AUTHORS

Catherine L. Hanks � Geophysical Instituteand Department of Geology and Geophysics,University of Alaska, Fairbanks, Alaska 99775-5780; chanks@gi.alaska.edu

Catherine Hanks is a structural geologist with anemphasis on fracture characterization and en-ergy resources. She received degrees in geologyfrom Rice University (B.A.) and the Universityof Washington (M.S.). After working for ARCOAlaska, she received her Ph.D. from the Uni-versity of Alaska Fairbanks, where she nowteaches classes in petroleum geology and res-ervoir characterization.

Grant Shimer � Department of Geologyand Geophysics, University of Alaska, Fairbanks,

Integrated reservoircharacterization and simulationof a shallow, light-oil,low-temperature reservoir:Umiat field, NationalPetroleum Reserve, AlaskaCatherine L. Hanks, Grant Shimer,Iman Oraki Kohshour, Mohabbat Ahmadi,Paul J. McCarthy, Abhijit Dandekar,Joanna Mongrain, and Raelene Wentz

Alaska 99775-5780; gtshimer@alaska.edu

Grant Shimer graduated from Beloit College inWisconsin with a B.A. degree in anthropology in2003. After completing his M.S. degree in ge-ology at the University of Alaska Fairbanks in2009, he continued on at the university to re-ceive a Ph.D. in the summer of 2013. His in-terests are interdisciplinary and include clasticsedimentology and stratigraphy, paleoenviron-mental reconstruction, and geochronology.

Iman Oraki Kohshour � Department ofPetroleum Engineering, University of Alaska,Fairbanks, Alaska 99775; imanoraki@gmail.com

Iman Oraki Kohshour received his B.S. degree inpetroleum engineering from Petroleum Univer-sity of Technology in Iran in 2010. He thenjoined the Petroleum Engineering Departmentat the University of Alaska Fairbanks and re-ceived his M.S. degree in 2013. His expertiseincludes reservoir engineering and productionoptimization. He has worked at BP in Anchorageand at InPetro Technologies in Houston as areservoir engineer.

Mohabbat Ahmadi � Department of Petro-leum Engineering, University of Alaska, Fair-banks, Alaska 99775; mahmadi@alaska.edu

Mohabbat Ahmadi received his petroleum en-

ABSTRACT

Umiat field in northern Alaska is a shallow, light-oil accumu-lation with an estimated original oil in place of more than 1.5billion bbl and 99 bcf associated gas. The field, discovered in1946, was never considered viable because it is shallow, inpermafrost, and far from any infrastructure. Modern drillingand production techniques now make Umiat a more attrac-tive target if the behavior of a rock, ice, and light oil system atlow pressure can be understood and simulated.

The Umiat reservoir consists of shoreface and deltaic sand-stones of the Cretaceous Nanushuk Formation deformed by athrust-related anticline. Depositional environment imparts astrong vertical and horizontal permeability anisotropy to thereservoir that may be further complicated by diagenesis andopen natural fractures.

Experimental and theoretical studies indicate that there isa significant reduction in the relative permeability of oil in thepresence of ice, with a maximum reduction when connatewater is fresh and less reduction when water is saline. A rep-resentative Umiat oil sample was reconstituted by comparingthe composition of a severely weathered Umiat fluid to a the-oretical Umiat fluid composition derived using the Pedersen

gineering degrees from Petroleum Universityof Technology in Iran (2003) and University ofTexas at Austin (2010) and has several yearsof industrial experience. He joined the University

Copyright ©2014. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received January 11, 2013; provisional acceptance May 30, 2013; revised manuscript receivedJuly 23, 2013; final acceptance August 20, 2013.DOI:10.1306/08201313011

AAPG Bulletin, v. 98, no. 3 (March 2014), pp. 563–585 563

of Alaska Fairbanks Petroleum EngineeringDepartment as an assistant professor in springof 2011, where he teaches undergraduate andgraduate courses in reservoir and gas engi-neering. His research includes CO2 enhanced oilrecovery and sequestration, reservoir simula-tion, and shale resource development.

Paul J. McCarthy � Department of Geologyand Geophysics, and Geophysical Institute,University of Alaska, Fairbanks, Alaska 99775;pjmccarthy@alaska.edu

Paul McCarthy received his B.Sc. and M.Sc. de-grees from the University of Western Ontarioand a Ph.D. from the University of Guelph,Canada (1995). After a postdoctoral fellowshipat the University of Western Ontario (1996–1999), he joined the faculty at the University ofAlaska Fairbanks where he is currently a pro-fessor of geology. His primary research interestsinclude paleopedology, paleoclimate, fluvialsedimentology, and nonmarine sequence stra-tigraphy of high-latitude Mesozoic alluvial de-posits in Alaska and western Canada.

Abhijit Dandekar � Department of Petro-leum Engineering, University of Alaska, Fair-banks, Alaska 99775; adandekar@alaska.edu

Abhijit Dandekar is currently a professor andchair of the Department of Petroleum Engi-neering at the University of Alaska Fairbanks. Heholds a B.Tech degree in chemical engineeringfrom Nagpur University, India, and a Ph.D. inpetroleum engineering from Heriot-Watt Uni-versity, Edinburgh, United Kingdom. Dandekarhas broad research interests that include gas toliquids, gas hydrates, viscous oils, wettabilityalteration, and CO2 sequestration.

Joanna Mongrain � Shell InternationalExploration and Production Inc., 200 NorthDairy Ashford, Houston, Texas 77079-1197;Joanna.Mongrain@shell.com

Joanna Mongrain received M.Chem. (1999) andM.Eng. (2000) degrees from the University ofOxford and Heriot Watt University, UnitedKingdom, respectively, before joining Conoco-Phillips as a reservoir engineer. She subsequentlyreceived a Ph.D. in geophysics from the Univer-sity of Alaska Fairbanks and was an assistantprofessor in petroleum engineering there until2012. Currently working for Shell in Houston, herwork and research interests are in enhancedoil recovery and carbon sequestration.

564 New Look at Umiat Field, Alaska

method. This sample was then used to determine fluid prop-erties at reservoir conditions such as bubble point pressure,viscosity, and density.

These geologic and engineering data were integrated intoa simulation model that indicate recoveries of 12%–15% canbe achieved over a 50-yr production period using cold gas in-jection from five well pads with a wagon-wheel configurationof multilateral wells.

