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f1 Source rock contributions to2 the Lower Cretaceous heavy3 oil accumulations in Alberta:4

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AUTHORS

L. A. AQ2Berbesi Organic Geochemistry, Helm-holtz Centre Potsdam, GFZ (GeoForschungs-Zentrum) German Research Centre for Geosci-ences, Potsdam, Germany;berbesi@gfz-potsdam.de

Luiyin Berbesi is a Ph.D. student at GeoFor-schungsZentrum AQ10Potsdam-TU Berlin, workingon petroleum system modeling of Canadianbasins. During his studies at the Central Uni-versity of Venezuela (Licenciatura in Geochem-istry), he focused mainly on evaluation of coal-bed methane potential in western Venezuela.His most recent interests include oil and gasgeochemistry, as well as petroleum systemanalysis through basin modeling.

R. di Primio Organic Geochemistry, Helm-holtz Centre Potsdam, GFZ (GeoForschungs-Zentrum) German Research Centre for Geosci-ences, Potsdam, Germany;dipri@gfz-potsdam.de

Rolando di Primio joined the GeoForschungs-Zentrum Potsdam as a senior research scientistin 2001 after having worked as an explorationgeologist in the Norwegian petroleum industryfor several years. He holds a diploma in geologyfrom the RWTH (Rheinisch-Westflische Tech-nische Hochschule) Aachen, Germany, a Ph.D.from the University of Cologne, and is an adjunctprofessor of petroleum geosciences at JacobsUniversity Bremen. His research interests includehydrocarbon phase behavior, basin modeling,and organic geochemistry.

Z. Anka Organic Geochemistry, HelmholtzCentre Potsdam, GFZ (GeoForschungsZentrum)German Research Centre for Geosciences,Potsdam, Germany; zahie@gfz-potsdam.de

Zahie Anka leads a Helmholtz Young-InvestigatorsGroup at GeoForschungsZentrum. She holdsa geologist degree from Universidad Central deVenezuela (Venezuela), an M.Sc. degree fromJohns Hopkins University (U.S.A.), and a Ph.D.from Montpellier University (France). She hasstudied sedimentary basins for almost 20 yr,including 8 yr in regional studies at PDVSA(Petrleos de Venezuela, S.A.)-Intevep. Her in-terests include basin analysis, seismic inter-pretation, hydrocarbon-plumbing systems, andthermogenic-methane emissions.UAthabasca and Peace River accumulations, followed by minoramounts from Exshaw (15%) and other Devonian to Lower

Copyright 2011. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received May 23, 2011; provisional acceptance July 20, 2011; revised manuscript receivedOctober 14, 2011; final acceptance November 14, 2011.DOI:10.1306/11141111064Ourmodel, based on available data, identifies theGordond

ntrapping controls are dominantly stratigraphic and structural.orrec

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A basin modeling studyL. A. Berbesi, R. di Primio, Z. Anka, B. Horsfield,and D. K. Higley

ABSTRACT

The origin of the immense oil sand deposits in Lower Cre-taceous reservoirs of theWestern Canada sedimentary basin isstill a matter of debate, specifically with respect to the originalin-place volumes and contributing source rocks. In this study,the contributions from the main source rocks were addressedusing a three-dimensional petroleum systemmodel calibratedto well data. A sensitivity analysis of source rock definitionwasperformed in the case of the twomain contributors, which arethe Lower Jurassic Gordondale Member of the Fernie Groupand the Upper Devonianlower Mississippian Exshaw Forma-tion. This sensitivity analysis included variations of assignedtotal organic carbon and hydrogen index for both source in-tervals, and in the case of the Exshaw Formation, variationsof thickness in areas beneath the Rocky Mountains were alsoconsidered. All of the modeled source rocks reached the early ormain oil generation stages by 60 Ma, before the onset of theLaramide orogeny. Reconstructed oil accumulations were ini-tially modest because of limited trapping efficiency. This wasimproved by defining lateral stratigraphic seals within the car-rier system.An additional sealing effect by biodegraded oilmayAAPG Bulletin, v. X, no. X (XXXX 2011), pp. 124 1

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72ited the understanding of the relative proportions of petroleum73contributed by different source rocks.74

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B. Horsfield Organic Geochemistry, Helm-holtz Centre Potsdam, GFZ (GeoForschungs-Zentrum) German Research Centre for Geosci-ences, Potsdam, Germany;horsf@gfz-potsdam.de

Brian Horsfield is a professor of organic geo-chemistry and hydrocarbon systems at theTechnical University of Berlin, Germany, andresearch department director at GeoForschungs-Zentrum German Research Centre for Geosci-ences. He is a member of the German Academyof Science and Technology. He has more than30 yr of experience in petroleum upstreamR&D, beginning with 9 yr at Conoco and AtlanticRichfield.

D. K. Higley U.S. Geological Survey, Den-ver, Colorado; higley@usgs.gov

Debra Higleys 29 yr in geologic research withthe U.S. Geological Survey were preceded by5 yr in uranium exploration. Her research in-terests include reservoir characterization, petro-leum system modeling, and petroleum resourceassessment in basins in North and South Amer-ica. She received her M.S. degree in geochem-istry and Ph.D. in geology from the ColoradoSchool of Mines and her B.S. degree in geologyfrom Mesa State College, Colorado.

ACKNOWLEDGEMENTS

We thank the GFZ (GeoForschungsZentrum)German Research Centre for Geosciences andthe U.S. Geological Survey (USGS) for supportand permission to publish. Z. Anka is the headof the Helmholtz-University Young InvestigatorGroup funded by the Helmholtz AssociationsInitiative and Networking Fund. This article hasbenefited from reviews of Stuart D. Harker, SteveLarter, and Kenneth Peters. Their commentsand suggestions helped improve the quality ofthe final manuscript. Michael D. Lewan (USGS)is also acknowledged for his comments anddiscussions on source rock geochemistry andthe source rock definition applied in this work.Any use of trade, product, or firm names is fordescriptive purposes only and does not implyendorsement by the U.S. Government.The AAPG Editor thanks the following reviewersfor their work on this paper: Stuart D. Harker,Steve Larter, and Kenneth E. Peters.

2 Source Rock Contributions to the Lower CretaSomeorganic geochemical studies (Leenheer, 1984; Fowleret al., 2001; Riediger et al., 2001) propose theUpperDevonianlower Mississippian Exshaw Formation as the main source ofpetroleum in Alberta. However, an alternative interpretationproposes the Gordondale Member of the Fernie Group as therected

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fJurassic source rocks. The proposed strong contribution of pe-troleum from the Exshaw Formation source rock to the Ath-abasca oil sands is only reproduced by assuming 25m (82 ft) ofmature Exshaw in the kitchen areas, with original total organiccarbon of 9% or more.

