The Sleipner Effect: a subtle relationship between the distribution of diagenetic clay, reservoir porosity, permeability, and water saturation

Transcription

1 Clay Minerals (2000) 35, 185±200 The Sleipner Effect: a subtle relationship between the distribution of diagenetic clay, reservoir porosity, permeability, and water saturation P. H. NADEAU* Statoil a.s, 4035 Stavanger, Norway (Received 1 December 1998; revised 18 April 1999) ABSTRACT: Petrographic, mineralogical and geochemical core analysis of Palaeocene turbiditic sandstones in the Sleipner East gas-condensate reservoirs show the importance of diagenetic clay distribution on porosity, permeability, and water saturation. An observed `high resistivity zone' (HRZ) corresponds to intervals with low water saturation, a more restricted distribution of diagenetic clay (mainly chlorite), and up to 5% quartz cement. The underlying `low resistivity zone' (LRZ) corresponds to intervals with more widely distributed diagenetic clay, which have lower degrees of quartz cementation, higher porosity, and variably reduced permeability. Crosscutting relationships of the HRZ/LRZ with mapped sedimentary depositional units, as well as fluid inclusion analysis data, suggest that the distribution of diagenetic clay was affected by an earlier (late Miocene?) oil charge, and more extensive chlorite formation in a palaeo-water zone. Recent gas condensate charge and structuring of these sandstones resulted in LRZ reservoirs with substantially higher water saturations than those in the HRZ. KEYWORDS: diagenesis, palaeocene sandstones, clay mineral distribution, quartz cement, hydrocarbon charge, fluid contacts. The Sleipner East Gas Condensate Field was discovered in 1981, and began production in The main reservoirs are m thick Palaeocene high net:gross submarine sands of the Ty Formation (formerly Heimdal Formation), deposited on the western margin and southern termination of the Utsira High, Block 15/9, Norwegian Continental Shelf (Strùmmen et al., 1998; Fig. 1). The field contains an estimated recoverable 48 billion m 3 of gas and 260 million barrels of condensate. The general geology, stratigraphy, and tectonic setting of the Sleipner East area have been presented by Pegrum & Ljones (1984). * pana@statoil.com Previous studies of the Palaeocene sands identified broad resistivity transition zones within the gas condensate reservoir. These are referred to as the `high resistivity zone' (HRZ), and `low resistivity zone' (LRZ). Studies of wells 11, 13 and 16 were conducted which provide a useful petrologic description of the Palaeocene intervals, and the importance of diagenetic clay (chlorite) was recognized. Despite these studies, no satisfactory explanation of the resistivity characteristics of the turbiditic sandstone reservoirs was developed. The presence of soft-sediment deformational water escape features, dish structures, and pipes noted from core description (Hurst & Buller, 1984), were implied to have influenced diagenetic clay distribution and resistivity profiles. The effects of primary sand quality, and variable clay content in part controlled by soft-sediment # 2000 The Mineralogical Society

