Correlation of fluid inclusions and reservoired oils to infer trap fill history in the South Viking...

Correlation of fluid inclusions and reservoired oils to infer trap fillhistory in the South Viking Graben, North Sea

G. H. Isaksen1, R. J. Pottorf1 and A. I. Jenssen21Exxon Production Research Co., PO Box 2189, Houston, Texas, 77252, USA (Present address:

Exxon Exploration Company, PO Box 4480, Houston, Texas 77210-4480, USA)2Esso Norge a.s., PO Box 60, N-4033 Forus, Norway

ABSTRACT: Organic geochemical correlations between fluid inclusions and associ-ated oils and oil-shows in Mesozoic reservoirs in the Sleipner area demonstrategeneration from the same source rock organic facies (type II) for inclusions in wells15/9-1 and 15/9-19. For well 15/9-9 the oil show is from a mixed type II/III sourcerock, whereas the fluid inclusion is from a type II source. All fluid inclusions are lessthermally mature than the associated free oils and are thought to represent theearliest hydrocarbon yield from the source rocks. GC/MS/MS analyses of the fluidinclusions proved essential for resolving biomarker compounds and correlating themto reservoired fluids. Among the biomarkers, bisnorhopane contents in the fluidinclusions are consistently lower than in the associated reservoired oil. The expecteddilution effect of bisnorhopane as progressively more hydrocarbons are generatedfrom kerogen maturation is not observed. The difference in bisnorhopane amountsin fluid inclusions and oils is primarily due to varying relative hydrocarbon yields,through time, from different source rocks.

KEYWORDS: Sleipner Vest, Sleipner Øst, gas chomatography, mass spectroscopy, biologicalmarker, bisnorhopane

INTRODUCTION

Fluid inclusions from potential reservoirs or from migrationpathways offer a unique opportunity to correlate inclusionchemical signatures with those of reservoired oil accumulationsand thus achieve a better understanding of the timing of sourcerock charge, effective migration pathways and hydrocarbonentrapment. This study compares the API gravity and biomar-ker character of fluid inclusions and drill-stem test (DST) oilsin the Mesozoic section of the Sleipner Vest and SleipnerØst fields (block 15/9) in the South Viking Graben of theNorwegian North Sea (Fig. 1). Traps in the area can be chargedfrom different directions and from source rocks with differingorganic matter compositions. As such, the chemical characteri-zation of fluid inclusions is key to understanding their relationto the present-day reservoired hydrocarbons, as well as the likelycomposition of any earlier reservoired fluid subsequently lostthrough re-migration or diluted by later hydrocarbon charges.Both GC/MS and GC/MS/MS analyses were carried out in

an effort to evaluate biomarkers in fluid inclusions. QuadrupoleGC/MS data proved difficult to interpret due to interferencefrom many compound classes. For instance, numerous non-sterane compounds in the mixture gave rise to fragment ions ofmass 217 atomic mass units, and as a result, made the m/z 217mass fragmentogram very complex. Consequently, biomarkerparameters commonly used for assessment of source rockorganic matter type and thermal maturity were prone to errordue to co-elution of numerous other compounds. To remedythis problem, GC/MS/MS analysis were performed due to itsgreater specificity and selectivity. At Exxon, fluid inclusionbiomarker analyses are routinely performed by GC/MS/MS.

Geological setting

The study area is located in Block 15/9 (Figs 1 and 2),approximately 240 km southwest of Stavanger, near the south-ern end of the South Viking Graben. The area consists of twomajor fields, Sleipner Øst and Sleipner Vest, containinggas-condensate and black oil. Combined estimated reserves forboth Sleipner Vest and Øst are 6.2 TCF gas, 436 MBBLSnatural gas liquids, and 358 MBBLS of oil.The Sleipner Vest field is located on the Sleipner Terrace at

approximately 3500 m below sea-level (Jurassic reservoir),whereas the Sleipner Øst field is located on the Ling High, andcontains some hydrocarbons at a depth of approximately2700 m in Triassic and Jurassic reservoirs. At Sleipner Øst theprinciple reservoir is the Palaeocene Heimdal Formation atapproximately 2500 m below sea-level; these hydrocarbonshave not been studied here.There are three main plays in the immediate area, as

illustrated on the schematic east–west geological cross-sectionof the South Viking Graben (Fig. 1). The lower Tertiary playconsists of fan sandstones charged by vertical spillage fromJurassic and Triassic traps along faults and flexures (Østvedt1987). The middle Eocene shales act as regional seals. The mainplays on the Norwegian side of the South Viking Graben arewithin the Middle Jurassic shallow marine sands of the HuginFormation. Within the UK sector, the Upper Jurassic Braesubmarine fan play is most important. Top seal for theMesozoic reservoirs are Upper Jurassic to Lower Cretaceousshales. The hydrocarbon source rocks are the Upper Jurassicoil-prone shales of the Draupne (Kimmeridge Clay) andHeather Formations and the gas-condensate prone shales andcoals of the Middle Jurassic Hugin and Sleipner Formations.