INTRODUCTION

The huge petroleum deposits in the foreland basins of Vene-zuela and Canada are exploitable resources that have only re-cently become more attractive to the petroleum industry, asoil prices have risen. The heavy and extra-heavy crude oil de-posits in Venezuelas Orinoco Belt are the biggest of theirtype (PDVSA, 2006) and have in-place estimates of 206 billionm3 or 1300 billion bbl. The oil sands in the Western Canadasedimentary basin (WCSB) are estimated to contain 260 bil-lion m3 (1635 billion bbl), which represents the largest knownconcentration of petroleum classified as crude bitumen (Na-tional Energy Board Canada, 2010). The main difference be-tween these two types is that heavy oils are still mobile in res-ervoir conditions, whereas the crude bitumen found in oil sandsis immobile and therefore cannot be produced by conven-tional techniques (Tissot and Welte, 1984).

The main oil sand deposits of the WCSB are in Alberta.These deposits are, from highest to lowest in-place estimates,Athabasca (189 billion m3), Cold Lake (32 billion m3), andPeace River (21 billion m3). Seventy-three percent of the re-serves are present within the Lower Cretaceous MannvilleGroup, where sandstones of the McMurray Formation are themain host rocks (Gingras and Rokosh, 2004). The possibleages of the source rocks contributing to these accumulationsrange from the Devonian to the Early Cretaceous.

The oil sand accumulations are the product of microbialdegradation of initially light oils, occurring after the onset ofthe Laramide orogeny (Head et al., 2003). The high level ofbiodegradation of these oils, ranging from 4 to 8 on the PetersandMoldowan scale (Brooks et al., 1988; Adams et al., 2006),has made the use of chemical parameters and biomarkers foroil-oil and oilsource rock correlations difficult. This has lim-ceous Heavy Oil Accumulations in Alberta

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n. Thgley eFigure 1. Location map of the Western Canada sedimentary basiin this study. A dark-gray square indicates the area modeled by Hilow-energy facies that is referred to in the Discussion section.main contributor.A three-dimensional (3-D)modeled Pr

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e square marked by thick dashed lines indicates the area modeledt al. (2009). The arrow indicates an increase in the percentage oft 102First, we put special attention to the trapping ef-

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rreccovering most of Alberta by Higley et al. (2009)indicated that long-distance migration of oils gen-

erated by theGordondaleMember is possible. Thiswork also proposed the organic-rich strata of theFernie Group as the main oil contributor to theoil sands in Alberta but had problems reproducingthe volumes of trapped oil. The main reasons werethe coarse grid size required for the simulations,exclusion of parts of the kitchen areas from themodel, migration of oil to zones outside of themodeled area, and software limitations such asthe inability to simulate the formation of biode-graded oil seals.

In this contribution, we present new under-standing and results derived from an extendedmodel of the WCSB, covering Alberta, Saskatch-ewan, and a part of the RockyMountains in BritishColumbia (Figure 1). Most of the input data usedfor the construction of this model was previouslyapplied in the model described by Higley et al.(2009). However, our contribution differs fromthe previously referred work in two main aspects.

ficiency of Cretaceous strata as the main factorlimiting the accurate assessment of accumulatedvolumes. Second, we conducted a sensitivity studyof total organic carbon (TOC) and hydrocarbonindex (HI) values, as well as source rock thicknessfor the two main proposed source rocks, namelyExshaw and Gordondale. The purpose of this as-sessment was tominimize the uncertainty related tosource rock occurrence beneath the Rocky Moun-tains and discuss the implications of the source rockdefinition on results derived from 3-Dmodeling ofthe petroleum systems in the region.

TECTONOSTRATIGRAPHIC HISTORY OF THEWESTERN CANADA SEDIMENTARY BASIN

The sedimentary sequence in the Western Cana-da Basin extends from the lower Paleozoic to thelower Tertiary (Figure 2) and reflects the deposi-tion and erosion of sediments under two maintectonic phases: a Paleozoic to Jurassic platformBerbesi et al. 3

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fFigure 2. Generalized stra-tigraphy and petroleum systemelements as introduced in thethree-dimensional model. Mod-ified from Higley et al. (2009)with permission of AAPG.

A4 Source Rock Contributions to the Lower Cretaceous Heavy Oil Accumulations in Alberta

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and an Upper Jurassic to Paleocene foreland basin(Wright et al., 1994).

The platform succession resembles a stablecraton adjacent to the ancient dominantly passivemargin of North America. In the study area, thebase of this interval is represented by the MiddleDevonianElkPointGroup carbonate rocks (Wrightet al., 1994). The strata contain mainly carbonates,with some siliciclastic (mainly shales and marls)and evaporitic layers. Several series of transgressionsand regressions occurred during deposition of thisstratigraphic section, resulting in the prolific oil andgas reservoirs associatedwith the former PeaceRiverEmbayment (Podruski et al., 1988; Gibson, 1975).

The Lower Jurassic strata represent the preoro-genic stage and consist of the limestones and phos-phatic sequences of the Nordegg Member and theorganic-rich Poker Chip Shale Member (Figure 2).Upper Jurassic strata were then deposited in thetransitional phase from a stable continental shelf toa subsiding foredeep trough (Wright et al., 1994) asa consequence of the collision of allochthonousterranes in the eastern Pacific with the westerlydrifting North American continent (Poulton et al.,1990). Amajor drop of sea level was responsible forsignificant erosion across the foreland trough (sub-Mannville unconformity) during the Early Creta-ceous. During the late Barremian, the western edgeof the craton was loaded with thrust sheets asso-ciated with allochthonous terrane accretion, bring-ing a new period of subsidence, and the depositionof the Lower Cretaceous Mannville Group (Cantand Stockmal, 1989).

The oldest sediments of the Mannville Groupconsist of sandstones deposited mainly by alluvialfans and rivers. Continued basin subsidence andrelative sea level rise resulted in the succession ofshales, siltstones, and lenticular sandstones of theostracod interval (Finger, 1983). Major sedimentinput associated with the Cordilleran evolutionpushed the shoreline northward and convertedmost of Alberta and Saskatchewan into flood-plains. Fluvial channel sandstones, siltstones, shale,and coal are characteristic of this depositional pe-riod (Finger, 1983; Christopher, 1984). Deposi-tion of the upper part of the Mannville Group wasfollowed by middle to late Albian lowstand andPETROLEUM SYSTEM GEOMETRYAND ELEMENTS

The WCSB has typical asymmetrical foreland ba-sin geometry, with a gently dipping eastern mar-gin and a steeper thrust-bounded western margin.The kitchen areas are located in the deep westernareas, where the highest temperatures were reached.The tilted migration pathways promoted lateralmigration of the generated petroleum to the shal-lower traps in the east (Higley et al., 2009). Onceaccumulated, low reservoir temperatures promotedsubsequent biodegradation of the petroleum.

Source Rocks

The ages of the petroleum source rocks within theWCSB range from the Devonian to the Late Cre-taceous. Here we describe the source rocks that areproposed as the main contributors to Mannvillepetroleum accumulations. From oldest to youn-gest, these are Duvernay, Exshaw, Doig, Gordon-dale, Poker Chip, as well as the ostracod and coald Proo

fLowerUpper Cretaceous Colorado Group corre-sponds to several periods of marine inundationsand regressions, as well as lateral variation fromoffshore to shoreface facies. As indicated by Mackand Jerzykiewicz (1989), the Paleocene PaskapooFormation in Alberta and the equivalent Raven-scrag Formation in Saskatchewan were depositedduring the thrusting event in the Cordillera, con-tainingmainly fluvial channel sandstones, siltstones,shales, and, in some locations, coal. Deposition ofthis interval was followed by major uplift and ero-sion associated with the Laramide orogeny, thusterminating the phase of foreland basin deposition.erosion, giving origin to the super-Mannville un-conformity. During the late Albian, most of thebasin was flooded because of a major rise in sealevel, with associated deposition of Joli Fou Shale(Smith, 2008), the main seal for the oil accumu-lations within the Lower Cretaceous reservoirs(Creaney and Allan, 1990). The Joli Fou Shale isalso the main seal in our 3-D model.