2 186 P. H. Nadeau FIG. 1. Field and well location map. An example of the gamma ray (GR) and resistivity (RT) log profiles from well 16 shows the enigmatic high resistivity (HRZ) and low resistivity (LRZ) reservoir zones, and problematic recognition of the water zone (WZ), identified by production tests. deformation and water escape, relative to reservoir permeability and resistivity, are readily evident (where the `Dish Structure' model was in part developed). Examination of similar data from other wells showed no such obvious relationship. Broad resistivity reduction over intervals of ~20 m are evident in relatively clean, uniform, sands with good to excellent reservoir properties, as indicated from log measurements (well 16, Fig. 1) and routine core analysis data. It was reasoned that although the effects of primary sand quality variation would always be evident in reservoir quality and saturation profiles, an acceptable explanation of the enigmatic resistivity transition zone noted across the field would have to explain its development in otherwise uniform clean sand intervals at approximately the same structural levels crosscutting the mapped depositional units. Sensitivity calculations indicated that the effect was unlikely to be a `clay conductivity effect' (cf. Waxman & Smits, 1968) given the relatively low clay contents, the high reservoir porosity, and the high formation water conductivity (high salinity). A pilot study noted the presence of highly microporous intergrowths of diagenetic clay, along with subtle changes in diagenetic mineral distributions. The `Sleipner Effect' model was proposed, by which the distribution of diagenetic clay minerals altered sand properties and fluid saturation characteristics of the reservoir, using in part the clay microporosity model of Hurst & Nadeau (1995). This paper advances the `Sleipner Effect' model, and its impact on reservoir properties. MATERIALS AND METHODS Given the limitations of the previous studies, and recognition that very subtle but important diagenetic effects were operative in these sands, an extensive petrologic/petrographic/geochemical data set was acquired to address the variations in reservoir properties. In addition, the special core analysis programme for selected production wells was designed to examine possible clay mineral effects on permeability, capillary behaviour and electrical properties of the reservoir. The scope of the study was increased during the course of data acquisition and field development. Selected Palaeocene samples were also added to a fluid inclusion study conducted by license partner Esso Norge (R. Pottorf, pers. comm.). Two key cored wells were examined in detail. These comprise well D3H, which allows examination of the reservoir in the northern part of the field near the gas condensate/water contact, and well A22 in order to evaluate the reservoir 60 m above the contact

3 The Sleipner Effect 187 near the top of the structure (see Fig. 1 for well locations). Only selected portions of the data set are presented here due to space limitations. RESULTS Primary sandstone quality The Ty sandstones consist of generally uniform fine- to medium-grained moderately well to poorlysorted sub-arkosic arenites. The reservoir sand facies are interpreted as mainly marine mid-fan channelized lobes, deposited by high-density turbidity currents, separated by thin hemipelagic mudstones (Strùmmen et al., 1998). Porosity and permeability values are generally between 20 30% and D, respectively (Fig. 2). Petrographic examinations show only minor changes in average grain size and sorting (Fig. 3) The whole-rock X-ray diffraction (XRD) analyses show a remarkably uniform petrologic assemblage, with minor carbonate cemented intervals occasionally present (Fig. 3). Quartz contents are generally high (~80 wt.%). Overall, average clay contents are low, usually 2 4% and generally very uniform, consisting predominantly of chlorite and muscovite/ illite. Minor amounts of kaolinite are occasionally present. The sporadic occurrence and distribution of kaolinite is suggestive of a detrital component. In this regard, the kaolinite probably represents a variable diagenetic or pedogenic product in the source terrain, transported and redistributed by sedimentological processes, prior to deposition within the massive deep marine turbiditic sands. It is also possible that some kaolinite was consumed in clay-carbonate diagenetic reactions. FIG. 2. Porosity-permeability data from petrologic data set samples. The inferred dominant processes acting in the high resistivity zone (HRZ) are quartz cementation/mechanical compaction, and in the low resistivity zone (LRZ), clay diagenesis.

4 FIG. 3. Well D-3H whole-rock XRD mineralogy in wt.% and petrographic analysis data in vol.%. Note the 3 isolated carbonate cemented samples, and the variable presence of kaolinite. The gas/water contact (GWC) is also indicated. 188 P. H. Nadeau

