6. Swarbrick Osborne 1998 AAPG MEMOIR 70

13

INTRODUCTION

Abnormally pressured rocks are typical of manysedimentary basins worldwide. The pressures aremostly recorded during drilling of deep boreholes (e.g.,by wireline pressure tools such as the Repeat Forma-tion Tester, or during a production test) in permeablesedimentary units, and also can be inferred from

drilling parameters (such as mud weight) in some con-ditions. The pore pressure of low-permeability rocks,such as mudstones and shales, is rarely known, andmust be inferred from adjacent permeable rocks, orfrom the interpretation of wireline logs (for example,by comparison of measured and expected porosity fora given depth, the porosity data usually being derivedfrom the sonic, density, neutron or resistivity/conduc-

AbstractNormally 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 significantlygreater than normal (overpressure) or less than normal (underpressure). Overpressured sediments arefound 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 over-pressure 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 tectonicprocesses) leading to disequilibrium compaction, (2) volume expansion, including porosity increasesdue 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 compactionand fluid volume expansion during gas generation. Disequilibrium compaction results from rapid bur-ial (high sedimentation rates) of low-permeability rocks such as shales, and is characterized on pressurevs. depth plots by a fluid retention depth where overpressure commences, and increases downwardsalong a gradient which can closely follow the lithostatic (overburden) gradient. Disequilibrium com-paction is typical in basins with a high sedimentation rate, including Tertiary deltas and some intracra-tonic basins. In older basins, disequilibrium compaction generated earlier in the basin history may bepreserved only in thick, fine-grained sequences, but lost by vertical/lateral leakage from rocks with rel-atively high permeabilities. Gas generation from secondary maturation reactions, and oil cracking in thedeeper parts of sedimentary basins, can result in large fluid volume increases, although the magnitudesare uncertain. In addition, the effect of increased pressures on the reactions involved is unknown. Wedoubt that any of the other mechanisms involving volume change can contribute significant regionaloverpressure, except in very unusual conditions. Hydraulic head and hydrocarbon buoyancy are mech-anisms whose contributions are generally small; however, they can be easily assessed and may be impor-tant when additive to other mechanisms. The effects of transference of overpressure generated else-where should always be considered, since the present pressure distribution will be strongly affected bythe ability of fluids to move along lateral and vertical conduits. Naturally underpressured reservoirs (asopposed to underpressure during depletion) have not been as widely recognized, being restricted main-ly to interior basins which have undergone uplift and temperature reduction. The likely principal caus-es are hydraulic discharge, rock dilation during erosional unroofing, and gas migration during uplift.

Swarbrick, R.E. and M.J. Osborne, 1998, Mechanisms that generate abnormalpressures: an overview, in Law, B.E., G.F. Ulmishek, and V.I. Slavin eds.,Abnormal pressures in hydrocarbon environments: AAPG Memoir 70, p. 13–34.

Chapter 2

Mechanisms thatGenerate Abnormal Pressures:an Overview

Richard E. SwarbrickMark J. Osborne1

Department of Geological SciencesUniversity of DurhamDurham, United Kingdom

1 Present Affiliation: BP Exploration, Shared Petrotechnical Resource, Basin Modeling and Geochemistry, Middlesex, United Kingdom

tivity logs (Hottman and Johnson, 1965; Mouchet andMitchell, 1989)).

In one of the first studies of abnormal pressures,using data from the Gulf of Mexico, Dickinson (1953)suggested that the high pressures in the clasticsequences there could be explained by incompletedewatering of the sediments. Other explanations werelater suggested for the high pressures in these rocks,including thermal effects (Barker, 1972), clay mineralchanges (Powers, 1967; Burst, 1969; Bruce, 1984) andosmosis (Marine and Fritz, 1981). In other basins, theinfluence of hydrocarbon generation/maturation hasbeen proposed to explain overpressured reservoirs(Spencer, 1987), and gas generation as a mechanism hasbeen invoked for the Gulf of Mexico situation (Hunt etal., 1994; 1998-this volume). Some authors suggest onedominant mechanism, e.g., disequilibrium compaction(Bredehoeft and Hanshaw, 1968; Summa et al., 1993),or hydrocarbon generation (Meissner, 1978a, b), whilstothers have attempted to ascribe the relative propor-tion of each mechanism (Hart et al., 1995). Most papersdealing with abnormal pressures provide a briefoverview of the range of possible mechanisms, butthere are few papers which deal specifically with each,and the conditions required for them to create abnor-mal pressures. A review of the mechanisms, especiallyas applied to drilling overpressured reservoirs, is pro-vided in Fertl (1976), Mouchet and Mitchell (1989) andFertl et al. (1994). Hall’s (1993) review of overpressuremechanisms explains each in terms of the physical andchemical reactions which govern rock behavior. A com-prehensive list of the mechanisms and the literaturepertaining to each is also available in Martinsen (1994).

In this paper we re-examine the basis for the inclu-sion of each abnormal pressure mechanism on a list ofpossibilities. We have become aware that there isstrong empirical evidence for some of the popularmechanisms (e.g., smectite-illite transformation, hydro-carbon generation), but great uncertainty about theexact processes involved and hence their ability to cre-ate abnormal pressures under normal burial conditionsin sedimentary environments. We conclude that formany of the mechanisms further research is required toverify the conditions under which they can produceabnormal pressures of the magnitude and distributionobserved in sedimentary basins around the world.

Overpressure

Overpressure is defined as “any pressure whichexceeds the hydrostatic pressure of a column of wateror formation brine” (Dickinson, 1953 and Figure 1).Another way to view overpressure, in terms of thedynamics of subsurface fluid flow, is the inability offormation fluids to escape at a rate which allows equi-libration with hydrostatic pressure, calculated from apressure gradient which varies from 0.433 psi/ft (9.71kPa/m) for fresh water to about 0.51 psi/ft (11.44kPa/m) for saturated brine. Hence any measured pres-

sure in the subsurface can be compared with the pres-sure of a column of formation water existing from thesurface to the same depth. Overpressure is a disequi-librium state resulting from fluid retention, and one ofthe primary controls on the presence and distributionof overpressure is therefore permeability, the rockattribute which controls seal behavior.

Many of the world’s basins contain overpressuredreservoirs; Hunt (1990) cites 180 basins, includingbasins from the Americas, Africa, Europe, Middle East,Far East, and Australasia, where overpressure has beenrecognized. The location of some of these, plus tabulardata, appear in Law and Spencer (1998-this volume).The age of rocks in which overpressures have been rec-ognized varies from Pleistocene to Cambrian. Over-pressure is found in carbonate and clastic reservoirs,and in rocks deposited in the full range of sedimentaryenvironments. Hydrocarbons are often associated withoverpressures, but not exclusively so, and there doesnot seem to be a universal relationship between over-pressure and hydrocarbon traps. For example in theSable Basin, offshore Nova Scotia, gas is found abovethe top of the overpressure in the shallower traps in thesouthwest, but largely below the top in the deepertraps to the northeast (Williamson and Smyth, 1992). Inthe Northern and Central North Sea, shallow oil andgas condensate occur in normally pressured reservoirs,above deeper and highly overpressured reservoirs,which contain a mixture of oil and gas condensate.Fluid inclusion data from the Northern North Sea havebeen used to argue for hydrocarbon migration whenthe reservoirs were normally pressured, and prior totheir current overpressured condition (Swarbrick, 1994).

Underpressure

Underpressure exists when pore pressure is signifi-cantly lower than the hydrostatic pressure (Figure 1).Fewer examples of underpressure are documented, in

14 Swarbrick and Osborne

Figure 1. Pressure vs. depth plot. Rocks whose pressuresplot between the hydrostatic and lithostatic gradients aretermed “overpressured” and those whose pressures areless than hydrostatic are “underpressured”.

comparison with overpressure, a factor which Hunt(1990) attributes to the difficulty of recognizing under-pressures during conventional drilling operations.Underpressure results from depletion during oil andgas production, but naturally underpressured reser-voirs have been described from a number of basins,particularly in Canada and U.S.A., including WestCanada Basin, Alberta (Gies, 1984; Davies, 1984; Grigg,1994; Rostron and Toth, 1994); Silurian Clinton sand,eastern Ohio (Davies, 1984); San Juan Basin, New Mex-ico and Colorado (Berry, 1959; Meissner, 1978a; Kaiserand Scott, 1994); and Red Desert and Green RiverBasins, Wyoming (Davies, 1984). In each of the abovecase histories, the basin has been uplifted and containsgas-bearing reservoirs, which have experienced reduc-ing temperatures. Law and Dickinson (1985) and Grigg(1994) believe underpressured reservoirs today havebeen overpressured in the past.