INTRODUCTION

Shallow oil production in arctic regions must contend with avariety of unique production issues, including low, potentiallysubfreezing, reservoir temperatures. Consolidated reservoirslocated in permafrost (ground that has remained below 0°Cfor at least 2 yr) may have production challenges even if theoil is light and not biodegraded. While deemed uneconomicin the past, horizontal drilling technology and higher oil pricesmay make these shallow accumulations economic if the res-ervoir character and rock and fluid behavior under these lowtemperature and pressure conditions can be adequately un-derstood and managed.

Umiat field of the National Petroleum Reserve Alaska(Figure 1) is an example of such a shallow, light-oil accumu-lation where most of the reservoir is within permafrost. Umiatfield was discovered during the initial exploration of north-ern Alaska in the 1940s and 1950s (Collins, 1958), decadesbefore the discovery of Prudhoe Bay and the building of theTrans-Alaska Pipeline (TAPS). This unexploited accumula-tion is located approximately 140 km (87 mi) west of TAPSand about 180 km (112 mi) southwest of Prudhoe Bay, withno permanent road access and little infrastructure.

ElevenUmiat wells were drilled by theU.S. Navy between1945 and 1952 (Figure 2); an additional well, Husky Seabee 1,was drilled in 1978. Initial estimates of primary recoverablereserves ranged from 30 to more than 100 million bbl, with anaverage of about 70 million bbl (Baptist, 1960). Oil quality ishigh (37° API), but the reservoir is very shallow (275–1055 ft[84–322 m]), with part of the reservoir within the permafrost.Reservoir pressures are very low (~350 psi [2.4 MPa]), withsmall quantities of solution gas. No active aquifer support ex-ists because of small peizometric head in the area, and no gascap exists. Production was determined to be uneconomic be-cause of this low reservoir pressure as well as loss of permeabilitybecause of ice formation in and adjacent to the wellbore. These

Raelene Wentz � Department of Geologyand Geophysics, University of Alaska, Fair-banks, Alaska 99775; present address:Exploration Department, Sumitomo Metal Min-ing Pogo LLC, Delta Junction, Alaska 99737;Raelene.Wentz@smmpogo.com

Raelene Wentz received her B.Sc. degree fromWestern State College Gunnison, Colorado, andis working toward an M.Sc. degree from theUniversity of Alaska Fairbanks (2013). She iscurrently working as the senior supervisorygeologist at Sumitomo Pogo. Her primary areaof interest is structural geology and ore depositsin Alaska.

ACKNOWLEDGEMENTS

This study was funded by Department of Energycontract NT0005641 and was a cooperativestudy between the University of Alaska Fairbanks(UAF) and Renaissance Alaska and Linc Energy.We especially acknowledge A. Huckabay andV. Bangia, whose contributions in the earlyphases of the study were critical to its success.This work also benefited from discussions withO. Levi-Johnson, K. Venepalli, V. Godabrelidze,C. Shukla, C. Sanders, W. K. Wallace, A. AhmedKamel, and J. Demallie. Helicopter support forgeologic field studies was provided by the AlaskaDivision of Geological and Geophysical Sur-veys. IRAP geologic modeling software wasprovided by Roxar (now Emerson). We grate-fully acknowledge helpful reviews by B. L.Faulkner, W. A. Ambrose, J. L. Jensen, M. L.Sweet, S. Laubach, and an anonymous reviewer,all of whose comments greatly improved themanuscript.The AAPG Editor thanks the following reviewersfor their work on this paper: William A. Ambrose,Barbara L. Faulkner, Jerry L. Jensen, and ananonymous reviewer.

engineering and geologic challenges, combined with its remotelocation, have thus far precluded Umiat development.

Umiat field remained essentially abandoned until recently,when the advent ofmodern drilling and production techniquesmade Umiat and similar fields in northern Alaska more at-tractive exploration and production targets (Watt et al., 2010).Modern horizontal drilling techniques have opened the pos-sibility of developing such a shallow reservoir by drilling longhorizontal wells, which allow for accessing more of the reser-voir and, thus, reducing the required number of wells and thesurface footprint. However, the unusual reservoir conditionspose a significant challenge and source of uncertainty. Little isknown about how to produce light oil from a lithified, butfrozen, reservoir and no information exists on the flow be-havior of a rock, ice, and light oil system at low pressures, in-cluding the relative permeability of oil in the presence of ice.

This article summarizes the work of an interdisciplinaryteam of geoscientists and petroleum engineers to build anaccurate geologic model of the reservoir and collect low-temperature rock and fluid property data that were then usedto develop a robust simulation model of the field where po-tential production techniques could be evaluated. While nolonger frozen, the original cores from the Umiat legacy wells(Collins, 1958) provided a valuable subsurface database withwhich to evaluate the reservoir interval. Analyses of nearbysurface exposures of the reservoir interval were combinedwithmodern core descriptions to develop a high-resolution faciesmodel of the reservoir to assess both vertical and lateral var-iability within the reservoir. Cores and outcrops were evalu-ated to determine if natural fractures could be a factor in res-ervoir permeability. Experimental work on existing samplesof Umiat reservoir sandstones and on Berea sandstone sam-ples determined the relative permeability of oil and gas in thepresence of ice. Experimental and modeling work on the onlyremaining sample of Umiat fluid provided information onthe potential fluid properties of the Umiat oil at reservoirconditions. These data were integrated into a simulation modelto test the performance of cold-gas injection as a recoverytechnique.

GEOLOGY OF UMIAT FIELD

Umiat is a thrust-related anticline at the leading edge of theBrooks Range fold and thrust belt (Figures 1, 2), with thereservoir consisting of multiple wave-dominated shoreface

Hanks et al. 565

Figure 1. Geologic mapof northern Alaska. Umiatfield (star) is located atthe leading edge of theBrooks Range fold andthrust belt. Map is modi-fied from Moore et al.(1994).

Figure 2. Structurecontour map of the top ofGrandstand sandstone,Umiat field, showing loca-tion of legacy wells. Umiattest wells 1–11 were drilledby the U.S. Navy and/orcontractors starting in1945 (Umiat 1) and endingin 1952 (Umiat 11). HuskySeabee 1 was drilled onbehalf of the U.S. Navyand the U.S. GeologicalSurvey in 1978. AA′ showsthe location of the seismicline in Figure 7. Contourintervals = 500 ft (153 m).Map is based on seismicinterpretation provided byRenaissance Alaska Inc.

