Clay Minerals (1994) 29, 463-473

R E S E R V O I R D I A G E N E S I S A N D H Y D R O C A R B O N M I G R A T I O N U N D E R H Y D R O S T A T I C P A L A E O P R E S S U R E

C O N D I T I O N S

R . E . S W A R B R I C K

Department of Geological Sciences, University of Durham, South Road, Durham, DH1 3LE, UK

(Received 18 July 1993; revised 25 February 1994)

A B S T R A C T : Fluid inclusion studies from two contrasting fields in the Northern North Sea reveal hydrostatic pressure conditions during the formation of secondary quartz overgrowths which trapped both brine and petroleum inclusions. In these fields, dating of authigenic illite, part of the diagenetic sequence and broadly coeval with quartz cementation, permits comparison with modelled pressure conditions. Pressure modelling indicates the likelihood of several periods of overpressure in the past, interspersed with normal pressure. The timing of diagenesis coincides with one of these periods of hydrostatic pressure. Furthermore, as both fields are now highly overpressured, the cause and timing of overpressure generation post-date the diagenesis. A model is proposed to link the pressure history and diagenesis.

Overpressure results from the inability of pore- fluid to escape at a rate which allows equilibration with a column of water (hydrostatic). The pri- mary geological control on overpressure is the permeabil i ty of ei ther the rock itself (e.g. shale) or the permeabil i ty of the rocks which confine a relatively permeable rock (e.g. sandstone reser- voir), i.e. its vertical and lateral seals. Mecha- nisms which are believed to create overpressure (e.g. disequilibrium compaction, mineral trans- formations, thermal maturat ion of kerogen, and cracking of oil to gas) can be internal to the overpressured section, or external, and transfer overpressure to sections with which there is communication. Some mechanisms can poten- tially influence a large part of the sedimentary section (e.g. rapid burial leading to disequili- brium compaction) whilst others operate only locally (e.g. hydrocarbon columns).

Present-day overpressure of a sequence of sedimentary rocks can be assessed in a variety of ways. The pore-pressure of a permeable rock is measured directly using the Repea t Format ion Tester (RFT) downhole logging tool, and also during a Drill Stem Test (DST). Mud weight and well stability are also crude indicators. The pore- pressure of low permeabil i ty rocks such as fine- grained carbonates and siliciclastics cannot be measured easily downhole. Overpressure can be inferred, however , by analysis of the response of

downhole logging tools sensitive to porosity (e.g. sonic, formation density, neutron) and compari- son with expected porosity values appropriate for the amount of overburden. Hence undercompac- tion (or excess porosity) is equated with over- pressure. In addition, overpressure can be inferred from analysis of drilling parameters (see Mouchet & Mitchell, 1989 for a review).

P A L A E O P R E S S U R E

Mechanisms which generate overpressure at the present day in many sedimentary basins around the world have undoubtedly operated in the geological past. Fossil evidence for overpressure includes dewatering structures, sandstone injec- tion dykes and sills, cone-in-cone structure in mudrock (Marshall, 1982), mud volcanoes (e.g. in accretionary prisms; Pickering et al., 1988), fractures in septarian nodules (Astin, 1986), and hydraulically fractured, bitumen-filled dykes overlying source rocks (Verbeek & Grout , 1992). The presence in the subsurface of minerals such as laumonti te, where pressure- temperature rela- tions are known (McCulloh et al., 1981), can also be used (e.g. Neogene basins, onshore California, McCulloh & Stewart, 1979). Each type of obser- vation records excess pore-pressure, although the timing and the degree of overpressuring are uncertain.

�9 1994 The Mineralogical Society

464

Fluid inclusions (small volumes of pore-fluids trapped in diagenetic cements) can be used to establish temperature and pressure conditions at the t ime of ent rapment in diagenetic cements, and if the timing of the diagenesis is known, the pressure conditions are also dated. It is necessary for two fluids of known composit ion to be trapped simultaneously (e.g. oil and brine; Narr & Bur- russ, 1984; Burruss; 1989; Walgenwitz et al. , 1990). If only one fluid (e.g. brine) is present, homogenizat ion temperatures (i.e. the tempera- ture at which the vapour bubble disappears) provide a range of minimum temperatures at the time of trapping. In this instance, trapping temperatures are conventionally est imated know- ing the salinity of the brine, the appropriate isochores (lines of equal density) for the system H20-NaC1, and assuming hydrostatic pressure (Fig. 1A).