OVERPRESSURE—THE SYSTEMIn order to understand overpressure in terms of

fluid retention we need to know about four principalaspects of the rock and fluid conditions (Figure 2):

A. Causal MechanismB. Rock Permeability as it Relates to Seal BehaviorC. Timing (and Rate)D. Fluid Type

Causal Mechanism

The amount of overpressure and the rate at which itcan build up will relate directly to the mechanismwhich is generating the excess fluid. A wide variety ofmechanisms have been proposed for generating over-

pressure in subsurface rocks. The processes which cre-ate overpressure allow the mechanisms to be groupedinto three categories (Figure 3):

1. Stress-related, (i.e., compression leading to porevolume reduction)

Mechanisms: Disequilibrium compaction (vertical

loading stress)Tectonic stress (lateral compressive stress)

2. Fluid volume increaseMechanisms:

Temperature increase (aquathermal)Water release due to mineral transformationHydrocarbon generation Cracking of oil to gas

3. Fluid movement and buoyancyMechanisms:

Osmosis Hydraulic head Buoyancy due to density contrasts

In addition, overpressure can result from redistribu-tion of overpressured fluids from elsewhere, some-times referred to as “transference”. Although not amechanism in itself, transference may exert a stronginfluence on many of the pore pressure profiles seen inthe subsurface, and may mask recognition of theunderlying causal mechanism (Swarbrick andOsborne, 1996).

Permeability as it Relates to Seal Behavior

Permeability of a rock is a constant (k) defined bythe equation which expresses Darcy’s law and relates

Mechanisms that Generate Abnormal Pressures: an Overview 15

Figure 2. Factors which control overpressure and the inability of rocks to maintain equilibrium at hydrostatic pressures. Each of the factors is interlinked. Permeability of a rock is directed related to its ability to act as a seal.

flow rate of a given fluid per unit of time, along aknown flow path across which there is a specified pres-sure drop:

Q = –kA∆PµL

where:Q = volume rate of flowk = permeabilityL = Length scale∆P = pressure drop across Lµ = fluid viscosityA = area across which flow takes place

Hence, permeability is an intrinsic property of therock which can be measured. Permeability is controlledby the properties of the rock (e.g., grain size, grainshape, grain tortuosity) and the properties of its fluidcontent (e.g., viscosity, density), plus the capillary effectswhere hydrocarbons are involved. In high-permeabili-ty rocks, such as aquifers and hydrocarbon reservoirs,permeability can be routinely measured. However,fluid retention leading to overpressure is largely con-trolled by the low-permeability, non-reservoir rocks,e.g., shales, evaporites and well-cemented carbonates(often referred to as “seals” in the petroleum litera-ture). Measurement of fluid flow in very low-perme-ability rocks is difficult and prone to large inaccuracies.

Permeability is the property which controls the abil-ity of a rock to act as a seal or barrier to flow. The termseal is defined by Watts (1987) as a rock which preventsnatural buoyancy-related upwards migration of hydro-carbons. In this paper we are concerned with the abili-ty of rocks to retain all fluids, in particular waterthroughout the sedimentary column, since overpres-

sured rocks include the lower water-bearing section aswell as the upper hydrocarbon-bearing section. (Anotable exception is the tight, regionally overpressuredlow-permeability reservoirs of the Rocky Mountainswhich produce only hydrocarbons—Law, 1984;Spencer, 1987; Surdam et al., 1994). Seals in the sense ofWatts (1987) can be a permanent barrier to flow, whereoil and gas are unable to flow across a membrane if theminimum displacement (or entry) pressure of the cap-rock, controlled by its capillary properties, is notreached (Watts, 1987). Hunt (1990) extended the defin-ition of a seal to any rock which is capable of prevent-ing all pore fluid movement (oil, gas and water) oversubstantial periods of geologic time, as this was crit-ical to his model of static pressure compartments.Deming (1994) argues that rocks are not capable of sus-taining zero effective permeability to water overextended periods of geological time. In this paper wesubscribe to the view that pressure build up and dissi-pation are continuous processes modifying the porepressures of abnormally pressured rocks through time(see below). However, since seals are viewed by someas the absence of flow over time, we will not over-emphasize the term, beyond its implication for arestriction to flow which assists in the creation ofabnormally pressured rocks.

Overpressure dissipation, or leakage, can be accom-plished not only by porous media flow through therock, but also by fracturing. In tectonically active areas,fault reactivation may be the release mechanism (Byer-lee, 1993). However, if pore pressures reach the fracturepressure of the rock during overpressure generation,the rock will hydraulically fracture, potentially releas-ing large volumes of fluid, and rapidly dissipating the


Figure 3. The principal classes of mechanisms include increased stress (vertical loading and horizontal compression),changes in fluid volume (mineral dehydration and transformation reactions) and hydraulic flow and buoyancy. The permeability of both the overpressured rock and its boundaries (seals) will contribute to the overpressure observed.

excess pressure until the fractures reseal (Engelder,1993). A close balance between the pore pressures mea-sured in the Jurassic and Triassic reservoirs, and theoverlying Kimmeridge Clay Formation organic-richshales in the Central North Sea (inferred from Leak OffTest data), suggests that these reservoirs are near frac-ture pressure, and may have already released theentrapped hydrocarbons from some valid traps(Gaarenstroom et al., 1993; Holm, 1998-this volume).

Timing and Rate

Darcy’s equation above defines flow rate, which istime dependent. Overpressure is a disequilibrium stateand will therefore change with time depending on theevolution of the system, unless zero effective perme-ability is achieved, which is very difficult to maintainin the water phase over geological time (Deming,1994). The distribution and magnitude of overpressurewill therefore change through time, both during the“build-up phase” when the generating mechanism isactive, and afterwards during the “dissipation phase”as leakage continues. Bredehoeft et al. (1994) have con-trasted their dynamic model of overpressure with thestatic model preferred by Hunt (1990). We also empha-size the ephemeral nature of overpressured basins, cer-tainly within the permeable reservoir units. We arelooking today merely at a “snap-shot” of the stressstate of the overpressured system; pore pressures mayhave been higher, or lower, in the past.

Fluid Type

Throughout any basin the most common type offluid is water, varying from near fresh water to highsalinity brines. The total dissolved solids (dominantlysalts) determine the pressure gradient, through theireffect on density, and to a very small degree exert acontrol on the flow properties, through their effect onviscosity. Where oil and gas are present (almost alwaysin the presence of water) the fluid and flow propertieswill be dependent on the composition of the hydrocar-bons, temperature, hydrocarbon saturation, and rockproperties (including relative permeabilities). Fluidproperties of hydrocarbons have particular signifi-cance to overpressure on account of their buoyancy(controlled by density contrast) and also the capillarypressure effects controlling relative permeability andentry pressure, and hence the effective sealing capacityof the rocks in which they occur. Buoyancy is inverselyrelated to fluid density. Gas is the most buoyant fluid,becoming more dense and decreasing its buoyancy atelevated pressures. Increases and decreases in pressurethrough time will have an influence on the composi-tion of petroleum in the basin. For example, fallingpressure during overpressure dissipation causes gasexsolution if the pressure falls below the bubble point;similarly more gas can remain in solution when pres-sure rises.

MECHANISMS FOR GENERATINGOVERPRESSURE

Stress-Related Mechanisms

Disequilibrium Compaction (Vertical Loading Stress)In a sedimentary basin, the weight of the overlying

rocks at a given depth, known as overburden stress, Sv,is a function of the thickness (Z) and density (ρb) of theoverlying rocks, and gravity (g):

Sv = Zρbg

The average bulk density can be determined in aborehole if a density log has been acquired. Bulk den-sity (ρb) is determined from the rock matrix density(ρma ), the fluid density (ρfl) , and the porosity (φ), suchthat:

ρb = ρma(1– φ) + ρfl(φ)

Some of the overburden stress is borne by the fluid,the pore pressure (P), and the remainder is distributedto the contacts between the rock particles, known asthe effective stress (σ). The relationship between effec-tive stress and overburden stress is given by Terzaghi’s(1923) equation:

σ = Sv– P

In a normally pressured rock, the effective stress at agiven depth is the difference between overburdenstress and hydrostatic pressure. The overburden stresscan be expressed in terms of pressure (sometimesreferred to as “lithostatic” pressure) if the average bulkdensity is known to the depth of interest. At the sur-face, where the porosity of the fine-grained sedimentsis high (say 60–70%), the average density is about 1.5g/cm3 (0.7 psi/ft), whereas at about 1.0 km the sedi-ment density is typically about 2.3 g/cm3 (1.0 psi/ft).Although the lithostatic gradient varies with depth,most pressure vs. depth plots use a default gradient of2.3 g/cm3 (1.0 psi/ft), based on average sediment den-sity (Mouchet and Mitchell, 1989).

