38 JANUARY 2003

Overview

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The topic of Field Revitalization has added the word Mature to its title for2003. Maybe we should spend a minute thinking about this adjective added tothe topic. Normally, we might think about a mature field as one in the latter yearsof its producing life. For an oil field, production may be on a steep decline witha high water cut or water/oil ratio. Many mature gas fields also have a fairly sig-nificant production decline, especially when development drilling has come toan end. These mature fields can be revitalized in many ways. In some instances,efforts are focused on the reservoir with further drilling to drain potentiallyunswept hydrocarbons with infill wells or horizontal laterals. The horizontaldrilling might be from new wellbores or wells that are currently temporarilyabandoned or near their economic limit. With the increase in horizontal-wellactivity, there is an abundance of new technology with advances in gravel-packdesign, underbalanced drilling with coiled tubing, and coiled-tubing fracturing.Besides these production improvements, operators are revamping both down-hole and surface facilities to help breathe new life into older fields. Advances aretaking place in the areas of artificial lift, intelligent-well completions, expandabletubulars, and others. Many of these efforts have been quite successful because ofclose cooperation developed between an operator and a service company. Inmaking design modifications, then implementing equipment changes in thefield, common goals and open communications are both key to achieving theobjectivesa win-win situation for both parties.

The Indian Basin field in Eddy County, New Mexico, near Carlsbad, is an excel-lent example of a mature-field revitalization project. The gas field, discovered in1963, produces from a 300-ft fractured vuggy dolomite. The producing reservoiris an Upper Pennsylvanian formation at a depth of approximately 7,500 ft. In thelate 1980s, gas production from the field fell below 100 MMcf/D from a peak of225 MMcf/D in the mid-1970s. The reservoir pressure was less than 500 psi inmany areas of the field, with a large portion of production coming from highwater-cut wells. In the mid-1990s, operators made improvements in well stimu-lation and completion designs and implemented a coproduction reservoir-man-agement program using large-volume electrical submersible pumps (ESPs). Amajor pump manufacturer redesigned its recirculation ESP system to handlehigh gas rates. On the basis of these lift improvements, individual wells are nowcapable of producing 6 to 8 MMcf/D of gas along with 7,000 B/D of total liquid.Total field production is now more than 350 MMcf/D of gas with liquid hydro-carbon volumes in excess of 15,000 B/D. Current produced water rates areapproximately 210,000 B/D. The removal of large volumes of water from thereservoir has had a major effect on field revitalization efforts at Indian Basin. Allwells are not conducive to ESP use, so each well is evaluated on its own meritsto select the optimum artificial-lift system. This focused reservoir-managementplan has improved the total hydrocarbon gas and liquid recovery from the fieldsignificantly.

In these mature fields, the incremental economics of field revitalization efforts can,many times, be more attractive than the financial results of the initial developmentproject. The papers presented in this topic area offer other challenging approach-es to extend the producing life of the mature fields around the world.

Robert Leibrecht is areservoir engineer withConocoPhillips work-ing in the Permianregion in Odessa,Texas. He has 28 yearsof experience in the

petroleum industry. He holds a BSdegree in aerospace engineering fromParks College of St. Louis U. and MSand PhD degrees from U. of Arizonain mechanical engineering. WithConocoPhillips, he has held previousengineering and management posi-tions in Dubai, London, Aberdeen,Russia, Houston, and Venezuela. He is amember of the Intl. Board of Directorsfor SPE representing the SouthwesternNorth American region and is a mem-ber of the JPT Editorial Committee.