566 New Look at Umiat Field, Alaska

Figure 3. Stratigraphic context of the Nanushuk Formation and Umiat field. (A) Regional stratigraphy of northern Alaska, with theNanushuk Formation outlined in bold. Modified from Mull et al. (2003), courtesy of the U.S. Geological Survey. (B) Reservoir stratigraphicnomenclature for the Nanushuk Formation at Umiat field as used in Collins (1958) and illustrated using the Umiat 2 well. Umiat 2produced oil during the initial drilling operations.

and deltaic sandstones of the Cretaceous (Albian–Cenomanian) Nanushuk Formation (Molenaar,1982; Shimer et al., in press) (Figure 3). The Na-nushuk Formation is widespread in the subsurfaceof the North Slope and in outcrop along the BrooksRange fold and thrust belt (LePain et al., 2009) and

regionally consists of topset deltaic facies associ-ated with deep-marine mudstones of the TorokFormation (Houseknecht and Schenk, 2005). Al-though the Nanushuk Formation has been consid-ered largely deltaic, the formation varies consid-erably in character from west to east, reflecting

Hanks et al. 567

Figure 4. Nanushuk Formation stratigraphy at Umiat field. A south-to-north cross section across the central part of the field illustratesthe vertical and lateral facies distribution in the subsurface. The surface trace of the cross section is illustrated in the inset map. The lowerGrandstand (shoreface) is very continuous and relatively consistent in thickness, whereas the upper Grandstand (delta front) begins tothin and pinch out toward the north. Sandstones in the Chandler are more discontinuous and harder to predict. The known depths ofpermafrost during original drilling operations are depicted for Umiat wells 7, 6, 2, 5, and 4. Umiat 3 did not encounter permafrost.

changing source areas and the relative influence ofwave, storm, and deltaic processes on coastal de-position (Huffman et al., 1985; LePain et al., 2009;Shimer et al., in press). Seals are provided by in-ternal shales within the Nanushuk (shale barrierand shales within the Chandler; Figure 3). Thepermafrost itself may also be a seal or partial seal.The source of the Umiat oil is thought to be theCretaceous Torok Formation (Magoon and Bird,1985; Magoon et al., 2003).

568 New Look at Umiat Field, Alaska

CHARACTERIZATION OFRESERVOIR INTERVAL

Key to understanding the flowbehavior of theUmiatreservoir is determining the distribution and per-meability structure of the sandstones within thereservoir interval that are themain flow units as wellas the distribution and character of interlayered fine-grained rocks that act as internal flow barriers and/or baffles. Legacy cores, combined with surface

Table 1. Facies Associations Identified in Legacy Core and In Outcrop

FaciesAssociations Diagnostic Features

EnvironmentalInterpretation Depositional Processes

1 Laminated shale or bioturbated mudstone(Cruziana ichnofacies).

Offshore and Prodelta Suspension settling in the prodelta or themarine shelf near storm-wave base.

2 Interbedded bioturbated mudstone (Cruzianaichnofacies) and upward coarseninghummocky and swaley cross-stratified sand(Skolithos ichnofacies), with some sand bedsobliterated by bioturbation. Increasingamalgamation up well, with highlybioturbated beds (Skolithos ichnofacies).

Lower Shoreface Mixed-energy shelf, above storm-wavebase but below fair-weather-wavebase. Deposition by suspension settlingand storm-wave redistribution of sandand silt originally delivered to the coastby deltaic systems.

3 Low-angle, trough cross-stratified, andplane-laminated fine-grained sandstone.Rare bioturbation (Skolithos ichnofacies).

Upper Shoreface andForeshore

Subaqueous bar migration abovefair-weather-wave base, with someswash zone deposits.

4 Wavy and lenticular bedding with localsoft sediment deformation coarsens up intoripple cross-laminated and massive sand.Bioturbation intensity and diversity low.

Delta Front Progradation of distributary mouth barsinto muddy prodelta. Rapid depositionassociated with massive sand, softsediment deformation, low bioturbationindex.

5 Carbonaceous mudstone with brackish waterbivalve assemblage (Corbula), volcanic ashdeposits, and plant fossils.

Delta Plain Suspension settling in protectedinterdistributary bays or lagoons, withsome tidal influence, organic matteraccumulation in marshes or swamps.

Wavy bedding coarsens up into flaser beddingand ripple cross-laminated sandstone. Bedsare 5–10 ft thick. Mud drapes are commonin some sandstone beds, and are commonlysideritzed, especially in Umiat 11.Rare mudstone rip-up clasts.

Crevasse Sands Crevasse channel and splay depositsthat form during flood or avulsion intointerdistributary bays or the delta plain.Some tidal influence indicated by muddrapes.

observations, provide a valuable means of examin-ing sedimentologic, compositional, diagenetic, andstructural controls on the character of the reservoir.

The Nanushuk Formation at Umiat can be char-acterized as a mixed wave-dominated shoreface anddeltaic system subdivided into five informal units(from oldest to youngest): the lower Grandstandsandstone, the shale barrier, the upper Grandstandsandstone, the heterolithic sandstones and mud-stones of the Chandler, and the Ninuluk sandstones(Figures 3, 4). Six facies associations are recognizedin core and outcrop (Figure 4) (Table 1). These fa-cies associations best describe vertical facies re-lationships in cores and have unique porosity andhorizontal and vertical permeability profiles.

The lower Grandstand sandstone is the thickestsandstone interval with the best reservoir proper-

ties (Table 2). It is also the deepest part of thereservoir interval, would be the least affected bypermafrost, and have the highest initial reservoirpressures. For these reasons, the lower Grandstandis considered the primary reservoir target for initialdevelopment. The lowerGrandstand consists of twothick (90–150 ft [27–46 m]), upward-coarseningwave-influenced deltaic associations with an inter-vening 20–50-ft (6–15-m)-thick shale (Figure 5).These sands are consistent in thickness and charac-ter across the field, with the shale interval acting asan internal flow barrier (Figures 4, 5). Average po-rosity is 15%; average permeability is highest in theupper 20–40 ft (6–12 m) of the lower Grandstand,and reaches 90md in the Umiat 9 well. Permeabilityanisotropy (vertical permeability (Kv)/horizontal per-meability (Kh)) in the two sands averages 0.70.