If a second fluid such as oil is t rapped at the same t ime as the brine, the trapping temperature and pressure can be est imated if the behaviour of both fluids within this new system can be accu- rately model led (Fig. 1B). In the case of oil and brine t rapped together in the same cements, formation waters will contain significant concen- trations of dissolved methane which will modify the behaviour of the brine inclusions (Hanor, 1980). In this paper, and following Burley et al. , (1989) and Robinson & Gluyas (1992), brines trapped in Mesozoic quartz cements from the

R. E. Swarbrick

North Sea are assumed to be saturated with methane, such that homogenizat ion temperatures are trapping temperatures (Hanor , 1980; Bur- russ, 1992). Unlike the H20-NaCI system, there- fore, there is no need to plot isochores as the bubble point is now above the trapping tempera- tures and pressures. However the PVT behaviour of the t rapped hydrocarbons must also be modelled to est imate the pressure of entrapment .

Experimental PVT analysis of four naturally occurring oils and gases (Burruss, 1992) shows a range of bubble point curves but a trend towards lower temperatures and pressures with increas- ingly light bulk compositions. Maturat ion of conventional Type I and Type II kerogen leads to early undersaturated petroleum products followed by increasingly lighter oils, condensates and gases. It is not yet possible to establish the detailed composit ion of the t rapped oil in fluid inclusions. However , the oil found in inclusions in diagenetic cements at the detrital grain bound- aries must be t rapped during the early fill-up history of the reservoir, certainly early in the progression of this stage of diagenesis. The composit ion is, therefore, likely to be signifi- cantly different from the oil now present in the reservoir, and will more closely resemble the oil formed at the early stages of maturation. In the absence of bulk composit ion data for the petro- leum inclusions, a generic bubble point curve and isochores, appropriate for an undersaturated

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Fl•. I(A). Pressure-temperature plot for HzO-NaCI (brine) system�9 Homogenization temperatures (Thor,) are minimum trapping temperatures which lie on the bubble point curve. Isochores (lines of equal density) allow corrections to estimated trapping temperatures by making a 'pressure correction' assuming hydrostatic pressure (Roedder, 1984). (B) Pressure- temperature plot used to establish conditions at the time of simultaneous trapping of brine and oil in fluid inclusions. Aqueous inclusion temperatures (Taq) are trapping temperatures because of methane saturations (Hanor, 1980; Burruss, 1992). Oil inclusion temperatures (Toi0 are corrected from minimum at the bubble point curve using oil isochores. The

point of intersection of the oil isochore with the trapping temperature yields the estimated pressure of entrapment�9

Reservoir diagenesis and hydrocarbon migration

black oil, was constructed from data in Narr & Burruss (1984), Burruss (1992) and several under- saturated North Sea oils. The reservoir oils in both the Northwest Hutton and Alwyn fields are undersaturated (Johnes & Gauer, 1991; Inglis & Gerard, 1991). Direct crush GC-MS analyses of oil extracted from inclusions in Alwyn North Field core samples (G. Macleod, Newcastle Research Group, pers. comm.) has yielded MPI-3 and 2-MeNa/l-MeNa ratios (see Tissot & Welte, 1984 for discussion) which show the trapped oil was generated from a source rock at the beginning of the oil window, which also appears to justify this assumption.

M E T H O D O L O G Y

Fluid inclusion temperature data have been collected using a modified gas-flow (Reynolds) stage and a 32x long-distance objective lens, with which inclusions down to 2-3 btm can be measured stlccessfully. Inclusions have been measured exclusively in quartz cements. The majority of the inclusions were located along the boundary between the original detrital grain and secondary overgrowths, plus a small percentage found within the overgrowths or in later fractures which cross overgrowths and can extend into the detrital grains. The inclusions are typically <10 ~tm across. Typically the oil inclusions found along detrital grain boundaries have a preferred orien- tation with the long axis parallel to the boundary. They are normally 5-10 btm in length although they can reach 20 ~tm in length but <5 btm deep, and in addition are characteristically larger and more irregular in shape than the brine inclusions. Inclusions found entirely within the quartz over- growths tends to be spherical to elliptical in shape irrespective of composition. Distribution of oil inclusions is sporadic. Inclusions tend to cluster along only one or two grain boundaries, sur- rounded by many similar grain boundaries with- out oil inclusions, or with only weak fluorescence.