5 The Sleipner Effect 189 FIG. 4. Scanning electron micrographs from well 15/9-D-3H at m. High magnification micrographs of a critical point dried sandstone sample showing intergrown development of diagenetic chlorite (platy) and illite (fibrous). Note the highly microporous nature of the intergrown clay network. Reservoir quality data show that the HRZ samples tend to cluster on a porosity-permeability diagram (Fig. 2), with a more distinct porositypermeability trend than samples from the LRZ and water zone. Despite the somewhat higher porosities in the LRZ intervals, the permeabilities are highly variable with no clear relationship, and they often show lower permeabilities than HRZ samples. Diagenesis At first approximation, the effects of diagenesis on the sandstones appears mainly confined to mechanical compaction, with minor quartz cementation and clay diagenesis (Fig. 4). Intergranular macroporosity is somewhat higher in HRZ intervals (Fig. 5). When normalized to routine core analysis He porosity data, it represents ~80 100% of these values. Small volumes of quartz cement (1 5%) are evident in the petrographic modal analyses, and are noticeably higher in the HRZ. The LRZ intervals are characterized by higher petrographic clay contents, mainly in the form of microporous dispersed clay, which is responsible for the reduction in effective porosity of these sands. An inverse relationship between quartz cement and dispersed clay is also observed (Figs. 3, 5). Petrographic modal analyses of total clay do not correspond directly with XRD values. This is partly due to clay microporosity and the difference between wt.% (XRD) and vol.% (petrographic) data. It is possible to recalculate the XRD semiquantitative data using mineral density and core porosity data, and compare the two methods (Fig. 6). The results show that the petrographic values are about three times those of the XRD measurements. This comparison allows a rough estimate of the microporous volume associated with the clay, which yields a relatively high average value of 70%. The value generally increases from substantially <70% in the HRZ, to ~70% and higher in the LRZ and water zone (Fig. 6). The highly microporous nature of the dispersed clay is consistent with a diagenetic origin. Petrographic recognition of this clay is difficult, requiring careful examination at high magnification. Some detrital precursor clay material, in the form of dispersed clay, may have also contributed to the diagenetic clay via a recrystallization mechanism. Other reactants which could have provided an internal source for diagenetic clay include unstable volcanic rock-fragments/grains, clay-rich pellets,

6 FIG. 5. Well A-22 whole-rock XRD, clay (<2 mm fraction) mineralogy in wt.%, and petrographic analysis data in vol.%. The location of the contact between the high and low resistivity zones (HRZ/LRZ) is also indicated. 190 P. H. Nadeau

7 The Sleipner Effect 191 FIG. 6. Well D-3H and A-22 whole-rock XRD clay mineral content in vol.% calculated using mineral density and core analysis porosity data vs. petrographic clay content measurements. The plots allow evaluation of the clay microporosity. The dashed line indicates an average microporosity of ~70%. Solid lines for 90% and 0% are also shown. Despite the large variations, a general trend of higher microporosity values from water zone (circles) and LRZ (triangles) samples, vs. lower values from HRZ (diamonds) samples can be observed. kaolinite and Fe/Mg bearing carbonates via claycarbonate reactions (cf. Nadeau, 1998). The diagenetic clay is readily apparent by scanning electron microscopy (SEM). Using critical point dried (CPD) preserved samples (see McHardy & Birnie, 1987, for procedure), the presence of diagenetic chlorite and to a lesser extent delicate diagenetic illite were observed (Fig. 4). The diagenetic clays are best developed and distributed in the water zone (well D-3H), but can be observed at all levels examined. The clay becomes more restricted and confined to thin grain-coatings and clusters towards and into the upper levels of the reservoir. Diagenetic quartz overgrowth cements are more evident in the upper zones, supporting the inverse relationship between quartz cement and dispersed clay noted in the petrographic data. Well A22 was examined to evaluate the reservoir in the southern portion of the field where the Ty sands are >60 m above the water zone. This well cored an interval of relatively uniform sand units, but the influence of primary sedimentological controls are also present locally. Relative to the previous wells, the results show some variations in quartz, feldspar and clay contents, confined mainly to the upper portion of the core (Fig. 5). Reservoir quality data show lower porosity values in the upper interval noted previously for the HRZ. At the top of the LRZ, a 5 7 m interval with some reductions in permeability corresponds to variations in primary sand quality and higher clay contents. A 5 m interval at ~2982 m shows major permeability reductions with only minor variations in sand quality noted in the porosity and XRD data. Petrographic data show increases in clay contents to ~20 vol.%, and corresponding reductions in macroporosity to ~10%. This is an enhanced `Sleipner Effect' feature which further demonstrates the importance of subtle diagenetic clay distribution. Petrographic data also show slightly lower average grain size in the upper portion of the core, and similarities to the D-3H results in that quartz cement is better developed in the upper interval with an inverse relationship with dispersed clay. The 5 m interval noted with substantial reductions in permeability (over two orders of magnitude) and little apparent change in primary sand quality, has widely distributed microporous diagenetic clay. The clay is present throughout the LRZ. Partially dissolved volcanic rock fragments have also been observed in this interval. Despite this observation, no noticeable increase in total rock fragments or secondary porosity (mainly partially dissolved feldspar grains) are observed. Petrographic vol.% data for well A-22 suggest that the clay is 70% microporous. Although difficult to resolve by optical microscopy, analyses of backscattered electron (BSE) images from carbon-coated polished thin-sections clearly show the extensive development of diagenetic clay (Fig. 7). This comparison shows that sands 2 m apart with essentially no differences in porosity (31.6% and 31.7%) or primary sand quality, differ in permeability by more than a factor of 200 (from 9 to 1940 md). Image analysis results (modified after the methods of Nadeau & Hurst, 1991) indicate major reductions of intergranular macroporosity by widely distributed volumes of microporous clay (Fig. 8). Segmentation of the image area into clay and microporosity at high magnification by filtered BSE data processing, yields 28% clay and 72% microporosity, in good agreement with the inde-