Petroleum Geoscience, Vol. 4 1998, pp. 41–55 1354-0793/98/$10.00 ?1998 EAGE/Geological Society, London

Fig. 1. Location map of the South Viking Graben in the North Sea and schematic west–east geological cross-section of the graben fromthe East Shetland Platform–Fladen Ground Spur at UK Block 16/12 to the Sleipner Terraces and southernmost extension of the UtsiraHigh at Block 15/9 in the Norwegian sector.

Fig. 2. Fields, well locations and blockboundaries in the Greater Sleipner area ofQuadrant 15 in the Norwegian sector of theSouth Viking Graben. Samples studied herein arefrom the middle Jurassic reservoirs of the 15/9-1and 15/9-19s wells, and the Triassic reservoirwithin 15/9-9.

42 G. H. Isaksen et al.

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Fig.3.Well-logresponses,coredintervalsandfluid-inclusionsamplinglocationsforthemiddleJurassicsectionofWell15/9-1.EstimatedAPI

gravitiesofthefluidintheinclusionsarealsogiven.MD=measureddepthinmetres.

Trap fill history in the South Viking Graben 43

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Fig.5.Well-logresponses,coredintervalsandfluid-inclusionsamplinglocationsfortheTriassicsectionofWell15/9-9.EstimatedAPIgravities

ofthefluidintheinclusionsarealsogiven.


Further details on the tectonic history, stratigraphy andhydrocarbon system are documented in Østvedt (1987),Ranaweera (1987), Patience et al. (1995), and Isaksen et al.(1997).

ANALYTICAL METHODOLOGY

Doubly polished sections about 50 µm thick were examinedpetrographically under ultraviolet (UV) light to identifyhydrocarbon-bearing fluid inclusions. Microthermometry wascarried out on fluid inclusion assemblages to determine homog-enization temperatures (Goldstein & Reynolds 1994) and APIgravity of the inclusions was inferred from their fluorescenceproperties. Inclusion oils were excited by 365 nm UV light andemission spectra were collected from 420–720 nm. Thirteenreservoired oil samples from the Norwegian North Sea withmeasured API gravities were similarly analysed and used as acalibration for the inclusion oils. Calibration of the Norwegianoils compares favourably to calibration data sets acquired inother parts of the world, with expected precision of about &4API units between the range of 20–40 API. It is assumed thatoils within inclusions can be determined with similar precisionusing the same fluorescence technique.GC/MS/MS analyses were made on a VG ProSpec Q

operating in a selected ion recording mode (SIR voltage) andmultiple reaction monitoring-quadrupole mode (MRMQ). Gas

chromatography was performed on a Carlo Erba 8000 GCfitted with a 30 m DB-5 column, 0.25 mm ID and 0.25 µm filmthickness. The GC temperature rate was 75–200)C at 5)C perminute and 200–315)C at 3)C per minute and held at 315)C for20 min. The injector temperature was 310)C. Resolution wasset at 1000 for both SIR-V and MRMQ. Direct GC analyses ofthe fluid inclusions were not performed due to insufficientsample material. One of the problems in the analysis of fluidinclusions is to ensure that all other petroleum-like material isremoved before the fluid inclusions are opened and theircontents analysed. Rock samples with identified fluid inclusionswere disaggregated in a chamber by repeated freezing andthawing. Individual grains were then washed several timesunder methylene chloride until the wash was clean (devoid ofany hydrocarbons) as per GC/MS/MS SIRV analyses. Thesamples were then crushed and extracted using methylenechloride. Aliquots of this solution were injected onto theGC/MS/MS.

