics are most often cited as the causes of abnormal pressure.

    The association of abnormal pressures with hydrocarbon accumulations is statistically significant. Within abnormally pressured reservoirs, empirical evidence indicates that the bulk of economically recoverable oil and gas occurs in reservoirs with pressure gradients less than 0.75 psi/ft (17.4 kPa/m) and there is very little production potential from reservoirs that exceed 0.85 psi/ft (19.6 kPa/m). Abnormally pressured rocks are also commonly associated with unconventional gas accumulations where the pressuring phase is gas of either a thermal or microbial origin. In underpressured, thermally mature rocks, the affected reservoirs have most often experienced a significant cooling history and probably evolved from an originally overpressured system.

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    Normally pressured reservoirs have pore pressures which are the same as a continuous column of static water from the surface. Abnormal pressures occur where the pore pressures are significantly greater than normal (overpressure) or less than normal (underpressure). Overpressured sediments are found in the subsurface of both young basins from about 1.0 to 2.0 km downwards, and in older basins, in thick sections of fine-grained sediments. The main mechanisms considered responsible for most overpressure conditions can be grouped into three broad categories, based on the processes involved: (1) ineffective volume reduction due to imposed stress (vertical loading during burial, lateral tectonic processes) leading to disequilibrium compaction, (2) volume expansion, including porosity increases due to changes in the solid:liquid ratios of the rock, and (3) hydraulic head and hydrocarbon buoyancy. The principal mechanisms which result in large magnitude overpressure are disequilibrium compaction and fluid volume expansion during gas generation. Disequilibrium compaction results from rapid burial (high sedimentation rates) of low-permeability rocks such as shales, and is characterized on pressure vs. depth plots by a fluid retention depth where overpressure commences, and increases downwards along a gradient which can closely follow the lithostatic (overburden) gradient. Disequilibrium compaction is typical in basins with a high sedimentation rate, including Tertiary deltas and some intracratonic basins. In older basins, disequilibrium compaction generated earlier in the basin history may be preserved only in thick, fine-grained sequences, but lost by vertical/lateral leakage from rocks with relatively high permeabilities. Gas generation from secondary maturation reactions, and oil cracking in the deeper parts of sedimentary basins, can result in large fluid volume increases, although the magnitudes are uncertain. In addition, the effect of increased pressures on the reactions involved is unknown. We doubt that any of the other mechanisms involving volume change can contribute significant regional overpressure, except in very unusual conditions. Hydraulic head and hydrocarbon buoyancy are mechanisms whose contributions are generally small; however, they can be easily assessed and may be important when additive to other mechanisms. The effects of transference of overpressure generated elsewhere should always be considered, since the present pressure distribution will be strongly affected by the ability of fluids to move along lateral and vertical conduits. Naturally underpressured reservoirs (as opposed to underpressure during depletion) have not been as widely recognized, being restricted mainly to interior basins which have undergone uplift and temperature reduction. The likely principal causes are hydraulic discharge, rock dilation during erosional unroofing, and gas migration during uplift.

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    The purpose of this paper is to review advances made in our understanding of the origin of overpressures in clastic rocks and examine the relationship between overpressuring and hydrocarbon expulsion. This study uses numerical simulations to examine overpressure models in clastic rocks. It is based on a review of previous regional overpressure modeling studies in rapidly subsiding basins (the Mahakam Delta, Indonesia, and the Gulf Coast, U.S.A.), and in slowly subsiding basins (the Williston Basin, U.S.A.-Canada and the Paris Basin, France). We show that compaction models based on effective stress-porosity relations satisfactorily explain overpressures in rapidly subsiding basins. Overpressures appear primarily controlled by the vertical permeability of the shaly facies where they are observed. Vertical permeabilities required to model overpressures in the Gulf Coast and Mahakam basins differ little, they are around 1-10 nanodarcies. Geological evidence and models suggest other causes of overpressure such as aquathermal pressuring or clay diagenesis to be generally small compared with compaction disequilibrium. Hydrocarbon (HC) generation can be a minor additional cause of overpressures in rich, mature source rocks. Shale permeabilities calibrated against observed overpressures appear consistent with direct measurements. Specific surface areas of mineral grains and relationships between effective stress/permeability implied by model calibrations agree with independent experimental determination. The main weakness of mechanical compaction models is that they overestimate the porosity of thick overpressured shales. Unlike in previous studies, we suggest that this mismatch is not caused by fluid generation inside overpressured shales. Instead, we infer that it is a consequence of an inappropriate definition of effective stress. If effective stress is defined as S - αP, instead of S - P, then with a around 0.65-0.85, porosity reversals predicted in overpressured shales are much reduced, and better in agreement with observations. Alpha (a) is known in poro-elasticity as the Biot coefficient. We show that the non-linear distribution of horizontal stress often observed in overpressured shale sequences confirms values of the Biot coefficient in the range indicate above.