Increases in effective stress, due to loading of sedi-ment during burial, normally cause rocks to compact,reducing the pore volume and forcing out the forma-tion fluids (Plumley, 1980). The rate of porosity lossvaries with rock-type. Each rock-type will have a lowerlimit beyond which no further mechanical compactionis possible and porosity loss is thereafter due to chem-ical compaction. Sandstones compact at a relativelyslow rate from a starting point of about 40–45% poros-ity to about 20–30% porosity due to rearrangement ofthe sand grains and some dissolution at grain contacts(McBride et al., 1991 and Figure 4). At depths of only1.5 to 2.5 km there is little potential for significant fur-ther reduction in primary porosity due to mechanical


compaction involving bed thickness reduction, andfurther porosity reduction is primarily a function ofdiagenetic cementation (McBride et al., 1991). By con-trast, clays have a typical porosity at the time of depo-sition of 65–80% and compact more quickly than sands(Figure 4). Clays will continue to compact, by grainrearrangement and ductility, to great depths (typically4–6 km) where the porosity can be reduced to 5–10% ofthe rock volume (Katsube and Williamson, 1994; Huntet al., 1994). However, not all clays behave in the sameway, which explains some of the variability in porosityvs. depth curves for clay-rich rocks (Figure 4). Aplin etal. (1995) show that the variability is largely controlledby mudstone lithology, although there is also the like-lihood that some porosity vs. depth data in Figure 4were derived from overpressured mudstones in whichthe rocks are not fully compacted relative to their over-burden.

Under conditions of slow burial, the equilibriumbetween overburden stress and the reduction of porefluid volume due to compaction can be most easilymaintained. Rapid burial, however, leads to fasterexpulsion of fluids in response to rapidly increasingoverburden stress. Where the fluids cannot be expelledfast enough the pressure of the pore fluids increases–acondition known as disequilibrium compaction.

Overpressure due to disequilibrium compaction isoften recognized by higher porosity than expected at agiven depth. Porosity can be considered as a functionof the overburden stress and the effective stress. If allthe fluid is retained the porosity and effective stressremain constant with depth. Conditions which favordisequilibrium compaction are rapid burial, and low-permeability rocks. Disequilibrium compaction istherefore likely to be found commonly in thick clayand shale successions during continuous rapid burial(England et al., 1987). Overpressure in adjacent, high-permeability reservoir rocks will result from isolationof the reservoir within the low-permeability section.

In addition to Terzaghi’s (1923) laboratory experi-ments, evidence cited for disequilibrium compaction isthe anomalous high porosity estimates for low-perme-ability sections as derived on borehole porosity tools(e.g., sonic log, density log). The sonic vs. depth plotfrom a North Sea well (Figure 5) shows a departurefrom the normal trend line at about 1.0 km (3,500 ft)towards anomalously high values of sonic travel time(interpreted as high porosity). This point is interpretedas the top of an overpressure zone. Critical to the inter-pretation is the validity of a “normal” trend line forporosity (or sonic travel time) and the inference thathigher sonic values equate to higher porosity. Otherporosity logs (e.g., density, neutron) should show the


Figure 4. Range of typical porosity-depth curves formudstones (solid lines), based on published empiricalmeasurements (after Dzevanshir et al., 1986; Aplin etal., 1995). The variability of curves (20% porosity rangeat 5,000 m) results from the control exerted by differentmudstone mineralogy, plus variable overpressure insome data areas. A porosity vs. depth curve (dashedline) for the mechanical compaction of a typical sand-stone is shown for comparison.

Figure 5. Interval travel time vs. depth plot from the UK21/20a-1 well, drilled in the Central North Sea. The shalevalues from the top of Miocene to the base of theEocene section are interpreted as overpressured due tothe high travel times relative to the “normal trend” (seeHottman and Johnson, 1965). Shale values plot close tothe normal trend adjacent to the normally pressuredPaleocene sands. Deeper, Jurassic shales are also inter-preted as overpressured, confirmed by pressure datafrom the adjacent sands. The cause of overpressure inthe Tertiary section is disequilibrium compaction.

same trend to have confidence in this technique. Criti-cal assessment of the rocks is required to verifywhether departure from the normal line relates tochanging lithologies or mineralogy, or a real manifesta-tion of overpressure and undercompaction (Herman-rud et al., 1998-this volume). The concept of using a“normal trend line” has been valuable in young basins,such as Tertiary deltas (Hottman and Johnson, 1965),but may not be a valid technique everywhere, particu-larly in older rocks (Wensaas et al., 1994).

Several approaches to modeling disequilibriumcompaction are now published (see Mann andMackenzie, 1990; Audet and McConnell, 1992), andform the basis for fluid flow in basin modeling soft-ware packages. The results from the models are criti-cally dependent on the choice of permeability function,especially at low porosity and high stresses. The per-meability of mudrocks is poorly known because it isdifficult to measure in low-permeability lithologies(see Neuzil, 1994). In addition, changes in permeabilitywith increasing overburden stress are also poorly con-strained. Consequently, basin modeling can show thepotential for building up overpressures in the subsur-face but the actual values are difficult to validate.

The lateral and vertical variability in permeability ofa sedimentary sequence (e.g., mudrocks, silts andsands in a clastic sequence) is critically important. Agroundwater flow model of up to 2.5 km of stratifiedhigh-permeability sand and low-permeability shale(Bethke, 1985) shows complete dewatering by a combi-nation of vertical and lateral flow. Sedimentation ratesup to 100 m/m.y. were modeled, and showed that theflow at shallow depth is concentrated upwards inresponse to relatively high permeabilities in themudrocks. At depths greater than 1.0 km, flow is

focused laterally to the edge of the basin, with increas-ing rates of flow towards the basin periphery. At alldepths flow was sufficiently slow to allow thermalequilibration, but fast enough to allow no overpressurein the model (Bethke, 1985).

In a section dominated by mudrocks and reservoirsof only restricted lateral extent, the ability to move flu-ids laterally along carrier beds is lost (Magara, 1974)and overpressures might be expected at depths greaterthan about 1.0 to 2.0 km (3,300 to 6,600 feet). Mann andMackenzie (1990) have documented several fieldexamples where pressures in isolated reservoir unitsshow increasing amounts of overpressure with depthin mudrock-dominated sequences. These examplescome from Tertiary deltas, such as the Nile and Missis-sippi, and the Tertiary sediments of the intracratonicNorth Sea basin. Additional examples include theMalay Basin (Yusoff and Swarbrick, 1994) and theCaspian Sea (Bredehoeft et al., 1988). In each case, dis-equilibrium compaction commences typically about1.0 to 2.0 km (3,300–6,600 ft) at the “Fluid RetentionDepth” (Figure 6) below which the increase in pressureremains nearly parallel to the lithostatic pressure gra-dient (and the effective stress remains approximatelyconstant). The depth at which the fluid retention depthoccurs is dependent on the sedimentation rate and therate of permeability reduction during compaction(Mann and Mackenzie, 1990).

When rate of burial slows down or stops, the over-pressure generated during rapid burial will dissipate.The rate of dissipation depends primarily on the per-meability of the sediments, controlling both verticaland lateral flow to permit pressures to return to equi-librium conditions, i.e., hydrostatic pore pressures.Overpressure will be reduced most rapidly in shallow,permeable units, and most slowly in thick, low-perme-ability units. Interbeds of contrasting lithologies withhigh and low-permeability will be differentially drawndown, leading to maximum overpressure in the centerof the low-permeability units, e.g., shale, and decreas-ing amounts of overpressure towards the contact withthe high-permeability units (Magara, 1974). The typicalshape of the pressure transition zones resulting fromdisequilibrium compaction (Figure 6) is modified aftercessation of burial, and is likely to have a modifiedtransition zone from normally pressured downwardsinto the overpressure, since the overpressure is prefer-entially lost from the top (Swarbrick and Osborne,1996). Luo et al. (1994) describe a thick, overpressuredrock unit from the Eastern Delaware Basin, Texas andNew Mexico, dominated by low-permeability shales,with the maximum pressures in the core. Pressures inreservoir-dominated units above and below are nor-mally pressured. Although the origin of the overpres-sure is uncertain, one possibility is that rapid burial 250Ma created high overpressure by disequilibrium com-paction, and that the overpressure today is the residualof a long period of slow dissipation involving an evap-orite seal (Castille Formation), possibly augmented by


Figure 6. Pressure (and/or stress) vs. depth plot foroverpressure generated by disequilibrium compaction.Fluid retention occurs at a depth where the permeabili-ty and sedimentation rate combine to prevent completedewatering. Below the fluid retention depth the profilerapidly changes to almost constant effective stressdownwards, i.e., a pressure profile almost parallel to thelithostatic pressure gradient.

gas generation from deeply buried source rocks (Swar-brick, 1995).