The stratigraphic section represented by theBerbesi et al. 5

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296Uncoogen, with TOC values ranging from 2 to 20 wt. %and HIs between 500 and 600 mg HC/g TOC.The thickness of this formation is variable, with anaverage of 44 m (144 ft), although greater thick-

ness (100m[328 ft] ormore) has beendescribedin some areas (Switzer et al., 1994).

Exshaw Formation (UpperDevonianLower Mississippian)

The Bakken and Exshaw formations comprise fine-grained siliciclastics deposited in euxinic to shal-low neritic environments during the late Famen-nian and the earliest Tournaisian (Richards et al.,1994), following a major drowning event that ter-minated the carbonate system of the Devonianrre

oil to the Cold Lake oil sands and the Provost field(Riediger et al., 1997; Higley et al., 2009). We willgive a brief description of these intervals, but theyare not considered as sources in our 3-D model,which mainly focused on the DevonianJurassicsource rocks.

Duvernay Formation (DevonianWoodbend Group)

As widely described in the literature (Creaney andAllan, 1990; Creaney et al., 1994), the DuvernayFormation is characterized by extensive basinal de-posits and consists of dark-brown to black bitumi-nous carbonates interbedded with gray-green cal-careous shales. The Duvernay represents a periodof great accumulation and preservation of organiccarbon under marine deep-water conditions. Evi-dence of euxinic water-column conditions andlow sedimentation rates were reported by Stoakes(1980), among others. The organic matter in thisinterval can be classified as type II (oil prone) ker-zones within the Mannville Group (Figure 2). TheSecond White Speckled Shale has been proposedas a source rock for oil in some Upper Cretaceousreservoirs (e.g., Creaney and Allan, 1990; Creaneyet al., 1994); however, because it did not contrib-ute oil to the Lower Cretaceous oil sands, we didnot model the Second White Speckled Shale. Theostracod zone and coal within theMannville Grouphave been indicated as important contributors of6 Source Rock Contributions to the Lower Cretaceous Heavy OiTheGordondaleMember (Figure 2) consists mainlyof dark-brown finely laminated calcitic mudstones,calcilutites, and calcarenites, with variably phos-phatic content and high radioactivity because ofthe presence of uranium (Asgar-Deen et al., 2004).This stratigraphic interval corresponds to the Nor-degg Member of the Fernie Group mentioned inmany publications (Poulton et al., 1990; Riedigeret al., 1990a; Riediger and Coniglio, 1992). It cov-ers a significant part of west-central Alberta andnortheastern British Columbia and was depositedafter a major marine transgression in the Early Ju-rassic. The thickness of this formation is variable,cted P

The Triassic Doig Formation consists of an uppersiltstone unit and a lower highly radioactive shaleunit. The generating interval is the basal unit, whichis also called the phosphate zone (Creaney andAllan, 1990;Riediger et al., 1990b). PublishedTOCand HI values for this interval are up to 11 wt. %and 480 mg HC/g TOC, respectively (Riedigeret al., 1990b). Oil in some Triassic reservoirs isproposed to originate from this source rock, whichcontains type II marine organic matter (Riedigeret al., 1990a). Riediger et al. (1990b) reported athickness of 78 m (256 ft) in the type section, ofwhich 39 m (128 ft) correspond to the basal phos-phate zone.

Gordondale and Poker Chip Shale Members ofthe Fernie Group (Lower Jurassic)roof

(Creaney andAllan, 1990). TheExshawFormationlies beneath the Alberta Plains and in outcrops inthe Foothills and Front Ranges of the Rocky Moun-tains, thickening from east to west. This sourcerock can be divided into lower black shale andupper siltstone members. The TOC values of theblack shale, which is the main generating interval,are up to 21 wt. % (Leenheer, 1984; Creaney andAllan, 1990; Caplan and Bustin, 1996; Smith andBustin, 2000). The average HI is approximately515 mg HC/g TOC, but values as high as 909 mgHC/g TOC have been reported for this type IImarine source rock (Smith and Bustin, 2000).

Doig Formation (Triassic)l Accumulations in Alberta

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rreas coals, which are described as mainly gas-pronesource rocks (Creaney and Allan, 1990; Riedigeret al., 1999). The ostracod zone is composed of es-tuarine valley fill strata deposited during a north-to-south transgression as limestone and calcareousfossiliferous shale. Riediger et al. (1997) describedthe section as consisting of a mixture of units con-taining type III kerogenwith beds containing types Iand II kerogen. Reported values of TOC andHI forthermally immature samples (Moshier andWaples,1985; Riediger et al., 1997) are approximately2.5 wt. % and 317 mg HC/g TOC, respectively.

Oil Contribution from Source Rocks toAccumulations in Lower Cretaceous Strata

No agreement exists as to the main source rocksfor reservoirs in the Lower Cretaceous Mannvillestrata. Brooks et al. (1988) used biomarkers to pro-pose that the Cretaceous reservoirs were chargedby oil that had experienced long-distance migra-2004) and reaches up to 800 mg HC/g TOC forimmature samples (Creaney and Allan, 1990;Riediger et al., 1990a; Asgar-Deen et al., 2004) .

The earlylate Toarcian Poker Chip A shale isthe rock intervalwith the best source rock potentialwithin the Poker Chip ShaleMember of the FernieGroup. It consists of black calcareous shales andthin limestones deposited in marine environmentsand are present in southern and western Alberta. Itcontains type II organic matter, with TOC valuesreaching up to 18.5% andHI of up to 740mgHC/gTOC for immature samples (Riediger, 2002).

Ostracod Zone and Coals in the MannvilleGroup (Lower Cretaceous)

The lowest stratigraphic section of the foreland ba-sin is rich in deltaic and coastal plain strata, as wellreaching maximum values of 67.7 m (222 ft), withapproximately 25 m (82 ft) as an average (Mossopand Shetsen, 1994). The Gordondale Member con-tains sulfur-rich type I/II-S marine kerogen, withTOCvalues reaching up to 28wt. % (Riediger et al.,1990a; Asgar-Deen et al., 2004). The HI rangesfrom 26 to 273mgHC/g TOC formature samples(Riediger et al., 1990a; Ibrahimbas and Riediger,ted Pr

ooftion, phosphate zone of the Doig Formation, andDuvernay Formation (Figure 2). A four-dimensional

model of a part of Alberta and Saskatchewan de-veloped by Higley et al. (2009) proposed thatsource rocks in the Jurassic Fernie Group (Gor-dondale Member and Poker Chip A Shale) werethe initial and major contributors of petroleum toMannville Group reservoirs.