Modelling of pressure through time has been based on the Platte River BASINMOD T M soft- ware, a PC-based 1-D basin modelling program. Porosity vs. depth for shales has been estimated using the Athy-type exponential relationship developed by Sclater & Christie (1980) based on North Sea data. Permeabilities are estimated using the Kozeny-Carmen equation (Burrus et al.,

465

1991), with permeability a function of porosity. BASINMOD T M has also been used to estimate the relative timing of oil and gas generation from the source rocks in depocentres adjacent to the oilfields studied.

M I D D L E J U R A S S I C R E S E R V O I R B R E N T P R E S S U R E H I S T O R Y

N o r t h w e s t Hu t ton , Nor thern N o r t h Sea

The Northwest Hutton field is located within the East Shetland Basin, structurally interme- diate between the East Shetland Platform to the west and the deep axis of the Viking Graben to the east. In common with many of the adjacent fields, oils are believed to have been sourced from local drainage areas of Kimmeridge Clay Forma- tion oil-prone mudstone source rocks (Goff, 1983; Scotchman et al., 1989). The Upper Jurassic Kimmeridge Clay Formation is separated from the underlying Middle Jurassic Brent reservoir by the Heather Formation mudstones. The diagene- tic modification of the Brent reservoir at North- west Hutton is similar to the typical Brent diagenetic sequence described by Haszeldine et al., (1992), i.e. early compaction and calcite cementation, followed by a later diagenetic phase represented by quartz, illite and kaolinite precipi- tation, accompanied by feldspar dissolution. Additionally, at Northwest Hutton there is minor chlorite and ferroan dolomite precipitation (Scotchman et al., 1989). This later diagenetic phase involving quartz and illite is shown from petrographic observations to be synchronous with oil emplacement in the field area. Petrographic analysis of sandstones from above the oil-water- contact at Northwest Hutton reveals oil trapped as inclusions along the boundary between some original detrital quartz grains and secondary quartz cements. Rare inclusions are also found in the overgrowths. Scanning electron microscopy (SEM) reveals illite and quartz as broadly coeval and both increase downwards from the crest of the Northwest Hutton structure. Illite age deter- minations reported in Scotchman et al., (1989), plus unpublished data (J.D. Cocker, pers. comm.) date illite diagenesis, and by implication both quartz precipitation and hydrocarbon fill-up of the Northwest Hutton field, at 49-35 Ma and in close agreement with dates of 45-33 Ma reported

466

later in Hamil ton et al. (1992). Diagenesis is assumed to have ceased by 35-33 Ma, effectively shut down by high oil saturation and restricted access to solutes, although diagenetic studies of oil-filled reservoirs elsewhere (e.g. Fulmar field, Central North Sea (Saigal et al., 1992) and Hal tenbanken, mid-Norway (Walderhaug, 1990)) indicate the possibility of some continued diagenesis after fill-up.

Fluid inclusion temperature data from North- west Hut ton (J .D. Cocker, pers. commun.) are shown in Fig. 2A. The homogenizat ion tempera- tures for hydrocarbon and low-salinity (2.5 wt%) brine inclusions are 65-85~ and 90-130~ res- pectively. As discussed above, in a methane- saturated system Thorn for the brine inclusions are the trapping temperatures. Adding the Thorn data for the oil inclusions on a P T diagram (Fig. 2B) yields an envelope of P T conditions for the simultaneous trapping of these fluids, ranging from temperatures of 90-130~ and pressures of 22-40 MPa. Since the age of hydrocarbon fill-up is interpreted from illite ages and petrographic relationships at 49-33 Ma, reconstruction of the burial history path of the Brent reservoir can be used to compare this range of temperatures and pressures with model led P T conditions. Modell- ing hydrostatic pressure and a similar tempera- ture gradient to the present day (i.e. 36.5~ based on corrected bot tom-hole temperature data) yields the fluid pressure- temperature ( F P T

gradient shown in Fig. 2B. If pressures at the time of trapping were significantly higher than hydros-

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110 1~0

R. E. Swarbrick

tatic, the P T envelope will be above the F P T

gradient line. In this dataset the F P T gradient passes through the lower part of the P T envelope defined from the fluid inclusion analyses. The P T

conditions for trapping of fluids at 40 Ma (middle of the range of illite ages) is also shown based on the reservoir depth at 40 Ma from a burial history profile (Fig. 3). This point falls within the range of P T conditions from fluid inclusion data, suggest- ing that the quartz and related diagenesis plus the accompanying oil migration into the reservoir at 40 Ma took place under hydrostatic or near hydrostatic conditions (i.e. at overpressures of <5 MPa or <700 psi).

