eor screening for ekofisk-2000

Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE European Petroleum Conference heldin Paris, France, 24–25 October 2000.

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ABSTRACTAn investigation of alternative EOR processes havingpotential application in the giant Ekofisk chalk field ispresented. Technical feasibility, process readiness, oilrecovery potential, and related uncertainties and risks of fiveselected EOR processes, namely hydrocarbon (HC) WAG,nitrogen (N2) WAG, carbon dioxide (CO2) WAG, airinjection and microbial EOR (MEOR), are assessed forpossible application at Ekofisk. The objective of thescreening study was to evaluate and rank the EORalternatives and to select the most attractive process(es) onwhich to pursue further work toward possible field pilottesting. The focus of the paper is on the technical assessmentof the relative oil recovery potential of each process, and onthe importance of identifying critical operational andlogistical considerations for implementation of an EORprocesses in the offshore North Sea operating environment.

Estimates of potential EOR incremental oil recovery forthe Ekofisk field can be quite significant. However, keyproject development and implementation issues andadditional cost elements must be weighed equally with oilrecovery forecasts in any EOR process ranking. Some ofthese issues (e.g. injection gas supply, facilitiesrequirements, and the impact of EOR on chalk compaction,subsidence and wellbore integrity) may be significantenough to eliminate a process from further consideration.

In addition, there are significant differences in thequantity and quality of key laboratory and field datasupporting the viability of the various EOR processes beingconsidered. Only a limited amount of field-specific data areavailable to calibrate the performance predictions for someof the processes. There is also a wide variation in thetechnical readiness of each process to begin field pilotdesign studies. Table 1 summarizes the state of technicalreadiness for field implementation of each process andidentifies some of the major risk elements and remainingwork required to progress these EOR processes at Ekofisk.

BACKGROUNDThe Ekofisk Field is located in the Norwegian Sector of theNorth Sea, Figure 1. The reservoir is an elongated anticlinewith the major axis running North-South covering roughly12,000 acres, Figure 2. It produces from two fractured chalkhorizons, the Ekofisk and Tor Formations, separated by atight zone. The overlying Ekofisk Formation has a depth ofabout 9,600 feet and thickness varies from 350 - 500 feetwith porosities from less than 30% to 48%. The underlyingTor Formation thickness varies from 250 - 500 feet withporosities from less than 30% to 40%. About two thirds ofthe 6.4 billion STB OOIP is in the Ekofisk Formation. Theinitial reservoir pressure was 7135 psia at a depth of 10,400feet. The field initially contained an undersaturated volatileoil with a bubble point pressure of 5560 psia at thetemperature of 268°F.

Ekofisk1 was discovered in 1969 and test production wasstarted in 1971 from the discovery well and three appraisalwells. Commercial test rates prompted development of thefield from three platforms. Permanent facilities with 54 wellslots and 300,000 STB/D (design capacity) process facilitieswere operational in May 1974. Development drilling wasstarted June 1974. Oil production peaked at 350,000 STB/Din October 1976. Produced gas was reinjected2 until a gaspipeline was installed to Emden, Germany, September 1977.

Figure 1. Map of North Sea with Ekofisk location.

SPE 65124

EOR Screening for EkofiskT.B. Jensen, K.J. Harpole, and A. Østhus, Phillips Petroleum Company

2 T.B. JENSEN, K.J. HARPOLE, A. ØSTHUS SPE 65124

Figure 2. Top structure map for Ekofisk field

Ekofisk went through the bubble point in 1976 and GORwent from 1,500 to 9,000 SCF/STB by 1986. Primarydepletion recovery (with reinjection of gas in excess ofcontract quantities) was initially estimated to be 18% ofOOIP of which 6-8% was produced above bubble point.Improved recovery studies were initiated soon after start ofprimary production.3 Favorable water imbibition resultsprompted a decision in 1983 to waterflood the northern TorFormation using unheated, 42°F, seawater. A 30 slot waterinjection platform with 375,000 BWPD injection capacitywas approved. Water injection started in 1987 to develop162 MMBOE. Favorable waterflood response promptedfieldwide water-flood expansion4. Water injection capacitywas increased to 820,000 BWPD which added almost 300MMBOE.

Reservoir compaction and seabed subsidence continue tobe a very important consideration in Ekofisk reservoirmanagement strategy. A 1992 field study5 concluded that theoptimum strategy for Ekofisk would be to minimize futureseabed subsidence by arresting pressure decline withpressure maintenance. Due to the age of the Ekofiskfacilities and continued seabed subsidence, a decision wasmade in 1994 to gradually phase out existing facilities andinstall a new 50 slot wellhead platform and new process andtransportation facilities. Drilling from the new wellheadplatform started in October 1996. The new process andtransportation facilities were commissioned in August 1998.

The current ultimate oil recovery estimate from Ekofiskis 38% of OOIP. The increase in recovery from the initialestimate of 18% is due primarily to the extensive waterflooding, implementation of effective well monitoring andstimulation techniques, compaction drive, aggressive infilldrilling, the Ekofisk redevelopment and extended field life,and overall field optimization.

Current plans for Ekofisk include continued waterinjection until 2012. At that point water injection will cease,and the field will be depressurized to the end of the licenseperiod in 2028. Opportunities to optimize the waterfloodwith continued infill drilling exist. Also, a majorrecompletion/sidetrack program is being evaluated for anumber of existing water injection wells. This ongoingoptimization of the Ekofisk waterflood has the potential forsignificant incremental oil recovery. Opportunities also existfor optimization of reserves during blowdown, beingprimarily associated with acceleration of reserves withadditional production wells and enhanced compaction drivedue to pressure depletion. Enhanced recovery methods alsocontinue to be investigated as means of significantlyincreasing reserves and accelerating recovery.