In contrast, the idea of the Nordegg (Gordon-dale) Member as the main source rock was notsupported by Riediger (1994), who consideredthat oils generated by sulfur-rich kerogen in thisinterval should have very low API gravities andwould not be able to migrate long distances. Thisauthor also indicated that oil samples found inAthabasca showed some biomarker distributionssuch as pristane/phytane, diasterane/regular ster-ane, and abundance of C35 relative to C34 hopanesthat were inconsistent with those found in Gor-dondale bitumens (Riediger et al., 1990a). Manybiomarker correlations indicate that the Exshawsource rock was the primary contributor to theLower Cretaceous oil sand deposits in Alberta(Leenheer, 1984; Fowler et al., 2001; Riediger et al.,2001). Adams et al. (2010) used biodegradation-resistant parameters to conclude that the PeaceRiver reservoirs received an important contribu-tion from the Gordondale Member, but that theAthabasca and Cold Lake deposits originatedmainly from the Exshaw Formation.

Reservoir Formations

The main oil sand deposits in the WCSB occur atAthabasca, Cold Lake, and Peace River. More than70% of the oil found in these deposits is within for-mations belonging to the Lower Cretaceous Mann-ville Group (Gingras and Rokosh, 2004). TheAthabasca and Cold Lake oil sands occur mainlytion, and which was generated by the same or atleast very similar source rocks. However, they didnot identify specific source rock candidates.

Creaney and Allan (1990) estimated that atleast 1.7 trillion bbl (270 109 m3) of oil in LowerCretaceous Mannville Group sands originated fromsource rocks in the following order of importance:Nordegg (Gordondale) Member, Exshaw Forma-Berbesi et al. 7

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referred to Vigrass (1968) for a more extendedgeologic description of the oil sands area.

Accumulations at Peace River and Cold Lakecorrespond to pinch-outs of the reservoirs againstshales and structural highs (Vigrass, 1968). Thetrapping mechanism of the Athabasca oil sands iscontroversial (Ranger, 2006). Vigrass (1968) in-dicated that most of the Athabasca accumulationcorresponds to a subtle domal structure that beganto form before deposition of the reservoir sands,with a later increase in amplitude approximatelyduring the Early Cretaceous. The same authorindicated that another part of the Athabasca ac-cumulation occurs in the trough and northeasternlimb of a syncline that resulted from salt dissolu-tion of Devonian evaporites. Ranger (2006) pro-posed that the structural control exerted by saltdissolution was important in the southeastern partof Athabasca, but not to the northeast, where thetiming of evaporite dissolution may have precludedthe development of a structural trap before migra-tion. For the latter case, this author suggested astratigraphic control where upperMannville shalesoverlapped and sealed the McMurray Formationreservoir against Paleozoic and Precambrian rocks.However, this hypothesis has not been confirmedbydirect evidence,whichmight havebeendestroyedduring the Pleistocene erosion (Ranger, 2006).

Seals

Among the Paleozoic to Tertiary sedimentary se-quences shown in Figure 2, many rock intervalsact as seals within the different petroleum systemsin the WCSB. The main seal for petroleum withinMannville strata across the WCSB is representedby the Joli Fou Formation of theMiddle CretaceousColorado Group. This formation is present acrosswithin the McMurray and Clearwater formationsand equivalent strata (Vigrass, 1968). The accu-mulations at Peace River are mainly in the Blue-sky andGething formations (Vigrass, 1968;Gingrasand Rokosh, 2004).

In general, the Mannville Group consists ofinterbedded sandstone and shale deposited on anerosional surface that truncates the Jurassic andolder strata of the WCSB. Interested readers are8 Source Rock Contributions to the Lower Cretaceous Heavy OicteK. Higley. Themodeling software used in this workwas Schlumbergers PetroMod 3-D version 11.3.Lithologies and Source Rock DefinitionThe stratigraphic sequences shown in Figure 2 werereproduced in the model by 22 layers that are re-gionally extended versions of those described byHigley et al. (2009). They extend south to the limitsof Alberta and east to the border of Saskatchewan-Manitoba. The ages and initial lithofacies are de-scribed by Higley et al. (2009). The model includeslateral facies variation for each layer. Vertical rockheterogeneity within each stratigraphic unit wasnot represented in detail but was influenced bythe use of mixed lithologies within assigned litho-facies. Conversion of the original 3-D model to anewer version of the modeling software required asubtle change on the initial lithofacies definition.Our lithofacies are slightly more permeable thanthose described by Higley et al. (2009) for carrierbeds and reservoirs.

For comparison purposes, we will use the termprevious model to refer to the model of Higleyet al. (2009) and the term extended model ford Proo

fmost of Alberta and extends eastward, reachingthe Manitoba Escarpment, where it is called theSkull Creek Member (Leckie et al., 2008). It con-sists of noncalcareous marine shale with a smallproportion of interbedded fine- to medium-grainedsandstone, which was deposited during a majorsea level high (Wickenden, 1949; Leckie et al.,2008).

THREE-DIMENSIONAL MODEL DEFINITIONAND CALIBRATION

Input Data

The 3-D model presented here includes parts ofAlberta, Saskatchewan, and the Rocky Mountainsof British Columbia (Figure 1), covering a totalarea of 1,412,400 km2 (545,330 mi2). A full-scalemodel of the basin containing 22 isopach mapsand preliminary lithofacies assignment was kindlyprovided by the U.S. Geological Survey and Debral Accumulations in Alberta

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the previous model of Alberta and are summa-rized in Table 1.

To reduce the uncertainty related to sourcerock heterogeneity, we performed a sensitivity anal-ysis with respect to TOC and HI for the Gordon-dale Member of the Fernie Group and the ExshawFormation. We focused on these two source rocksbecause they are the two intervals described in theliterature as the main likely contributors to theMannville reservoirs. Later, we will discuss the in-compatibility of the results based on our initial as-sumptions with some interpretations from organicgeochemistry in relation to the origin of petroleumin the Lower Cretaceous strata of Alberta. We alsoevaluated the impact of thickness variations in theExshaw Formation.

Oil Generation Kinetics

The first kinetic parameters applied in our modelthe larger version described in this article. Thethickness of the source rock layers as well as theTOC and HI contents were initially assigned as in

Table 1. Major Modeled Source Rocks and Initial Input Parame

Source Rock Layer Kerogen TypeTOC

(wt. %)

Poker Chip Shale A (Fernie Group) II 7.36Gordondale Member (Fernie Group) I/II-S 15.89Doig Formation II 2.90Exshaw Formation II 9.64Duvernay Formation II 5.81

*The values correspond to those applied in the previous three-dimensional mode**A0 = frequency factor; Ea = activation energy.were based on the relationship between the organic

de Lca fe yde rC oc bti iple 1 shows the vcorrect reproduction of maximum burial temper-ature and timing. In a basin currently at maximumburial, the principal variable to achieve a goodtemperature calibration is the basal heat flow. Ininverted (uplifted) basins, maximum paleotem-peratures reached by the sediments depend on acombination of heat flow, erosion magnitude, andtiming.