RESULTS AND DISCUSSION

Liquid hydrocarbon inclusions were observed petrographicallyin approximately half of 27 wells investigated in a larger,unpublished, study. The wells that presently contain gas-condensate rarely contain hydrocarbon inclusions, exceptwhere oil shows or oil legs are locally present. This behaviour

Table 1. Geochemical data for DSTs and oil show

Well 15/9-1 15/9-19s 15/9-9Sample depth (m) 3630–3635 4316–4338 2649.7Formation Hugin Hugin SkagerrakSample type DST 1 DST 1 Core ExtractPristane/phytane 1.36 0.65 1.52Pr/n-C17 0.58 0.55 1.11Ph/n-C18 0.47 1.1 0.47nC17/(nC17–nC27) 0.54 0.82 0.29Saturates (%) 44 30 44Aromatics (%) 42 57 6Polars (%) 10 10 10Asphaltenes (%) 3 3 41

Table 2. Comparison of fluid inclusion GC/MS/MS data and oil (DST and show) data

Wellsample

15/9-1fluid incl.

15/9-9fluid incl.

15/9-19fluid incl.

15/9-1DST 1

15/9-9oil show

15/9-19sDST 1

C29/C30 0·68 1·00 0·78 0·40 0·69 0·40%NH 40·4 50·0 43·9 28·7 41·0 28·6Ts/Tm 1·68 1·55 1·37 0·80 0·32 0·50%BNH 4·1 4·9 3·4 20·9 23·4 36·4%C32 22S 62·1 65·1 63·1 59·3 59·1 60·0%C27 33·3 36·4 36·9 31·3 31·6 31·3%C28 23·3 28·6 18·4 25·4 25·9 24·4%C29 38·1 28·6 36·9 30·6 36·8 30·7%C30 5·2 6·4 7·9 12·7 5·7 13·6C27/C29 0·88 1·27 1·00 1·02 0·86 1·02%C29 20S 31·1 28·5 40·2 52·9 53·3 53·5C34/C35 1·69 2·36 1·16 1·06 1·33 0·92%TNH 32·4 42·9 41·0 21·3 27·3 19·5% Ro 0·5–0·55 0·55 0·55 0·75–0·8 0·75–0·8 0·75–0·8

C29/C30 – norhopane/hopane; %NH – norhopane/(norhopane+hopane); %BNH – bisnorhopane/(bisnorhopane+hopane);%C32 22S – 22S/(22S+22R homohopane); %C27, %C28, %C29, %C30 – steranes distributions; C27/C29 – áââ steranes; %C29 20S– 20S/(20S+20R) ááá steranes; C34/C35 – homohopanes; %TNH – Ts+Tm/(Ts+Tm+hopane); % Ro – vitrinite reflectance.


suggests that wettability is an important factor in controllingwhether or not hydrocarbon inclusions are trapped. At reser-voir conditions, ‘gas-condensates’ exist in a gaseous state andare rarely the wetting phase, whereas oils may show mixedwettability and a greater propensity to be trapped as inclusions.Of the wells that contain hydrocarbon inclusions, we have

selected three to demonstrate (a) the application of GC/MS/MS technology for characterization of fluid inclusions, and(b) the utility of such correlations as an element in understand-ing the hydrocarbon fill history of reservoirs. These wells are15/9-1 in the northeastern part of the Sleipner Vest field,15/9-19s north of Sleipner Øst and 15/9-9 within Sleipner Øst(Fig. 2). In addition to providing a good geographical distribu-tion, the gas-condensates in these fields represent three differ-ent hydrocarbon families (Patience et al. 1995; Isaksen et al.1997). Figures 3, 4, and 5 show the sampling points for the fluidinclusions within cored intervals, the number of inclusionsmeasured for fluorescence analysis, lithology and wireline logresponses. Hydrocarbon correlations by GC/MS and GC/MS/MS were made between these inclusions and DST samples(15/9-1 and 15/9-19s) and an oil show (15/9-9).Selected biomarker parameters from GC/MS and GC/

MS/MS analyses are listed in Tables 1 and 2, and will bediscussed individually by well.