    In slowly subsiding basins, there is no compaction disequilibrium. Pressures are regionally controlled by the surface topography. The persistence of high overpressures in thin (few meters thick), mature source rocks in the HC window implies uncommon conditions : a very rich source interval (total organic carbon content, TOC, >10%), a very low permeability (100-1,000 times smaller than for the Mahakam Delta or Gulf Coast shales), and, possibly, a very low porosity (2-3%). The examples examined suggest that permeability of shales in Paleozoic-Mesozoic, slowly subsiding basins are significantly more variable than in Cenozoic rapidly subsiding basins. More complex tectonic and diagenetic histories could explain this greater variability. Our study suggests that, at least at the regional scale considered, diagenetic processes do not need to be invoked in young rapidly subsiding basins. This does not exclude the possibility that locally permeabilities can be decreased if cementation takes place, resulting in an increase of overpressures. It is probable that more mature basins with intermediate sedimentation rates and ages, have mixed chemical and mechanical compaction mechanisms.

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    Fluid pressure detection and porosity evaluation from well logs are largely based on an assumed relationship between high fluid pressures and high porosities due to undercompaction. However, few data have been presented which demonstrate to what extent porosities are higher in overpressured than in normally pressured shales of similar type, and how this porosity difference is detected by the responses from standard logs. Jurassic intra-reservoir shales on Haltenbanken (offshore mid-Norway) are particularly well-suited for such an investigation because (a) the area is subdivided into two, major, distinctive pressure regimes (one normally pressured, the other highly overpressured) and (b) the lithology, depositional environment and present burial depth do not vary significantly across the area.

    Log comparisons reveal that neutron and density responses show no significant porosity difference between the two regimes, whereas sonic and resistivity responses show higher (apparent) porosities in the overpressured area. It is thus suggested that porosity is unaffected by differences in fluid pressures, but that the sonic and resistivity logs are reacting to textural changes induced in the rocks by overpressuring rather than high porosities due to undercompaction.

    High fluid pressures in combination with low shale porosities could be explained by pressure unloading (i.e., fluid overpressuring post-dating shale compaction), and this cannot be ruled out from the Haltenbanken data. However, log data from North Sea shales also show that formation density does not significantly vary with fluid overpressuring, whereas sonic log data decreases with depth irrespective of overpressuring. As it is unlikely that fluid overpressuring in all of these formations postdated compaction, it appears that shale porosity reduction may proceed without significant hindrance by fluid overpressuring.

    These findings suggest that standard principles applied to pore pressure evaluation from well logs may not always be valid, thus partly explaining the large degree of uncertainty attached to such work. Furthermore, basin modeling of fluid flow, overpressure buildup, hydrofracturing and hydrocarbon migration appears to rely on equations which give improper descriptions of fluid transport in shales.

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    Direct measurements of porosities from Tertiary and Cretaceous shales in the Texas-Louisiana Gulf Coast show that in many areas shale porosity is either constant or increasing at the depths where high overpressures occur andwhere hydrocarbons are being generated. In the absence of a decrease in porosity with sediment load (depth), gasgeneration becomes the principal cause of overpressures and hydrocarbon expulsion.