Tectonic (Lateral Compressive Stress)

The same principles of overpressure generation dueto compaction and incomplete dewatering apply whenreducing pore volume by horizontal tectonic compres-sion. Overpressuring due to lateral stress is reportedalong major fault zones, both within the fault and inthe adjacent porous wall-rock (Byerlee, 1993). Episodicrelease of overpressured fluids is associated withearthquakes and fault rupture (Byerlee, 1990). In addi-tion, overpressure is a characteristic of accretionarysedimentary prisms, where horizontal compressioncoupled with loading and underplating is caused bysubduction (Davis et al., 1983; Neuzil, 1995). Theamounts of horizontal compression are most likelysmall in passive continental margin and intracratonicareas, but may contribute to overpressure in unde-formed sedimentary sequences where the rock neitherbuckles nor faults. Changes in intra-plate stress overgeological time, and their magnitude, are not well doc-umented and are an active research area at the presenttime (Van Balen and Cloetingh, 1993). High fluid pres-sures encountered in deep boreholes in the CaliforniaCoast Ranges are attributed to lateral tectonic com-pressive forces (Berry, 1973).

Fluid Volume Increase Mechanisms

Several mechanisms have been proposed which cancreate overpressure, if there is an increase in fluid vol-ume. The main mechanisms proposed include (a) tem-perature increase (aquathermal expansion), (b) mineraltransformation, (c) hydrocarbon generation, and (d) oilto gas cracking.

Temperature Increase (Aquathermal Expansion)

The principle which governs aquathermal expan-sion as an overpressure mechanism is the thermalexpansion of water when heated above 4°C. If the bodyof water is contained in a sealed vessel the pressurerises rapidly. For example, Barker (1972) shows a pres-sure rise of 8,000 psi (55.1 MPa) in water heated from54.4° to 93.3°C caused by a volume increase of only1.65%. This pressure increase over about 1.0–1.5 kmwould lead to a sharp transition zone at the top of theoverpressured section. The critical observation whichmust be met to satisfy this mechanism is that the envi-ronment must be completely isolated, with no changein pore volume. Several authors (e.g., Daines, 1982;Luo and Vasseur, 1992) have shown that the conditionsfor aquathermal pressuring will rarely be met. In par-ticular when water is heated its viscosity reduces andfacilitates more rapid expulsion, even at low perme-abilities. An additional objection to aquathermalexpansion is that in many overpressured rocks there isa gradual transition zone to high amounts of overpres-sure. This implies permeability and hence the section is

not fully sealed and cannot fulfill the requirements foraquathermal pressuring (Daines, 1982). Numericalmodeling of aquathermal expansion (Luo and Vasseur,1992) shows negligible overpressure development inmudrocks with permeabilities as low as 3 x 10–27 m2

(3 x 10–14 md), permeabilities several orders of magni-tude lower that the measured permeabilities of realmudrocks (Deming, 1994).

Aquathermal pressuring is only feasible if a sealwith permeability close to zero can be proven to exist.Hunt (1990) suggested that there are diagenetic sealswith highly effective sealing properties, typically atdepths of about 3.0 km, which are laterally extensive.Although banded cements have been described wherethe top of the overpressure is observed (Tigert and Al-shaieb, 1990), the origin of these diagenetic seals andtheir ability to form regional impermeable barriersremains, in our view, open to question.

Mineral Transformation—Water Release Due toMineral Diagenesis

Several common mineral transformations in sedi-ments involve the release of bound water. The mostcommon of these involves the dehydration of smectite,a multi-layered, mixed-layer clay commonly found inmudrocks. Smectite also transforms to a new mineral,illite, involving the release of water. Other dehydrationreactions include gypsum to anhydrite in evaporiticsediments, and coalification (Law et al., 1983).

Smectite Dehydration

Several authors have proposed that smectite dehy-dration is staged in two (Powers, 1967) or three pulses(Burst, 1969), and that these pulses of released waterwere instrumental in driving hydrocarbons fromsource rocks to traps. The overall volume changeaccompanying the complex smectite-illite reaction isnot currently known (Hall, 1993). Our own calculationsindicate a total increase in volume of 4.0%, occurring inthree pulses of water release. The first two are likely totake place within the top 1.0 km of burial, with only thelast pulse at depths where significant amounts of over-pressure are measured. However, the volume of waterreleased is only about 1.4%, and will not create signifi-cant overpressure unless the rock is completely sealed.Colton-Bradley (1987) has suggested that overpressurewould inhibit the dehydration reaction, since the dehy-dration temperatures are elevated with increasingpore-fluid pressure. The smectite dehydration reactionis therefore thought to be a secondary rather than amajor cause of overpressure, but may be additive tooverpressure created by disequilibrium compaction.

Gypsum to Anhydrite Dehydration

The temperature-controlled reaction of gypsumtransforming to anhydrite results in loss of boundwater, and is thought to be an important mechanism togenerate overpressure in evaporite sections. The reac-tion occurs at 40°–60°C at ambient pressure and can


potentially generate a fluid pressure significantly inexcess of overburden pressure at 1.0 km (Jowett et al.,1993). High fluid pressures in Permian Zechstein car-bonate-evaporite sequences in the North Sea and adja-cent areas are attributed to this mechanism, as well asin the Buckner Formation of Mississippi, U.S.A.(Mouchet and Mitchell, 1989).

Smectite-Illite Transformation

Clays such as smectite can adsorb water due to animbalance in their ionic charge. During burial, smectitealters chemically by addition of Al and K ions and therelease of Na, Ca, Mg, Fe, and Si ions plus water, toproduce illite, which does not have the same capacityto adsorb water. The reaction is kinetically controlledand is dependent on the combined effects of time andtemperature, as well as the influence of mineral fabricand permeability (Hall, 1993). In several mud-domi-nated basins a gradual and systematic change fromsmectite to illite downwards in the stratigraphic sec-tion is observed, broadly coincident with the transitionto high amounts of overpressure (Bruce, 1984). Thetransition occurs over a temperature range of70°–150°C and appears to be independent of sedimentage and burial depth. By contrast, in the highly over-pressured Caspian Sea basin, there is no change insmectite to illite ratio to a depth of 6.0 km and temper-ature of 96°C (Bredehoeft et al., 1988).

The overall volume change involved with the smec-tite transformation is not well known, in part becausethe exact chemistry of the reaction(s) is not known.Conversion of one volume of smectite to illite wouldrelease 0.36 volumes of water according to the reactionproposed by Hower et al. (1976), leading to an overallvolume decrease of about 23% if all the reactions occurin a closed system. Boles and Franks (1979) claim arelease of 0.56 volumes of water, which would create avolume increase of about 25%. Hence the origin ofoverpressure by this mechanism is far from conclusive.However, the coincidence of overpressure at the samestratigraphic levels as smectite to illite transformationmay be related to the ensuing changes in the rock fab-ric, trapping excess fluids generated by another mech-anism, e.g., disequilibrium compaction.

The transformation of smectite to illite clay isaccompanied by changes in the physical characteristicsof the sediments. Firstly, the collapse of the smectiteclay framework and release of bound water influencesthe compressibility of the sediment. If the rock com-pressibility factor is increased, the overburden inducesadditional compaction requiring expulsion of thenewly released water from the rock to achieve equilib-rium. If the low-permeability of the rock acts to retainthe fluid, then overpressure will result, i.e., disequ-ilibrium compaction induced by mineral dehydration.

Another consequence of the mineral transformationfrom smectite to illite is the release of silica. Foster andCustard (1980) proposed that diagenetic silica reducesthe permeability of the shales to produce a hydraulic

seal and hence potentially a transition into the over-pressured section below. Freed and Peacor (1989), how-ever, have argued that the coincidence of overpressurenear the depth of the smectite-illite transformationresults from a reduction in the permeability of theshales, not due to silica cementation promoted by thereaction, but by reordering of the illite into packets.Reduction of permeability by mineral reorderingwould help to retain fluids and hence contribute to thepreservation of overpressure, but would not be respon-sible for its initiation. Silica cementation could involvesome volume change but the rate is likely to be tooslow to create overpressure.

Hydrocarbon Generation

Generation of liquid and gaseous hydrocarbonsfrom kerogen maturation is kinetically controlled anddependent on a combination of time and temperature.The kinetics have been broadly described for each ofthe main kerogen Types I, II, II-Sulfur, and III; but thekinetics of each of the many individual reactionsinvolved is not well known (Tissot et al., 1987). Each of


Figure 7. (a) Estimation of volume change when Type IIkerogen in the Bakken shale, Williston Basin, maturesto produce oil, then wet gas and condensate, and finallydry gas (Meissner, 1978b). Note the increase in volumeat all stages of thermal maturity of the kerogen. (b) Esti-mation of volume change when Type II kerogen in theToarcian Black shale, Paris Basin, France, matures tooil, then gas (Ungerer et al., 1983). Early oil maturitycorresponds to 0.65% Ro (vitrinite reflectance) and peakgas generation occurs at a thermal maturity of about2.0% Ro. Note the volume decrease during oil genera-tion, and volume increase during gas generation.

the compositional changes during kerogen maturationhas implications for the total volume of the reactantand products with potential for both volume increasesand decreases. The two main reactions involved withthe generation of oil and gas from petroleum sourcerocks are: (1) kerogen maturation to produce oiland/or gas, and (2) oil and bitumen cracking to gas.These reactions typically occur at depths of 2.0 to 4.0km and at temperatures in the range 70°–120°C forkerogen maturation (Tissot et al., 1987), and 3.0–5.5 kmand 90°–150°C for oil cracking to gas (Barker, 1990).