For the WCSB, we started the calibration byaddressing the heat-flow distribution. Afterward,ted Pr

oof

quency factors. Composite samples of immaturePoker Chip A Shale were not available when thesekinetic parameters were obtained. For this reason,the kinetic parameters for this source rock are thesame as those for type II-S kerogen from the Gor-dondale Member, which is a reasonable assump-tion based on its lithology, consisting of organic-rich black calcareous shale and thin limestone(Higley et al., 2009).

Boundary Conditions

For model calibration, the main control lies in the

450 40 52.5 26.8500 4.2 53.6 27.1510 43.6 58.5 28.7

lberta published by Higley et al. (2009).HImg HC/g TOC)

Average Thickness(m)

Ea**(Kcal/mol)

Log A0**(1/m.y.)

550 15.8 37.6 21.9526we addressed the erosion magnitudes and the sed-527

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529tip n on530er v fl531re m

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533w u re534d b535used for these initial activation energies and fre- bining two published maps.activation energy, the frequentermined from the compensatween these two variables. Taby factor canon relationshe de-be-

alues

The heat-floin Figures 3Amaps used in oand B and werer model aevelopedBerbesi et al.showny com-fraction of kerogen (Sorg/Sorg + ). By means f this Heat Flow

pyrolysis experiments using th organic sulfu mole

mates of the activation energy d rived fromh rous (Ro) and temperature measu ments fro wells.Uand Ruble (2002), and it basi lly consists o esti- the basin w e calibrated to itrinite re ectance2009). This methodology is scribed by ewan process, mul le one-dimensio al extracti s acrossnsulfur content of kerogen and the kinetic param-eters determinedby hydrous pyrolysis (Higley et al., iment water interface temperature (SWIT), as wellas the paleobathymetry. During each step of the9

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Bachu and Burwash (1994) analyzed the geo-thermal regime in the sedimentary rocks of theWCSB using corrected bottom-hole temperaturemeasurements. Based on 487 data points, theyconstructed a basement heat-flow map that in-cludes the Foothills and northern parts of Albertaand the southern part of Saskatchewan. Their val-ues, which range between 40 mW/m2 in southernAlberta and Saskatchewan and more than 80mW/m2 in the northern parts of Alberta and north-western Canadian Territories, correspond well withthe geothermal gradient in the region.

The second data source for our heat-flow mapswas the geothermalmapofNorthAmerica (Blackwelland Richards, 2004), which integrates extensive in-

Figure 3. Basal heat-flow maps developed for this study. (A) Prsymbols are locations of wells that have vitrinite reflectance datadustry thermal data sets and research on heat-flow

10 Source Rock Contributions to the Lower Cretaceous Heavy Ocorresponding to early stages of development ofthe foreland basin. Themain event began at 58Maand finishes at the present time and correspondscted P

roof

values were considered as constant because theseareaswere not affected by anymajor thermal event.

Erosion

The next step in the calibration of our model wasthe estimation of erosion magnitudes. The two mainerosional events that influenced thermal matu-ration and petroleum migration were introducedinto the model based on reported data discussedbelow. Theminor event was assigned between 150

land phase (380119 Ma). (B) Foreland phase (1190 Ma). Plus580to the onset of the Laramide orogeny and581

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595Uncodata. Thismap showsheat-flowvalues approximately80 mW/m2 beneath the Rocky Mountains insoutheastern British Columbia and 50 to 60 mW/

m2 in Alberta and Saskatchewan, with a trend ofincreasing heat flow from south to north inAlberta.

In general, our heat-flow values are within thenormal range for a foreland basin (Allen and Allen,1990; Deming, 1994). Variation of heat flowthrough time was considered for the areas locatedbeneath the Rocky Mountains, considering the tran-sition from a platform in a passive margin to rapidaccretion and subsidence associated with the Lar-amide orogeny. For the areas corresponding to theplains in Alberta and Saskatchewan, the heat-flow

subsequent basin uplift and erosion. In the case ofpre-Mannville erosion before Mannville deposi-tion, a relatively low value of 180 m (590 ft) wasassigned. This value corresponds to an erosion rateof 0.006 mm/yr, which is comparable to estimatesfor geologic settings under the influence of slow ero-sion (Flowers et al., 2006). Most attention was putinto the Laramide erosion because it followed theperiod of maximum burial in Alberta and thus had amajor influence on the temperature and pressureevolution on the basin (Hitchon, 1984; Issler et al.,1999).

Magara (1976) used shale-transit time valuesrecorded on sonic logs to estimate the magnitudeof Laramide erosion in the southwestern part of theil Accumulations in Alberta

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625the Rocky Mountains, coinciding mostly with the626

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WCSB, obtaining values up to 1400 m (4600 ft).These magnitudes were later discussed by Kumarand Magara (1979), who indicated that the rate ofvelocity increase is a parameter that changes withdepth, and therefore, the estimates of erosion usingMagaras technique are highly dependent on themethod of extrapolation in a curve of transit time

versus depth. Hacquebard (1977) used the equi-tevalues proposed by Nurkowski (1984).Sediment-Water Interface Temperatureand Paleobathymetryd Proo

f

of 500 m (1600 ft) in the Alberta plains and Sas-katchewan and reach 2500 m (8200 ft) beneath

Figure 4. Erosion map assignedfor the Laramide orogenic period.629

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rrelibriummoisture of coals published by Steiner et al.(1972) and compared these values with a graphderived from European data, which relates theequilibrium moisture of coal to its original depthof burial. He estimated maximum thickness oferosion of about 800 m (2600 ft) in the east ofAlberta and 3000 m (9800 ft) in the west. Thesevalues are considerably higher than those estimatedinitially by Magara. Later, Nurkowski (1984) ap-plied a similar methodology but included theranks of coal that are present in the Alberta plainsin the curve that relates equilibriummoisture withdepth of burial. He obtained similar trends, al-though around 500 m (1600 ft) less erosion foreach area.

After integrating and combining the publisheddata, we built an eroded thickness map that wasused as input for the model (Figure 4). Accordingto this map, erosion values have an average value

The temperature at the sediment-water interfacewas initially estimated using a tool of the modelingsoftware, which generates a SWIT trend over geo-logic time for a given present-day latitude, longi-tude, and paleowater depth (Wygrala, 1986).

The application of this tool resulted in SWITvalues approximately 20C for most of the mod-eled period, except since the onset of the lastglaciation to the present, where the SWIT rangesbetween 5 and 10C.

Given the large area covered by our model, weconstructed paleowater depth distribution mapsinstead of assigning a single paleowater depth trend.We built 10maps representing the paleobathymetryfor the time from the Devonian to the Late Cre-taceous. These maps are based on organic faciesdistribution for Devonian andMississippian strata(Fowler et al., 2004; Stasiuk and Fowler, 2004),lithofacies described for Triassic and Jurassic rocksBerbesi et al. 11

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AQ1212 Source Rock Contributions to the Lower Cretaceous Heavy Ooofr

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(Edwards et al., 1994; Ross and Bustin, 2006),and early Turonian paleobathymetry reconstructionbased on lithofacies and faunal data. Finally, 0 mof water depth was assigned from the Laramideorogeny to the present.