Hanks et al. 569

Table 2. Reservoir Interval Properties, Umiat 9 and 11 Wells

Kh (md)** Kv (md)

Interval Thickness (ft) Net: Gross Porosity (Mean, %)* Mean Median Max Mean Median Max

Ninuluk† 120 0.83 13 10 3 59 4 3 17Chandler 315 0.16 14 – – – – – –

Upper Grandstand 130 0.73 12 28 4 293 73 23 337Shale barrier 210 0.09 – – – – – – –

Lower Grandstand 265 0.80 15 55 7 542 154 68 850

*Porosity was determined using published data sets (Collins, 1958).**Air permeability was determined from slabbed whole core using a handheld probe permeameter. Kh = horizontal permeability, measured parallel to bedding; Kv =

vertical permeability, measured perpendicular to bedding.†Data for the Ninuluk from the Umiat 11 well alone.

Increased permeability is clearly linked to increasedgrain size and probably related to increases in poresize and connectivity. The upper shoreface faciesassociation also implies higher wave energy, leadingto greater sorting and a lower degree of bioturbation,both of which limit the presence of impermeablemudstone laminations or burrow linings.

The lower Grandstand sandstones are overlainby a thick (290–335-ft [88–102-m]) shale infor-mally known as the shale barrier (Figure 4). Thisshale consists of offshore shallow-marine mudstoneswith thin, isolated sandstones. Although individualsandstones within this interval have good porosityand permeability, they are few in number, thin, andappear to be laterally discontinuous. Subsequently,this interval is considered a flow barrier with littlesignificant reservoir potential.

The upper Grandstand consists of a singleupward-coarsening, river-dominated deltaic sand-stone 35–80 ft (11–24m) thick (Figure 5). Like thelower Grandstand, the upper Grandstand can betraced across the Umiat anticline in the subsurfaceand even appears in the Umiat 1 well, 2 mi (3 km)west of the field (Shimer et al., in press). The upperGrandstand is less consistent in thickness acrossthe field than the lower Grandstand, however, andappears to become more heterolithic toward thenortheast along depositional dip (Figure 4). Theseobservations are consistent with the delta-frontorigin of the upper Grandstand. Coalesced distrib-utary mouth bar lobes in delta-front environmentsare known to cover several miles in lateral extent(Olariu and Bhttacharya, 2006), and although in-ternal heterogeneities may be created by variation

570 New Look at Umiat Field, Alaska

in sedimentary structures related to changes in flowregime, distributary mouth bars tend to merge andform broad strike-parallel sheets that may eventu-ally be bifurcated by delta channels up to 4 mi(6 km) apart (Tye and Hickey, 2001). These ob-servations support subsurface interpretations ofthe lateral extent of distributary mouth bar sand-stones in the upper Grandstand.

The upper Grandstand is at its thickest in thecentral part of the field, near theUmiat 2 and 5wells(Figure 2). These wells produced oil for a limitedtime during the drilling efforts in the 1940s–1950s(Collins, 1958). Like the lower Grandstand, thegreatest porosity and permeability in the upperGrandstand occurs in the upper part of the upward-coarsening succession. Average porosity and per-meability in the upper Grandstand in the Umiat 9well are 12% and 28 md, respectively. Permeabilityanisotropy (Kv/Kh) is high in comparison to thelower Grandstand, with a low average ratio of 0.05.Anisotropy in the upper Grandstand is affected byimpermeable lamination surfaces found on bed-ding planes,which are generally absent in the lowerGrandstand.

The permeability distribution in both of theGrandstand sandstones is further complicated bychanges in grain composition and diagenesis. Com-positionally, the Umiat reservoir sandstones arelithic arenites rich in feldspar and metamorphicrock fragments. The percentage of metamorphicfragments is inversely proportional to permeabil-ity, suggesting that winnowing of ductile phylliticgrains by high-energy shoreface deposits may bepartially responsible for an increase in porosity and

Figure 5. Stratigraphic columns from thick sandstones in the Umiat 9 well. (A) lower Grandstand sandstones; (B) upper Grandstandsandstones. Note that both horizontal (dark circles) and vertical permeabilities (open triangles) increase toward the top of facies as-sociations FA-3 (upper shoreface) and FA-4 (delta front). This effect may be controlled largely by grain size and its contribution to greaterintergranular porosity and pore-throat continuity. Other controlling factors could be type and abundance of diagenetic clays and cementsand the presence or absence of ductile lithic grains. (J. Davis, 2012, personal communication).

Hanks et al. 571

permeability at the top of Grandstand sandstones(Fox et al., 1979; Bartsch-Winkler, 1985; Huffmanet al., 1985). The dominant cement in these sand-stones consists of authigenic kaolinite and illite aswell as quartz overgrowths. Pore-filling authigenicminerals, such as kaolinite, also reduce porosity,whereas pore-lining authigenic minerals, such as il-lite andmicrocrystalline quartz, narrow pore throatsand reduce permeability. However, these authi-genic phases are not uniformly developed through-out the reservoir interval.

STRUCTURAL ANALYSIS

The Umiat structure is an east–southeast-trending,approximately 8-mi (12.9-km)-long, 2-mi (3.2-km)-wide, thrust-related anticline related to a detach-ment in the underlying Torok shale (Figures 2, 6).The Nanushuk topset sandstones overlying theTorok are deformed into an open asymmetric anti-cline bounded to the north by two thrust faults.Closure exists in both the hanging-wall and foot-wall parts of the fold.

Natural fractures could enhance permeabilityif open or block permeability if they are filled withice or cement. The existing vertical wells wouldnot be expected to intersect many fractures if thefractures are vertical and widely spaced. Despitethis, several vertical natural fractures were observedin core from Umiat field (e.g., Figure 7A). Severalof these fractures were filled with calcite cement;others had no cement. No surface ornamentationindicative of mode of opening was observed. Be-cause these legacy cores were not oriented andhave been allowed to thaw, the orientations of thefractures and the presence of ice within the frac-tures could not be determined.

Examination of nearby exposures of similarthrust-related anticlines indicates that at least twosets of fractures exist in the area and may occur atUmiat. A north–south-striking, near-vertical set ofopening-mode fractures are widely spaced (average58 cm [23 in.]), vertically extensive (average 60 cm[24 in.] in height) and are both calcite filled anduncemented. The north–south calcite-filled frac-tures are the most common fractures in exposures

572 New Look at Umiat Field, Alaska

nearest Umiat and are approximately orthogonal tothe structural grain, suggesting they may be partof a regional set of orogen-perpendicular exten-sion fractures seen elsewhere in the Brooks Range(Hanks et al., 2006; Duncan et al., 2012).