    Gulf Coast shale porosities decrease exponentially in normally compacting shales only down to porosities of about 30%, after which the decrease is linear until a constant porosity is reached. These linear trends are believedto be related to the high quartz content (74%) of the clay-size fraction (=4 microns).

    The depths at which shales reach relatively constant porosity values appear to depend on the internal surface areas of the shales. Shales containing minerals with small, internal surface areas, such as finegrained quartz andcarbonates, stop compacting at porosities around 3%, whereas shales containing minerals with large surface areas, such as smectite and illite, stop compacting around 10%. This interval of no compaction usually is reached at depths around 3 to 4 kilometers (temperatures of 85° to 110°C) prior to the development of deep high overpressures and the generation of large quantities of hydrocarbons in the Gulf Coast. Model studies indicate that gas generation is the dominant process creating these deep overpressures.

    The porosity-depth profiles that show a linear decrease with depth followed by a constant porosity do not conform to the hypothesized exponential profiles used in many modeling programs today. This means that more direct shale porosity measurements are needed to confirm the type of profiles that actually exist and should be used in any basin modeling program.

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    Exploration for and the development of oil and gas fields in zones of abnormally high formation pressures (AHFP) require a good understanding of the origin of AHFP and the development of predictive methods. We classify the causes of AHFP into two genetic groups: (1) a syn-sedimentary group characterized by undercompaction of rocks and (2) a post-sedimentary group characterized by secondary decompaction of rocks. The choice of methods for the prediction and evaluation of AHFP should be based on the origin of abnormal pressure and the lithology of the rocks. The reservoir properties of rocks in AHFP zones suggest that large, in-place resources of hydrocarbons may be present in complex low- permeability clastic and carbonate reservoirs despite low rates of production.

    Plastic deformation of reservoir rocks which result from the decrease of reservoir pressure in the course of well testing and production in AHFP zones is dependent on the origin of abnormal pressure. Careful monitoring of the critical limit of formation pressure is necessary to avoid irreversible deformation of reservoir rock. Changes in the stress field in the productive reservoir should be controlled in order to prevent the initiation of induced earthquakes. In the AHFP zones of syn-sedimentary origin, water flooding should be implemented from the start of production in order to prevent subsidence with consequent environmental damage.

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    Statistical analyses of oil and gas pools in ancient platforms (Precambrian), young platforms (post- Hercynian),and mobile belts (foreland troughs, and intermontane depressions) of the Commonwealth of Independent States (C.I.S.), do not reveal any significant differences in the relationships between commercial production and the magnitude of overpressure. However, pressure data from all three structural provinces indicate 90% of all oil and gas pools are in reservoirs with pressure abnormality coefficients (Ac—the quotient of the measured pressure divided by the hydrostatic pressure) less than 1.8 (0.81 psi/ft, 18.7 kPa/m), suggestive of a commercially practical upper limit for productive reservoirs.

    In ancient platforms, more than 90% of hydrocarbon pools are present in reservoirs in which the Ac is less than 1.7 (0.77 psi/ft, 17.8 kPa/m). Oil pools in ancient platform provinces are more common in reservoirs where the abnormality coefficient ranges from 1.1-1.3 (0.50-0.54 psi/ft, 11.5-12.4 kPa/m), whereas most gas pools occur in reservoirs with an Ac ranging from 1.06-1.1 (0.48-0.50 psi/ft, 11-11.5 kPa/ m). Very few oil and gas pools in ancient platforms occur in reservoirs with abnormality coefficients greater than 1.6 (0.72 psi/ft, 16.6 kPa/m). On young platforms, the majority of oil pools occur in reservoirs in which the Ac is less than 1.6 (0.72 psi/ft, 16.6 kPa/m). Gas pools in young platforms are found in reservoirs with abnormality coefficients as high as 2.0 (0.9 psi/ft, 20.8 kPa/m). In mobile belt provinces, 90% of oil pools occur in reservoirs with Ac values less than 1.8 (0.81 psi/ft, 18.7 kPa/m). A small number of pools occur in reservoirs where the abnormality coefficient is as high as 2.0 (0.9 psi/ft, 20.8 kPa/m). In mobile belt provinces, 90% of all oil and gas pools occur in reservoirs with Ac values less than 1.8 (0.81 psi/ft, 18.7 kPa/m) and are most common where the abnormality coefficient ranges from 1.2 to 1.3 (0.54-0.59 psi/ft, 12.4-13.6 kPa/m). The statistical data demonstrate that as the Ac increases, the frequency of occurrence of commercial oil and gas accumulations generally decreases. Very few oil and gas pools, regardless of structural setting, occur in reservoirs with abnormality coefficients greater than 1.8 (0.81 psi/ft, 18.7 kPa/m).