The Northwest Hut ton field is now overpres- sured by 17 MPa (2450 psi) above hydrostatic, based on R F T and DST measurements in the Brent reservoir, and present pressure and tem- perature of the reservoir plots well above the F P T

gradient (Fig. 2B). Modell ing of the pressure conditions in the Brent reservoir and adjacent mudrocks through t ime for the Northwest Hut ton field and the adjacent depocentre to the south- west using a computer simulation is shown in Fig. 3. For the early burial history of the Brent reservoir, hydrostatic pressures are model led, followed by two periods of significant overpres- sure (excess pressure above hydrostatic) coinci- dent with periods of rapid burial. The first occurs during the period 62-30 Ma as a result of rapid burial during the Palaeocene (62-55 Ma) and dissipation of much of the overpressure over the following 25 My. Up to 5 MPa (725 psi) excess

N W HUTTON, N. NORTH SEA B / A 60 / / / /

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0 i i i -25 0 25 50 100 150 200

PMT plot for fluid inclusi~ data from NW Hutton. (Dam f r~ Clmcker les, commo, and unpublished),

FIG. 2(A). Homogenization temperatures for oil (Toil) and brine (Taq) inclusions in quartz cements from Northwest Hutton field reservoir samples. (B) Pressure-temperature (PT) plot of fluid inclusion data from the Northwest Hutton field. The PT conditions at the time of entrapment (shaded) are defined by the intersection of the range of trapping temperatures from the brine inclusions (T.q) and the oil isochores from the range of homogenization temperatures from the oil inclusions (Toi0. The Fluid Pressure/Temperature (FPT) gradient passing through the envelope of PT conditions suggests hydrostatic to near

hydrostatic conditions at the time of entrapment.

Reservoir diagenesis and hydrocarbon migration 467

pressure above hydros ta t ic is mode l led at the occurs at the p resen t day when in the field there is crest of the field, bu t 32.9 MPa (4770 psi) in the 17.1 M P a (2465 psi) excess pressure relat ive to depocent re . The second per iod of overpressure hydrostat ic , a close match to present -day

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TIME (Ma) FI~. 3(A). Excess pressure-time plot for the Brent reservoir Northwest Hutton field (modelled for the 21]/27-3 well at the crest of the structure). Two distinct episodes of overpressure are shown; the first from 62-50 Ma and the second from 2~) Ma. (B) Burial history profiles for the Brent sandstone reservoir in the Northwest Hutton field, and the adjacent depocentre to the west, both corrected for compaction. The depth of the reservoir at 40 Ma is indicated. Note the rapid burial rate from 98-55 Ma, with highest rate from 62-55 Ma (i.e. early Tertiary). Oil generation in the adjacent depocentre (62-50 Ma) and illite age dating of quartz cementation and associated hydrocarbon fill-up (49-33 Ma) are also illustrated.

468 R. E. Swarbrick

measurement of subsurface pressure in the Brent reservoir. The model predicts 53.4 MPa (7745 psi) excess pressure in the depocentre today. This second period of overpressure is modelled from rapid burial of the section in the last 2.0 My. The larger amount of overpressure in the second period of overpressure relative to the first stems from lower permeabilities commensurate with deeper burial. Overpressure is modelled exclusi- vely in this study with disequilibrium compaction as the generating mechanism, and with no contri- bution from cracking of liquid hydrocarbons to gas in the neighbouring depocentre. Northwest Hutton now contains undersaturated oil (with gas/oil ratio of 800 scf/barrel) and probably filled during one relatively short-lived migration event (Scotchman et al., 1989) with no evidence of a later gas influx.