8 192 P. H. Nadeau FIG. 7. Back-scattered electron micrographs from well A-22: (a) at m showing turbiditic sandstone with highly micro porous clay (grey intergranular pore-fill), 31.6% porosity, 8.69 md permeability (core analysis data); (b) at m showing similar turbiditic sandstone 2 m below the sample in (a) which lacks pervasive diagenetic clay, with 31.7% porosity and 1940 md permeability (core analysis data). Image analysis data indicate that only ~40% of the total core analysis porosity is `effective' at m (a), vs % at m (b). pendent XRD/petrographic method. This high microporosity value explains how relatively small amounts of clay, generally <5 wt.%, can have such large effects on reservoir permeability and fluid saturation. Unlike the D3H well, only very minor amounts of delicate diagenetic illite are observed in well A22. The diagenetic clays are best developed and widely distributed in the LRZ and water zone. The clay becomes confined to thinner grain coatings and more restricted clusters in the HRZ. Diagenetic quartz overgrowth cements are more evident in the upper levels of the well (Fig. 9), supporting the inverse relationship between quartz cement and dispersed clay noted in the petrographic data. Geochemistry and fluid contacts Determination of the fluid contact level in a gas reservoir with good quality sands is ordinarily a straightforward evaluation of the fluid saturation profile from log measurements (usually resistivity), and the contact would normally be relatively sharp. Because of the complex resistivity characteristic of the Palaeocene Sleipner reservoirs, determination of the contact level has been problematic. Analyses of major and minor elements were performed on well D3H samples by X-ray fluorescence (XRF), neutron activation (NA), and inductively coupled plasma emission spectroscopy (ICP-ES). Well A-22 samples were analysed by XRF and NA. The

9 The Sleipner Effect 193 FIG. 8. High magnification back-scattered electron micrographs from well A-22: (a) at m showing raw data from microporous clay in turbiditic sandstone. Histogram (below) shows poorly defined intensity spectrum; (b) filtered data of the same image. The filtered intensity data allow separation of the clay and microporosity components. The filtered histogram results (below) indicate that microporosity (bottom left) accounts for 72.5% of the total image area.