Well 15/9-1

The gas-condensate in the Hugin reservoir is associated with anoil-leg with black oil at an API gravity of 24.3). GC/MSanalyses of the DST 1 oil collected within this oil-leg (near3650 m; Fig. 3) show a sterane and triterpane distribution(Fig. 6) characteristic of oils generated from the Kimmeridgian–Volgian age Draupne Formation. The C34/C35 hopane ratio isrelatively low (1.06) indicating reducing conditions for thesource rock depositional environment (Peters & Moldowan1991). Another redox parameter, the pristane/phytane ratio, isrelatively high (1.36) due to mixing of gasoline-range hydro-carbons generated from several source rocks (Draupne,Heather, Hugin and Sleipner Formations) with marine algal andterrigenous higher plant kerogen (Patience et al. 1995; Isaksenet al. 1997). Bisnorhopane values of 20.8 % (relative to C30Hopane) are also in agreement with generation from theDraupne Formation (Grantham et al. 1980; see later discussion).However, the specificity of bisnorhopane in this area is low asit occurs in all source rock formations (Draupne, Heather,Hugin and Sleipner Formations). Sterane distributions (Table 2)show near equal amounts of C27 and C29 des-methyl steranes,with appreciable amounts (up to 15% of steranes for DST1 at15/9-19s) of C30 des-methyl steranes indicative of generationfrom a marine algal source rock (Fig. 7). Thermal maturityestimates suggest a normal-mature oil at a maturity levelcorresponding to an equivalent vitrinite reflectance value of0.75–0.85% Ro. This is based on the %C29 ááá 20S and %C29áââ sterane parameters. Figure 8 shows the comparison ofrelative maturities for the samples analysed.GC/MS/MS data for fluid inclusions collected from 3659 m,

in the oil-leg in the 15/9-1 well, are shown in Fig. 9

Fig. 6. GC/MS quadrupole data for DST 1 in Well 15/9-1,monitoring common fragment ions (a) m/z 217 for steranes, (b)m/z 191 for hopanes, and (c) m/z 191 for the fluid inclusionsfrom 3659 m measured depth. Non-hopanoid fragment ions withmass of 191 atomic mass units are also represented in the fluidinclusion GC/MS data because no pre-separation of compoundclasses were made. Peak identification: 5=C27 13â(H),21á(H) 20Sdiacholestane; 6=C27 13â(H),21á(H) 20R diacholestane; 14=C275á(H),14â(H),17â(H) 20R cholestane; 15=C27 5á(H),14â(H),17â(H) 20S cholestane; 22=C28 5á(H),14â(H),17â(H) 20R ergostane;23=C28 5á(H),14â(H),17â(H) 20S ergostane; 28=C29 5á(H),14â(H),17â(H) 20R stigmastane; 29=C29 5á(H),14â(H), 17â(H) 20S stig-mastane; 64=C27 18á(H)-22,29,30- trisnorneohopane (Ts); 66=C2717á(H)-22,29,30-trisnorhopane (Tm); 69=C28 17á(H),21â(H)-28,30-bisnorhopane; 73=C29 17á(H),21â(H)-30-norhopane; 78=C3017á(H),21â(H)-hopane; 80=C31 17á(H),21â(H)-homohopane 22S;81=C31 17á(H),21â(H)-homohopane 22R.

Fig. 7. Des-methyl sterane distributions among DSTs, oils shows,and fluid inclusions. The four bars represent, from left to right,the C27, C28, C29 and C30 steranes.

Fig. 8. Relative thermal maturities of DST oils, oil shows and fluidinclusions as represented by sterane maturity parameters. %C29 ááá20S: 100[C29 5á(H),14á(H),17á(H) 20S/(C29 5á(H),14á(H),17á(H)20S+20R)]; %C29 áââ: 100[C29 5á(H),14â(H),17â(H) 20S+20R/(C29 5á(H),14â(H),17â(H) 20S+20R+C29 5á(H),14á(H),17á(H)20S+20R)]. LOM – level of organic maturity.


Fig.9.GC/M

S/MSanalysesofthefluidinclusionsfrom

3659minWell15/9-1.Parent-to-daughtertransitionsareshownforsteranes(top

row)havingdaughterionswith

m/z217and

hopanes(bottomrow)havingdaughterionsofm/z191.TheC27throughC30compoundsareshownforbothsteranesandhopanes.


and selected biomarker parameters listed in Table 2. Thebiomarkers differ from those of the DST-1 oil primarily withrespect to thermal maturity, but also in terms of the organicmatter within the source rock. The effects of compositionalfractionation during formation of the inclusions have also been

considered (see later discussion). Organic facies parameters,such as the sterane C27/C29 ratio (0.88), suggest derivationpredominantly from a marine algal source rock with secondaryamounts of herbaceous/woody organic matter. These resultsindicate hydrocarbon charge from both the Draupne andHeather Formations. The thermal maturity of the fluidinclusion suggest equivalent vitrinite reflectance values of0.5–0.55% Ro. This thermal maturity assessment is based on a%C29 ááá 20S sterane value of 31%; the %C32 áâ hopane 22Sparameter has reached equilibrium at 62%. We interpretthese low maturities to correspond to the initial generationpulse of oil from the source rock, and differs significantly fromthe higher maturity oil presently reservoired at this location(Fig. 8).

