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Sequestration Potential Petroleum

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  • 8/11/2019 Sequestration Potential Petroleum



    Steven A. Smith, Energy & Environmental Research CenterRandolph B. Burke, North Dakota Geological SurveyLynn D. Helms, North Dakota Industrial Commission

    David W. Fischer, Fischer Oil and Gas, Inc.James A. Sorensen, Energy & Environmental Research Center

    Wesley D. Peck, Energy & Environmental Research CenterEdward N. Steadman, Energy & Environmental Research Center

    John A. Harju, Energy & Environmental Research Center

    September 2005


    The Plains CO2Reduction (PCOR)Partnership region has significant potentialfor carbon sequestration. While themethods employed in this study lookspecifically at the potential sequestrationcapacity of oil fields within the WillistonBasin, they can be used to determinereconnaissance-level sequestrationcapacity in any oil-producing region. Twomethods have been utilized to estimate

    capacity, one based on oil poolsundergoing enhanced oil recovery (EOR)and the other assuming that the reservoirpore space can be filled to capacity withcarbon dioxide (CO2). The focus of the workdescribed in this paper is to broadlycharacterize the potential CO2sequestration capacity of Williston Basinoil fields.

    This report will discuss the methods usedand provide some general quantitative

    values in determining the sequestrationcapacity of selected Williston Basin oilfields. These fields have been chosen basedon their cumulative production totals andare thought to possess the characteristicsthat will promote long-term storage of CO2.

    The objective of this work is to develop a

    method that can be used to choose sitesbased not only on EOR potential, but alsoon the CO2volume that can besequestered.

    Absent non-market-based incentives, CO2sequestration in many geologic sinks is notgenerally economically viable undercurrent market systems. However, EORmiscible flooding is a proven, economicallyviable technology for CO2sequestrationthat can provide a bridge to conducting

    non-EOR-based geologic sequestration. Forexample, a portion of the revenuegenerated by CO2EOR activities can payfor the infrastructure necessary for futuregeologic sequestration in brine formations.It is expected that unitized oil fieldssubjected to this type of recovery processshould retain all of the injected gas(including the amount recycled duringproduction) as a long-term storagesolution. The process of CO2injection withrespect to EOR has been engineered to

    reduce the amount of CO2needed forinjection while maximizing incremental oilproduction. One approach to implementinggeologic sequestration is to use the30 years of experience injecting CO2intoreservoirs in an effort to maximize CO2sequestration, with incremental


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    recovery becoming a benefit rather thanthe objective.

    As production matures, those fields thathave not yet been unitized and undergoneEOR or are considered depleted and

    abandoned become prime candidates forCO2sequestration. Sequestration can beaccomplished in these fields by initiatingEOR with CO2miscible flooding or bysimply considering the reservoir for storageand filling it to capacity. Withapproximately 1100 oil fields in theWilliston Basin region of the PCORPartnership, the potential CO2storagecapacity is significant.

    Based on the data available, North Dakota,Saskatchewan, and Manitoba unitized oilfields were chosen to study the potentialincremental oil recovery and subsequentCO2storage capacity resulting from EOR.Of the unitized fields examined, thepotential maximum storage value of CO2,in billion cubic feet (Bcf), for each of theseareas is listed here: North Dakota, 2095;Saskatchewan, 1515; and Manitoba, 319.

    This is equivalent to nearly 241 milliontons of CO2when combined. A more

    complete table of selected fields in each ofthese areas is given in the text.

    Fields were also looked at as potentialstorage areas for non-EOR-related CO2sequestration. The calculation is basedlargely on the pore volume of the reservoirthat can be filled with CO2. This gives amaximum storage potential for each fieldlooked at in the study area. As a generalreconnaissance, based on available data,oil pools in selected fields of North Dakota,

    Montana, and South Dakota wereexamined with the thought that themethod could be applied to any reservoirwith a competent top and bottom seal toget a rough estimate of storage capacity. Toillustrate the potential, the cumulative

    yearly production of CO2from sourceswithin a 150-mile radius centered atDickinson, North Dakota, is approaching45 million tons. The selected North Dakota

    pools (20) have the potential to holdapproximately 2.1 billion tons of CO2,based on the non-EOR CO2sequestrationmethod. This volume representsapproximately 47 years of the currentcumulative CO2emissions from 25 source