Calibration Data

Thermal data from 33 wells across Alberta andSaskatchewan were used for model calibration andinclude drillstem test (DST) and corrected bottom-hole temperatures, aswell asmeasuredRo. Figure 5shows the calibration results and burial historycurve for one well located in west-central Alberta(Figure 1). In general, the model achieves a very

good reproduction of the temperatures and ma-turity trends with depth. Nonetheless, the temper-ature calibration was problematic for a few wellsin central Alberta, possibly reflecting local heat-flow anomalies (Hitchon et al., 1990; Bachu andBurwash, 1994) related to basement radiogenic heatproduction or heat transfer by groundwater flow.

Migration Modeling

We used the hybrid calculation method for the pe-troleum migration simulation. This method com-bines Darcy flow and flowpath (ray-tracing) tech-niques (Schlumberger, 2010). In the hybridmethod,a threshold permeability value is set. When this

Figure 5. Burial history and calibration at well 01-27-060-26W4 (see location in Figure 1). The onset of the Laramide orogenic phase isindicated with the dashed line in the burial curve.il Accumulations in Alberta

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permeability threshold is exceeded by the mod-eled lithofacies, the flowpath method is activated,otherwise,migration ismodeled by theDarcy flow.In thismanner,migration through low-permeabilitylithologies (e.g., shales and siltstones) is based onthe Darcy flow, and in more permeable carrier li-thologies (i.e., sandstones), flowpath modeling isimplemented (Welte et al., 2000).

RESULTS AND DISCUSSION

Generation

We will first discuss the petroleum generation re-sults from our simulations using the initial sourcerock input parameters as defined in Table 1. As

shown in Figure 6, the kitchen areas are located inwestern and southwestern Alberta, correspondingto the foothills and sedimentary section below theRocky Mountains.

Significant transformation ratios (50%) arereached by the Gordondale Member and PokerChip A Shale of the Fernie Group at 75 Ma. Suchtransformation ratios are also observed for theDuvernay and Exshaw formations at 65 Ma andapproximately 5m.y. later for theDoig Formation.This sequence of generation timing reflects theburial history of the sequences. Early generationfrom the Lower Jurassic Fernie Group source rocksis caused by the fast kinetic parameters corre-sponding to labile type II-S kerogen.

At 60 Ma, all of the source rocks considered inour model reached Ro values that correspond to

Figure 6. Present-day transformation ratio (tr) distribution showing the location of kitchen areas and time extractions for three selectedpoints.Berbesi et al. 13

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early or main oil generation in western or south-western Alberta and wet or dry gas generationbeneath the accretion zone. This time representsthe point of maximum burial before the onset ofthe Laramide orogeny (Issler et al., 1999). Fromthis point on, the rate of kerogen transformationdecreased and ultimately ceased as a consequenceof the continuous decrease in temperature.

Figure 7 shows the cumulative evolution of oilgeneration for the modeled source rocks. The re-sults for the Gordondale Member and the PokerChip A are closely similar to those published byHigley et al. (2009). According to this first sce-nario, theGordondaleMember of the FernieGroupis the main generator, producing a maximum yieldof oil of almost 400 billion m3 (2515 billion bbl),which is approximately four times more oil thanthe amount generated by any other source rock.Total generation values for the Duvernay, Doig,and Exshaw formations are higher than those ofthe previous 3-D model of Alberta because of the

Figure 7. Cumulative oil generation usinginitial source rock parameters.14 Source Rock Contributions to the Lower Cretaceous Heavy Octed P

roof

of approximately 19 billion m3 (119 billion bbl)was obtained, which coincides in general with thatobtained from the previous model of Alberta.However, this volume is low compared with cur-rent estimates of 260 billion m3 (1635 billion bbl)for the Lower Cretaceous oil sands (National EnergyBoard Canada, 2010). Two possible reasons for thisresult were addressed: (1) inadequate source rockdefinition and amount of generated oil and (2) in-adequate trap definition and that enough petroleumwas generated but it was not efficiently trapped.

The total volume of oil generated by the fivemodeled source rocks shown in Figure 7 is 694billion m3 (4365 billion bbl), which is more thanthe amount of petroleum required to fill the oilsand accumulations in Alberta. This seems to in-dicate that the low accumulation volumes are nota direct consequence of the source rock definitionor assigned generative potential. The model alsoshows an efficient expulsion of generated hydro-carbons from the source rock layers that exceeds758

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and software changes (Figure 1). In summary, theorganic-rich intervals within the LowerMiddleJurassic section generate more oil than the sum ofall organic-rich strata located between the De-vonian and Triassic sedimentary sections.

Migration and Accumulation

Initial Models DefinitionUsing the initial conditions described in Table 1,a total oil contribution from the modeled sourcerocks to the Mannville Formation (reservoir layer)

70% in all the cases.Under this configuration of the model, the

traps are filled to spill and/or have experienced re-migration during one or more periods. Most of theoil reaching the Lower Cretaceous strata contin-ued migrating beyond Athabasca to the north andnortheast, escaping from the modeled area, or mi-grated to the east to form large shallow oil accu-mulations along the Precambrian shield in Saskatch-ewan. In other words, the initial trap definition inthe model was insufficient to account for present-day accumulations. Higley et al. (2009) listed thecoarse grid size of the model relative to subtleil Accumulations in Alberta

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stratigraphic traps as one of the main reasons whyinsufficient amounts of petroleum were trapped.Another possible reason was the incapacity of themodeling software to simulate biodegradation. In theWCSB, nonbiodegraded light oil reached shallowreservoirs and suffered water washing and biode-gradation, resulting in a heavier viscous oil that wasa factor in the trapping of the subsequently ac-cumulated oil. We tried to address both possibi-lities starting with a revision of our facies distribu-tion maps.

Evaluation of Trapping EfficiencyThe Lower Cretaceous sequence of the WCSBconsists of interbedded sandy, silty, and shaly unitswhose lateral and vertical lithologic variations couldnot be reproduced in detail. These lithologic var-iations are a strong factor in the trapping of petro-leum. Vigrass (1968) indicated, for example, theimportance of onlap traps as controls on oil accu-mulations at Peace River and the poor lateralcontinuity of the sandstone beds in the Athabascaarea. The dominance of shaly units in the LowerCretaceous strata to the north of the Peace Riverarea has been reported (Vigrass, 1968;Mossop andShetsen, 1994) and relates to the predominantlymarine conditions in northern Alberta during thisgeologic interval (Leckie and Smith, 1992). Theabundance of low-energy facies has been describedfor the northeastern limits of the Athabasca accu-mulation. Hayes et al. (1994) showed an increasein the percentage of low-energy facies following anorientation similar to that indicated by the arrow inFigure 1. In a detailed study by Ranger (2006), theauthor proposes that the main controls hinderingthe migration of petroleum to the northeast ofAthabasca were stratigraphic, although evidencefor this hypothesis might have been removed dur-ing erosion.