A second set of conjugate fractures commonlyobserved on the exposed anticlines are northeastand southeast striking, steeply dipping, and un-cemented (Figure 7B). The average spacing ofthese fractures is 43 cm (17 in.); the verticalextent is highly variable depending on locationand host lithology and ranges from 2 to 500 cm(0.8 to 197 in.). These fractures are interpreted tobe shear fractures based on abundant slickensideson fracture surfaces. The acute bisectors of thisconjugate set of fractures trend approximatelynorth–south, perpendicular to the host fold axes,suggesting that these fractures may be directlyrelated to these structures.

Unfortunately, exposures were not extensiveenough to develop a detailed evaluation of the re-lationship of the fracture character of each set withthe Nanushuk mechanical stratigraphy.

The lack of orientation data from the fracturesobserved in the Umiat core prevents directly as-signing these fractures to one of the sets observedin surface exposures. However, the occurrence ofcalcite cement in the fractures observed in the coresuggests that these fractures may be part of thenorth–south-striking, calcite-filled set of fracturesseen in nearby surface exposures. If so, this suggeststhat fractures in the subsurface at Umiat strikeapproximately north–south, are vertical, verticallyextensive, and widely spaced. If unfilled with cal-cite, these fractures are likely filled with ice in theupper part of the section, where the reservoir lies inthe permafrost. However, these same fractures maybe open (or partially open) below the permafrost, inthe lower Grandstand, and thus could contributeto permeability.

RESERVOIR MODEL ANDOIL-IN-PLACE ESTIMATES

A reservoir property model was constructed basedon published data from Umiat field (Levi-Johnson,

Figure 6. South–north vertical time slice through Umiat field. Top: uninterpreted; bottom: interpretation by G. Shimer. Vertical scale istwo-way time in seconds. LCU = lower Cretaceous unconformity. Location of seismic section shown in Figure 2. Seismic data courtesy ofRenaissance Alaska Inc.

2010) and subsequently modified to incorporatenew information and interpretations regardingsandstone distribution and permeability anisotropy(Figure 8). Geologic observations indicate that the

upper and lower Grandstand have distinct litho-facies, petrophysical properties, and permeabil-ity structure and should be treated separately. Inaddition, the lower Grandstand sandstone was

Hanks et al. 573

Figure 7. Natural fracture distribution at Umiat field. (A) Natural steeply dipping fracture (arrow) observed in core from the Umiat 11well. (B) Orientations of natural fractures in outcrops of correlative stratigraphy on similar structures near Umiat field. Map modifiedfrom Mull et al. (2004).

subdivided into upper and lower sandstones with anintervening shale that would act as a flow barrier.

The sandstones in this reservoir property modelhad a wide variability in porosity and permeabil-ity, which resulted in a wide range of water satu-rations at any given depth in the reservoir interval(Figure 9). To accommodate the subsequent vari-ation in oil saturation and to simplify the stocktank original-oil-in-place (STOOIP) calculation,

574 New Look at Umiat Field, Alaska

sandstones were subdivided into three differentpermeability classes and assigned different cap-illary pressure curves (Figure 9) (Table 3).

A single realization of this geologic model usingaverage observed porosity and water saturation val-ues yielded an estimated STOOIP of about 1.52billion bbl with 99 bcf associated gas. A MonteCarlo simulation evaluated the sensitivity of thisSTOOIP value to a range of porosities, initial water

Figure 8. Reservoirmodel of the Umiat field.Faults are not shown forclarity. The model is basedon seismic data providedby Renaissance Alaska,Inc., legacy well data, re-examination of legacycore, and examination ofnearby outcrops. Themodel was constructedusing the reservoir mod-eling software packageRoxar IRAP RMS. Modifiedfrom Levi-Johnson (2010).

saturations (Swi), bulk volume (Vb), net-to-grossratio (NTG), and oil formation volume factor (Bo)(Table 4). The results of this simulation yieldedSTOOIP estimations ranging from 750 to 2474 mil-lion bbl with a 50% probability (P50) value of 1550million bbl or greater (Figure 10).

FLUID PROPERTIES

The phase behavior of the Umiat fluid needs to bewell understood for a reservoir simulation to beaccurate. However, only a small amount (~6 oz.[~177 mL]) of Umiat oil was available; this oil was

collected in the 1940s and was severely weath-ered. The composition of this dead Umiat fluidwas characterized by gas chromatography. Thisanalysis was then compared to theoretical Umiatcomposition derived using the Pedersen meth-od (Pedersen et al., 1989) with original Umiatfluid properties published in the original reports(Table 5) (Figure 11). This comparison allowedestimation of the lost light hydrocarbon fractions.After addition of n-heptane through n-dodecane(to make up the lost light ends in the availableUmiat oil sample as seen in Figure 11), total massesof individual components single carbon number(SCN)C7 throughC12 were calculated (C13 through

Figure 9. Water satura-tion height for differentsandstone permeabilityclasses. Sandstone per-meability classes are de-fined in Table 3.

Hanks et al. 575

Table 3. Lower Grandstand Sandstone Permeability ClassesUsed in Simulation*

SandstonePermeability Class

PermeabilityRange (md)

RepresentativePermeability (md)

1 K < 1 0.4082 1 < K < 50 22.53 K > 50 100

*Sandstones were subdivided into three permeability classes based on permeabilityand assigned different capillary pressure curves in the simulation. These classesare independent of facies associations.

Table 4. Variable Ranges Used as Input to Monte Carlo Simu-lation of Stock Tank Oil-in-Place Calculations for Lower Grandstand

Input Variable Range

Initial water saturation (Swi) 0.35–0.45Net-to-gross (NTG) 0.1–0.7Reservoir volume (× 10+9 ft3) 36–56Porosity (%) 5.00–22.00Formation volume factor (Bo)(reservoir barrels of oil/standardcubic feet of gas)

1.001–1.05

C25+ remaining the same) and converted to moles.The individual component moles were then nor-malized to mole percent to obtain the molar com-position of the recreated dead oil sample. Thecompositional distribution by the Pedersen meth-od and the recreated dead oil sample, and the dataon density, viscosity, and molecular weight show agood match (Figure 11) (Table 5), indicating thesuccessful recreation of a physical as well as a nu-merical pseudorepresentative Umiat dead oil sam-ple. Differences are caused by the theoretical na-ture of the Pedersen method, the use of normalalkanes (e.g., the lost C7 fraction not being 100%alkane but instead amixture of paraffin, naphthene,and aromatics) to make up the lost light ends, andthe use of SCN fraction properties. The procedureis discussed in more detail in Shukla (2011).