Several enhanced oil recovery (EOR) methods have beenconsidered for improving oil recovery beyond the Ekofiskwaterflood scenario. Recognizing that 1% enhanced oilrecovery represents about 64 million barrels of oil onEkofisk, significant resources have been used in studyingvarious EOR processes. Crestal gas injection, mainly foroperational swing gas purposes, has been ongoing since1975. A total of 1.3 TSCF of gas, around 21% of thecumulative produced gas, has been reinjected in Ekofisk asof June 2000. Analysis of early production behavior abovethe bubble point suggest that no immediate production offree gas was experienced. Less than 1% of the injectedtracers were recovered following gas tracer injection tests in1986 to 1988 which led to the conclusion that the injectedgas has covered a large area. Review of well performancebelow the bubble point pressure has provided little clearevidence of oil production response to variation in gasinjection rates. Based on numerous laboratory evaluations ofoil phase continuity and field performance the assumption ofcapillary continuity has been used in modeling work toevaluate gas injection processes.

A major crestal nitrogen injection study6 was completedin the late 1980’s. Project economics were not favorable,due mainly to the significant costs of nitrogen rejection fromthe gas sales stream. Efforts were also put into a study ofenhanced imbibition processes in the mid 1990’s in order todetermine the potential for increased oil recovery byinjection of low concentration surfactants. The project wasterminated in 1997 due to laboratory measurements of highsurfactant adsorption, especially at the reduced reservoirtemperatures around existing Ekofisk water injection wells.

WAG processes have been evaluated in the laboratory,through mechanistic simulations, and in one limited fieldinjection test at Ekofisk. A single-well WAG pilot test wasinitiated in 1996 to test hydrocarbon gas injectivity into anEkofisk well which had injected a total of 44 million barrelsof water since 1991. Gas injection rates dropped to zero in amatter of hours. Subsequent analysis of the injection testshowed that hydrate formation in the cold region around the

SPE 65124 EOR SCREENING FOR EKOFISK 3

injector was the most likely reason for the loss of gasinjectivity. Various remedial measures are underconsiderations for gas injection in a possible futurehydrocarbon WAG scenario.

APPROACH AND PREMISESIn 1998 the decision was made to conduct a broad

scoping study to assess enhanced oil recovery potential forthe Ekofisk Field. The objective was to evaluate and rankvarious EOR alternatives and to select the most attractiveprocess(es) on which to pursue further work toward possiblefield pilot testing. Two underlying premises were adopted inthe approach to evaluating EOR alternatives for Ekofisk.First, in the absence of definitive data to the contrary, anyminor technical or logistical uncertainties were assumed tobe favorably resolved prior to process implementation.Second, in the absence of sufficient Ekofisk-specificlaboratory or field performance data, EOR processperformance in the Ekofisk reservoir was assumed to beconsistent with typical performance demonstrated in otherfield applications or calculated based on industry field andlaboratory performance data. One consequence of thesepremises is that those less mature, emerging technologies(i.e. MEOR and air injection) may tend to be representedmore favorably relative to the more extensively studied andtested technologies (HC WAG) where process performanceis more constrained by Ekofisk-specific lab testing and/orfield performance data.

Injectant Contact with Waterflood Residual OilOne of the key issues determining incremental oil

recovery by any EOR process being considered forapplication at Ekofisk is the ability of the EOR injectant tocontact and mobilize waterflood residual oil in the fracturedchalk. The premise for the process performance modelingused to generate the forecasts in this screening study is thatinjected gas will be able to move into the chalk matrix tocontact and viscously displace water flood residual oil. Thismodeling premise is based on performance of theimbibition/viscous displacement of oil by water undercurrent water flood operations as represented in the currentfull-field Ekofisk model.

However, any gas injection EOR process followingwaterflood at Ekofisk will operate under a different(dominantly gas/water) flow system than that which isdominant under water flooding. If gas preferentially flowsthrough the fracture system and its contact with residual oilin the matrix blocks is either prevented by capillarythreshold entry pressures or is severely rate-limited by arelatively slow process such as gas-water diffusion, then theincremental oil recovery could be dramatically lower thanforecasted. The field simulation model forecasts andlaboratory experimental work to date were all conductedunder the implicit premise that injection gas will be able tocontact residual oil in the chalk matrix.

Although studied in the past,2 additional study of gasflow and displacement mechanisms in fractured Ekofiskchalk is needed to validate this premise. This involvesstudies to understand the relative importance of viscous,capillary and diffusion dominated mechanisms in fracturedEkofisk chalk gas injection processes. While this issue may

to some extent be examined in laboratory experiments, it is afield-scale issue and one of the central questions to beaddressed in a field pilot test of any gas injection EORprocess. Additional mechanistic modeling work would beuseful in further examination of this question and will beneeded to help design and interpret any field pilot test.

The Incremental Impact of CompactionAny incremental impact (positive or negative) of a

specific EOR process on the mechanical properties of thechalk, have not been incorporated into the processperformance modeling forecasts or project implementationscenarios presented in this screening study. Suchincremental compaction impacts on recovery and/orsubsequent impacts on seabed subsidence may be caused bychalk dissolution, alteration or compaction.

Modeling Approach Used To Generate EOR ForecastsThe SENSOR7 compositional simulator was used to

model gas injection phase behavior and the ability of HCand non-HC injection gases to mobilize and recoverincremental oil in water flooded portions of Ekofisk. Asector model having representative Ekofisk layer propertiesand well spacing was used for the EOR process simulations.The sector model was a 7x7x14 five-spot configuration withlayer properties taken from the central water flood area ofEkofisk. The residual oil saturation under water-oildisplacement was 30% and the residual oil saturation undergas-oil displacement was 25%. The EOR processsimulations used a 15-component EOS tuned to availablelaboratory PVT data on Ekofisk fluids and the specificinjection gas.