We tried to reproduce these lithologic varia-tions and to increase the trapping efficiency of ourmodel by creating a stratigraphic barrier that cov-ered the northern parts of Alberta and the north-eastern edges of the Athabasca deposit. The totalamount of accumulated oil in theMannvilleGroupstrata using this configuration is about 230 billionm3 (1450 billion bbl), which represents moreted Pr

oof

than 1200% increase with respect to our first re-sults. Another improvement achieved by imple-menting this impermeable barrier is related to thestability of the oil accumulations. The initial con-figuration of themodel without this barrier resultedin remigration of petroleum, with accumulationsthat changed continuously in volume and areathrough time after the onset of the Laramide ero-sion. This occurred as a consequence of the shal-low nature of these reservoirs, which made themvulnerable to tilting produced by nonuniform ero-sion across the basin. When this low-permeabilitylateral seal was applied, remigration of petroleumdiminished, allowing us to study the compositionalevolution of independent reservoirs through time.The contribution from the main sources to LowerCretaceous strata as a function of time is shown inFigure 8. The reservoir filling curves are slightlysusceptible to variations in the Laramide uplift pat-tern; however, the total contributions from in-dividual source rocks as well as the general trendsare constant.

A second approach implemented an imper-meable barrier as discussed above, however, as apiercing lithology that simulates the time-dependentsealing effect of biodegraded oil. This piercing bodyappears in the north and eastern limits of the knowntrapping areas of Alberta at 55 Ma, extending pro-gressively to the south and west until it occupiesits final area at 30 Ma, as shown in Figure 9. Thistime configuration assumes that biodegradedseals did not occur before the onset of the Lar-amide erosion and further introduction of freshwater to the reservoirs. This approach resulted inlarge accumulations in northwestern Saskatchewanand northeastern Alberta before the piercing li-thology reached its maximum extension. Afterexperimenting with the timing and areas for thispiercing barrier, it appears that the sealing effectof biodegraded oil may have been important inhindering the migration of petroleum in thenorthern areas, but the timing was not optimal forimpeding the movement of fluids to the east ofAthabasca.

One limitation of our progressive lateral seal isthat it cannot model the volume decrease of pe-troleum through time as biodegradation occurs.Berbesi et al. 15

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However, because the main limitation of a biode-graded seal is the timing of its occurrence and notthe masses involved, we consider that the maintrapping control was structural and stratigraphic,as previously proposed by Vigrass (1968) andRanger (2006).

Oil Composition and Source Rock ContributionsSome authors propose the Exshaw Formation asthe main contributor to Mannville Group oils(Leenheer, 1984; Fowler et al., 2001; Riediger et al.,2001) based on organic geochemical analysis andbiomarker characterization. Heavy biodegradationcomplicates interpretations of biomarkers for theAthabasca oil sands. Nevertheless, new techniquesfor the study of this type of hydrocarbons haveallowed us to address the sources of the oil withinthe accumulations that we analyze in this study. Toidentify variable source contributions to the oil

Figure 8. Cumulative oil contributionsfrom the modeled source rocks to theMannville Group reservoirs using an im-permeable barrier covering the northernlimits of Alberta and the eastern edge ofthe Athabasca accumulation.sands from the Exshaw, Gordondale, and Duver-

16 Source Rock Contributions to the Lower Cretaceous Heavy Octed P

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tions within the Mannville Group has been sug-gested by the previous 3-D model of Alberta(Higley et al., 2009), which proposed that sourcerocks of the Fernie Group generated almost twicethe combined volume of oil from all other Devo-nian through Lower Cretaceous source rocks. This3-D model also suggested that oils generated fromthe high-sulfur Gordondale Member were able toexperience long-distance migration, which can becompared with some other known systems werelong-distancemigration of oils generated fromhigh-sulfur sources occurred (Higley et al., 2009). Ex-amples include migration of oils from the Phos-phoria source rocks inWyoming and Jurassic sourcerocks in Iraq (Sheldon, 1967; Claypool et al., 1978;Pitman et al., 2004). The importance of Gordon-dale as source rocks has also been suggested byother analysis of biomarkers, metals, and stablesulfur isotopes (Lewan et al., 2008) and by a re-917cently developed technique based on the compar-918

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titative gas chromatographymass spectrometrymethods optimized for heavy oils, as well as highlybiodegradation-resistant proxies like the metal Scontent, and analysis of source-dependent high-molecular-weight multiheteroatom compounds.In the case of the Peace River region, they indi-cated mixing of Gordondale- and Exshaw-sourcedoils. In the case of southern Athabasca, they in-dicate an origin from the Exshaw Formation withminor contributions from the Duvernay Formation.

In contrast, the importance of the GordondaleMember as a main contributor to the accumula-

ison of 187osmium/188osmium at the time of gen-eration (Osg) and platinum/palladium (Pt/Pd) ratiosin oils and their potential source units (Selby et al.,2011). Moreover, Orr (2001) listed oils and tarsin reservoirs of the Mannville Group that wereindicative of type II-S kerogen and, as indicatedby kerogen analysis (Riediger et al., 1990a; Asgar-Deen et al., 2004), the only important source in-terval containing II-S organic matter within thestudy area is the Fernie Group.

In Figure 8, the Gordondale Member contrib-utes more than five times more petroleum to theMannville layer than the Exshaw Formation. Thisil Accumulations in Alberta

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same model also proposes that more than 54% ofthe oil volume in all present-day individual accu-mulations corresponds to Gordondale-sourced pe-troleum, whereas the contribution from Exshawnever exceeds 15%. This set of results is in agree-ment with the proposition that oils in the WCSBweremainly sourced by rocks of the Jurassic Fernie

Group (Lewan et al., 2008; Higley et al., 2009;Selby et al., 2011).

Source Rock SensitivityOur initial TOC and HI values are reasonablebased on available data. However, a significant partof the kitchen areas of the modeled source rocks

Figure 9. Implementation of an impermeable barrier in the Mannville Group reservoirs to enhance the trapping efficiency of the three-dimensional model. View at 55 (A), 50 (B), 40 (C), and 30 (D) Ma. Present-day oil accumulations are represented in bright green. Thegray shape represents the evolution of the impermeable barrier through time.Berbesi et al. 17

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953Figure 10. Thickness of theExshaw layer (A) applied to theinitial configuration of our mod-el. It corresponds to the thicknessapplied by Higley et al. (2009).(B) Applied in the revised versionof the model that considersthickening of the Exshaw For-mation from eastern to westernAlberta. Subtle thickness increasein southern Saskatchewan was

not intended and resulted from

18 Source Rock Contributions to the Lower Cretaceous Heavy Of

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are located beneath the Rocky Mountains, wheresource rock occurrence and properties are uncertain.Therefore, considering these uncertainties as well asthe known source rock heterogeneity, we conducteda sensitivity study of TOC and HI values for theGordondale Member and Exshaw Formation.

Increasing the TOC value for the Gordondalesource rock results in generation and accumulationvolumes that explain the amounts of petroleum in

the Alberta deposits, suggesting a strong predom-inance of Fernie oils, with only minor contribu-tions from other source rocks. Using a TOC of15% and an HI of 600 mg HC/g TOC for theExshaw Formation result in 860 billion m3 totaloil from Devonian to Lower Cretaceous sources,from which 250 billion m3 are produced only bythe Exshaw Formation. Nevertheless, within theLower Cretaceous reservoirs, Gordondale-sourced

the methodology described inthe text. However, because thissection was modeled as non-generative, it did not influencethe observed differences in gen-erated and accumulated masseswith respect to the initial versionof the model.il Accumulations in Alberta

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oil represents 75% for AthabascaCold Lake and70% for Peace River, with Exshaw-sourced petro-leum representing less than 5% of the oil volumesin these reservoirs.