The first period of modelled overpressure predates the diagenesis and hydrocarbon mig- ration in the Brent reservoir documented above at 49-33 Ma, but is synchronous with the main phase of oil generation from the Kimmeridge Clay Formation in the adjacent source area to the SW (63-52 Ma). Hence, the most rapid burial with its associated overpressure, and the main phase of hydrocarbon generation from kinetic modelling are independent in time from the diagenesis and hydrocarbon migration into the Northwest Hutton structure. In addition near- hydrostatic pressures are modelled between 49- 33 Ma, similar to the fluid inclusion trapping pressures derived independently from the fluid inclusions.

A l w y n Nor th , N o r t h e r n N o r t h Sea

The Alwyn field comprises several separate structures containing a mixture of oil and gas- condensate accumulations. The Brent sandstone is the main reservoir but reserves are also found in the deeper Statfjord sandstone (Jourdan et al., 1987; Johnson & Eyssautier, 1987). The field is located at the southern extent of the East Shetland Basin, and immediately west of the Viking Graben axis. The diagenesis of the Brent reservoir sandstones is similar to other Brent fields, being characterized by authigenic quartz, kaolinite and illite precipitation associated with feldspar dissolution as the main mineral phases recognized (Jourdan et al., 1987). Brine and

petroleum-filled fluid inclusions are found mostly at detrital-authigenic cement boundaries, and rarely within the quartz overgrowths. The K-Ar age data for the Alwyn North field area (Jourdan et al., 1987) date illite and associated quartz diagenesis primarily at 75-65 Ma, although with some ages at 45-35 Ma.

The fluid inclusion results, analysed in the same way as for Northwest Hutton above, show quartz and illite diagenesis during hydrocarbon fill-up occuring at hydrostatic pressures, with tempera- tures at the time of trapping of 90-110~ and at pressures of 20-32 MPa (2800-4600 psi; Fig. 4A). The reference F P T gradient was constructed for hydrostatic pressure and the present-day geother- mal gradient of 33~ from corrected bottom- hole temperatures. The modelled P T conditions from the burial history curve for the reservoir at 70 Ma and 40 Ma (mid-ages of illite dates) fall outside the P T envelope derived from intersec- tion of the fluid inclusion isochores. This suggests that the temperature gradients of the fluids during diagenesis were greater than at the present day, an observation which led Jourdan et al. (1987) to suggest derivation of the fluids from deeper in the basin.

The burial history profile for the Alwyn struc- ture reconstructs the Brent reservoir at a depth of only 1.25 km at 70 Ma, corresponding to a temperature of 5~60~ and hydrostatic pressure of 12.5 MPa. From the point of view of pressure development due to rapid burial (Fig. 4B), the burial history of the Alwyn North area is more complicated than at Northwest Hutton, in that there are several phases of rapid burial during the Tertiary with intervening periods of slower burial (Fig. 4C). Consequently pressure modelling of overpressure based on disequilibrium compaction yields several phases of overpressure. In the field the first occurs between 64-50 Ma, a second period from 36-20 Ma and a final period with rapid pressure build-up from 5 Ma to the present day (Fig. 4B). The pressure modelled at the present day from disequilibrium compaction alone is 7.1 MPa (1030 psi) compared with overpressure measurements from RFT data of 10-13 MPa (1450-1885 psi). The discrepancy could result from a contribution of overpressure from another mechanism (e.g. the volume expan- sion during gas generation in the depocentre), which has not been modelled, or from trans- ference of pressure from deeper in the basin.

Reservoir diagenesis and hydrocarbon migration 469

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FIG. 4(A) Pressure-temperature plot for Alwyn North field. Hydrostatic pressure conditions at the time of entrapment of fluids is indicated by the coincidence of the PTenvelope (shaded) and the FPTgradient. Illite age dates indicate two periods of diagenesis at 75~5 Ma and 45-35 Ma. Mid-age PT conditions for both periods are shown. See text for discussion. (B) Excess pressure-time plot for the Alwyn North field. Three main periods of overpressure are modelled in the field area, each related to rapid burial shown in Fig. 4C. An earlier period of high pressures is modelled in the depocentre. (C) Burial history of the Alwyn North field (base d on well 3/9a-2), and the depocentre located to the east. Note the variable burial rates from 100 Ma to the present day. Illite age dates for diagenesis and hydrocarbon fill-up are coincident with hydrostatic or

small overpressure conditions.