    The PCOR Partnership is a collaborativeeffort of public and private sectorstakeholders working toward a betterunderstanding of the technical andeconomic feasibility of capturing andstoring (sequestering) anthropogenic CO2emissions from stationary sources in thecentral interior of North America. It is oneof seven regional partnerships funded bythe U.S. Department of Energys (DOEs)National Energy Technology Laboratory(NETL) Regional Carbon SequestrationPartnership (RCSP) Program. The Energy &Environmental Research Center (EERC)would like to thank the following partnerswho provided funding, data, guidance,and/or experience to support the PCORPartnership:

    Alberta Department of Environment Alberta Energy and Utilities Board Alberta Energy Research Institute Amerada Hess Corporation Basin Electric Power Cooperative Bechtel Corporation Center for Energy and Economic

    Development (CEED) Chicago Climate Exchange Dakota Gasification Company Ducks Unlimited Canada Eagle Operating, Inc.

    Encore Acquisition Company Environment Canada Excelsior Energy Inc. Fischer Oil and Gas, Inc. Great Northern Power Development,

    LP Great River Energy Interstate Oil and Gas Compact

    Commission Kiewit Mining Group Inc.

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    Lignite Energy Council Manitoba Hydro Minnesota Pollution Control Agency Minnesota Power Minnkota Power Cooperative, Inc. MontanaDakota Utilities Co.

    Montana Department ofEnvironmental Quality

    Montana Public Service Commission Murex Petroleum Corporation Nexant, Inc. North Dakota Department of Health North Dakota Geological Survey North Dakota Industrial Commission

    Lignite Research, Development andMarketing Program

    North Dakota Industrial CommissionOil and Gas Division

    North Dakota Natural ResourcesTrust

    North Dakota Petroleum Council North Dakota State University Otter Tail Power Company Petroleum Technology Research

    Centre Petroleum Technology Transfer

    Council Prairie Public Television Saskatchewan Industry and

    Resources SaskPower Tesoro Refinery (Mandan) University of Regina U.S. Department of Energy U.S. Geological Survey Northern

    Prairie Wildlife Research Center Western Governors Association Xcel Energy

    The EERC also acknowledges the followingpeople who assisted in the review of this


    Erin M. OLeary, EERCEdward C. Murphy, North Dakota

    Geological SurveySteve G. Whittaker, Saskatchewan

    Industry and ResourcesKim M. Dickman, EERCStephanie L. Wolfe, EERC

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    As one of seven Regional CarbonSequestration Partnerships (RCSPs), thePlains CO2Reduction (PCOR) Partnershipis working to identify cost-effective carbon

    dioxide (CO2) sequestration systems for thePCOR Partnership region and, in futureefforts, to facilitate and manage thedemonstration and deployment of thesetechnologies. In this phase of the project,the PCOR Partnership is characterizing thetechnical issues, enhancing the publicsunderstanding of CO2sequestration,identifying the most promisingopportunities for sequestration in theregion, and detailing an action plan for thedemonstration of regional CO2sequestration opportunities.

    This report focuses on the sequestrationpotential of oil fields in the Williston Basin.Preliminary calculations, based on readilyavailable data sources, were made todetermine the quantity of CO2that couldpotentially be sequestered in pools that arecurrently in a distinct phase of production.For convenience, data were separated intothose fields that are undergoing enhanced

    oil recovery (EOR) and those that are not.The process involved in making adetermination of the characteristics thatmake specific geologic reservoirs within thePCOR Partnership region suitable for CO2sequestration is discussed in more detailin the following text.

    The results of this report are based on thepresent status of oil production in theWilliston Basin and primarily aims toprovide insight into the method used to

    determine how much CO2can potentiallybe sequestered in geologic reservoirs.

    Tables found throughout this report havebeen compiled from the regional analysisand are generally a reflection of the poolsthat have significant potential to beconsidered for CO2sequestration.


    Carbon sequestration through EOR is oneof the first mechanisms to be used as along-term strategy for reducinganthropogenic CO2from greenhouse gas

    emissions. The oil and gas industry hasbeen involved in EOR through miscibleCO2flooding for over 30 years. Thisknowledge has direct application to CO2sequestration. Based on rock and fluidproperties, it has been estimated thatabout 80% of the oil reservoirs worldwidewould be candidates for CO2injection(Kovscek, 2002). In response to this, thePCOR Partnership felt it was crucial toconsider this aspect of carbonsequestration a priority.