Well 15/9-19s

The black oil (API 30)) encountered in DST 1 in this well isunique in the Greater Sleipner area. It has a high sulphurcontent (2 wt%) and biomarkers typical of generation from ananoxic, marine algal source facies. This uniqueness is exempli-fied by a pristane/phytane value of 0.65, C27/C29 des-methylsteranes ratio of 1.02, a high C30 des-methyl sterane content(13.6%) and a low C34/C35 homohopane ratio (0.92) (Table 2).It also contains the highest content of bisnorhopane (36%relative to C30 hopane) (Fig. 10) among the samples analysed(Table 2; Fig. 11). Thermal maturity estimates from steraneand triterpane biomarkers (Table 2) give equivalent vitrinitereflectance values of 0.75–0.85% Ro, corresponding to normaloil-window maturities for this organic matter type. The lowC34/C35 homo-hopane ratio (1.09) supports generation from asource rock deposited in a highly anoxic environment. Figure12 provides a comparison among the samples analysed of therelative ‘anoxicity’ of the source rock. The 15/9-19s oil isthought to have been generated from a separate sub-basinlocated between the Sleipner Vest and Sleipner Øst fields in thenorthern part of block 15/9 (Isaksen et al. 1997). During thelate-Jurassic, this sub-basin is thought to have been ratherisolated with the development of an anoxic sediment-waterinterface and accumulation of marine algal organic matter.Although not penetrated by drilling, the source lithologiesmay show calcareous enrichment with a limited amount ofiron available to bind sulphur inorganically, resulting inincorporation of sulphur into the kerogen. Thus, we infer,based on oil chemistry, that this sub-basin may have a type II-Ssource rock.The sterane compounds within the fluid inclusions (Fig. 13)

show good agreement with the corresponding steranes in theDST 1 oil (Table 2), whereas significant differences can be seen

Fig. 10. GC/MS quadrupole data for DST 1 in Well 15/9-19s,monitoring common fragment ions m/z 217 for steranes and m/z191 for hopanes (top two traces) and m/z 191 for the fluidinclusions from 4340.25 m measured depth (bottom trace).Non-hopanoid fragment ions with mass of 191 atomic mass unitsare also represented in the fluid inclusion GC/MS data because nopre-separation of compound classes were made. Peak identificationas listed for Fig. 6.

Fig. 11. Bisnorhopane contents in DST oils, oil shows and fluidinclusions. The bisnorhopane content is measured relative to C30áâ hopane as 100*[C28 17á(H),21â(H)-28,30-bisnorhopane/([C2817á(H),21â(H)-28,30-bisnorhopane+C30 17á(H),21â(H)-hopane)].Bisnorhopane contents are consistently lower in the fluidinclusions.

Fig. 12. Estimates of ‘relative anoxia’ of the oil-producing sourcerocks by measurement of the C35 and C34 homohopanes. C35homohopanes tend to be enriched relative to C34 in anoxicenvironments due to direct reduction of the four bound sites onthe side-chain of the precursor bacteriohopanetetrol.


Fig.13.GC/M


Well15/9-19s.Parent-to-daughtertransitionsareshownforsteranes(top


m/z217

andhopanes(bottomrow)havingdaughterionsofm/z191.TheC27throughC30compoundsareshownforbothsteranesandhopanes.


among the triterpanes (see later discussion). C27 and C29des-methyl steranes are present in equal amounts (Fig. 7),whereas C30 des-methyl steranes are at 7.9% (relative to C30hopane), which is the highest concentration of any of thefluid inclusions. An estimation of anoxia from the C34/C35homohopane index shows a value of 1.16 (Table 2; Fig. 12)in-line with generation from a type II-S source rock in thenearby sub-basin. Thermal maturity data from des-methylsteranes and triterpanes (Table 2) give an equivalent vitrinitereflectance value of 0.55% Ro, corresponding to an early matureoil-expulsion phase, even for a type II-S source rock.