Kerogen Maturation—Oil Generation

There are two parallel and generally coeval process-es involving volume change that take place duringkerogen maturation/hydrocarbon generation. First isthe creation of mobile generated fluids (mainly oil andhydrocarbon gases, but also CO2 and water) from anoriginal solid immobile kerogen; and second is the cre-ation of porosity volumes that are not in equilibriumwith normal overburden compaction until fluids havebeen expelled.

The coincidence of overpressure and hydrocarbongeneration was given early prominence by the study ofthe Type II Bakken shale in the Williston Basin, Mon-tana and North Dakota, U.S.A. (Meissner, 1978a, b).The abnormal pressure was attributed by Meissner(1978b) to two processes: (1) increased volume ofhydrocarbons and residue relative to unaltered organ-ic material, and (2) inhibited structural collapse of therock framework as overburden-supporting solidorganic matter is converted to hydrocarbon pore fluid.The proposed increase in volume has since receivedmore attention in the literature as a possible mecha-nism, rather than the collapse of the rock framework.The fluid volume increase was estimated by Meissner(1978a) at about 25%, with even greater increases involume when maturation proceeds from oil to wet gas,and later to dry gas (Figure 7a). Burrus et al. (1996;1998-this volume) remodeled the overpressure andmaturation histories of the Bakken shales in the Willis-ton Basin using TEMISPACK, a 2D basin model. Theirmodel produces a close match between the overpres-sure recorded in the Bakken siltstones within theorganic-rich shales and volume change during oil gen-eration, although it is not clear how the overpressure iscreated within their model. Their analysis shows nopotential contribution from disequilibrium compactiongenerated by the burial history of the rocks in this partof the succession.

Spencer (1987) extended the link between overpres-sure and volume increase during oil generation to mostof the deeper parts of the Rocky Mountain basins. Bre-dehoeft et al., (1994) concluded that maturation of theType I Green River shales can account for the highoverpressures in the Altamont-Bluebell field, UintaBasin, Utah. Sweeney et al., (1995) model volumeincreases from organic maturation during oil genera-tion, leading to 25% of the total overpressure found in

the La Luna Formation source rocks in the MaracaiboBasin, Venezuela. The remainder of the overpressure isdue to disequilibrium compaction within the maturingsource rocks.

In our view, there is considerable uncertainty aboutthe volume change (i.e., comparison between volumeof starting reactants compared with total volume ofproducts and residue) when kerogen matures to oil,plus associated gas, residue and by-products (mainlyCO2, H2S and H2O), at least at the maturation stage upto Ro = 1.2%. In contrast to Meissner’s (1978a) volumeincrease, Ungerer et al., (1983) show a small volumedecrease when modeling the composition changesfrom kerogen maturation (up to Ro = 1.3%) in Type IIToarcian black shale in the Paris Basin, France (Figure7b). Part of the explanation for differences in calculat-ed volume change relate to assumptions about thegases generated (e.g., CO2 and H2S) and to the volumeand density of the residual kerogen/coke. We considerthat it is premature to assume that there is an overallfluid volume increase in all cases of kerogen matura-tion to oil, and additional research (included in theGeoPOP project, see Acknowledgements) is needed toresolve the volumetric change with burial and matura-tion for the range of kerogens found in petroliferoussource rocks.

It is generally accepted that high pressures are nec-essary to drive expulsion (primary migration) of petro-leum from low-permeability source rocks into carrierbeds (England et al., 1987, who believe that volumechange during oil maturation is negligible). The porepressures in the source rocks must be sufficient to forcethe oil and gas out of the micropores and/or to initiatemicrofractures to release the petroleum (Palciauskasand Domenico, 1980). If there is no fluid volumechange during the early maturation of source rocks tooil, how do hydrocarbons migrate out of these sourcerocks? Can primary migration be achieved withoutvolume change? The second main change during kero-gen maturation, the creation of additional pore vol-ume, may provide an answer.

Kerogen maturation involves increased pore vol-ume as a consequence of transforming solid immobilekerogen into mobile fluids. Reduction of the solid frac-tion as the kerogen transforms to liquids, gases andresidue, alters the distribution of the overburden stressbetween solid rock and pore fluids. For example, takea source rock with a porosity of 13% and a further 10%by volume of kerogen, immediately prior to matura-tion. If half of the kerogen by volume is transformed toliquid hydrocarbons the total porosity is increasedfrom 13% to 18% as the solid fraction is reduced from87% to 82% of the original volume, assuming no loss inhydrocarbons due to primary migration. Where thekerogen sustains part of the overburden stress, thatstress will be transferred to the liquid phase. If the liq-uid cannot escape, there will be an increase in porepressure. This change is illustrated in Figure 8, wherethe amount of overpressure is related to the effective


stress vs. porosity relationship for the modified sedi-ment (i.e., the disequilibrium compaction when thesolid:liquid ratio goes down, and the fluids cannotescape). In the example the kerogen is instantaneouslytransformed at Point A into liquids. The pressureincreases by 1,100 psi (Point B), a maximum deter-mined by the effective stress which is in equilibriumwith the rock with a porosity of 18% (i.e., a burial depthat Point C). The calculation of overpressure in Figure 8assumes an even distribution of kerogen throughoutthe rock, a maximum amount of overpressure, and noexpulsion of fluids. In practice, the magnitude of over-pressure resulting from this mechanism will varythroughout the source rock depending on the distribu-tion of the original kerogen–lean laminae will experi-ence little change, whereas almost continuous organic-rich laminae could experience pressures as high asfracture pressure (e.g., >85% lithostatic), if almost all ofthe overburden is supported by the fluid phase. Thericher the source rock, the greater the increase in aver-age pressure, assuming the same proportion of kero-gen is transformed. We believe this mechanism may belargely responsible for primary migration, but furtherresearch is required.

In any given basin, the distribution of overpressurecreated by this process is controlled by the availabilityof maturing source rocks within the stratigraphic suc-cession, and we are doubtful that this mechanism willcreate regional overpressure, except under circum-stances of close linkage between source rocks andreservoirs. The overpressures in the Bakken Shale sec-tion, measured within siltstones enveloped withinmaturing organic-rich shales (Burrus et al., 1993; 1996),may be an example of local overpressure sourced bythis mechanism, and where there has been minimalescape of hydrocarbons.

Kerogen Maturation—Gas Generation

The maturation of a gas-prone source rock (e.g.,Type III kerogen) results in significant increase in fluidvolume during maturation. Law (1984) observed over-pressures in low-permeability Upper Cretaceous andTertiary coal and carbonaceous sediments, which heattributes to volume change during thermogenic gasgeneration from these Type III source rocks. BothMeissner (1978a, b) and Ungerer et al. (1983) calculatelarge volume expansion (between 50% and 100%) rela-tive to the initial volume of the kerogen, when a TypeII source rock reaches higher levels of thermal maturi-ty (e.g., Ro = 2.0) at which the main hydrocarbon prod-ucts are gas (Figure 7). Hence where source rocks aregenerating significant amounts of gaseous hydrocar-bons, and especially where the hydrocarbon phase iseither gas condensate or dry gas, there is the potentialfor overpressure to result from the large volumechanges which occur. The amounts of volume change,their rates, and the influence of the changing pressureconditions remain to be determined. However, the dis-tribution of overpressure resulting from this mecha-

nism alone will reflect the depth and temperatures atwhich the necessary maturation levels are reached, andthe location of source rocks in which the volumechange is taking place (Swarbrick and Osborne, 1996).

We do not know how a build-up of overpressureduring gas generation influences the reaction rateswhich govern kerogen maturation. It is conceivablethat although the transformation of kerogen to hydro-carbons is a kinetically controlled reaction, the build-up of high pressures may act to retard the reaction(Price and Wenger, 1992). Fang et al., (1995) reportanomalous immature source rocks in overpressuredbasins in China, and similar data from Siberian oil andgas basins are reported by Neruchev and Gildeeva(1994). Regardless of any volume change, the presenceof oil and gas as separate phases (from water), espe-cially within fine-grained rocks including source rocks,will severely reduce the effective permeability of therocks. This phenomenon will be very important to theretention capacity of these rocks and their ability toseal excess fluids created by any of the overpressuremechanisms. For example, gas in the Greater GreenRiver Basin, Wyoming, Colorado and Utah, originallygenerated from Type III kerogen in coals and carbona-ceous source rocks, and now in tight overpressuredreservoirs, has been trapped by reduced permeabilityof the rock to gas (Law, 1984).