    As part of this study, it was necessary toperform a regional geologiccharacterization of many of the oil fieldswithin the Williston Basin. This wasaccomplished by gathering data fromreadily available public sources collected atstate agencies throughout the region.Immediately, it was found that the numberof oil fields in the three states and twoCanadian provinces of the Williston Basin

    would need to be pared down to amanageable number.

    Since many of the opportunities for CO2sequestration in the Williston Basin arelocated in North Dakota, and the NorthDakota PCOR Partnership partners affordus access to detailed data in North Dakota,much of this report deals with NorthDakota oil fields. While production datawere generally available, they were usuallycombined into cumulative field statistics.

    Future data collection efforts will need tosplit this into primary and secondaryproduction to determine reservoirperformance and response to recoverytechniques. As an initial screening criteria,those fields with a current cumulativeproduction of at least 800 thousandbarrels of oil (MBO) were selected to collectreservoir data on and, in turn, determine asequestration potential. For EOR, only

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    those unitized fields that have gonethrough, or are currently in, a secondaryrecovery phase were considered. Ingeneral, secondary performance data arenecessary to accurately predict tertiaryperformance.

    Several data sources listing the reservoircharacteristics for each state andCanadian province were compiled andcombined into a large spreadsheet (one foreach state and province). Thesespreadsheets include the key variablesneeded for evaluating the use of CO2EORand additional rock and fluid propertiesnecessary for determining geologicsequestration in depleted reservoirs.Because of the availability and ease of datacollection with respect to the geologicparameters needed, North Dakota wasused to illustrate both methods in thisstudy. To give a general characterization ofthe region, each additional state andprovince throughout the Williston Basin isrepresented by one of two methods.Further study will begin to identify specifictargets and determine whether a field issuitable for EOR or non-EOR CO2sequestration. This will include detailed

    production, reservoir, and geophysicalanalyses for identified targets.

    A discussion follows of the process used forthe identification and sequestrationcapacity of pools with suitable propertiesfor carbon sequestration through EOR inNorth Dakota. The approach applied hereis similar to that applied by Nelms andBurke (2004) in their evaluation of CO2EOR to North Dakota oil reservoirs. Theprocedures described in this report have

    been applied to each state and province(where applicable data were available) inthe Williston Basin area of the PCORPartnership region.

    Methods Used for CO2SequestrationCapacity Through EORData for North Dakota unitized oil poolswere acquired from the North DakotaIndustrial Commissions (NDICs) Web site

    (www.oilgas.nd.gov). All units consideredare at least in secondary recovery phase(water injection). The specific pools wereselected through a joint meeting betweenthe Energy & Environmental ResearchCenter (EERC) and the North Dakota Oil

    and Gas Division and the North DakotaGeological Survey (NDGS) (two NDICagencies) as being good candidates for CO2EOR. NDGS has been assessing all aspectsof the CO2sequestration problem as aresearch provider for the InternationalEnergy Agencys (IEAs) Weyburn CO2Monitoring and Storage Project (Burke,2003), including CO2injection for EOR toenhance production in the Williston Basin(Burke and Nelms, 2004a) which has beenthe emphasis of the Oil and Gas Division.Historically, this technique has beenengineered to reduce the amount of CO2needed for injection while maximizingincremental oil production. The objective ofthe method employed herein is to maximizethe volume of sequestration CO2. This willbe done using the knowledge gained frompast and present CO2studies coupled withproduction and injection histories. Thefollowing list of reservoir and fluidproperties was suggested by Bachu et al.

    (2004) and provides a simple guideline forscreening reservoirs for CO2EOR:

    Oil gravity between 27 and 48 API

    Temperature between 90 and 250F(32 and 121C)

    Reservoir pressure greater than1100 psi (77.3 kg/cm2)

    Pressure greater by at least 200 psi

    (14 kg/cm2

    ) than the minimummiscibility pressure (14502175 psi[102153 kg/cm2])

    Oil saturation greater than 25%

    This study considers these properties aswell as the overall production history of thefield, secondary recovery performance,depth to production, rock properties, and

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    characteristics of the produced fluid. Forexample, the average temperatures andpressures across the basin will exceedthese suggested values. For North Dakota,average reservoir temperature andpressure were found to be greater than

    200F (93C) and 4000 psi (281 kg/cm2),respectively.