All EOR simulation modeling used a single porositymodel with effective properties and viscous displacementcharacteristics tuned to match the primary depletion andwaterflood performance in the history-matched full-fieldEkofisk model. This provides the EOR injectant unrestrictedaccess to water flooded residual oil in the chalk matrix. Ifgas preferentially flows through the fracture system and itsaccess to residual oil in the matrix blocks is limited, then theincremental oil recovery could be dramatically lower.However, the effect should be similar for all the gasinjection processes.

The air injection oil displacement process involves first acombustion effluent gas front (N2/CO2) which moves aheadof the thermal reaction front, followed by a thermal reactionzone with a complex of possible mechanisms includingsteam distillation and low or high-temperature oxidationreactions, depending on local reservoir conditions, O2 fluxrates, etc. Air injection was modeled in Sensor using ahybrid approach by first forecasting the effect of thecombustion reaction effluent gas front. Following this, theeffect of the thermal front was simulated using a first-contact miscible gas flood with displacement parameters setto model those of the thermal displacement front (asdetermined from prior industry combustion tubeexperiments with North Sea oils). The velocity of themiscible front was calibrated to the air utilizationrequirement and velocity of the “thermal” front, and the fuel


requirement of the thermal reaction was modeled using amiscible residual oil saturation of 5% PV.

Detailed modeling of the thermal reaction mechanismsrequire laboratory data from reservoir core material andfluids (combustion tube experiments using Ekofisk oil andchalk) and a rigorous-physics thermal simulator, neither ofwhich were available or within the scope of this preliminarystudy. Subsequent simulation modeling using the STARSthermal simulator produced incremental oil recovery resultsvery close to those obtained using the hybrid modelingapproach.

Microbial (MEOR) oil recovery forecasts were generatedby up-scaling a composite of typical field project results. Itwas necessary to use this empirical approach to estimateMEOR performance as the exact mechanisms of microbialoil recovery are still poorly understood and consequentlythere are no simulation models available to make reliableMEOR field performance forecasts.

Scaling of forecasts from sector model to full fieldThe various EOR production forecasts and relative

injection and production volumes were scaled up from theindividual sector model process simulations for comparisonand ranking in a hypothetical full-field EOR projectdevelopment. Scaling factors were chosen such that the finalupscaled incremental cumulative oil, cumulative gasinjection, and cumulative gas production for the HC WAGprocess sector model matched earlier full-field model HCWAG simulation forecasts for a premised full-field projectdevelopment having a total injection rate of 350 MMSCF/D.All the other EOR process sector model forecasts were thenupscaled using the identical scaling factors such that keyprocess-related differences in the magnitude and timing ofproduction responses were preserved and would be properlyreflected in any subsequent comparative analyses. Obviouslysuch a scaling procedure is not rigorous, and the resultingincremental EOR production forecasts are hypothetical andintended for comparative ranking purposes only.

The final comparative process performance forecasts fora hypothetical full-field implementation of each of the fiveEOR processes are shown in Figure 3. Keep in mind that thecharacter of the upscaled, full-field response retains theprofile of the underlying mechanistic sector model andwould generally not be expected to be the same as if acomprehensive full-field modeling study had beenconducted for each individual EOR process. The mostnotable difference is that the EOR response is much sharperin the sector model than would be expected from a full fieldmodel, even though the final incremental recoveries shouldbe very close. The scaled-up forecasts provided realisticfull-field volumes and relative injection/production rates toallow gas supply and facilities needs to be assessed for thevarious EOR alternatives.

The EOR performance forecasts shown in Figure 3 allpremise the same hypothetical, full-field EOR developmentplan. These forecasts honor both the relative processperformance characteristics from the mechanistic sectormodeling and existing field facilities constraints. WAGcycle sizes and operating schedules were adjusted slightly asneeded to keep upscaled field production rates withinexisting facilities capacity limits. Also there was no

optimization performed for any individual EOR process.Each EOR process is premised to be implemented beginningin 2004. EOR injection continues for 13 years, withblowdown of the reservoir beginning in 2017. Thehypothetical full-field WAG development plan premises 30current water injection wells being converted to EOR(WAG) service. A gas injection capacity of 350 MMSCF/Dis premised for all WAG processes based on facilityconcerns.

Air injection is premised as continuous gas injection into30 injection wells at an injection capacity of 650MMSCF/D. MEOR premises treatment of 30 injection wellswith nominal capacity of 800,000 BWIPD.

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Figure 3. Comparative full-field cumulative incremental oilequivalent forecasts for the five EOR processes.

COMPARATIVE EOR PROCESS EVALUATIONSThe key technical and logistical issues associated with

each EOR process are addressed in the individual processdiscussions which follow. Each discussion includes: (1) asummary of major process mechanisms and the sources andquality of data available to characterize the process, (2)examination of key premises and issues regardingimplementation of the EOR process at Ekofisk, and (3) adiscussion of major cost/benefit elements associated witheach process. If not resolved, some of the issues raised maybe significant enough to eliminate an EOR process fromfurther consideration.

HC WAGSummary of Major Process Mechanisms, Data Sources,and Data QualityThe initial displacement of water flood residual oil byinjected HC gas takes place as a viscous displacement of theoil by the injected gas. The residual oil saturation followingWAG displacement is lower than the residual oil saturationto water flooding. This viscous displacement mechanism isvolumetrically relatively minor over the project life, andprogressive vaporization of intermediate oil components byinjection gas becomes the dominant oil recovery mechanismas cumulative injected gas volume increases.8 Laboratoryexperiments have shown that HC gas efficiently vaporizesintermediate Ekofisk oil components in the C5 to C13 rangeunder field operating conditions.