470 R. E. Swarbrick

Pressure modelling of the depocentre shows rapid build-up of pressure between 97.5 Ma and 83 Ma when there was a phase of rapid burial (Fig. 4B). Lithostatic pressure is reached, followed by pressures of 75% lithostatic until slow burial rates from 83 Ma onwards allows dissi- pation of the high pressures and return to hydrostatic pressure in the reservoir, from 75~55 Ma and coincident with the earlier age dates for diagenesis and hydrocarbon fill-up.

The adjacent depocentre from which the fluids are believed to have migrated is located to the east (Jourdan et al . , 1987) where Kimmeridge Clay source rocks are buried to about 6.0~5.5 km and at temperatures at which only gas is stable. Geochemical modelling of this region suggests oil generation between 90-66 Ma followed by gas generation from 50 Ma to the present day (Fig. 4C). Fluids in the Alwyn North accumu- lation include gas condensate in the Statfjord reservoir, closest to the depocentre (Jourdan et

al . , 1987) and evidence for later gas migration from the depocentre into the Alwyn structure.

D I S C U S S I O N

The Northwest Hutton and Alwyn North field studies show a consistent pattern of quartz cementation, accomplished at least in part in the presence of hydrocarbons, probably low hydro- carbon saturations during the early fill-up history of the fields, under conditions of hydrostatic pressure. In each case, the reservoir is overpres- sured at the present day and it is noted that there has been rapid burial which post-dates reservoir diagenesis and could lead to overpressure due to disequilibrium compaction. In both cases there has also been rapid burial prior to diagenesis and the associated influx of hydrocarbons. Pressure modelling shows this earlier rapid burial is also likely to have resulted in overpressure, with maximum pressures in the depocentres. Using the principles of Mann & Mackenzie (1990), the high pressure in the depocentre may be transferred updip where there is a continuous reservoir section, but only if horizontal permeabilities are sufficiently high. This is more likely during earlier phases of rapid burial than in the later events (i.e. within the last 5 Ma and at depths of 5-7 kin) when permeabilities are expected to be much lower.

The timing of oil generation, from kinetic modelling of the Kimmeridge Clay source rocks, in adjacent depocentres to both Northwest Hut- ton and Alwyn North fields is coincident with rapid burial, 90-65 Ma in the Alwyn North area (Fig. 4C) and 63-50 Ma in the Northwest Hutton field (Fig. 3). In Northwest Hutton, oil generation pre-dates diagenesis by at least 10 Ma, i.e. hydrocarbon migration has been delayed. In Alwyn North, the first influx of oil into the reservoir is synchronous with the latter half of the period of oil generation in the depocentre (Fig. 4C). Is it possible that overpressure exerts a fundamental control on fluid flow, such that in some instances fluids migrate only when pressures are near normal, and that periods of overpressure are marked by relatively static subsurface fluids?

As permeability is the prime control on fluid flow and overpressure development, low permea- bility zones will encounter highest amounts of overpressure irrespective of the generating mechanism. A succession dominated by stratified siliciclastic rocks, such as encountered in the Mesozoic and Tertiary rocks of the North Sea, would be expected to have differential pressure build-up between the fine-gr~ned, low permeabi- lity rocks such as shales, and the coarser-grained and higher permeability rocks such as sandstone reservoirs when modest burial rates exceed the ability of the finer grained rocks to dewater. This state is here termed local overpressure (Fig. 5A). However, when rapid burial takes place across a large part of a basin (e.g. Late Cretaceous and Early Tertiary subsidence history of the North Sea; Thorne & Watts, 1989; White & Latin, 1993), overpressure may build up in all rocks, especially where the higher permeability rocks are either encased in mud or confined laterally by low permeability conduits such as faults. This state is termed here regional overpressure (Fig. 5B). Additionally, when periods of slow burial or uplift follow the development of regional overpressure, a transitional phase of local overpressure would be expected.