10 194 P. H. Nadeau FIG. 9. Scanning electron micrographs from well A-22. A sequence (a, b, c) of critical point dried sandstone samples showing extensive development of grain-coating predominantly diagenetic chlorite in the LRZ at m lacking quartz cement. Micrographs (d, e, f), at m from the HRZ show less extensive coatings and more restricted clusters of diagenetic clay, associated with significant development of quartz cement. resulting data were applied to address this issue (see Patience et al., 1995 for additional information). Well D3H bromine (Br) values, determined by NA, showed values of ~5 30 ppm and generally reflect the resistivity character of the reservoir into the water zone, where the samples were collected in the native state (uncleaned). Cleaned samples from well below the contact showed much lower values

11 The Sleipner Effect 195 FIG. 10. Bromine and organic geochemical core analysis data (a, b) across the gas/water contact (GWC), Well D-3H. Note the increase in Br and decrease in organic matter S1 across the contact at ~2506 m. Combined with the core porosity measurements, the data can be used to calculate the apparent water saturation (Swa, c) by assuming that Br content reflects residual salt from formation water with a Br concentration of ~200 ppm (estimated from water zone samples). The Swa data from well A22 (top structure, above the contact) plotted vs. total petrographic clay in vol.% (d). Note that water saturations >0.2 are generally associated with clay contents >7%, and high Swa values of ~0.5 are not uncommon. (~1 ppm, which is the detection limit in many cases). Experience from Statoil's database suggested that the Br values reflect residual salts from evaporated formation water. The data were evaluated further for use as a fluid saturation/ contact indicator (Fig. 10). The core analysis porosity and grain density values were used to calculate the Br water composition in the water zone samples assuming that the Br reflected residue salts from evaporated high salinity formation water at water saturations of 100%. The results indicated a formation water with 200 ppm Br, and are similar

12 196 P. H. Nadeau to a water compositional group in the Gulf Coast which are enriched in Br relative to seawater (Group II of Rittenhouse, 1967). Bromine analyses of water samples are not performed routinely. Special Br analyses of more recently acquired water-zone fluid samples from well A24 gave 205 ppm Br. This agreement with the calculated results gives reasonable confidence to the interpretation that the core analysis Br content is an indication of reservoir water saturation (Swa). Similar calculations for well A22 data (Fig. 10d), where the reservoir is 60 m above the water zone, indicate that Swa values >0.2 are generally associated with >7 vol.% petrographic clay contents, with variable increases to ~ in the LRZ. The Swa data generally agree with special core analysis and conventional resistivity log (Archie derived) water saturations (Fig. 11). The high and low resistivity character of the sands generally reflect the fluid saturation profile of the reservoir. The low permeability zone containing large volumes of microporous diagenetic chlorite clay noted previously (~ m), is also associated with anomalously high water saturation values (~0.6). When integrated with the petrologic/ petrographic results, the data support the conclusion FIG. 11. Well A-22 calculated water saturation (Sw) profile from resistivity log measurements (solid line using log analysis parameters a = 1, m = 1.75, n = 2.1, Rw = at 938C) and special core analysis measurements (crosses), and apparent water saturation, Swa, from Br geochemical data (circles) using the methodology outlined in Fig. 10. Note the relatively good agreement of the three data sets, and the distinct change in resistivity across the HRZ and LRZ contact at 2953 m. Gamma ray curve (GR) is shown at right for comparison.