Specific laboratory PVT data were available to describethe phase behavior and fluid properties of mixtures ofprospective HC injection gas and Ekofisk crude. These datawere used to tune the EOS in the compositional simulationmodel. Gas injection core flood data from imbibed corevaporization experiments were available to validate thedisplacement mechanisms of HC gas displacing water floodresidual oil in chalk matrix.

Major Process Implementation Issues and PremisesSuccessful implementation of any HC WAG project requiresa source of HC gas for injection. The project performanceforecasts premise that a supply of HC gas will be availableto be taken from the gas sales line at Ekofisk. Note that thisEOR process involves the injection of HC gas and thusdeferment of net HC gas sales.

A major technical issue remaining for implementation ofHC WAG is resolution of injectivity problems in cooledregions around Ekofisk water injectors where hydrates areexpected to form based on thermodynamic considerations.This study premises that an effective solution or “workaround” will be found for the gas hydrate problem.

The performance forecast does not include any impact ofor on chalk mechanical compaction due to the HC gas WAGprocess. This premise should be evaluated further if thisprocess is selected to be progressed towards a field pilot.

Major Cost ElementsSome of the additional cost elements for the HC WAGprocess in large-scale application at Ekofisk are:

Potential Incremental Costsa) Acquiring HC gas for injection (product costs &

pipelines),b) Upgrading of existing compression facilities,c) Additional CO2 tax for added compression/operations,d) Upgrading of injection system and wells for high

pressure gas injection,e) Incremental operating costs (including costs to mitigate

gas hydrate problem), andf) Opportunity costs – produced gas capacity constraints.

Potential Benefitsa) Reduced costs for gas lift. Injection of HC gas, with the

resulting decrease water injection relative to the baseforecast will cause reduced water production over time.Figure 4 shows a comparison of water production atEkofisk with and without HC WAG. A significantreduction in produced water with HC WAG injection isobserved which will result in the need for less gas-liftgas. This in turn reduces operating costs and will allowfor increased gas sales in periods when gas processingis plateaued at facility capacity.

b) Reduced future costs/penalties associated with producedwater handling. The decreased amount of producedwater as a result of gas injection will reduce costsassociated with cleaning and disposing and/orreinjection of produced water under a National ZeroDischarge Order as expected to be in effect from 2005.

c) Increased capacity for oil. Currently, Ekofisk is total

liquid capacity limited. If this capacity constraintcontinues, we should see an increased capacity for oilwith a reduction of produced water. This will allowfurther acceleration of oil recovery as long as the baseforecast is total liquid constrained.

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Figure 4. Comparison of Water Production for Water InjectionCase Versus HC WAG Injection Case.

N2 / FLUE GAS WAGSummary of Major Process Mechanisms, Data Sources,and Data QualityThe displacement of water flood residual oil by injected N2

is much the same as that described for HC WAG, althoughN2 (or flue gas) is less efficient than HC gas in vaporizingintermediate Ekofisk oil components. Laboratoryexperiments have shown that N2 is able to efficientlyvaporize intermediate Ekofisk oil components only up toabout C8 under field operating conditions. N2 injection isvolumetrically more efficient (in terms of voidagereplacement) than other injection gases being considered forEOR application at Ekofisk. Furthermore, no injectivityproblems (hydrates) are expected with N2 gas injectionbased on thermodynamic considerations.

Specific laboratory PVT data were available to describethe phase behavior and fluid properties of mixtures of N2

with Ekofisk crude. PVT results and mechanistic simulationmodeling of N2 injection as a secondary recovery IORinjectant7 was available to guide the work in this study.These data were used to tune the equation of state (EOS) inthe compositional simulation model. Injected N2 interactswith and dissolves in Ekofisk oil, replacing light HCs andforming a methane-rich gas front at the leading edge of thedisplacement. This results in significant shrinkage of theremaining oil volume and reduction in the oil formationvolume factor. The remaining N2-contacted oil is less mobileand more difficult to displace due to higher oil viscosity andhigher interfacial tension.

Compositional simulations with flue gas (N2/CO2

mixture) indicated that adding up to 20% CO2 provided onlymarginal improvement in oil recovery performance.

Major Process Implementation Issues and PremisesN2 supply would be obtained using a cryogenic (or other) airseparation process. Size and weight requirements for airseparation facilitates and associated compression require an


additional process platform with related pipeline tie-ins, etc.Injection wells would need to be upgraded for high-pressureWAG injection service. Significant additional facilitieswould also be required on the production side to handlerejection of N2 contaminated produced gas and recovery ofassociated NGLs.

The N2 WAG injection performance forecasts do notinclude any impact of or on chalk mechanical compactiondue to a N2/flue gas WAG process. This premise should beevaluated further if this process is selected to be progressedtowards a field pilot. Flue gas, with its higher CO2 content,would be of most concern in this regard.

Major Cost ElementsSome additional cost elements for the N2 WAG process inlarge-scale application at Ekofisk are:

Potential Incremental Costsa) Additional platform with air separation, compression,

and rejection facilities,b) Additional CO2 tax for added compression/operations,c) Pipelines to/from N2 facilities,d) Upgrading of injection system and wells for high

pressure gas injection, ande) Incremental operating costs for WAG

injection/production.

Potential Benefitsa) Reduced costs for gas lift,b) Reduced future costs/penalties associated with handling

of produced water,c) Increased capacity for oil during liquid constrained

periods,d) Acceleration of HC gas recovery, ande) No gas hydrate problems expected.