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    The Central Graben is a major hydrocarbon province. Oil, condensate, and gas are found in a variety of horizons ranging in age from the Devonian to Eocene. The principal economic zones are the Upper lurassic Fulmar Sandstone, the Upper Cretaceous Chalk Group, and the Paleocene Forties Formation.

    The Upper lurassic sandstones in the Central Graben vary from being normally pressured, 0.01 MPa/m (0.45 psi/ft) near the graben margins, to pressure gradients in excess of 0.02 MPa/m (0.867 psi/ft) in the center of the graben. The Paleocene sandstones consist of sheet sandstones forming a normally pressured regional aquifer, and the Chalk Group, where overlain by these sandstones, is similarly normally pressured. In the southern part of the graben, the Paleocene consists of clay stones that act as a seal to both overpressure and hydrocarbons in the Ekofisk Formation of the Chalk Group.

    The origin of the overpressure was formerly considered to result from compaction disequilibrium. In recent years it has been recognized that hydrocarbon generation can play a crucial role in generating the extreme overpressures that are present in the Jurassic sandstones. The Kimmeridge Clay stone Formation is an excellent source rock with a TOC locally greater than 10%. It varies from sub-mature at the graben margins, to late-stage gas generation within the depocenter of the graben.

    In highly overpressured rocks, pore pressures may approach the fracture gradient and the dynamic interplay between pore pressure and fracture gradient is indicative of a dynamic overpressure system. In this type of system, the overpressure is produced by the volumetric expansion associated with the generation of oil and gas. When the pore pressure exceeds the minimum confining stress, episodic fluid expulsion occurs through fractures in the seal.

    Recognition that the overpressure is generated from hydrocarbon generation in a dynamic system is important both in modeling the distribution and magnitude of the overpressure and to understanding the relationship between migration and distribution of hydrocarbons in the Central Graben of the North Sea.

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    The exploration for oil and gas in the Adriatic Basin of Italy has resulted in a large quantity of pressure data. Abnormally high pressures in the area are mainly caused by compaction disequilibrium resulting from the high sedimentation rate of the Pliocene to Quaternary strata. The comparison of pressure profiles in the northern and central Adriatic basins has shown the presence of five pressure regions. Three regions are present in the post-Messinian siliciclastic succession that infills the Adriatic foredeep, and two pressure regions have been identified in the Cretaceous to Miocene carbonates of the Apulian continental margin. The boundaries of these regions are coincident with the main structural features of the Apenninic belt, indicating that the major thrusts act as pressure barriers. In the post-Messinian strata, the innermost region (with respect to Apenninic vergence) includes the inner buried thrusts in front of the Apenninic chain. This region is characterized by moderate to low overpressures, hydrostatic gradients, and good lateral hydraulic continuity. In the second region, in proximity of the outermost thrusts, overpressures are high and compartmentalization is pronounced. In the third pressure region, the undeformed foredeep of the Apennines, lateral hydraulic continuity prevails and high overpressures are present in the two principal Pliocene depocenters (the Romagna foredeep and the Pescara Basin). The fourth region, in the Cretaceous to Miocene carbonates, includes strata involved in Apeninnic thrusting; it is characterized by moderate overpressures. The fifth pressure region, in the foreland of the Apulian margin, has normal pressure conditions. Gas pools in the lower Pliocene interbedded sandstone-shale sequence in the first pressure region are mostly found below regional mudrock seals; whereas in the second and third pressure regions the overpressured shale beds in the lower Pliocene provide excellent seals for the interbedded gas-bearing sandstone reservoirs.