13 The Sleipner Effect 197 that variation in the distribution of microporous diagenetic clay between the HRZ and LRZ is mainly responsible for the differences in reservoir water saturation. K/Ar age dating of diagenetic clay Isotopic age dating of diagenetic clay from the low permeability interval in well A-22 was undertaken in order to place the sequence of reservoir diagenetic events within an absolute time frame. Using a two-component method modified after Ehrenberg & Nadeau (1989), Pevear (1992), and Nadeau & Eliassen (1996), <1 mm, <0.5 mm, and <0.2 mm clay fractions were separated, analysed by XRD and dated by conventional K/Ar methods in collaboration with Geochron Labs, Cambridge, MA, USA. The results indicate that the diagenetic illitic clay from m formed at Ma, and the detrital illite component of this sample is Ma in age. The model ages place reservoir diagenetic events into the burial and hydrocarbon charge history of the Sleipner area. Fluid inclusion studies/mineral cement paragenesis At Statoil's request, selected HRZ Palaeocene samples including wells D3H and A22 were also added to a fluid inclusion study conducted by license partner Esso Norge (R. Pottorf, pers. comm.). Due to the low levels and unusual distribution of quartz cement in the Palaeocene reservoir, successful sample acquisition relied on petrographic data. The results show that the Palaeocene inclusions are predominantly hydrocarbon bearing with a wide range of API gravities, which are significantly lower than the current 588 API of the reservoir fluid. The temperature of formation of the quartz cement is estimated at C. Diagenetic clay formation must postdate HRZ palaeo-hydrocarbon charge in order to affect the clay distribution, as well as predate the main phase of quartz cementation. Thermal history and K/Ar model results suggest that diagenetic clay formed at ~708C, in the early Miocene (20 Ma), which predates the quartz cement fluid inclusion temperatures of >808C. The formation of diagenetic quartz from Pliocene to the present reflects the trapping time at ~1 5 Ma, but must precede charge by the present-day gas/condensate, suggesting this last event occurred relatively recently. The model also indicates that the presence of hydrocarbons does not prevent the formation of diagenetic quartz cement, in agreement with theoretical calculations and observations (Bjùrkum et al., 1998; Bjùrkum & Nadeau, 1998). DISCUSSION In order to construct the reservoir model relating petrology, petrography and resistivity properties, it is necessary to identify and quantify within a general framework the main diagenetic processes affecting porosity and permeability evolution with depth/temperature. After deposition of the massive turbiditic sands, mechanical compaction proceeded along nominal gradients to depths of ~2 km during the late Miocene, reducing sand porosities to ~30% and elevating reservoir temperatures to ~708C. At or before this time, early hydrocarbon charge of the HRZ probably occurred, after which the main phase of complex diagenetic clay reactions altered rock properties in the hydrocarbon bearing and water zones. These reactions, which involved unstable framework grain dissolution, detrital clay recrystallization, and possibly clay/carbonate reactions, resulted in widely dispersed chlorite and illitic clays as grain coatings and irregular masses, variably and often substantially reducing permeability without reducing porosity. Subtle variations in primary sand composition with regard to reactants are probably responsible for variable diagenetic clay content and composition noted, for example, in well A22 (cf. Nadeau et al., 1997; Ehrenberg et al., 1998). Similar reactions in hydrocarbon zones were restricted, thus limiting distribution of diagenetic clay to incomplete grain coatings and isolated clusters with only minor effects on permeability. The presence of hydrocarbons may have also locally enhanced iron/ reactant solubility and influenced the timing and composition of the diagenetic clay products. Further burial in the late Miocene and Pliocene resulted in continued mechanical compaction followed by the onset of quartz cementation at 808C, which lowered HRZ reservoir porosity to ~25% but only moderately reduced permeability. These porosity reducing processes were inhibited in the water zone by the presence of widely distributed diagenetic chlorite, which reduced the available area of free quartz surfaces for nucleation and growth of diagenetic quartz overgrowth cement (cf. Ehrenberg, 1993; Bjùrkum et al., 1998).