    In trying to determine the sequestrationcapacity for the unitized pools, someassumptions had to be made. The firstmajor assumption was to simplify theprocess for projecting the oil recoverypotential from injection of CO2. Shaw andBachu (2002) noted that the oil productionincrease could be anticipated to bebetween 7% and 23% of the original oil inplace (OOIP) through successful miscibleflooding techniques, while Nelms andBurke (2004) suggest a value of 7% to11%. The spreadsheet used herein uses anaverage value of 12% recovery of the OOIP.Next, the quantity of CO2necessary torecover incremental oil was needed. Nelmsand Burke (2004) discuss the quantity ofCO2required for EOR. The purchaserequirement they used was 13 thousandcubic feet (13 Mcf) per barrel of oil

    recovered. Of this purchase quantity,about 3 to 5 Mcf per barrel of oil will berecovered at the surface and reinjectedafter separation. This evaluation uses8 Mcf per bbl incremental oil recovered.

    The total quantity of CO2injected fortertiary recovery should be the amount leftin the reservoir for long-term storage.Postproduction treatment of the reservoir,such as blowdown, will need to beevaluated to determine the effect on thefate of CO2storage. Table 1 lists 28

    unitized pools in North Dakota. It indicatesthe potential for EOR incremental oilrecovery as well as volume of CO2that canbe sequestered through the process.

    The calculation is as follows:

    Q = (OOIP) * (0.12) * (8000)

    Where:Q = CO2remaining in the reservoir afterflooding process is complete, ft3

    OOIP = Original oil in place, stb0.12 = Estimated recovery of oil from CO2flood, %

    8000 = CO2purchase requirement to produce1 barrel of oil from CO2flooding, ft3

    Currently, CO2-based EOR is unrealized inNorth Dakota, with one obstacle being theeconomics of delivering CO2to the injectionsite (Burke and Nelms, 2004a). CO2flooding is under way at the Weyburn Fieldin Saskatchewan and appears to besuccessful in recovering significantamounts of incremental oil (Hassan, 2004).

    With the progress of the research as part ofthe IEA Weyburn CO2Monitoring andStorage Project, the potential sequestrationof CO2through the use of EOR techniquesin the Williston Basin can be realized. Thepossibility of initiating CO2injection in theWilliston Basin may come from theindependent oil field operator interested intertiary recovery from fields located closeenough to the 200-mile stretch of pipelinebetween Beulah, North Dakota, and

    Weyburn, Saskatchewan. Figure 1 showsthe proximity of the selected North Dakotaunitized oil fields to the existing CO2pipeline.

    Sequestration in Oil Reservoirs NotCurrently Undergoing EORCarbon sequestration through EOR may beeconomically feasible in the near future ifcarbon storage credits become availableand, in turn, will help develop the networkof infrastructure necessary to transmit CO2

    throughout the Williston Basin. There areEOR operations in about 80 oil fields inNorth Dakota, primarily throughwaterflooding. This is about 15% of all thefields in the state, a number that willincrease as more operators move tosecondary recovery mechanisms. Asproduction within the basin matures, somefields that have not yet been unitized andundergone EOR, or are considered

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    Table 1. North Dakota Unitized Pools and Their Potential for CO2EOR and CO2Storage Capamounts of OOIP)

    NDIC Unit NameNDIC PoolUnitized


    OOIP,million stb

    CO2OilRecovery at12% NDIC

    OOIP, millionstb

    CO2 NeededUsing 8 Mcf/bblOil Recovered,




    Cedar Hills South Red River 'B' 360 43 346 3Tioga Madison 216 26 207 2

    Beaver Lodge Madison 172 21 165 1

    Big Stick Madison 166 20 159 1

    Fryburg HeathMadison 155 19 149 1

    Beaver Lodge Devonian 139 17 133 1

    Antelope Madison 100 12 96

    Newburg SpearfishCharles

    96 12 92

    Wiley Glenburn 96 12 92

    Blue Buttes Madison 93 11 89

    Charlson North Madison 80 10 77

    Rival Madison 79 9 76

    Dickinson Heath 62 7 59

    Medora HeathMadison 58 7 56

    North ElkhornRanch

    Madison 56 7 53

    Beaver Lodge Silurian 34 4 33

    Lignite Madison 33 4 31

    Rough Rider East Madison 31 4 30

    Clear Creek Madison 27 3 26

    Fryburg South Tyler 22 3 21

    Knutson Madison 19 2 18

    Beaver Lodge Ordovician 18 2 18 Antelope Devonian 16 2 16

    Mohall Madison 15 2 15

    Bear Creek Duperow 14 2 13

    Charlson South Madison 10 1 9

    Tracy Mountain Tyler 9 1 9

    Landa Madison 8 1 8

    Total Potential Storage in Selected Units 20

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    Figure 1. Selected North Dakota unitized oil fields and their potential EOR andsequestration capacity. This figure is based on the data presented in Table 1 and

    shows the proximity to the existing Dakota Gasification Company (DGC) CO2pipeline.