Well 15/9-9

The oil show in this well was obtained from a cored section at2649.7 m within the gas-filled Skagerrak Fm. (Triassic) reser-voir. It belongs to an oil family separate from the two otherDSTs analysed herein (Patience et al. 1995; Isaksen et al. 1997)and is characterized by generation from mixed type II/IIIsource rock(s). This source type is evidenced by a pristane/phytane value of 1.52 and predominance of C29 versus C27des-methyl steranes (Tables 1 and 2). The C34/C35 triterpaneratio is the highest among the three oil samples (Table 2),suggesting derivation from source rocks with a more dysoxicenvironment than that of the source for the 15/9-19s oil. Thethermal maturity of the oil show is in the same range as for thetwo DST’s described earlier (Fig. 8). Mass fragmentograms areshown in Fig. 14.Sterane and triterpane biomarkers (GC/MS/MS analyses) in

the fluid inclusions (Fig. 15) show higher relative contents ofC27 des-methyl steranes, with a C27/C29 sterane ratio of 0.86(Table 2; Fig. 7). Also, the C34/C35 ratio is 2.36; the highestvalue encountered herein. The steranes suggest derivation froma source rock facies with a higher content of algal material thanthat having generated the oil in the show at 2649.7 m. Thermalmaturities estimated from sterane biomarkers (Table 2) are

equivalent to 0.55% vitrinite reflectance, i.e. an early matureproduct from a type II, marine algal source rock.The more pronounced type II source signature in the 15/9-9

fluid inclusion can be explained by competing hydrocarboncharges, a common feature in the Greater Sleipner area(Ranaweera 1987; Patience et al. 1995; Isaksen et al. 1997). Thefluid inclusions (at 2747.9 m) may represent the initial charge ofoil from the southernmost extension of the north–southoriented sub-basin between Sleipner Vest and Sleipner Øst. Theoil show at 2649.7 m could be the product of mixing betweenthe black oil generated from the sub-basin between SleipnerVest and Øst and hydrocarbons charged from the mainSleipner source kitchen in the deeper South Viking Graben tothe west of block 15/9.

Hydrocarbon yield history and timing of fluid inclusionformationThe source rocks in this part of the South Viking Graben arethe paralic coals and shales of the Middle-Jurassic Hugin andSleipner Formations (terrigenous higher plant organic matter)and the Late Jurassic marine shales of the Heather andDraupne Formations (marine, algal organic matter). Com-pared to the Draupne shales, the Heather shales accumulatedin more oxic depositional environments and have lowerorganic carbon contents. Burial and hydrocarbon yield history(80 Ma to present) for the Heather and Draupne Formationsis shown in Fig. 16. One-dimensional basin modeling suggeststhat Heather and Draupne shales in the main graben startedgenerating hydrocarbons near 75–55 and 55–50 Ma, respect-ively. Given the basin’s structural configuration (Fig. 1),source rocks are present in the main graben as well as onthe many terraces stepping up to the Sleipner Field area(Block 15/9). Consequently, these source rocks will reachtemperatures for oil generation at very different geologicaltimes. Concurrently, gas-condensate was generated from theHugin and Sleipner coals and shales, as well as the mostmature sections of the Heather and Draupne shales. Thisgeological control is important, as the source rocks in thedrainage area for the Sleipner fields have yielded both oil andgas from about 60 Ma (late Paleocene to early Eocene) topresent day.To estimate the time at which the hydrocarbons in the

inclusions were trapped within cements, burial history analyseswere combined with estimates of pressure, volume, and tem-perature (PVT) properties of the hydrocarbons in the inclu-sions. More detailed information on the use of these techniquescan be found in Goldstein & Reynolds (1994). At the 15/9-1well location (closest to the source kitchen) temperatures of>80)C were reached at approximately 50 Ma, during theEocene. This marks a reasonable estimate for the earliest timefor quartz overgrowth and formation of fluid inclusions.Measured homogenization temperatures range from 116–130)Cfor samples from Well 15/9-1 (Fig. 3), 95–110)C for Well15/9-9 (Fig. 5), and 90–102)C for Well 15/9-19s (Fig. 4). A plotof the 15/9-1 reservoir temperatures against burial history (Fig.16) suggests that the hydrocarbons in the inclusions weretrapped during the last 5 million years. This implies a ratherlong duration between the earliest possible oil charge to thereservoir and our inferred timing of fluid inclusion formation;55 Ma in the extreme case. Biomarker data (see below) suggestthat this initial oil charge (estimated API gravity of 22–33))came primarily from a source rock facies with greatest affinityto the Heather Formation. This early mature oil trapped in theHugin reservoir was likely displaced by the later-arriving gas-condensate, although some oil stains remained as adsorbed oil

Fig. 14. GC/MS quadrupole data for the oil show from 2649.7 min Well 15/9-9, monitoring common fragment ions m/z 217 andm/z 218 for steranes (top two traces) and m/z 191 for hopanes(bottom trace). Non-hopanoid fragment ions with mass at or near191 atomic mass units are also represented in the fluid inclusionGC/MS data (e.g. methyl-phenathrenes) because no pre-separationof compound classes were made. Peak identification as listed forFig. 6.