14 198 P. H. Nadeau The relatively good agreement between conventional log analysis with core analysis and the Br method of water saturation determination in well A22 indicate that the presence of formation water is responsible for the resistivity character of the Palaeocene reservoirs. Petrographic observations and image analysis data indicate that the distribution of delicate highly microporous diagenetic clay is responsible for altering the reservoir water saturation characteristics. More recent studies of chlorite-coated sandstone reservoirs have also demonstrated the impact of diagenetic clay formation on water saturation (Nadeau et al., 1999). Given the relationships between petrology, reservoir quality, and fluid saturation properties reported here, it follows that more recent gas/condensate charge of the Sleipner East structure resulted in LRZ reservoirs with higher porosities, more variable and often lower permeability as measured by routine core analysis, and higher water saturations, than the HRZ. The geological model is summarized in Fig. 12. Variations in primary sand composition could solely produce the observed diagenetic relationships, for example via subtle variations in diagenetic precursors/reactants or amounts. The proposed model, which incorporates effects of probable earlier hydrocarbon charge, is preferred because it can explain the HRZ/LRZ crosscutting relationship with respect to mapped depositional units within the marine fan reservoir complex. The model also contributes to further geological evaluations of hydrocarbon prospectivity in the Sleipner Terrace area. CONCLUSIONS Based on the integrated results of this study, the following conclusions and geologic model can be drawn. (1) The Palaeocene Ty (formerly Heimdal) Formation reservoir units are generally petrologically uniform, massive, fine- to medium-grained, moderately-well to poorly-sorted, quartz-rich sandstones with relatively low clay contents. (2) The effects of variable primary sand quality/ composition are locally important. FIG. 12. Diagenetic model for development of the high and low resistivity zones, respectively, Sleipner East Field (see text).

15 The Sleipner Effect 199 (3) The distribution of microporous diagenetic clay minerals, mainly chlorite, is responsible for the unusual resistivity and water saturation reservoir characteristics. (4) The main phase of diagenetic clay formation occurred at a reservoir temperature of ~708C and mechanical compactional porosities of ~30%, during the early Miocene. (5) The high resistivity zone (HRZ) is characterized by more restricted development and distribution of diagenetic clay, and lower water saturation. (6) The low resistivity zone (LRZ) is characterized by more widely distributed diagenetic clay and higher water saturation, which damaged reservoir permeability relative to the HRZ. (7) The distribution of diagenetic clay may have been affected by an earlier (late Miocene?) oil charge with more extensive chlorite formation in the palaeo water zone. (8) Quartz cementation began in the late Miocene±Pliocene at reservoir temperatures of 808C, and is best developed in the HRZ. (9) Widely distributed diagenetic clay inhibited quartz cementation, and possibly further mechanical compaction, in the LRZ. (10) This diagenetically-induced contrast in reservoir properties, referred to as the `Sleipner Effect', is a subtle diagenetic phenomenon and probably more common than has been previously recognized. (11) Characterization of this effect has been facilitated in part by the unusual compositional and textural uniformity of the massive turbiditic Palaeocene sand reservoirs. ACKNOWLEDGMENTS Thanks to O. Malm, S. Strùmmen, R. Patience, C. Halvorsen, J. Lien, S. Hillier, E. Mearns and to W. McHardy for technical contributions and discussions. Thanks also to R. Pottorf for fluid inclusion analysis data; to Sleipner license partners Esso Norge, Norsk Hydro, Elf and Total, and to Den norske stats oljeselskap a.s (Statoil) for permission to publish this work. REFERENCES Bjùrkum P.A. & Nadeau P.H. (1998) Temperature controlled porosity/permeability reduction, fluid migration, and petroleum exploration in sedimentary basins. Austral. Petrol. Prod. Expl. Assoc. J. 38, Bjùrkum P.A., Oelkers E.H., Nadeau P.H., Walderhaug, O. & Murphy W.M. (1998) Porosity prediction in sandstones as a function of time, temperature, depth, stylolite frequency, and hydrocarbon saturation. Am. Assoc. Petrol. Geol. Bull. 82, Ehrenberg S.N. (1993) Preservation of anomalously high porosity in deeply buried sandstones by graincoating chlorite: Examples from the Norwegian Continental Shelf. Am. Assoc. Petrol. Geol. Bull. 77, Ehrenberg S.N. & Nadeau P.H. (1989) Formation of diagenetic illite in sandstones of the Garn Formation, Haltenbanken area, mid-norwegian Continental Shelf. Clay Miner. 24, Ehrenberg S.N., Dalland A., Nadeau P.H., Mearns E.W. & Amundsen, H. (1998) Origin of chlorite enrichment and neodymium isotopic anomalies in Haltenbanken sandstones. Marine Petrol. Geol. 15, Hurst A. & Buller T. (1984) Dish structures in some Paleocene deep-sea sandstones (Norwegian Sector, North Sea): Origin of the dish-forming clays and their effects on reservoir quality: J. Sed. Pet. 54, Hurst A. & Nadeau P.H. (1995) Clay microporosity in reservoir sandstones: An application of quantitative electron microscopy in petrophysical evaluation. Am. Assoc. Petrol. Geol. Bull. 79, McHardy W.J. & Birnie A.C. (1987) Scanning electron microscopy. Pp in: A Handbook of Determinative Methods in Clay Mineralogy (M.J. Wilson, editor). Blackie, Glasgow. Nadeau P.H. (1998) An experimental study of the effects of diagenetic clay minerals in reservoir sands. Clays Clay Miner. 46, Nadeau P.H. & Hurst A. (1991) Application of backscattered SEM to the quantification of clay microporosity in sandstones. J. Sed. Pet. 61, Nadeau P.H. & Eliassen P.E. (1996) Dating of igneous intrusives and burial/thermal history by illite geochronology of clay diagenesis in shales. Am. Assoc. Petrol. Geol. Ann. Conv. Prog. Abstracts, A103. Nadeau P.H., Bjùrkum P.A. & Walderhaug O. (1997) Sedimentologic controls on diagenetic processes in sandstones. Pp in: I Latin Congress on Sedimentology, Vol. 2. Geological Society of Venezuela, Spec. Publ. Caracas. Nadeau P.H., Hillier S., Boe R. & Lieng E. (1999) Chlorite diagenesis in sandstones: Impact on reservoir properties. Conf. Euro. Clay Groups Assoc., Cracow, Program Abstracts, 115. Patience R.L., van Graas G., Knudsen K., Berge E., Flùtre A.B., Gilje A.E., Due A., Skadsem-Eikelmann K. & Nadeau P.H. (1995) Determination of oil-water and gas-water contacts from simple geochemistry methods. Pp in: Organic Geochemistry: Developments and Applications to Energy, Climate,