The other revised source rock parameter wasthickness of the Exshaw Formation. Initial thicknessassigned to this source rock in Alberta is generallyless than 8 m (26 ft) (Figure 10A), which is in ac-cordance with the previous model of Alberta anddata published by Caplan and Bustin (1996). How-ever, some literature indicates an increasing thick-ness of this formation from east to southwesternAlberta. For example, Savoy et al. (1999) and Smithand Bustin (2000) indicate a thin Exshaw Forma-tion for most of the study area but describe thick-ening in some areas in western Alberta, where thelower black shale member can have a thickness of20 m (65.6 ft) or more. Because the kitchen areasoare located in the western part of the model, weted Pr

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Alberta. This modification did not influence thepredicted timing of oil generation, which is con-trolled by the thermal history of the basin and thedeposition history of the overburden rock (Deming,1994). However, effects of this change are seen inthe volumes of generated oil and the compositionof the modeled accumulations.

This revised model resulted in more than 700billion m3 (>4402 billion bbl) of Exshaw-sourcedoil (Figure 11), followed by 400 billion m3 (2515billion bbl) of oil generated by the GordondaleMember andminor amounts from the other sourcerocks, giving a total of 1300 billion m3 (8173 bil-lion bbl) of generated petroleum.

The volume of trapped of oil withinMannvillestrata (Figure 12) is 303 billion m3 (1905 billionbbl), from which approximately 280 billion m3

(1761 billion bbl) is in the Athabasca and Cold

Figure 11. Cumulative oil generationfrom the main modeled source rocks whenthe thickness of the layer correspondingto the Exshaw source rock is increased.1013Lake accumulations. This represents 28%more oil1014

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of the western areas of the Exshaw layer.We did this by creating a model that contains

the same input data used for the first simulationsof our expandedmodel (Table 1) but also includesthe stratigraphic barrier described in section B. As-signed thickness for the Exshaw Formation wasfrom approximately 3 m (9.9 ft) in Athabasca toan average of 25 m (82 ft) in the kitchen areasbeneath the Rocky Mountains (Figure 10B). Thiswas achieved through uniform thickening of theentire Exshaw layer that, given its geometry, af-fected mostly the kitchen areas located west of

than the initial present-day estimates for this area(National Energy Board Canada, 2010), evenwhenthe model does not include what are believed to bethe main sources for the Cold Lake accumulations.For the Peace River accumulation, the model pre-dicts 24 billion m3 (151 billion bbl) of oil, whichis also higher than initial estimates of 20.5 billionm3 (126 billion bbl) for this area. These resultsappear reasonable especially because our modelingsoftware does not consider petroleum mass losscaused by biodegradation.

Our revised model proposes that the ExshawFormation provided 41% of the oil within theBerbesi et al. 19

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Athabasca and Cold Lake accumulation, followedby a 35% of contribution from the GordondaleMember and minor amounts from the other sourcerocks. From eastern to western Alberta, the im-portance of the contribution from the Gordondalesource rock increases. The samemodel predicts that52% of the oil in the Peace River deposit originatedfrom the Gordondale source rock. These resultsgenerally agree with those of Adams et al. (2010),although ourmodel does not suggest an importantcontribution from the Duvernay Formation.

This model manages to reproduce both the vol-umes and compositions of the main oil accumula-tions in the WCSB, favoring published results pro-posing the Exshaw Formation as the main sourcerock in the basin (Fowler et al., 2001; Riediger et al.,2001; Adams et al., 2010). However, one main limi-tation of this model exists that must be taken intoaccount until new accurate data are available to sup-port or contradict the assumed source rockproperties.Although some studies (Savoy et al., 1999; Smith

Figure 12. Cumulative oil contributionfrom the main source rocks to the ManvilleGroup reservoirs as a function of time.Average thickness of the kitchen areasof the Exshaw Formation is 25 m (82 ft).An impermeable barrier is present in theareas shown in Figure 9D before the oilstarts reaching the reservoir layer.andBustin, 2000) indicate thickening of theExshaw

20 Source Rock Contributions to the Lower Cretaceous Heavy Octed P

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dale source rock is the dominant contributor at43% of the oil in Athabasca, followed by Exshaw(26%), Doig (23%), and less than 1% from eachof the other source rocks. Very similar trends areobtained when the 25-m (82-ft) average thick Ex-shaw is split into two equivalent layers, with onlythe lower member modeled as generator, with ini-tial TOC and HI contents as indicated in Table 1.Based on these results, unless new data demonstratethat the thicker western parts of the Exshaw For-mation possess immature TOC levels of 9% or moreacross all of its extension, modeling results based onavailable data continue to support the GordondaleMember of the Fernie Group as the main con-tributor to the oil sand deposits in the WCSB.

CONCLUSIONS

A 3-D model of the WCSB was constructed andcalibrated to well data. Thermal calibration results1080propose heat-flow values between 45 and 75mW/1081

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Formation (including the lower black shalemember)to the west of Alberta, no data are available to sup-port themodeling assumption that theTOCcontentremains constant through all the generative section.Besides, many studies on DevonianMississippiansource rocks in North America (Schmoker, 1980;Robl et al., 1983; Comer, 1991, 1992) show an in-verse relation betweenTOCand thickness as a resultof some degree of organic matter dilution by addi-tional sedimentary contributions.

When this thicker Exshaw layer is assignedonly half of the initial TOC content, the Gordon-

m2 and total erosion of up to 1400 m (4593 ft),coinciding well with previously reported values.All the modeled source rocks reached early ormain oil generation before 60 Ma, when the onsetof the Laramide orogeny occurred. Our model sup-ports the possibility of long-distance migration ofoil from the Gordondale source rock proposed byHigley et al. (2009) and does not consider this asa limitation for a contribution from Jurassic oils tothe Lower Cretaceous accumulations. Without ap-propriate barriers, our model generates large andshallow oil accumulations along the Precambrianil Accumulations in Alberta

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proposed by Ranger (2006). The effect of addi-tional trapping caused by seals formed by biode-gradation of petroleum was found to be minor,and its influence is proposed to be restricted onlyto the north of Athabasca.

Having improved the trapping efficiency ofthemodel, our initial source rock definition resultsin about 230 billion m3 (1450 billion bbl) of oilreaching the strata of the Mannville Group. Atindividual accumulations, the Gordondale sourcerock appears to contribute more than 54% of theoil, whereas the contribution from the ExshawFormation never exceeds 15%.

The proposed strong contribution of Exshawproducts to the Athabasca oil sands can be onlysupported by the model when the initial thicknessin the kitchen areas of the Exshaw layer is increasedto an average of 25 m (82 ft). However, until newdata can demonstrate that the Exshaw Formationpossesses TOC levels of 9% ormore across its entireextension beneath the Rocky Mountains, our re-sults support that the Gordondale Member of theFernie Group was the main contributor to the oilsands in the WCSB.

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