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    depleted and abandoned, may becomecandidates for CO2sequestration.Sequestration may be accomplished in theproducing pools of some of these fields byinitiating EOR with CO2miscible floodingor by considering the pool as a storage

    tank and filling it to capacity. The potentialfor sequestration continues to expandwhen the entire Williston Basin region andits approximately 1100 oil-producing fieldsare considered. While not the primary goal,injection into fields economicallyunsuitable for EOR can be engineeredtoward maximizing incremental oilproduction. Revenue from this could helpoffset the cost of CO2compression andtransmission (Kovscek, 2002). Themethods and criteria for determining thequantity of CO2that could be sequesteredper oil field are described in the followingsection.

    Methods Used for Geologic SequestrationCapacity in Currently Abandoned orDepleted Oil FieldsUsing the same production criterion of800 MBO (cumulative field production)that was used on the EOR pools, a detailedspreadsheet of geologic and fluidcharacteristics was developed for NorthDakota.

    Data for this spreadsheet were compiledfrom a number of sources, including Web-based data sets and data collection at state(Burke and Nelms, 2004b;www.state.nd.us/ndgs) and federalagencies. Each pool in a field appears as aunique entry in the database; some ofthese include unitized fields. This sameprocedure was used for pools in the

    Williston Basin region for which data wereavailable prior to the writing of this paper.In calculating the sequestration capacity,the following criteria were used:

    Field surface area Average pay thickness Average porosity Reservoir temperature Initial reservoir pressure

    Field area, thickness, and porosity wereused to determine the pore volume of theproducing reservoir. Reservoir temperatureand pressure were used to determine thedensity of CO2at reservoir conditions.

    These temperature and pressure values

    were used to determine reservoir suitabilityfor miscible flooding. Because there issignificant variability in temperature andpressure throughout the oil-producingformations in North Dakota, the resultingsequestration values are to be viewed as ageneral reconnaissance.

    The calculation is as follows:

    Q = (A) * (T) * () * (CO2

    ) * (1 Sw)

    Where:Q = Storage capacity of the oil reservoir, lbCO2A = Field area, ft2

    T = Producing interval thickness, ft= Average reservoir porosity, %


    = Density of CO2, lb/ft3

    (1 Sw) = Saturation of oil, where SWis theinitial reservoir water saturation, %

    This calculation yields the maximum storagecapacity of an oil-bearing reservoir in pounds(lbs) of CO2.

    The major assumption made for thesefields was that all of the fluid in thereservoir would be replaced with CO2,effectively giving the maximumsequestration volume. While actualsequestration volumes will be significantlyless, this means of developing approximatesequestration volumes has been used in

    prior studies (Bradshaw et al., 2004). Withfurther study, a more detailedunderstanding of the exact sequestrationcapacity of the basin can be accomplished.A list of 20 fields selected on sequestrationcapacity is shown in Table 2; they areillustrated in Figure 2 relative to theirproximity to the existing DGC pipeline.

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    Table 2. Selected North Dakota Oil Fields and Their Potential for CO2Sequestr

    Producing Pool2

    Field Name Group Formation Subformation

    Est. CO2Capacity, million


    Cedar Hills Big Horn Red River B 576

    Little Knife Big Horn Red River Nonspecific3

    278 Rough Rider Jefferson Duperow Nonspecific 103

    Mondak Big Horn Red River Nonspecific 102

    Beaver Lodge Big Horn Red River Nonspecific 89

    Beaver Lodge Madison Lodgepole Capa 83

    Rough Rider Madison Undesignated Nonspecific 79

    Cedar Creek Big Horn Red River Nonspecific 79

    Charlson Madison Undesignated Nonspecific 74

    Rough Rider Madison Mission Canyon Nesson 72

    Charlson Jefferson Birdbear/DuperowNonspecific 64Beaver Lodge Madison Undesignated Nonspecific 64

    Charlson Jefferson BirdBear Nisku 63

    Rocky Ridge Minnelusa Tyler Heath 61

    Charlson Nonspecific Interlake Nonspecific 60

    Bicentennial Madison Mission Canyon Nonspecific 58

    Fryburg Madison Mission Canyon Nonspecific 55

    Mondak Jefferson Duperow Nonspecific 50

    Tioga Madison Undesignated Nonspecific 49

    Blue Buttes Big Horn Stonewall Nonspecific 49 Total Potential Storage in Selected Pools 2106 1 This table is a representation of the potential for sequestration in an entire field, assumin

    pore space will be filled with CO2.