Oil and Bitumen to Gas Cracking

At high temperatures oil converts to lighter hydro-carbons and ultimately to methane. Thermal crackingis initiated generally at temperatures of 120°–140°C


Figure 8. Estimation of the overpressure created by dis-equilibrium compaction in a maturing source rock. Halfof the initial kerogen (10% by volume) is transformedinto liquid products, thereby increasing the porosityfrom 13 to 18%. The effect is to transfer the part of theoverburden supported by the original kerogen onto thepore fluid.

with almost complete cracking to gaseous hydrocar-bons (mainly methane) at temperatures in excess of180°C (Mackenzie and Quigley, 1988). At standard tem-peratures and pressures, one volume of standard crudeoil cracks to 534.3 volumes of gas, plus a small volumeof graphite residue. This observation led Barker (1990)to suggest that when the system is effectively isolated(i.e., has a perfect seal) there is an immediate and dra-matic increase in pressure as oil cracks to gas. In facthis calculations show that only 1% cracking of oil isrequired for the pressure to reach lithostatic and there-after further cracking should lead to fracturing andsubsequent leakage. A much smaller volume increaseis observed at typical depths of burial (3.0 to 5.0 km),where the compressibility of gas must be considered as

well as its solubility in brine. Large volume increasesare still likely, however, with the potential for generat-ing overpressure.

The effect of increased pressure as an influence onthe rate of reaction of oil to gas cracking is poorlyknown. Low temperature pyrolysis experiments atincreasing pressures (Domine and Enguehard, 1992)show that rate of cracking of C20 to C5–3 decreased withincreasing pressure, as expected from Le Chatelier’sprinciple. As stated earlier, the presence of gas as a sep-arate phase within the fluid will reduce the permeabil-ity of the rocks and contribute to their retention capac-ity and ability to maintain overpressure generated byanother mechanism.

There are several basins where the distribution ofoverpressure is coincident with the deeper parts of thebasin where oil to gas cracking is assumed to be occur-ring. Law et al. (1980) note the active generation of

large amounts of wet gas and the development of over-pressure in Upper Cretaceous rocks in the northernGreen River Basin. Hunt et al. (1994) observe a strongcoincidence of the top of overpressure and peak gasgeneration in the Gulf of Mexico. Other examplesinclude Jurassic and Triassic reservoirs in the Northernand Central North Sea, the Jurassic Smackover reser-voir of Mississippi/Alabama, Lower Pennsylvanian ofthe Anadarko Basin, Oklahoma, and the Lower Creta-ceous of the Powder River Basin, Wyoming (Meissner,personal communication). In the North Sea the highestoverpressures are found where the Kimmeridge Clay ismost deeply buried and presently mature for gas (Cay-ley, 1987; Holm, 1998-this volume), but the Jurassic andTriassic reservoirs are everywhere overpressured(Gaarenstroom et al., 1993), even at depths well aboveactive source rock maturation. The origin of the over-pressure here remains controversial.

Fluid Movement and Buoyancy Mechanisms

Osmosis

Large contrasts in the brine concentrations of forma-tion fluids, from dilute to saltier water, across a semi-permeable membrane can induce transfer of fluidsacross the membrane. Marine and Fritz (1981) suggest-ed that osmotic pressure could be an explanation forsome overpressured sections. We have examined theosmotic behavior of a typical North Sea shale composi-tion in contrast with near perfect membrane behaviormodeled elsewhere (see Fritz, 1986). Our calculations(shown in Figure 9) indicate osmotic pressure in typi-cal North Sea rocks is only about 3.0 MPa (435 psi),even with salinity contrasts as high as 35 Wt% NaClequivalent. If a shale contains microfractures osmosisis impossible.

A further argument against this mechanism havinganything but very local importance is the requirementfor recharge of the more saline, and discharge of theoriginally less saline, waters to maintain the pressure.In practice we believe this is unlikely to happen duringnormal compaction processes. In addition, it has beenobserved that brines in overpressured zones tend to beof a lower salinity than adjacent normally pressuredbrine, which would act to reduce the pressure in theoverpressured zones.

Hydraulic Head

The hydraulic or potentiometric head resulting fromelevation of the water table in highland regions (chargeareas) exerts a pressure in the subsurface if the reser-voir/aquifer is overlain by a seal (Figure 10). Wellsdrilled into the overpressured aquifer are known asartesian wells and will produce water flow at the sur-face due to the excess pressure. The potentiometrichead is measured either as the vertical height of thewater rise above datum (the practice in hydrogeology)or as the height converted to pressure with knowledge


Figure 9. Graph illustrating the osmotic pressure creat-ed by a typical North Sea shale, with 5% porosity and55% clay content, acting as a semi-permeable mem-brane for a range of salinity contrasts up to 35 Wt.%NaCl eq. Note that pressure reaches a maximum atabout 10 Wt.% NaCl eq., and the amount of pressure ismuch lower than for the theoretical values for an idealmembrane, calculated using the osmotic efficiencyequations in Fritz (1986).

of the formation fluid density. Neuzil (1995) refers tothis situation as “equilibrium overpressure” in recog-nition of the direct relationship between elevation ofwater table above a reference datum and the amount ofoverpressure in the sediments. Lateral continuity ofreservoirs beneath a continuous seal is required for thismechanism to operate. In many interior forelandbasins (e.g., Alberta Basin; Bachu, 1995) there is scopefor the generation of significant amounts of overpres-sure by this mechanism. The amount of overpressure,measured as a potentiometric head (Figure 10), cannotexceed the height of the elevated water table above thepotentiometric surface, but in many basins the pres-sures measured in the subsurface far exceed this value,and an alternative explanation is required.

Hydrocarbon Buoyancy (Density Contrasts)

All gases and most oils have a lower density thanthe associated formation waters and hence have alower pressure gradient. Since overpressure is theexcess pressure above hydrostatic for a given depth,there is always some amount of overpressure wherev-er a column of oil or gas is present. This mechanism isrestricted to structural and stratigraphic traps ofhydrocarbons, and cannot cause regional overpressure.The amount of overpressure within the hydrocarbonaccumulation is a function of the pressure gradients ofoil, gas and water and the height of the hydrocarboncolumn (Figure 11). The excess pressure increases fromthe water contact upwards, and is calculated by multi-plying the column of any one fluid by the difference inpressure gradient between the overlying hydrocarbonand underlying water. In the North Sea the maximumoverpressure attributed to this mechanism is only 6.0MPa (600 psi), calculated by adding the effect of thelongest oil and gas columns together. In practice, thin-ner hydrocarbon columns lead to the overpressure dueto buoyancy in most fields being less than 1.0 MPa (145psi). Buoyancy-driven excess pressure is not regardedas “abnormal”. The overpressure created by this mech-anism is in addition to any regional overpressure in the

water zone, but the additional overpressure may besufficient to influence the sealing capability of thecaprock seals.

There is another potential link between overpres-sure and hydrocarbon buoyancy. When gas rises anddecreases in temperature, the volume of the gasincreases and its density decreases. However, in a total-ly sealed container (e.g., in a drill pipe), gas is unable toexpand because of the incompressibility of the sur-rounding fluid and the pipe, and consequently thepressure of the gas and the fluid rises. The potential forthis mechanism to increase the fluid pressure in natur-al rock systems has not been fully evaluated. In partic-ular, the permeability requirements are not known, andconditions for the generation of free gas are dependenton pressure as well as temperature. If the mechanismdid create increases of pressure, the gas, existing as aseparate phase, may be forced back into solution at ele-vated pressure, such that the system may be self-limit-ing, and resultant overpressures are therefore difficultto predict. In addition, the creation of pressure willdepend on the compressibility of the fluids and therocks (generally considered small).

TRANSFERENCE OF PRESSURE

Transference is the redistribution of excess porepressure in the subsurface. Although not a primarymechanism to create overpressure within a sedimenta-


Figure 10. Cartoon to illustrate over-pressure as a result of hydraulic head(excess pressure due above datum(here as sea level) and connectivitybetween upland areas of waterrecharge into a subsurface aquifer.