Fig.15.GC/M


2747.9minWell15/9-9.Parent-to-daughtertransitionsareshownforsteranes(top


m/z

217andhopanes(bottomrow)havingdaughterionsofm/z191.TheC27throughC30compoundsareshownforbothsteranesandhopanes.


on mineral grains and in micro-fractures within individualquartz grains and subsequently trapped as fluid inclusions. Thegas-condensate was primarily generated from the coaly sourcerocks of the Hugin and Sleipner Formations and secondarilyfrom the most mature sections of the Heather and DraupneFormations. Black oil and volatile oil was generated concur-rently from the less mature sections of the Draupne Fm.During the long residence time in the reservoir (prior toformation of inclusions) we believe that the oil avoidedbacterial degradation as temperatures were greater than 80–90)C.

Correlation to source rocks

As the graben continued its subsidence during the Neogene, agreater proportion of the hydrocarbon charge naturally camefrom the Draupne Fm. shales. This is supported by (a) apredominance of C27 steranes derived from marine, algalorganic matter, and (b) higher contents of homo-hopanes in thereservoired oils as compared to the fluid inclusions (Figs 6, 10and 14). Homo-hopanes are believed to be derived from the

C35 bacteriohopanetetrol compound common in procaryotes(Ourisson et al. 1979). The homo-hopanes are typically moreprevalent in marine, algal kerogens as compared with woody-coaly kerogens (Isaksen 1995). The distribution of C31–C35homo-hopanes, and notably elevated C35/C34 ratios, is com-monly associated with reducing conditions (low Eh) duringaccumulation of organic matter, and a calcareous shale facies ofthe Draupne Fm. The DST oils (15/9-1 and 15/9-19s) and oilshow (15/9-9) have lower C34/C35 homohopane ratios than thefluid inclusions found in these reservoirs (Table 2; Fig. 12).Thus, although primary productivity from marine algal organicmatter appears to have been similar during deposition ofHeather Fm. and Draupne Fm. shales, the hopanes pointto differences in redox conditions between the two sourcerocks.Furthermore, bisnorhopane contents are consistently lower

in the fluid inclusions as compared with the reservoired oils/oilshow (Fig. 11). Although the exact origin of bisnorhopane isuncertain (Waples & Machihara 1991), it appears not to begenerated from kerogen but rather derived from free bitumenin the source rock (Moldowan et al. 1984, Noble et al. 1985). Intheir study of a core through the Kimmeridge Clay and Heather

Fig. 16. Representation of temperature,hydrocarbon yield, and quartzovergrowth diagenesis, throughgeological time, within the Huginreservoir sands in Well 15/9-1. Thehydrocarbon yield curves represent theearliest yield from Draupne andHeather shales in the deepest part ofthe drainage polygon. Yield from thesesource rock facies has continued up topresent-day as more and more of theSleipner Terrace entered the oil-window(see structural geology in Fig. 1).Measured homogenization temperaturesrange from 116 to 130)C which, alongwith PVT analyses, suggest that fluidinclusions were formed during the last5 Ma.

Fig. 17. Comparison of %bisnorhopane (black bars) and %trisnorhopane (white bars) in fluidinclusions, DST oils, and oil shows.Trisnorhopane contents (calculated asTs+Tm/[Ts+Tm+C30 hopane]) areconsistently higher in the fluidinclusions as compared with thecorresponding DST or oil show.Bisnorhopane contents are calculated asbisnorhopane/(bisnorhopane+C30hopane).