    2 Pool is a unit of production within a field. An oil field may consist of one or more pools.3 The authors have applied the term nonspecific to pools for which no subformation name

    available data.

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    Figure 2. Selected North Dakota oil fields showing the estimated maximum CO2volume thatcan be sequestered. This is calculated using entire field area, thickness of the producing

    interval, porosity, and CO2density. The DGC pipeline is also shown.


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    As mentioned previously, the methods fordetermining sequestration capacitiesthrough EOR and geologic sequestration

    were used throughout the Williston Basin.These fields were chosen on theircumulative production histories and thegeologic parameters that make themsuitable for CO2storage. While fieldsthroughout the region are in varying stagesof recovery and are either unitized ornonunitized, the following sections provideexamples of the methods used todetermine sequestration capacities. As thisproject progresses, more detailed studieswill be completed, and individual fields willbe geologically and economicallycharacterized to determine their potentialfor sequestration and EOR. A shortexplanation of the data presented for eachadditional state and Canadian province ispresented below.

    South DakotaWhile several fields in South Dakota wereconsidered, only the Buffalo Field wasselected for this study. Cumulativeproduction in the state is approaching40 million barrels of oil (MMBO) fromwhich nearly 30 MMBO comes from thisfield. With only the southern edge of theWilliston Basin extending into SouthDakota, most of the production occurs tothe north. This does not lessen theopportunities for EOR and sequestrationthrough CO2flooding in the area. TheBuffalo Field is undergoing a high-pressure

    air injection flood (fireflood), which hasincreased production dramatically. Similarpotential for increased production may bepossible using CO2, without the risk ofdamaging the reservoir. Table 3 shows thepotential for CO2sequestration in the

    Buffalo Field. Because this field is under afireflood method of tertiary recovery, asequestration-only calculation was usedthat assumed all the available pore spacewould be filled with CO2.

    MontanaCumulative production was used to choosefields for sequestration in Montana. Whilemany of these fields are usingwaterflooding and other techniques as atertiary recovery mechanism and, in turn,have been unitized, a sequestration-onlycalculation was used to determine thesequestration capacities. This was donebecause of data availability and ease ofcollection at the time of this study. Many ofthe reservoir characteristics necessary forthe calculations were available on thenonunitized pools but not on thesubsequent unitized pools. Asdemonstrated with the North Dakotaexamples, the two methods differ with

    respect to the variables needed to performthe calculation. Both methods can beapplied in Montana; however, at the timeof this study, the OOIP for the unitizedpools had not been obtained. With moredetailed studies, the characteristics for theunits can be obtained and a figure for EORpotential given. It is clear with the currentlevel of production and drilling activity that

    Table 3. South Dakota Buffalo Field and Its Potential for CO2Sequestration1

    Producing Pool

    Field Name Group Formation Subformation

    Est. CO2Capacity, million


    Est.SequestrationCapacity, Bcf

    Buffalo Big Horn Red River Nonspecific 69 11311This table is a representation of the potential for sequestration in an entire field, assuming that 100% of

    the pore space will be filled with CO2.

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    Table 4. Montana Oil Fields and Their Potential for CO2Sequestration1

    Producing PoolField Name Group Formation Subformation

    Est. CO2Capacity,million tons

    Pine Interlake Nonspecific 184

    Kevin- Sunburst

    Nisku/Madison/Sawtooth Nonspecific 114

    Little BeaverEast

    Big Horn Red River Nonspecific 104

    Pine Big Horn Red River Nonspecific 99

    Bell Creek Cretaceous Muddy Nonspecific 93

    Cabin Creek Interlake Nonspecific 75

    Poplar East Madison Madison A, B, and C 72

    Little Beaver Big Horn Red River Nonspecific 71

    Cabin Creek Interlake Horst Block 66

    Sioux PassNorth

    Mission Canyon,Nisku

    Nonspecific 53

    Poplar, East Madison Charles B 52

    Cabin Creek Big Horn Red River Nonspecific 49

    Dwyer Big Horn Red River Nonspecific 46

    Pennel Interlake Nonspecific 39

    Cabin Creek Madison Madison Mission Canyon 39

    Cabin Creek Interlake East Block 38

    Cabin Creek Red RiverInterlake Nonspecific 37

    Cabin Creek Madison Madison Horst Block 36

    Monarch Interlake, Red River Nonspecific 34

    Pennel Big Horn Red River Nonspecific 33

    Total Potential Storage in Selected Pools 1333 1 This table is a representation of the potential for sequestration in an entire field, assuming that 1

    be filled with CO2.