16 200 P. H. Nadeau Environment and Human History (J.O. Grimalt & C. Dorronsoro, editors). AIGOA Publication, San Sebastian. Pegrum R.M. & Ljones T.E. (1984) 15/9 Gamma Gas Field Offshore Norway, new trap type for North Sea Basin with regional structural implications. Am. Assoc. Petrol. Geol. Bull. 68, Pevear D.R. (1992) Illite age analysis, a new tool for basin thermal history analysis. Pp in: Water Rock Interaction, Proc. 7th Int. Symp. Water- Rock Interaction. (Y.K. Kharaka & A.S. Maest, editors). A.A. Balkema, Rotterdam. Rittenhouse G. (1967) Bromine in oil-field waters and its use in determining possibilities of origin of these waters. Am. Assoc. Petrol. Geol. Bull. 51, Strùmmen S.K., Halvorsen C., Langlais V., Laursen G., Nadeau P.H. & Samuelsen E.T. (1998) Sleipner ést Field, a sand-rich Palaeocene (Ty Formation) gascondensate reservoir offshore Norway: Sedimentology, stratigraphy, heterogeneity and paleocontact influence on reservoir properties, flow and production. EAGE/AAPG Third Research Symposium, Spain, Abstract A014. Waxman M.H. & Smits L.J.M. (1968) Electrical conductivity in oil-bearing shaly sands: Soc. Petrol. Eng. J. 8,