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    The Nile Delta and North Sinai Basins are active geodynamic (high subsidence rate) basins with a thick, clay-dominated Oligocene to Recent sedimentary section. Abnormally high formation pressures have developed in this section and in the underlying pre-Tertiary section primarily due to rapid sedimentation. Secondary mechanisms may be locally superimposed where the Messinian evaporite super seal is present. The abrupt development of pore pressure in the southern part of the Nile Delta is believed to be due to changes in the volume of pore fluids or rock matrix as a consequence of either aquathermal expansion, hydrocarbon generation, or thermal cracking of oil to gas in the lower Miocene-upper Oligocene compartment. Fluid flow in the Nile Delta and North Sinai Basins is mainly due to compaction-and thermal-driven forces.

    The sedimentary sequence in the study area is divided into eight pressure compartments, separated by seals, some of which are associated with major unconformities. Four seals are clearly demonstrated in the North Sinai, Early Cretaceous basin and are referred to as: 1) Upper Jurassic-Lower Cretaceous; 2) Aptian; 3) Albian; and 4) Upper Cretaceous-Eocene carbonates. A total of four seals are also recognized in the Nile Delta and are referred to as: 5) Aquitanian-Burdgalian; 6) Langian; 7) Serravalian-Tortonian; and 8) Messinian.

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    The maintenance of abnormally high formation pressure (AHFP) over long periods of geologic time cannot be explained by compaction or structural deformation without the addition of fluids from underlying rocks. Abnormally high pressures develop in the deepest parts of basins that contain 8-10 km of sedimentary rocks. The deeper part of the sedimentary fill typically occurs in the zones of late catagenesis and incipient metamorphism with temperatures ranging from 200° to 300°C. The observed increase of formation pressure above normal hydrostatic pressure with increasing depth and temperature, in conjunction with other factors, indicates that extended zones of AHFP first appear at temperatures of 175°C and higher. At lower temperatures, abnormally high pressures occur only locally at the crests of anticlinal structures.

    The main cause of abnormal pressure in the zone of late catagenesis is the generation of large volumes of methane, carbon dioxide, hydrogen, water, and other volatile components. The devolatilization process is commonly associated with elevated temperatures, loss of porosity and permeability, and fracturing of rocks. In rocks which have experienced a high level of catagenesis, such as those in the structurally inverted parts of the Donbas foldbelt and the western Lviv depression adjacent to the Carpathian foldbelt, abnormally high formation pressures are absent.

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    A deep wildcat well in the southern Piceance Basin of western Colorado (Mobil O’Connell F11X-34P) encountered three separate and distinct overpressured zones. The shallowest overpressured zone occurs within the Upper Cretaceous Mesaverde Group and coincides with gas-charged, thermally mature coal beds with vitrinite reflectance (RO) ranging from 0.8 to 2.0%. This overpressured zone is located in the center of the basin where Mesaverde coal beds are thickest and where burial beneath Tertiary sediments is deepest. The overpressured zone is surrounded by subnormally pressured zones, and normally pressured, water-saturated strata occur along the basin margins.

    A deeper overpressured zone occurs within marine shales of the Upper Cretaceous Niobrara and Frontier Formations. These gas-charged, depleted source rocks have RO values ranging from 2.8 to 3.5% in the O’Connell well. The overpressured zone occupies the center of the basin. Subnormal pressures apparently occur in a ring around this overpressured zone. Low pressure gas has also been found below the Niobrara-Frontier section in fractured quartzitic sandstones of the Lower Cretaceous Dakota Group.

    Highly overpressured salt water flows were encountered in the Pennsylvanian Minturn Formation and caused severe drilling and casing complications in the O’Connell well. This overpressure zone occurs in fractured quartzitic sandstones and is sealed by overlying argillaceous limestone beds. Salinity and isotope data indicate that the water is probably original formation water. The lateral extent of this pressure system is not known.