CO2 WAGSummary of Major Process Mechanisms, Data Sources,and Data QualityMinimum miscibility pressure correlations and phasebehavior predictions indicate that CO2 will likely be multi-contact miscible or near-miscible with Ekofisk crude oversignificant portions of the reservoir. Miscible displacementconditions are more likely in the low temperature regionssurrounding existing water injectors. An initial, minorviscous displacement period will be followed by progressivevaporization of intermediate oil components with continuedgas injection. CO2 should be significantly more efficientthan HC gas in vaporizing intermediate Ekofisk oilcomponents. While no specific CO2-oil PVT data has beenmeasured for Ekofisk, significant extraction of oilcomponents from C5 up to C20 could be expected based onindustry experience. This behavior is supported bycompositional simulation forecasts using an untunedequation of state.

The basic oil recovery mechanisms by which CO2 is ableto mobilize water flood residual oil include swelling of theresidual oil volume and reduction in oil viscosity as CO2

dissolves in the oil, strong vaporization and extraction ofintermediate components in the oil into the CO2-rich gas

phase, and reduction in the interfacial tension forcesallowing mobilization of the water flood residual oil. Bothincreasing temperature and the presence of contaminants(particularly N2) in the CO2 injection gas will have anegative impact on oil recovery efficiency.

Major Process Implementation Issues and PremisesImplementation of any CO2 WAG project requires a CO2

supply source for injection. The project performanceforecasts premise that the required delivery rate of CO2 willbe available for the project. However, it is important to notethat no supply source of CO2 for any Ekofisk project hasbeen identified at this time. A project evaluation at theGrane Field9 premises that an onshore CO2 supply ofcomparable delivery capacity will come from a HC gas firedpower plant. A similar onshore CO2 supply scenario forEkofisk may be the most likely possibility, however thecosts to deliver CO2 from these types of sources could bequite high. The only natural CO2 supply source identified inthe North Sea is from the Sleipner Gas Field,10 however itappears that only about 60-70 MMSCF/D would beavailable (which is currently reinjected at Sleipner). A CO2

supply of the requisite purity, volume, and deliverablitymust be identified for Ekofisk if this process is selected asone to be progressed toward a field pilot.

Implementation of a CO2 project at Ekofisk wouldrequire a supply pipeline to deliver CO2 from the source tothe field. CO2 is generally transported as a supercriticalfluid, typically at pressures of 1500-2000 psi as it can bepumped much like a liquid at these conditions. Boostercompression would be required at the field to bring the CO2

to the required injection pressure. Rejection of producedCO2 from produced fluids will be a major issue and willrequire extensive CO2 separation, compression, and NGLrecovery facilities. The size and weight requirements for thepremised compression and recycle facilities will require anadditional CO2 facilities platform with related pipeline tie-ins, etc. Injection wells will need to be upgraded withspecial wellheads for high-pressure CO2 WAG injectionservice. Additional expense for increased corrosion treatingwill also be required. Problems with injectivity due to CO2-hydrate formation in cooled regions (below about 60°F)around existing water injectors may be anticipated based onthermodynamic calculations.

The CO2 WAG injection performance forecasts do notinclude any impact of or on chalk mechanical compaction.Laboratory testing conducted to date indicates thatintroducing CO2–charged injection water into Ekofisk chalksamples results in an immediate and vigorous dissolutionreaction with large axial strains and high strain rates.

The additional compaction would provide additionaldrive energy in the system, the high local strain rates mayresult in well failures and in ultimate sea bed subsidencebeyond acceptable limits. The impact of CO2 on compactionmust be evaluated extensively if this process is selected tobe progressed further. Also, reaction of CO2-rich injectionwater with calcium carbonate in the rock matrix willconsume some (potentially significant) fraction of the totalinjected CO2 volume, thus making it unavailable toparticipate in the oil recovery process. The impact of thisreduced effective CO2 slug size has not been quantified or


included in the screening forecasts and would need to beevaluated in any future work on application of this process.

Major Cost ElementsSome additional cost elements for the CO2 WAG process inlarge-scale application at Ekofisk are:

Potential Incremental Costsa) CO2 supply gas acquisition costs, CO2 supply pipeline

and transportation costs,b) Additional platform with CO2 compression and

rejection/recycle facilities,c) Additional CO2 tax for added compression/operations,d) Pipelines to/from CO2 facilities,e) Upgrading of injection system and wells/wellheads for

high pressure CO2 service,f) Incremental operating costs (incl. corrosion) for CO2

WAG injection/production, andg) Possible increased well failures & subsidence

mitigation costs.


of produced water,c) Increased capacity for oil,d) Acceleration of HC gas recovery, ande) Possible increased reserves due to enhanced compaction

drive.

AIR INJECTIONSummary of Major Process Mechanisms, Data Sources,and Data QualityThe air injection process involves continuous injection of airresulting in an exothermic reaction of oxygen with residualoil and generation of a thermal reaction front that propagatesthrough the reservoir. Laboratory accelerating ratecalorimetry (ARC) tests conducted with Ekofisk crudeshowed favorable reaction profiles indicating that a thermalreaction front could be generated and maintained in thereservoir. It is likely that an enriched air (30% O2) processcould be used to improve the process performancecharacteristics at Ekofisk and to provide spontaneousignition around cooled water injectors. Specific laboratorycombustion tube (CT) tests have not been conducted withEkofisk chalk core material to date, however a significantamount of ARC and CT data are available for similarsystems. These industry laboratory data, along with oilrecovery and air utilization data from industry fieldprojects,11-12 formed the database for the air injectionperformance forecasts for Ekofisk.