The physically recreated dead oil sample wasthen recombined with solution gas to produce apseudolive oil sample, which was subsequentlyused for experimental PVT and phase behaviorstudies to determine fluid properties over therange of reservoir pressures and temperatures. Bub-ble point pressures of the Umiat pseudolive sam-ple agree with earlier measured values (Baptist,1960) and modeled values (Figure 12). All valuesare in agreement with each other with an aver-age absolute deviation of less than 6% and areanother indicator of a successful recreation of theUmiat dead oil sample and, subsequently, the liveoil sample.

The phase behavior of the live oil was simulatedusing the Peng-Robinson equation of state (EOS)(Figure 12; Robinson and Peng, 1978). The EOSmodel was tuned with measured experimental data

576 New Look at Umiat Field, Alaska

to accurately simulate the differential liberation teststo obtain the necessary data for reservoir simulationstudies, including bubble point pressure and oilviscosity (Table 6). The bubble point pressure ofthe reconstructed Umiat oil is 345 psi (2.4 MPa),suggesting that maintenance of reservoir pres-sures above that pressure will be important forany proposed production technique.

ROCK PROPERTIES AT LOW TEMPERATURES

Amajor part of predicting how the Umiat reservoirwill perform is determining the relative permeabil-ity of oil in the presence of ice. Early in the project,the University of Alaska Fairbanks (UAF) performedtwo-phase gas-oil relative permeability measure-ments on six sandstone samples from the remain-ing core from Umiat 11 under both frozen andunfrozen conditions (e.g., Figure 13; Godabrelidze,2010). For all the samples, the results indicated asignificant reduction in the relative permeability ofgas as well as oil under frozen conditions. When oilendpoint relative permeability is compared, thereduction ranges from40% to 92%,with an averagedecline of 61%. However, the range of reductionis much narrower (46%–57%) when core sampleshaving similar porosity, absolute permeability, andinitial water saturation are compared (Godabrelidze,2010). This suggests that other factors, such as dia-genesis, clay type and content, etc., probably havean effect.

To remove geologic variability as well as eval-uate the higher porosity Umiat sandstones, we

Figure 10. Result ofMonte Carlo simulation ofresource volumetricsbased on variable rangesin Table 4 and 10,000runs. OOIP = original oilin place in stock tankbarrels.

conducted similar experiments using Berea Sand-stone samples that had permeabilities similar tothat of the main reservoir facies (permeabilityclass 3, Table 3) (Venepalli, 2011). Berea sand-stone is widely used in experimental permeabil-ity work and is commercially available. In thesesamples, continuous reduction in oil endpointrelative permeability was observed when tem-peratures were reduced from 23°C to −10°C, withan average reduction of 44% when saturated withdeionized (DI) water and an average reduction of34% when saturated with water with salinitiesapproximating those in the Umiat reservoir(Figure 14). Although the two tested Berea sam-ples (cores 1 and 2) were of similar characteristics,their absolute permeabilities differed by about15%. Because the absolute permeability is used as abase permeability, this 15% difference contributesto the difference in oil endpoint relative perme-abilities measured for core 1 vs. core 2 (Figure 14)(Table 7). The calculated experimental error was4.2% (Venepalli, 2011), whereas the actual var-iation between the oil endpoint effective perme-

Table 5. Physical Properties of Umiat Dead Oil Samples

PropertyThis Work (Legacy

Umiat Dead Oil Sample)S

Density at 15.5°C and 14.7 psi 877.8 kg/m3

or 29.7° APIViscosity at 37.8°C and 14.7 psi 9.16 cPMolecular weight (kg/kg-mol) 245.00 N

*Estimated from the true boiling point (TBP) distillation data provided in Collins (1958)**Not measured, but calculated from the molar composition of recreated Umiat dead

ability of the two cores at different temperaturesand different water salinity was 6.3% (Table 7).This difference between the calculated experi-mental error and the actual variation can be in-terpreted as caused by textural differences be-tween the two Berea samples.

Fluid systems such as the ones studied in thiswork and shown in Figure 14 could be construedas a three-phase (ice, oil, and water) system; how-ever, assuming ice is immobile and the remainingunfrozen water is at irreducible saturation, the flowsystem reduces to merely a single-phase (oil) flowbecause only endpoints are compared. Based onthese results, Figure 14 and Table 7 suggest that thereduction of the relative permeability is stronglydependent on both the reservoir temperature andsalinity of connate water.

RESERVOIR SIMULATIONS

Low reservoir pressures will require pressure sup-port from the initial production of the field. No gas

chlumberger(2008)

Collins(1958)

This Work (RecreatedUmiat Dead Oil Sample)

874.9 kg/m3

or 30.2° API842.0 kg/m3

or 36.6° API836.0 kg/m3

or 37.6° API7.60 cP 2.90 cP 2.75 cP (at 39.95°C)

ot measured 184.17* 183.38**

.oil sample.

Hanks et al. 577

Figure 11. Molar com-positions of legacy Umiatoil determined by gas chro-matograph (GC) and theo-retically determined usingthe Pedersen method werecompared to determine theamount of light hydrocar-bons lost during degrada-tion of the legacy oil sample.This value was used to rec-reate an Umiat oil samplethat was then used to de-termine Umiat fluid proper-ties at reservoir conditions(e.g., Figure 12).

cap or indication of an active aquifer occurs; lowtemperatures preclude water injection as injectedwater would freeze and block permeability. Tomaintain thermal equilibrium with the permafrostfor wellbore stability, the desired pressure supportwill be provided by injection of cold lean naturalgas. Lean or dry gas refers to a gas that contains verysmall or almost no liquefiable hydrocarbon and iseasy to separate from produced oil, facilitating itsreuse. Gas will be sourced from undrilled under-

Figure 12. Comparison of themeasured bubble point pressureof the Umiat pseudolive oilsample at two different tem-peratures with that predicted byan untuned Peng-Robinsonequation of state (PR EOS), themeasured value reported byBaptist (1960), and the valuespredicted by two empirical cor-relations of Standing (1947) andVasquez and Beggs (1980). Allvalues are in agreement witheach other, with an average ab-solute deviation of less than 6%.This is another indicator of asuccessful recreation of theUmiat dead oil sample and,subsequently, the live oil sample.