Figure 11. Hydrocarbon buoyancy due to the lower densities of light-medium oils and gases relative towater leads to overpressure, illustrated by a long gas-cap above a medium-light oil, based on data from NorthSea fields.

ry basin, transference can be the principal control onthe distribution of overpressure found there. Fluidmovement is driven by differences in excess pressureand controlled by the permeability of the rocks. High-permeability reservoir sections will be the most effec-tive rocks in redistributing excess pore pressure whenit is created, whereas long periods of geological time

will be necessary to equilibrate the overpressure pro-files of low-permeability rocks. The effects of transfer-ence are illustrated in Figure 12, in which the onlymechanism creating overpressure is disequilibriumcompaction, in the shales below the fluid retentiondepth. There are a series of tilted sandbodies, Athrough G, of which four (C, E, F, and G) have beenpenetrated by Well X. Sand bodies A, B, and E areenveloped within normally pressured shales, and pres-sures within the sandbodies are normal, confirmed bythe pressure data from E (Figure 12b). Well X hasdrilled sandbodies F and G in their updip position,such that the pressures within them are influenced byhigher pressures deeper down (since overpressureincreases downwards beneath the fluid retentiondepth; Figure 6). Pressure data from F show a smallamount of overpressure at the well location, despite itsposition above the fluid retention depth, due to trans-ference. The pressures in G are also elevated by trans-ference, above the pressures predicted by disequilibri-um compaction in the shales (Figure 12b). Finally, thepressures in C are lower than anticipated, since Well Xpenetrated this sand in a downdip position. Note thatall the pressures within each sandbody show a pres-sure gradient for water, i.e., parallel to hydrostatic.However, a prominent pressure transition zone (Swar-brick and Osborne, 1996) exists between sandbodies Cand G though the shales (Figure 12b).

Examples of overpressure distribution stronglyinfluenced by transference include the Paleocene sand-stone reservoir of the North Sea and the Miocene sedi-ments of the Mahakam Delta, eastern Kalimantan,Indonesia. The Central North Sea Paleocene sand-stones were deposited as an extensive axially-located,turbidite-dominated submarine fan extending laterallyinto silts and muds, and overlain by up to 3.0 km offine silts and muds. The high sedimentation rate and


Figure 12. a) Schematic cross-section of a series of iso-lated sandbodies, encased in shales, and tilted uniform-ly. The fluid retention depth (see Figure 6) is indicatedby a dashed line. The arrows indicate pressure transfer-ence to equilibrate higher shale pressures at the base,and lower pressures at the crest of the sandbodies. b)Pressure vs. Depth plot for Well X drilled through sand-bodies C, E, F and G. Transference is taking place in allsandbodies at or below the fluid retention depth.

Figure 13. Schematiccross-section from theCentral North Sea, with atypical pressure vs. depthplot on the left. Tertiaryclays are overpressured(see Figure 5) above aregionally extensive,subcropping, Paleocenereservoir. Fluid escapeallows equilibration tohydrostatic pressure in the reservoir due to trans-ference. In the deeperJurassic shales trans-ference of pressure leadsto higher than expectedpressures at the crest ofeach confined fault block.

the fine-grained nature of the post-Paleocene sedi-ments have produced overpressure in the shales,except in the top 1.0 km or so (Ward et al., 1994). Themechanism for overpressure generation is, in this case,disequilibrium compaction. The Paleocene sandsbeneath are only overpressured at the extreme limits ofthe sand sheet, where the sandstones are isolated with-in shales. Elsewhere, there is active transference ofexcess pore pressures from the basin up the regionalslope to the northwest (Figure 13), and eventually tonear the sea-floor in the Moray Firth area (Cayley,1987), a distance of about 250 kilometers. Pressures areat, or close to, hydrostatic wherever the sand sheet iscontinuous. In the Miocene sediments of the MahakamDelta there is hydrological continuity from the deltaslope to the delta top, with transference from the over-pressured mud-dominated section in the east to thesand-dominated, normally pressured section to thewest (Burrus et al., 1994; Grosjean et al., 1994).

Transference can also take place vertically, most fre-quently associated with active faulting (Burley et al.,1989). Leakage of fluids due to fracturing at the crest ofstructures is an effective way of transferring the excesspore pressures from deeper in a basin to shallower lev-els. Examples documented in the literature include aSoutheast Asia basin where hydrofractures arebelieved to be permitting upward transfer of hot fluidsto shallower reservoirs (Grauls and Cassignol, 1993),and the Gullfaks field, whose pressures are close to thefracture pressure, where a gas chimney is locatedabove the crest of the shallowest of a number of pres-sure-connected oil fields (Caillet, 1993).

MECHANISMS FOR CREATING UNDERPRESSURE

Observations

From published studies of underpressured rocks itis possible to make some generalizations about thegeological settings in which underpressuring occurs.Underpressure commonly occurs in relatively shallow-ly buried (0.6–3.0 km) permeable rocks which are fre-quently isolated within, or interbedded with, low-per-meability mudrock sections (e.g., Dickey and Cox,1977). In many instances underpressured rocks havealso been uplifted in the geological past (e.g., Bachuand Underschultz, 1995).

A variety of mechanisms have been proposed for thecreation of underpressure (Figure 14) and these will besummarized below. The controlling parameters influ-encing pressure in an underpressured rock remain thesame as for an overpressured rock—i.e., the magnitudeof the pressure depends on the mechanism, thepermeability related to seal integrity of the rocks, therate at which the mechanism operates and the timingrelative to onset/completion of the mechanism, andfluid type.

Mechanisms

Differential Discharge—Groundwater Flow

Underpressure can occur in a topographically-dri-ven flow system where there are very low-permeabili-ty rocks in the recharge area, but high permeability inthe outflow area (Belitz and Bredehoeft, 1988) (Figure14). For example, high-permeability Mesozoic andPaleozoic rocks in the Denver basin, U.S.A., are beingrecharged from the Rocky Mountain uplift to the west,but are discharging fluids along the eastern side of thebasin. However, the permeable rocks are isolated fromtheir meteoric recharge area by thick, low-permeabilityshales. This means that the rate of fluid discharge fromthe high-permeability units is greater than the rate ofrecharge through the low-permeability units (Belitzand Bredehoeft, 1988). As more fluid is leaving the per-meable units than entering them, there is no continu-ous fluid column through the rocks from their highestto lowest elevation. This means that pore pressures areless than hydrostatic values, and in the Denver basin,permeable aquifers are often 1,000–1,500 psi (7–10MPa) underpressured at 0.6–3.0 km depth of burial(Belitz and Bredehoeft, 1988). Underpressuring due tosteady-state regional ground water flow is possible inany subaerial, topographically tilted basin which iscapped by a thick sequence of low-permeability rocks.The mechanism may also operate where low-perme-ability barriers exist in the subsurface, effectively dis-connecting a high-permeability rock in the deep basin,from its subaerially exposed counterpart at a highertopographic level (Belitz and Bredehoeft, 1988).

Differential Gas Flow

A model for differential hydrocarbon flow was usedby Law and Dickinson (1985) as partial explanation forthe underpressures observed in several uplifted basinsin North America, including the San Juan, Piceance,Appalachian, and Alberta Basins. During uplift gas inoverpressured, saturated reservoirs comes out of solu-tion as the temperature and confining pressure arereduced. This exsolved gas migrates out of the lowerpermeability reservoirs at a greater rate than continuedgas generation in the source rock. The imbalancebetween gas migration and generation leads to a reduc-tion in the overpressuring (Figure 14) and, dependingon the magnitude of the temperature reduction and gasloss from the system, pressures below regional hydro-static may result (Law and Dickinson, 1985).

Rock Dilatancy

During erosion of a shallow-buried, clay-rich lithol-ogy, dilation of the pores can occur (Figure 14). Theincrease in pore volume may facilitate the dissipationof overpressure, and possibly produce underpressure,depending on the amount of dilation, rate of removal,and the permeability of the rock (Luo and Vasseur,1995; Neuzil and Pollock, 1983). Permeable units may


also become underpressured, if they are isolated with-in mudrocks which are undergoing dilation, becausewater is drawn from the sandstones into the shales inresponse to the expansion in the shale pore volume.Bachu and Underschultz (1995) describe the process asbeing “analogous to water suction by a previouslysqueezed sponge.”

The amount of dilation following erosion is at pre-sent uncertain, because the rheology of variousmudrocks is poorly known. Neuzil and Pollock (1983)assumed that mechanical compaction was reversible,hence in their models, rock dilatancy has a major effecton pore pressure. However, this may not be a realisticassumption in all instances, because many experimen-

tal studies indicate that compaction is nearly irre-versible (e.g., Karig and Hou, 1992). There is a furtherproblem in that laboratory studies are necessarily ofshort duration, hence slow unloading processes, suchas clay swelling, which occur over thousands of years,may not be reproduced on a laboratory time scale(Peterson, 1958). Such clay swelling is most likely inrocks which are rich in smectitic clays such as mont-morillonite. The amount of smectite present inmudrocks generally decreases with depth of burial,due to the conversion of smectite to illite and otherminerals ( Perry and Hower, 1972). Hence rocks whichhave been buried to temperatures greater than70°–100°C will often contain less smectite and be less


Figure 14. Summary diagram for the major mechanisms thought to be responsible for generating underpressure. Foran explanation of each see text.

prone to swelling upon uplift. In addition, deeplyburied mudrocks are generally more compacted andcemented, which will again reduce the amount of dila-tancy during uplift. Therefore, it seems likely that theeffect of pore dilatancy will be most important in smec-titic mudrocks which have never been deeply buried(<2.0 km), and which have been uplifted.