Major Process Implementation Issues and PremisesAir compression/enrichment facilities capable of injectingup to 650 MMCFPD were premised for the field-scaleproject performance forecasts. Additional facilities would berequired on the production side to handle rejection ofproduced gas contaminated with N2/CO2/CO/etc reactionproducts and for recovery of a significant volume ofassociated NGLs in the produced gas stream. The size and

weight requirements for the premised air separationfacilities, produced gas processing facilities, and associatedcompression would likely require an additional facilitiesplatform with related pipeline tie-ins, etc.

Two different scenarios were considered for the airinjection process. Scenario 1 involves no separation ofsalable gas from flue gas. All produced gas will bereinjected in this case. There will be a significant capitalcost saving in this case as the gas separation/rejection unitwill not be needed, but there will also be a significant loss ofrevenue from loss of the salable gas. Scenario 2, which isperceived as the more realistic, involves complete separationof salable gas from flue gas with export and sales of salesgas and reinjection of flue gas. Evaluations showed thatseparation of sales gas from flue gas (i.e. reinjection of onlyflue gas) is the preferable option.

Injection wells and lines would need to be upgraded forhigh-pressure air injection service. Injection and productionwells would probably need to be upgraded to handleexposure to the elevated temperatures. Additional expensefor increased corrosion treating should also be anticipated.

The air injection performance forecasts do not includeany impact of or on chalk mechanical compaction due to thethermal effects of the high-temperature air injection processand the effects of combustion gases on the chalk matrix.Possible high-temperature calcination reactions maysubstantially alter and weaken the rock. Preliminary datafrom one combustion tube test on an outcrop chalk showedthat the rock matrix may be weakened by 25% throughexposure to this high-temperature process. The CO2 in thecombustion products generated by the thermal reactionswould likely have a significant impact on the mechanicalintegrity of the matrix also, as discussed for the CO2 WAGprocess. The impact of this process on mechanical integrityof the Ekofisk chalk and resulting compaction/subsidenceeffects must be evaluated more thoroughly if this process isselected to be progressed further.

The air injection process might be considered analternative to blowdown as the final stage in the exploitationprocess. Air injection can potentially be implementedfollowing any of the other processes.

Major Cost ElementsSome additional cost elements for the air injection processin large-scale application at Ekofisk are:

Potential Incremental Costsa) Additional platform with air compression and

enrichment facilities,b) Additional CO2 tax for added compression/operations,c) Upgrading of injection system and wells for high

pressure air injection,d) Upgrading of injection & production wells for high-

temperature service,e) Incremental operating costs for high volume gas

handling and corrosion treating, andf) Possible increased well failures & subsidence

mitigation costs.



of produced water,c) Increased capacity for oil during liquid constrained

periods,d) Acceleration of HC gas recovery, ande) Possible increased reserves due to enhanced compaction

drive.

MICROBIAL EORSummary of Major Process Mechanisms, Data Sources,and Data QualityMicrobial enhanced oil recovery (MEOR) is still anemerging technology and the exact mechanisms by whichmicrobial agents are able to effect mobilization and recoveryof incremental oil in a given reservoir are not clearlyunderstood. MEOR processes likely act through a complexof different mechanisms, including wettability alteration,IFT reduction, oil viscosity reduction, and others. As aconsequence, there are no robust predictive models availableto effectively simulate MEOR process applications and oilrecovery potential at Ekofisk. Moreover, at this time, thereare no specific laboratory data to support or refute claims ofoil recovery potential by MEOR in the Ekofisk reservoir.Estimates of recovery potential in this paper are made byanalogy under the premise that a viable MEOR system canbe developed for application at Ekofisk which will haveperformance characteristics analogous to other field resultsreported to date.

Major Process Implementation Issues and PremisesThe microbial oil recovery forecasts were generated by up-scaling a composite of typical field project results. It wasnecessary to use this empirical approach to estimate MEORperformance as the exact mechanisms of microbial oilrecovery are still poorly understood and consequently thereare no simulation models available to make reliable MEORfield performance forecasts. The nature of microbialtransport in a fractured chalk reservoir has not beenevaluated. Reduced reservoir temperatures near the waterinjection wells would probably be favorable for microbialgrowth. Issues of the viability of microbes over the widerange of temperatures existing in Ekofisk, and particularlythe impact of higher reservoir temperatures on the MEORprocess, needs to be investigated further.

Several of the possible mechanisms suggested for oilmobilization in MEOR involve wettability alteration and/orIFT reduction. These are mechanisms similar to those ofsurfactant flooding, which has been considered previouslybut is not being actively pursued as an EOR method atEkofisk because of low oil recovery forecasts. This raisesthe question of how and why the MEOR process is differentfrom surfactant processes considered earlier and thereforemerits continued interest?

The MEOR process is not just a surfactant process – themechanisms suggested as being important in MEOR arevaried and complex (e.g. oil viscosity reduction, gasproduction, solvent production) and are not fullyunderstood. Another key difference between MEOR and

surfactant flooding lies in the envisioned method ofsurfactant delivery to the point of contact with residual oil.Microbes would tend to move preferentially through thefracture system, being excluded from directly entering thechalk matrix because of their size relative to the pore throatsize distribution of the chalk. Microbes have the ability toseek out and adhere to any films of residual oil at thefracture/matrix interface or residing in larger pores adjacentto the fracture system. Thus, microbes may penetrate fairlydeep into a fractured chalk reservoir and generate surfactantin situ, thereby avoiding much of the potential adsorptionlosses expected with surfactant flooding. Since the microbeswould use residual oil as a food source, total injectionvolumes and costs would be substantially reduced.