578 New Look at Umiat Field, Alaska

lying accumulations in the Torok or from nearbygas fields. The gas will be injected at a reservoirtemperature of 26°F.

To prepare the simulation model, the geologicmodel was gridded horizontally into 200 × 200 ft2

(61 × 61 m2) grid blocks (Figure 8). To capturethe vertical heterogeneity present in the field, themodel was vertically subdivided into 32 grid lay-ers with thicknesses ranging from 5 ft (1.5 m) inthe sandstones to 45 ft (14 m) in the shales.

Table 6. Fluid Properties at Initial Reservoir Conditions Used to Initialize Simulation Model

Parameter Value Source

Oil density 52.1873 lb/ft3 Shukla (2011)Oil bubble point pressure 345 psi Shukla (2011)Gas density 0.04539 lb/ft3 Shukla (2011)Water phase density 62.4 lb/ft3

Water formation volume factor 1.002 rb/stb McCain (1990)Water compressibility 3.06 × 10−6 1/psi McCain (1990)Water viscosity 1.78 cp Beal (1964)Reservoir temperature 26°F Baptist (1960)Reservoir pressure 350 psi Baptist (1960)Reference depth 900 ft ArbitraryDepth of water/oil contact 1500 ft Linc Energy, 2012, personal communication

Initial simulations focused on the lower Grand-stand, which was identified as having the best res-ervoir properties and, as the deepest reservoir in-terval, could have the most reservoir accessed byhorizontal drilling while having the least amountof reservoir in the permafrost zone with the asso-ciated relative permeability reduction. This up-scaled model was initialized with the rock andfluid properties determined by the experimentaland theoretical work conducted earlier in thestudy (Table 6).

A wagon-wheel pattern was used in the sim-ulation as themost efficient means of accessing the

maximum amount of the reservoir interval whileminimizing the surface footprint (Figure 15). Inthe proposed pattern, five well pads will be locatedon the hangingwall of theUmiat structure, parallelto the strike of the fold. Each pad will consist ofone vertical well in the center with two dual lat-eral injectors in the north and south at the top ofthe target interval, the lower Grandstand. Thesefour injection legs will be supporting pressure foreight dual lateral producers (16 legs) at the bottomof the lower Grandstand, spaced at 36° intervals tothe east and west. The horizontal wells have a totallength of 3000 ft (914 m), with a 1500-ft (457-m)

Figure 13. Gas and oil relativepermeabilities of core plug 60 fromthe Umiat 11 well at −10°C and at22°C with water salinities reported byBaptist (1960). kro = oil relativepermeability; krg = gas relative per-meability. Core sample 60 is fromthe lower Grandstand sandstone,represents sandstone permeabilityclass 1 (Table 3), and shows an oilendpoint relative permeability re-duction of 46%. For all the testedsamples, the reduction ranges from40% to 92% with an average declineof 61%. The range of reduction ismuch narrower (46%–57%) for coresamples having similar porosity,absolute permeability, and initialwater saturation. Modified fromGodabrelidze (2010).

Hanks et al. 579

Figure 14. Relative oilpermeability vs. tempera-ture curves for two BereaSandstone cores for de-ionized (DI) and two salineformation waters. Experi-mental results from Umiatreservoir samples byGodabrelidze (2010) areincluded for comparisonpurposes. Modified fromVenepalli (2011).

horizontal leg, and a 4.5-in. (11.4-cm) open-holecompletion across the productive area. To reducesurface impact and the cost of infrastructure, onlyfive pad locations were used in the simulation, re-sulting in a total combination of 80 producers and25 injectors.

Three scenarios were evaluated in the simula-tion: cold gas injection with bottomhole injec-tion pressures (BHIP) of 400 and 600 psi (2.8 and4.1 MPa) and no gas injection. Higher injectionpressures were not considered because of the lowinitial reservoir pressures (350 psi [2.4 MPa]) andthe desire to avoid overpressuring and fracturingthe reservoir. Simulations were run for a projected50-yr lifespan. Because Umiat field was never pro-

Table 7. Comparison of Oil Endpoint Effective Permeabilities*

23°C 0°C

Core 1 Core 2 DFM% Core 1 Core 2 DFM

DI 81.2 87.2 7.1 67.3 79.9 17.1Salinity 1 90.5 93.2 2.9 87.6 82.5 6.0Salinity 2 88.1 89.9 2.0 87.2 83.7 4.1

*In millidarcys of the tested Berea sandstone samples (cores 1 and 2) in the temperaturThe average percent difference from the mean of the two cores at different tempVenepalli (2011). DFM = Difference from the mean.

580 New Look at Umiat Field, Alaska

duced, these simulations could not be refined usingdynamic data.

At the present time, the characteristics of theopen fracture network in the subsurface are notwell constrained, precluding the developmentof a discrete fracture network model of the reser-voir. Consequently, the impact of open fractures inthe lower Grandstand sandstone on flow was incor-porated by testing the sensitivity of the reservoirperformance to permeability anisotropy (Kv/Kh).

Simulation results indicate that recovery will besensitive to both injection pressure and permeabil-ity anisotropy (Figures 16, 17). As expected, thehigher the injection pressure, the higher the aver-age reservoir pressure and the more oil production.

−5°C −10°C

% Core 1 Core 2 DFM% Core 1 Core 2 DFM%

48.3 49.5 2.4 46.1 48.0 4.074.4 77.3 3.8 60.3 63.6 5.366.5 75.6 12.8 55.1 59.7 8.1

e range of 23°C to −10°C containing immobile DI, salinity 1, and salinity 2 water.eratures and different water salinity is 6.3%. Table constructed with data from

Figure 15. Example of wagon-wheel configuration used in thesimulation. Each pad has one vertical production well and onevertical injector. Producing legs consist of eight dual laterals (16legs) radially spaced to the east and west. Injecting legs consist ofone dual lateral injector (2 legs) to the north, and one dual lateralinjector (2 legs) to the south. Five pads spaced along the crest ofthe Umiat structure were used in the simulation.

Recovery over 50 yr using 400 psi (2.8 MPa) BHIPis approximately 12%, 15% for 600 psi (4.1 MPa)BHIP, and 8% for no gas injection.

Higher permeability anisotropies (low Kv/Kh)reduce the effectiveness of the cold gas injection,reducing recovery (Figure 17). This is probablycaused by reduced ability of the injected gas tocontact the reservoir away from the wellbore, re-ducing the sweep efficiency. The presence of openfractures would contribute to a high Kv/Kh ratio,leading to higher cumulative oil production.