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    Table 5. Manitoba Unitized Pools and Their Potential for CO2EOR and CO2Storage Capapercentages of the estimated OOIP)

    FieldName Formation Unit

    Original Oilin Place,

    million stb

    CO2OilRecovery at12% OOIP,million stb

    CO2Needed Using8 Mcf/bbl OilRecovered, Bcf

    Waskada LowerAmaranth A



    149 18 143

    Pierson LowerAmaranth

    MissionCanyon 3b A



    70 8 67

    Daly Lodgepole A CombinedDaly Units

    110 13 106

    Daly Bakken A CombinedKola Units

    4 0.4 3

    Total Potential Storage in Selected Units

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    Table 6. Selected Saskatchewan Unitized Pools and Their Potential for CO2EOR and CO2Storage Capacity (based on the amounts of estimated OOIP)

    Field Name Formation Unit

    Original Oilin Place,

    million stb

    CO2OilRecovery at12% OOIP,

    million stb

    CO2 NeededUsing 8 Mcf/bblOil Recovered,







    tonsSteelman Midale Combined

    Midale Units697 842 669 669 41

    Midale Midale CombinedMidale Units

    538 65 516 516 32

    Pinto Midale CombinedMidale Units

    124 15 119 119 7

    Steelman Frobisher CombinedFrobisher


    113 14 109 109 7

    Workman Frobisher CombinedFrobisher


    43 5 41 41 3

    Midale Frobisher CombinedCentral


    38 5 37 37 2

    Workman Midale CombinedMidale Units

    12 1 11 11 1

    Pinto Frobisher CombinedFrobisher


    7 1 7 7 0.4

    Tableland Winnipegosis Winnipegosis 4 0.5 4 4 0.2

    Benson Midale Combined

    Midale Units

    1 0.2 1 1 0.1

    Total Potential Storage in Selected Units 1515 93

    the Montana portion of the Williston Basinholds significant reserves. With theinstallation of the infrastructure for CO2transmission, the recovery of thesereserves may become reality. Table 4shows the selected Montana fields andtheir producing formations, with theirapproximate sequestration capacity.

    ManitobaManitobas CO2sequestration capacity isbased on the OOIP figures for the best-producing unitized pools. The methodologyused here is the same as on the NorthDakota units. Table 5 shows the combinedselected Manitoba unitized pools and theirEOR and sequestration potentials.

    SaskatchewanCO2sequestration is being tested inSaskatchewan by the IEA Weyburn CO2Monitoring and Storage Project. It isestimated that approximately22 million metric tons of CO2will beinjected into the Mississippian Midalereservoir of the Weyburn Field. The resultof injection will be the net storage ofapproximately 15 million metric tons whenconsidering the combustion of the oilproduced by the flood and the CO2produced in compression and transmissionof CO2to the site (Whittaker, 2004). Withthis in mind, it was decided to look atseveral additional unitized oil fields that

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    traverse the Saskatchewan portion of theWilliston Basin to calculate their CO2sequestration potential. A general crosssection across the Saskatchewan portion ofthe Williston Basin was chosen, and thelarger fields were evaluated based on OOIP

    value. The method for the calculationremains the same as that used in theNorth Dakota study area.

    Table 6 shows the quantities determinedfrom the calculation and is based on datacollected from the 2002 Reservoir Annualproduced by Saskatchewan Energy andMines (Reservoir Annual, 2002).

    Key Issues to ConsiderThe volumes of potentially sequestered CO2determined here are generalreconnaissance values. Actualsequestration volumes will be significantlysmaller. To calculate a more exactsequestration capacity for a reservoir, asystematic analysis, including detailedgeologic characterization, productionhistory, and modeling efforts, is necessary.Detailed geologic and engineeringcharacterization, including field studiesand modeling on the level that is necessary

    prior to unitization and secondaryrecovery, is required. Specifically, adetailed production history, includingupdated OOIP, projected cumulativeprimary and cumulative secondaryrecovery, injection statistics, andproduced-water chemistry must beobtained. In addition, from a regulatoryand royalty standpoint, a detailed protocolregarding mineral value will need to bedeveloped prior to permanentsequestration in abandoned fields and

    units. The protocol will include 1) value tomineral owners for produced fluid, 2) valueto mineral owners for storage, 3) liability inownership of sequestered CO2, and4) liability for leakage through preexistingproperly and improperly abandoned wellbores. These risk assessment andeconomic feasibility studies will need to bepart of a thorough evaluation.