The MEOR performance forecasts represent anextension of limited laboratory and field results to a full-scale MEOR project at Ekofisk. The oil recovery projectionsare based on the following premises: (1) a viable microbialsystem will be identified for application at Ekofisk; and (2)the oil recovery potential of that process will be comparableto that of successful MEOR processes seen in otherlaboratory and field studies (with adjustments for reservoirconditions at Ekofisk). Potential regulatory andenvironmental issues/concerns with injecting microbes intoa reservoir in the North Sea have not been addressed. Also,the potential for reservoir souring must be closely evaluatedbefore implementing injection of any microbes into Ekofisk.

The material and equipment requirements and logisticsof implementing a full-field microbial oil recovery project inan offshore North Sea operating environment do not appearto be a limiting factor. Equipment requirements are modest,operating costs are fairly low, and there would appear to beonly minimal impact on existing operations. The real issuewith this process is the viability of the oil recovery processitself under Ekofisk reservoir conditions. Additional “proofof concept” laboratory work is required to establish theviability of any claims for incremental oil recoverypotential. MEOR is the most uncertain of any of the EORprocesses being considered for application at Ekofisk.

Major Cost ElementsSome additional cost elements for the MEOR process inlarge-scale application at Ekofisk:

Potential Incremental Costsa) Microbial culture generation tanks (small, inexpensive)b) Small, low-volume chemical injection pumps,c) Laboratory facilities for quality control and process

monitoring, andd) Possible environmental/regulatory costs or concerns.

Potential Benefitsa) Relatively easy and inexpensive process to implement

and operate,b) Compatible with existing water injection facilities and

operations, andc) Could possibly be used in combination with a gas

injection EOR process.


EOR DEVELOPMENT & OPERATIONAL PREMISESInjection Gas AvailabilityIt is assumed the gas can be made available in sufficientquantities for the gas injection processes. For air injectionthis is a compressor sizing issue. For N2 injection, the gasavailability also premises separation (cryogenic or other) ofN2 from air.

HC gas availability on the Norwegian Continental Shelf(NCS) is as always quite uncertain and variable. Theavailability depends on off-take to the European market,variations in price, and development of new gas reserves.Gas for HC WAG will be taken from the sales gas stream atEkofisk. HC gas is available in sufficient quantities atEkofisk, but substitute gas for sales commitments may haveto be acquired through a different source and supplier. Theonly effect accounted for with respect to HC gas injectionwas the economic effect of deferring the gas sales as a resultof gas injection.

On the CO2 availability issue, there is not much known.The only concept studied is the Grane field9 where CO2 waspremised to be separated from flue gas at an onshore gaspower plant before being piped offshore for injection intothe reservoir. The Grane operator has not been able to findviability in such a scenario and the concept has beenshelved. The only known significant natural source of CO2

gas on the NCS is at the Sleipner field.10 However, thevolumes/rates at Sleipner are only one sixth of that requiredfor full field CO2 WAG at Ekofisk.

For CO2 injection, we assume that the CO2 can be madeavailable from a gas power plant onshore Norway and that apipeline has to be built to transport the gas to Ekofisk withassociated compression facilities. The price estimate for CO2

was taken from a SINTEF study.13 Price for CO2 wasestimated to range from $1.13/MCF to $1.69/MCF. Here,we premise that the CO2 gas is available at an average priceof $1.5/MCF at the wellhead.

Injection and Well premisesGas injection will be at the main water injection facility into30 wells. The WAG scenarios (HC, N2 and CO2) premise 30injection wells divided into 3 well groups. Gas is premisedto be injected in 6 month WAG cycles into 10 injectionwells at the time at a nominal injection rate of 350MMSCF/D at 6000 psia wellhead pressure. The remaining20 injection wells will be on water injection. For airinjection, we premise that all 30 injection wells will receivecontinuous air injection at a nominal rate of 650 MMSCF/Dat a wellhead pressure of 6000 psia.

For HC and N2 WAG the injection well upgrade premiseredrill of 20 injection wells and tubing replacement in 10injection wells. For CO2 WAG there will be a need tosidetrack all 30 injectors and complete with chrome tubing.For air injection, 30 injection wells and 30 production wellsneed to be upgraded (sidetracked and chrome tubingcompleted). Chrome tubing for the CO2 and air injectionscenarios is required as a corrosion prevention measure.

For MEOR, there will be no change in the injectionpattern or volumes. No wells will require workover beyondthat which is required in the base case. Microbe solution ispremised to be commingled with the current injection water

topside. No additional cost for sour service in the event ofreservoir souring was accounted for.

Hydrate PreventionHC gas/water hydrate was thought to cause the failure of thefirst WAG pilot performed at Ekofisk. This is believed to bea general problem with any future HC WAG scenario.Prolonged injection of cold sea-water results in reservoirtemperatures and pressures such that gas hydrates form ifHC gas is subsequently injected in the same well.

Several possible alternatives for hydrate prevention havebeen discussed, including:

1. Chemical heating of the near wellbore area prior to gasinjection,

2. Heating of the injection water to raise near wellboretemperature outside of the hydrate envelope,

3. Sidetrack injectors to outside of the cooled zone prior togas injection,

4. Co-injection of water and gas, and5. Chemical inhibition to prevent and/or retard the onset of

hydrate formation.

The chemical heating option was selected for fieldtesting in 1998. The chemicals showed great promise, butthe test failed as the reservoir pressure was too high to beovercome with the current top-side wellhead and pipelinepressure limitations.

For screening purposes, we assumed that a combinationof chemical heating and heating of the injection water wouldsuffice to prevent hydrates in a full field WAGimplementation as follows:

A. Heating 60,000 bbl/d to 85-90°C and mix with cold seawater to achieve proper temperature level• Other heating options, e.g. incorporating waste heat

recovery, is an upside.B) Chemical treatment (exothermic reactions).