Periods of regional overpressure, marked by similar amounts of overpressure in an entire succession irrespective of permeability, will be characterized by an absence of internal pressure potential which (from Darcy's equation) is required for subsurface fluid flow. These periods should be characterized by a scarcity of diagenetic alteration, since formation fluids would be essen-

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Reservoir diagenesis and

PRESSURE

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Fro. 5(A) Open system with local overpressure in low permeability strata (mud illustrated) and potential for fluid flow and pressure dissipation through higher permeability strata (sand reservoir/carrier bed illustrated). Over time there is the potential for equilibration at hydrostatic pressure when normal compaction-related flow (Bethke, 1985) will occur. (B) Closed system during rapid burial leading to regional overpressure. No pressure differential between different lithologies, irrespective of permeability, hence no active flow across lithological boundaries at this time, and until pressure can be dissipated when an open system (Fig. 5A) is established, i.e. when burial rate is

slower or ceases.

tially static and the supply of solutes for precipi- tation in reservoirs will be arrested. The availabi- lity of quartz due to pressure solution along grain contacts will also be reduced due to high pore- pressures relieving some of the overburden stress. The fate of migrating hydrocarbons is more difficult to predict under regional overpressure. In circumstances where continued burial and heating generates sufficient local pressure to drive hydrocarbons from the source rock into adjacent carrier beds and buoyancy pressure is enough to maintain migration towards a trap, migration and fill-up are still possible. In the case of the North

hydrocarbon migration 471

Sea, where the primary migration pathway in many areas is stratigraphically down section from the Uppe r Jurassic Kimmeridge Clay into Middle Jurassic Brent sandstone reservoirs and there must be downwards directed pressure which exceeds buoyancy pressure, the relationship between source rock and subjacent reservoir favours a cessation of migration until local overpressured conditions return.

An alternative explanation for the lack of evidence for hydrocarbon migration synchronous with overpressure in these two field areas relates to the control of overpressure on maturat ion of kerogen. Al though the influence of high pressure on reaction kinetics is not well known, experi- mental studies (Enquehard et al., 1990) show that increasing pressure decreases the rate of thermal cracking of larger to smaller hydrocarbon mole- cules. High pressure also retards the carbonation of organic matter , as illustrated by experimental study on conodonts (Epstein et al., 1977).

Northwest Hut ton and Alwyn North have experienced rapid burial, equated to a period of regional overpressure, followed by slower burial rates marked potentially by high throughput of fluids as pressure (and hence excess fluid) in the succession was dissipated first from the strata with high permeabili ty, and later from the lower permeabil i ty strata. A further factor of relevance to the timing of diagenesis following large excess pressure is the changing solubilities of diagenetic minerals such as quartz as pressure fluctuates. High pressures enhance solubility; falling pres- sure reduces solubility and enhances precipi- tation. Hence, the late Cretaceous to early Tertiary history of the North Sea with high pressure followed by lower pressure would be favoured as a t ime during the basin history for diagenesis and the accompanying reduction in reservoir quality.

C O N C L U S I O N S

( l ) Pressure-temperature plots of homoge- nization data from brine and petroleum-filled fluid inclusions in quartz cements from two North Sea fields indicate hydrostatic pressure conditions during entrapment .

(2) Pressure modell ing using a PC-based 1-D model and disequilibrium compaction as the overpressure generating mechanism, also indi-

472

cates hydros ta t ic condi t ions dur ing the per iod of quar tz cementa t ion .

(3) Bo th fields are now overpressured , adequa- tely model led by disequi l ibr ium compac t ion dur ing rapid late Ter t iary burial in the Nor thwes t H u t t o n field, bu t potent ial ly with an addi t ional con t r ibu t ion f rom gas genera t ion or t ransference f rom the adjacent depocen t r e in the case of the Alwyn Nor th field.

(4) Quar t z cemen ta t ion with coeval illitization of the reservoir post -dates phases of rapid burial (late Cre taceous to early Ter t iary) , which was likely to have been m a r k e d by overpressure . These per iods are also the p robab le t iming of ma tu ra t ion of oil f rom local Kimmer idge Clay Forma t ion source rocks.

(5) The coincidence of diagenesis following periods of regional overpressure due to rapid basin-wide subs idence and sed imen ta t ion sug- gests a close l inkage be tween pressure history and fluid flow.

A C K N O W L E D G M E N T S

Data for this study, and on which this paper is based have been kindly provided by Amoco, Mobil, and Total. Stephen Edwards is thanked for discussions and a review of an early draft, and the comments of an anonymous referee are also acknowledged.

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