Underpressuring due to unloading is also criticallydependent upon the sediment permeability. When themudrock has a moderate permeability and is slightlyoverpressured before uplift, unloading may result insub-hydrostatic pressures of up to 600 psi (4 MPa) (Luoand Vasseur, 1995). When mudrock permeabilities areextremely low and the rock is highly overpressuredbefore uplift, rapid unloading will decrease pressuresalong a path similar to that of the overburden load, andthere will be no underpressure (Luo and Vasseur, 1995).

Computational modeling suggests that unloading isa major cause of abnormal pressure in the AlbertaBasin of western Canada, in which reservoirs/aquifersare about 440 psi (3 MPa) underpressured and wherethe uplift can be as much as 800 m in the Cenozoic(Corbet and Bethke, 1992). Pore dilation may also helpto explain underpressure in lenticular sandstones ofthe Mid-Continent of the U.S.A., which are isolatedwithin mudrocks which have been uplifted (Dickeyand Cox, 1977). These sandbodies are 500–700 psi(3.4–4.8 MPa) underpressured, are oil and/or gas bear-ing, but contain virtually no water. This lack of watercan be explained if water (but not hydrocarbons) hasbeen drawn into the surrounding shales due to poredilation (Dickey and Cox, 1977). The lack of hydrocar-bon movement may have been due to capillary effects.

Osmosis

As outlined earlier, osmotic pressure can be generat-ed across a shale membrane if fluids of differing salini-ty exist in formations on either side of the shale (Figure14). Water will flow from the high salinity side of themembrane to the low salinity side, while salts will tendto be excluded. On the high salinity side of the mem-brane, underpressures could be produced due to loss ofwater, while on the low salinity side of the membrane,overpressure could be produced due to increase influid volume (Hitchon, 1969). However, most shales arenot efficient membranes, because their porosities aretoo high (>5%) and their cation exchange capacities aregenerally too low (<30 meq/100g). Hence the amountof underpressure generated by osmosis is likely to besmall (<400 psi, <3 MPa). As shales are non-ideal mem-branes, some ions do pass across the membrane,though in the opposite direction to the movement ofwater. This means that the salinity contrast will slowlyequilibrate due to movement of ions and fluid acrossthe membrane, thus the osmotic potential of the cellwill ultimately diminish through time. Underpressureis normally found in fine-grained sediments which areshallowly buried, but at shallow depths the porosity ofthe shales will be too high for osmotic behavior. In

addition, in most underpressured basins, the salinitycontrasts required for extensive osmotic flow are notpresent (e.g., Dickey and Cox, 1977).

Thermal Effects

If water in a completely sealed container is cooled,the fluid will decrease in density. In a completely iso-lated container, this will result in a reduction in fluidvolume, producing underpressuring if the fluid pres-sure was initially hydrostatic (Figure 14). This mecha-nism is thought to generate underpressure in reser-voirs which possess good lateral and vertical seals(Barker, 1972). The objections we have raised againstwater expansion as a mechanism to generate overpres-sures, also apply to this reverse process of watershrinkage. The process will only be an effective causeof abnormal pressure if the rock is perfectly sealed,because the change in water volume during shrinkageis extremely small (<2%). For example, computationalmodeling of pore fluid cooling during uplift of theWestern Canadian Basin, indicated that where the porefluid is water, fluid shrinkage is a negligible cause ofunderpressure (<5% of the magnitude) (Corbet andBethke, 1992). The majority of the underpressure isproduced by the effect of rebound and dilation of pores(Corbet and Bethke, 1992).

The volume change in hydrocarbons, due to temper-ature reduction during uplift, may be greater than inwater, due to the higher compressibility of both oil andgas. In most basins the distribution of hydrocarbons isrestricted to traps, source beds, and migration path-ways, and is volumetrically small in comparison withwater-bearing strata. The regional effect on pore pres-sures is likely to be small. However, in the San Juan andPiceance Basins a pervasive gas phase is reported in thedeep, axial portions of uplifted basins, where low-per-meability reservoirs are both overpressured and under-pressured (Law and Dickinson, 1985; Surdam et al.,1994). The contribution to the underpressuring fromvolume reduction in hydrocarbons due to temperaturereduction requires evaluation, particularly with respectto the magnitude of expansion related to reduced con-fining pressure. However, despite this uncertainty, it isclear that many instances of underpressure recorded inthe literature can be adequately explained by mecha-nisms other than fluid expansion/contraction. As inthe case of aquathermal pressuring, mechanical effectsare likely to be far more important than thermal effectsin generating abnormal pressure.

CONCLUSIONS

1. There are several mechanisms capable of creatinglarge overpressures in sedimentary basins. The mostlikely mechanisms for most basin settings, however,are disequilibrium compaction due to rapid loadingin fine-grained sediments, and the volume expan-sion associated with gas generation.


2. Disequilibrium compaction dominates as an activemechanism in young basins experiencing rapid sed-imentation, including Tertiary deltas (e.g., Baram,Nile, Niger, Mississippi, Mackenzie), and young,intra-cratonic basins (Caspian Sea, North Sea, Malay,South China Sea). The magnitude of overpressuregenerated by disequilibrium compaction is limitedto the additional overburden stress. Higher amountsof overpressure in these basins is most likely causedby transference, especially where there are laterallycontinuous but confined reservoirs with consider-able vertical relief, or by some other mechanism.

3. Disequilibrium compaction as a consequence of min-eral dehydration and transformation may createoverpressure in rocks during these alterations.Where part of the rock matrix is converted into freefluid (for example, during kerogen maturation orsmectite dehydration), the pore fluid will tend toassume that portion of the overburden previouslycarried by the rock matrix.

4. Gas generation seems to be a likely mechanism tocreate regional overpressure, although the volumechanges are not yet determined. Both gas generationfrom gas-prone source rocks and oil to gas crackingare responsible. Possible examples of overpressuredue to fluid volume increase with gas generationinclude the deeper reservoirs of the North Sea, Gulfof Mexico, and the Anadarko Basin. The amount ofoverpressure generated could be considerable, dueto the large potential increases in volume. There isuncertainty about the influence of increasing pres-sure on the reaction rate, however. Relative perme-ability effects due to two or three fluid phases mayalso be important.

5. Other mechanisms which rely on increased volumechange are unlikely to create significant overpres-sures. These mechanisms include smectite to illitetransformation, oil generation, and gypsum to anhy-drite and smectite dehydration reactions. However,the changes in the physical properties of the rocksundergoing these changes may be significant in pro-ducing local overpressure by disequilibrium com-paction as the rock:fluid ratio is modified in each case.This local effect may be additive to other synchronousmechanisms, e.g., disequilibrium compaction.

6. Osmosis can only create minor amounts of overpres-sure in favorable conditions. Shales do not act asideal membranes and the amount of overpressure islimited, even at high salinity contrasts.

7. Overpressure in oil and gas accumulations due tohydrocarbon buoyancy can be assessed if the densi-ties of the fluids are known. Similarly if the poten-tiometric (hydraulic) head of water in an uplandarea is known, its impact in generating overpressure

in subsurface aquifers can be calculated. Neither ofthese mechanisms generates sufficient overpressureto explain high overpresssures in many basins.

8. Modeling overpressure is dependent on a full under-standing of the geological setting of the basin, andthe overpressure mechanism, plus the permeabilitiesof the fine-grained rocks in which it is created, andretained (by seals). Further research is required todetermine the appropriate permeability values toassign to such rocks.

9. Underpressure as a geological phenomenon is lesswell known than overpressure. Underpressuredreservoirs have been recognized mainly in low-per-meability, gas-charged reservoirs in uplifted basins.The mechanisms for generating naturally underpres-sured reservoirs relate to changes in the rock andfluid properties during erosional uplift, e.g., reduc-ing temperature, rock dilatancy, gas solubility andgroundwater discharge.

ACKNOWLEDGEMENTS The authors wish to thank thesponsors of the Overpressure Research Project (GeoPOP) atthe Universities of Durham, Newcastle, and Heriot-Watt fortheir support: Amerada Hess, Agip, Amoco, ARCO,Chevron, Conoco, Elf, Enterprise, Mobil, Norsk Hydro,Phillips Petroleum Company Ltd., Statoil and Total. Theauthors accept responsibility for the content of the paper andopinions expressed. The manuscript has benefited fromreviews by Neil Goulty, Ben Law and Fred Meissner.

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6. Swarbrick Osborne 1998 AAPG MEMOIR 70

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