• This elevates the near wellbore temperature, for adesigned treatment depth, to a level above thehydrate formation temperature.

• The chemical treatment is once per well only for thefirst cycle of water injection.

CONCLUSIONS1. Incremental oil recovery forecasts for the five processes

at Ekofisk were as follows:• HC WAG: 3.3% OOIP• N2 WAG: -2.2% OOIP• CO2 WAG: 5.6% OOIP• Air Injection: 6.5% OOIP• MEOR: 0.6% OOIP

2. Only Hydrocarbon WAG and Air Injection showsufficient promise for application at Ekofisk to becarried forward into further studies. Key conclusionsand recommendations regarding each process are asfollows:• N2 WAG injection:

Negative reserves potential. Eliminated from further consideration.


• CO2 WAG injection: Large reserves potential. Significant dissolution/compaction concern. No CO2 source is available in the foreseeable

future. Dropped from consideration until CO2 can be

secured at cost significantly less than $1.50/MCF at the wellhead.

• Microbial EOR: Limited reserves potential. The MEOR process lacks definitive proof of

technical ability to economically mobilizewaterflood residual oil in Ekofisk or similarchalk.

Dropped from further consideration.• Air Injection

Large reserves potential. Significant risk and uncertainty. If air injection is to be employed at Ekofisk it

will most likely be late in the field life,potentially after some other EOR process hasbeen employed. Hence, further studies of airinjection are not time-critical but should beprogressed in a timely manner in order tounderstand the risk areas and ‘show stoppers’associated with this process.

Recommended further study of risk areas (O2

breakthrough, compaction, and flue gasseparation & reinjection).

• HC WAG injection Significant reserves potential. Most mature and technically ready process. Recommended updating of full field WAG

development forecasts with progress towardspilot feasibility if full field economics aresufficient.

ACKNOWLEDGEMENTSThe authors acknowledge permission to publish the abovepaper from Phillips Petroleum Company Norway and theEkofisk Coventurers, including Fina Exploration Norways.c.a., Norsk Agip A/S, Elf Petroleum Norge A/S, NorskHydro Production as, TOTAL Norge A.S. and Den norskstats oljeselskap a.s.

REFERENCES1. Hermansen, H., Thomas, L.K., Sylte, J.E. and Aasbøe,

B.T., “Twenty Five Years of Ekofisk ReservoirManagement,” Paper SPE 38927 presented at the 1997

SPE ATCE, San Antonio, Texas, 5–8 Oct. 1997.2. Jakobsson, N. M. and Christian, T. M., "Historical

Performance of Gas Injection of Ekofisk," Paper SPE28933 presented at the 1994 SPE ATCE, New Orleans,Sept. 25-28, 1994.

3. Thomas, L.K., Dixon, T.N. and Pierson, R.G., "FracturedReservoir Simulation," SPEJ (Feb. 1983) 42-54.

4. Hallenbeck, L.D., Sylte, J.E., Ebbs, and D.J., Thomas,L.K., "Implementation of the Ekofisk Waterflood," PaperSPE 19838 presented at the 1989 SPE Annual TechnicalConference, San Antonio, October 8-11, 1989.

5. Christian, T.M., Currie, J.C., Lantz, T.G., Rismyhr, O.,and Snow, S.E., "Reservoir Management at EkofiskField," SPE 26623 presented at the 1993 SPE AnnualTechnical Conference, Houston, October 3-6,1993.

6. Thomas, L. K., Dixon, T. N., Pierson, R. G. andHermansen, H., "Ekofisk Nitrogen Injection," Paper SPE19839 presented at the 1989 SPE ATCE, San Antonio,Oct. 8-11, 1989.

7. Coats, K., Thomas, L.K., Dixon, T.N. and Pierson, R.G.,“Compositional and Black Oil Reservoir Simulation,"Paper SPE 29111 presented at the 13th SPE Symp. onRes. Sim., San Antonio, TX, USA, 12-15 Feb., 1995.

8. Wegener, D.C., Thomas, L.K. and Sylte, J.E.,“Effectiveness of a Dry Gas Injection WAG Process in aPreviously Waterflooded Chalk Reservoir,” Paper SPE48950 presented at the 1998 SPE ATCE, New Orleans,Louisiana, 27-30 September 1998.

9. Skotner, P., “Evaluation of CO2 Flooding on the GraneField,” presented at the 7th Conf. On Reservoir Mgmt –The New Petroleum Age, Bergen, Norway, Nov. 18-19,1998.

10. Baklid, A., Kobol, R. and Owren, G., “Sleipner VestCO2 Disposal, CO2 Injection into a ShallowUnderground Aquifer,” Paper SPE 36600 presented atthe 1996 SPE ATCE, Denver, CO, USA, 6-9 Oct. 1996.

11. Kumar, V.K. and Fassihi, M.R., SPE, “Case History andAppraisal of the Medicine Pole Hills Unit Air InjectionProject,” Paper SPE 27792 presented at the SPE/DOE9th Symp. on IOR, Tulsa, OK, USA, 17-20 April 1994.

12. Watts, B.C., Hall, T.F. and Petri, D.J., “The Horse CreekAir Injection Project: An Overview,” Paper SPE 38359presented at the Rocky Mountain Regional Meeting,Casper, WY, USA, 18-21 May, 1997.

13. Holt, T. and Lindeberg, E., “Thermal Power - WithoutGreenhouse Gases and With Improved Oil Recovery”,Energy Convers. Mgmt., Vol. 33, No. 5-8, pp. 595-602,1992.

Table 1. Technical Readiness of EOR implementation at Ekofisk.

eor screening for ekofisk-2000

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