    A reservoir with excellent porosity was discovered in dolomite beds of the Mississippian Leadville Formation. Measured borehole temperatures ranged from 441° to 464°F (239°C), indicating a present-day geothermal gradient of 2.2°F/100 ft (40°C/km). Measured RO values above the reservoir are as high as 4.4 to 6.1%. During testing, the Leadville reservoir flowed carbon dioxide gas, traces of methane, nitrogen, hydrogen sulfide, and salt water to the surface at approximately normal pressure. Isotope data indicate that the carbon dioxide gas was derived from alteration of carbonate rocks, probably due to hydrothermal activity associated with Tertiary igneous intrusions along the southeastern margin of the basin.

    Burial and thermal history reconstructions indicate that maximum paleogeothermal gradient was 3.0°F/100 ft (52°C/km). Maximum paleotemperature in the Leadville Formation was as high as 644°F (340°C), based on estimates from vitrinite and fluid inclusion data from core samples. Maximum paleotemperature occurred at approximately 27 Ma, based on argon thermochronology of cuttings from the Pennsylvanian Maroon Formation. Analyses of apatite fission tracks in cuttings from the Wasatch Formation and upper Mesaverde Group indicate that significant erosion and cooling have occurred since 5 Ma. Cooling, removal of overburden and gas leakage along faults and fractures have contributed to gradual pressure decline in the Niobrara and Mesaverde overpressured zones.

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    Abnormal pore pressure is widespread in the Tertiary through upper Mesozoic, clastic-dominated section of the Eastern Venezuelan Basin and the eastern extension of the basin into Trinidad. Some of the largest oil and gas columns are found within abnormally pressured sandstones which account for 43 million bbl (6.8 million m3) of oil in Poui field and 882 billion ft3 (24.98 billion m3) of gas in Cassia field. Abnormal pressure within the Tertiary to Upper Cretaceous rocks resulted from the transfer of overburden stress to the pore system during the rapid subsidence and infilling of the foredeep basin during the Miocene and Pliocene. Primary migration from thick, Upper Cretaceous source rocks and secondary migration through the thick Tertiary elastics occurred principally through hydraulically induced fractures within a highly overpressured section. Final migration out of the overpressured section and charging of present-day reservoirs off the east coast of Trinidad occurred during the late Pliocene to Pleistocene uplift and associated complex normal faulting. The multiple pressure compartments within the six fields studied are separated by relatively thin, abnormally pressured shale. The shale seals are most effective in trapping hydrocarbons when the pressure difference across the shale is less than 4 psi/ft (90 kPa/m) regardless of the shale thickness. Normal faults form effective pressure seals throughout the basin, separating porous sandstone pressure compartments with pressure differences as great as 1,856 psi (12.8 MPa). The oil and gas fields of offshore Trinidad reveal a widely varying depth to the top of abnormal pressure, large pressure differences across faults, pressure reversals, and a narrow zone of transition from mild abnormal pressure (<11 PPG [lb/gal] equivalent) to highly overpressured conditions (>14 PPG equivalent).

  14. Page 247

    Abnormally high formation pressures in the Potwar Plateau of north-central Pakistan are major obstacles to oil and gas exploration. Severe drilling problems associated with high pressures have, in some cases, prevented adequate evaluation of reservoirs and significantly increased drilling costs. Previous investigations of abnormal pressure in the Potwar Plateau have only identified abnormal pressures in Neogene rocks. We have identified two distinct pressure regimes in this Himalayan foreland fold and thrust belt basin: one in Neogene rocks and another in pre-Neogene rocks. Pore pressures in Neogene rocks are as high as lithostatic and are interpreted to be due to tectonic compression and compaction disequilibrium associated with high rates of sedimentation. Pore pressure gradients in pre-Neogene rocks are generally less than those in Neogene rocks, commonly ranging from 0.5 to 0.7 psi/ft (11.3 to 15.8 kPa/m) and are most likely due to a combination of tectonic compression and hydrocarbon generation. The top of abnormally high pressure is highly variable and doesn’t appear to be related to any specific lithologic seal. Consequently, attempts to predict the depth to the top of overpressure prior to drilling are precluded.

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