DISCUSSION

TheUmiat reservoir sandstones consist of coarsening-upward successions of wave-dominated shorefacesandstones (lower Grandstand) and delta-front sand-stones (upper Grandstand). Porosity and perme-ability are best at the top of these successions. Per-meability anisotropy within these successions issignificant; compositional and diagenetic effects

further complicate the permeability structure ofthe sands. Intervening offshore mudstones of theshale barrier and a shale between the two sand-stones of the lower Grandstand act as effectiveflow barriers and vertically compartmentalize thereservoir.

Natural fractures are observed in both outcropsand in legacy core. Based on these observations,potentially conductive fractures in the subsurfaceare expected to be oriented approximately north–south, be approximately 100 cm (39 in.) in height,and widely spaced (~58 cm [~23 in.]). However,these fractures may be filled or partially with cal-cite cement; if not totally filledwith calcite cement,fractures will be filled with ice in the permafrostzone. Below the permafrost, unfilled or partiallyfilled fractures will improve north–south perme-ability within individual sand bodies but are notlikely to extend beyond the sand bodies and prob-ably will not provide vertical connectivity be-tween the two sandstones of the lower Grand-stand or between the lower and upper Grandstandintervals.

These geologic observations suggest that hor-izontal wells should target the upper part of themajor sandstones to target the zones of highestporosity and permeability. The average size of eachsand body is probably larger than the field size, sovariability in porosity and permeability with azi-muth is expected to be minimal across the field.However, production in horizontal legs will varywith azimuth if the observed north–south fracturesare open or partially cemented and contribute toflow. In this case, east–west-oriented horizontal legsmay be more susceptible to early gas breakthroughthan legs of other orientations.

Recovery will be reduced in those parts of thereservoir that reside in the permafrost zone andare at subfreezing temperatures because of a re-duction of relative permeability of oil in the pres-ence of ice by as much as 61%. However, lowerparts of the reservoir will be below the permafrostzone and, thus, will not see this reduction in relativepermeability. This, combined with the greater depthand greater thickness of the lower Grandstand sand-stones, makes the lower Grandstand sandstones theprimary focus of initial development.

Hanks et al. 581

Figure 16. Simulationresults for Umiat (lowerGrandstand) for differentbottomhole gas injectionpressures (BHIP) over a50-yr projected life span.(A) Cumulative oil pro-duction; (B) oil rate andproducing gas/oil ratio.

To reduce the surface footprint while acces-sing the maximum amount of the lower Grand-stand interval, development from five surface lo-cations on the hanging wall of the Umiat structureusing a wagon-wheel pattern of multilateral in-jectors and producers is being considered. No ac-tive aquifer support exists because of the smallpeizometric head in the area and no gas cap exists,so an alternative method of pressure support isneeded. Cold gas injection is being considered as aviable means of providing pressure maintenancewhile maintaining wellbore stability and reducingimpact on the permafrost. However, this is contin-gent on having a local source of gas. If a local source

582 New Look at Umiat Field, Alaska

of gas is not available, another type of gas couldbe considered to avoid disturbing the permafrostand, considering the relatively high vertical per-meability of the lower Grandstand, take advantageof the density difference between oil and gas. Acandidate alternative gasmay be flue gas, amixtureofmainly CO2 and nitrogen that could be generatedby burning a small amount of the produced oil.

Reservoir simulations predict that cold gas in-jection from a wagon-wheel pattern of multilateralinjectors and producers will yield 12%–15% re-covery of the estimated 1.5 billion bbl of STOOIPin the lower Grandstand sandstones. The lack ofproduction data and subsequent inability to refine

Figure 17. Simulation results showing variation in the Umiat oil rate (A) and cumulative oil production (B) for different permeabilityanisotropy ratios (Kv/Kh) over a 50-yr projected life span.

the simulation model via history matching increasesthe uncertainty inherent in these simulations. Con-sequently, the projected recovery rate will vary onseveral factors that are unconstrained at the pres-ent time, including the actual injection pressureused, the actualKv/Kh encountered, the presence ofconductive natural fractures, and the actual lateralvariability, continuity, and quality of the sandstones.

CONCLUSIONS

Umiat field was one of the earliest oil fields dis-covered in northern Alaska. Although the amountof estimated oil in place is significant (>1.5 billionbbl), development of the field was never consid-ered viable because it is shallow with low reservoirpressures, resides in the permafrost zone, and is farfrom any infrastructure. Horizontal drilling tech-niques now make the Umiat reservoir accessiblewith minimal surface footprint, but the low tem-peratures and pressures remain an engineeringchallenge.

The Umiat field consists of lithic sandstones ofthe Cretaceous Nanushuk Formation deformedby a thrust-related anticline above a detachment

in the underlying Torok shale. These Cretaceoussandstones consist of several coarsening-upwardshoreface successions separated by thick shalesthat are, in turn, overlain by deltaic sandstones. Po-rosity and permeability are greatest at the top ofthese successions, resulting in a significant per-meability anisotropy within each sand body. Thereservoir is further compartmentalized by the in-tervening shales. The negative effect of this per-meability structure may be offset by potentiallyconductive, north–south-striking natural fractures.

Experimental work indicates that a significantreduction in the relative permeability of oil in thepresence of ice should be expected in parts of thereservoir that reside in the permafrost zone, with amaximum reduction when connate water is freshand less reduction when water is saline. This re-duction in oil endpoint relative permeability maybe as much as 44% (fresh water) and 34% (salinewater) at −10°C. This reduction in relative per-meability should not affect the part of the Umiatreservoir that lies below the permafrost zone. This,combined with higher initial pressures, greater sand-stone thickness, and better porosity and permeabil-ity, resulted in the identification of the lower partof the Nanushuk, known in the subsurface as the

Hanks et al. 583

lower Grandstand sandstone, as the initial devel-opment target.

The low reservoir pressures require that pres-sure support will be needed from the beginning offield development. Injection of cold, locally avail-able lean or dry natural gas is the preferred initialpressure support mechanism to maintain reservoirtemperature and borehole stability. To reduce sur-face footprint, the initial development plans callfor five well pads with a wagon-wheel configura-tion of multilateral wells. Simulation models of thelower Grandstand interval test the efficacy of thispreferred production method and indicate thatrecoveries of 12%–15% can be achieved over a50-yr production period using this approach.

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