    Furthermore, CO2source proximity,availability, and industry support must beconsidered as crucial aspects to geologicsequestration.


    Williston Basin oil reservoirs havesignificant potential for carbonsequestration. The storage capacity for thepools on which the nonunitized methodwas done is approximately 3.5 billion tons.

    This represents a capacity of 78 years ofannual emissions from stationary sourcesthroughout the Williston Basin.

    Screening criteria for field candidates werebased on primary recovery of the oilreservoir. Fields that have been unitizedand initiated a secondary phase of recoveryare considered good candidates for CO2sequestration through EOR. It is expectedthat all of the injected gas will remain inthe reservoir for long-term storage whentertiary recovery ends. The remainingnonunitized fields may be excellentcandidates for additional storage and couldpotentially have the fluid in the pore spacereplaced by CO2, with revenue from any

    incremental oil recovery helping to offsetthe cost of injection.

    North Dakota, Saskatchewan, andManitoba unitized oil field data wereavailable to study the potential incrementaloil recovery and subsequent CO2storagecapacity resulting from EOR. Theremaining states were looked at for storageafter tertiary recovery ends. Table 7illustrates the cumulative potentialsequestration values for the selected fields

    referred to in the text. As mentionedpreviously, these general estimatesillustrate the methods used in thecalculation. With further study, a muchmore detailed approximation ofsequestration capacity can be attained.

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    Table 7. Cumulative Totals from Previous Tables Showing the Method Used andthe Conversion from Bcf to Metric Tons

    CumulativeTotal forSelectedFields

    CO2RetentionPotential, Bcf,nonunitized


    CO2RetentionPotential, milliontons, nonunitized


    CO2RetentionPotential, Bcf,


    CO2RetentionPotential, million

    tons, unitizedmethod

    North Dakota 34,356 2106 2095 128

    South Dakota 1131 69

    Montana 21,734 1333

    Manitoba 319 19

    Saskatchewan 1515 93


    Bachu, S., Shaw, J.C., and Pearson, R.M.,2004, Estimation of oil recovery andCO2storage capacity in CO2EORincorporating the effect of underlyingaquifers: Society of PetroleumEngineers Paper 89340, p. 113.

    Bradshaw, J., Allinson, G., Bradshaw,B.E., Nguyen, V., Rigg, A.J., Spencer,L., and Wilson, P., 2004, AustraliasCO2geological storage potential and

    matching of emission sources topotential sinks: Australian PetroleumCooperative Research Centre (APCRC)Web site, www.apcrc.com.au(accessed

    July 2004).

    Burke, R., 2003, An international researchproject with significant economicimplications to North Dakota and theWorldNDGS provides part of geologicframework for Weyburn Project: NorthDakota Geological Survey Newsletter,

    v. 29, no. 2, p. 14.

    Burke, R.B., and Nelms, R., 2004, Is CO2enhanced oil recovery technologyapplicable for recovering additionalNorth Dakota oil reserves: NorthDakota Geological Survey Newsletter,v. 31, no. 1, p. 1011.

    Burke, R., and Nelms, R., 2004b, Geologic,

    petrophysical and engineeringspreadsheet for North Dakota oil fieldunits: North Dakota Geological SurveyNewsletter, v. 31, no.1, p.1314.

    Hassan, D., ENCANA, 2004, personalcommunication, May 17, 2004.

    Kovscek, A.R., 2002, Screening criteria forCO2storage in oil reservoirs: PetroleumScience and Technology, v. 20, nos. 7and 8, p. 841866.

    Nelms, R.L., and Burke, R.B., 2004,Evaluation of oil reservoircharacteristics to assess North Dakotacarbon dioxide miscible floodingpotential, Williston Basin HorizontalWell and Petroleum Conference, 12th,Minot, North Dakota, May 24,Proceedings: p. G1G11.

    North Dakota Industrial Commission Oiland Gas Division, 2004, www.oilgas.nd.

    gov(accessed March 2004).

    Reservoir Annual, 2002, SaskatchewanEnergy and Mines, MiscellaneousReport 93-1, ISSN 0707-2562.

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