formations in Well 210/25-3 in the Tern Field (UK), Granthamet al. (1980, p. 34) showed high bisnorhopane contents (38–51 ppm) within high-sulphur, anoxic facies and low values (lessthan 1 ppm) within more oxic facies. Although not identified assuch in the paper, the samples from the anoxic and oxic faciesare from the Kimmeridge Clay and the Heather Formation,respectively. Conversely, Huc et al. (1985) observed bisnorho-pane to be near absent in the ‘hot’-gamma-ray Draupne shalesand a major compound in Heather Fm samples taken about100 m deeper. Figure 8 shows the relative maturity ranges ofthe six samples discussed herein. If any free bisnorhopane werediluted by hydrocarbons generated from kerogen maturation,one would expect the percentage of bisnorhopane (relative tohopane) to decrease with increasing maturity. These samplesshow the opposite. The least mature oil trapped as fluid inclu-sions displays the lowest relative concentrations of bisnorho-pane; consistently less than 5% (measured as bisnorhopane/[bisnorhopane+C30 hopane]).Differences are also observed among the trisnorhopanes in

the DST, oil show, and fluid inclusion samples. Both trisnorho-pane contents (measured as Ts+Tm/[Ts+Tm+C30 hopane])(Table 2 and Fig. 17), as well as Ts/Tm ratios (Table 2), areconsistently higher in the fluid inclusions as compared to thecorresponding DST or oil show. The Ts/Tm ratio typicallyincreases with increasing thermal maturity, as shown both byfield observations (Seifert & Moldowan 1978) and molecularmechanics calculations (Kolaczkowska et al. 1990). The Ts/Tmratio is also known to vary according to organic facies(Moldowan et al. 1986), and has been shown to be especiallylow in carbonate source rocks (McKirdy et al. 1983; Rullkötteret al. 1985). The Draupne Fm. siliciclastic shales do grade intocalcareous shales, especially during periods of maximum trans-gression and low siliciclastic input to the graben.The details of the formation of fluid inclusions are not well

known, epecially as they relate to potential fractionation effectsbetween the bulk oil composition and encapsulated hydrocar-bons. From theoretical considerations, one could expect thatthe more polar compounds within petroleum would adheremore strongly to mineral grains and thus be preferrentiallyconcentrated within inclusions. It is well established thatearly–mature oils are the most polar, with the concentration ofpolar compounds decreasing with increasing thermal maturity(Hunt 1979; Tissot & Welte 1984). We do not consider theprocess of polarity-induced fractionation to have played asignificant role for the regular steranes and triterpanes (bothcompound classes are non-polar). Thus, we attribute theobserved differences between the steranes and triterpanes in theinclusions and the reservoired hydrocarbons to varying hydro-carbon yields, through time, from different source rocks. Ourdata suggests that the hydrocarbons trapped as fluid inclusionsare derived primarily from a source facies akin to the HeatherFormation and that the reservoired (DST) oils and oil showhave a much higher contribution from the Draupne-type sourcerock. When placed in the proper geological context, thesedifferences can be understood in terms of the relative timing ofyields from the different source rocks and the timing ofinclusion formation.

CONCLUSIONS

Conventional GC/MS quadrupole analyses of rock extracts oroils is typically preceded by liquid chromatography providingsub-fractions of the compound classes in question. With fluidinclusion analyses such work-up procedures are at present notpractical due to the nature of the sample and the small amountsavailable. The greater specificity and selectivity of the GC/

MS/MS technique makes it the preferred analytical procedurefor chemical characterization of fluid inclusions. This study hasdemonstrated the value of detailed correlations between fluidinclusions, reservoired oils and oil shows. Migration of an earlyoil-phase has been identified, together with correlation to thelikely source rock type and the thermal maturity of the variousoil phases. The fluid inclusions are thought to represent theearliest phase of hydrocarbon expulsion, secondary migrationand entrapment; primarily from the Heather Fm. shales, withmore contribution from the Draupne Fm. for the fluid inclu-sions in 15/9-9. DST samples from 15/9-1 and 15/9-19s andthe oil show from 15/9-9 are more mature, representing themain stage of oil expulsion. Their biomarker signatures suggesta significant input from the Draupne Fm. shales. As such, thesefindings help assessments of the timing of trap fill as well as thecomposition of hydrocarbon fluids charging a trap throughtime. Indeed, when considering all reservoired hydrocarbons,we believe that there has been a significant change in hydro-carbon fluid types in Sleipner Vest and Øst during the past5 Ma. Greater volumes of black oil shown, in part, by oil stainswithin present-day gas columns, have been gradually displacedby gas and natural gas liquids.

We would like to thank Esso Norge a.s. and the Sleipner licencepartners (Statoil [operator], Norsk Hydro, Elf Petroleum Norgea.s., and Total Norge a.s.) for permission to release these data.The manuscript was improved by the comments of A. M. Spencer,B. Dahl, and G. van Graas.

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Received 19 February 1996; revised typescript accepted 18 June 1997.


Correlation of fluid inclusions and reservoired oils to infer trap fill history in the South Viking...

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