JPT

Additional Technical Papers

SPE 77671, A Case Study:Using Modern ReservoirCharacterization to OptimizeFuture Development of aMature Asset

SPE 77918, BuffaloRedevelopmentThe Wee FieldThat Grew

SPE 75685, New CompletionTechniques Improve ProductionRates in a Maturing GasReservoir

Available at the SPE e-Library:www.spe.org

JANUARY 2003 39

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Optimizing an AggressiveDril l ing Program at theStatfjord Field

After 23 years of production fromthe North Sea Statfjord oil field,more than 60% of the stock-tankoil originally in place has beenrecovered. The remaining reservesare characterized by complex distri-butions of oil, water, and gas. Themain challenge is to identifyremaining oil in targets that arebecoming increasingly smaller,more complex, and more uncertain,then to drain these targets in themost profitable manner.

IntroductionThe Statfjord field was discovered in1973 and is more than 25 km long andaverages 4 km wide. Three fully inte-grated Condeep concrete platformswere used to develop the field.

Production is from the Brent,Dunlin, and Statfjord reservoirs, withBrent and Statfjord being the mainreservoirs. Cumulative oil productionas of May 2002 was 612106 std m3.The expected recovery factor is 65%.The field now contains three phasesand several fluid contacts. The remain-ing reserves are scattered over a widearea and in several reservoirs.Consequently, each new well locationis gradually decreasing in size andassociated with considerable risk.

A multidisciplinary organizationapplying well-defined work processesis necessary to recover the remainingreserves in a cost-effective manner. Anoptimized drilling programis the result of implement-ing work processes thatensure a high activity levelin the field.

Field StatusMore than 280 wells havebeen drilled in the field.Approximately 340 pro-duction logs and 220 satu-ration logs have beenacquired. Field activitycomprises drilling 15 infillwells per year and morethan 100 annual well inter-ventions. There are 124

active wells in the field with no spareslots available. Therefore, all newwells are drilled as sidetracks fromexisting wells. Fig. 1 illustrates thecontribution from infill wells andwell interventions.

Remaining oil accumulations arefound in structurally complex areas, inpoor quality sandstone, or wedgedbetween the emerging gas and waterfronts. The distribution of remainingoil is a result of several drainage pat-terns with a large variation in fluid con-tacts within each reservoir.

Optimizing the Drilling ProgramThe overall challenge is to optimizehydrocarbon recovery and maximizenet present value for the life of thefield. Efforts involve mapping theremaining oil accumulations and iden-tifying projects for infill drilling andwell interventions.

Being a mature producing field, theremaining lifetime depends on factorssuch as ultimate recovery, operationalcosts, drilling, and well-activity relat-ed cost. A strong focus on bothincreasing recovery and reducing costis necessary to extend field life.Improved oil recovery techniquessuch as extended-reach drilling, mul-tilateral wells, improved completiondesign, and water-alternating-gasflooding have been implemented inthe field. Continuous attentiontoward the use of new technology is

required. The production of remain-ing gas by deep depressurization inthe late life of the field is one possi-ble scenario.

The basis for an optimized drillingprogram is a portfolio of attractivedrilling projects. A dynamic workprocess is required that involves alldisciplines, with focus on geologicaland reservoir technical aspects andwell solutions and cost.

The current Statfjord field reservoir-utilization organization consists offive teamsa platform team for eachof the Statfjord A, B, and C platforms;one Statfjord satellites team; and one

strategy and support team.These teams comprise geol-ogists, geophysicists, andpetrophysicists along withreservoir, production, drill-ing, and well engineers.

Fig. 2 shows the interac-tion between the differentwork processes. A funda-mental work process is theyearly update of the geo-model on the basis of athorough field geologicaland geophysical evaluation.The flood-front monitoring(FFM) process integratesthe geological framework

This article, written by TechnologyEditor Dennis Denney, contains high-lights of paper SPE 78347,Optimization of an AggressiveDrilling Program at the StatfjordFieldMaximizing Production in aMature Field, by Anne-GretheHansen, SPE, Atle Brendsdal,Dag Schistad Arnesen, andMarian Morris, Statoil ASA, origi-nally presented at the 2002 SPEEuropean Petroleum Conference,Aberdeen, 2931 October.

For a limited time, the full-lengthpaper is available free to SPE mem-bers at www.spe.org/jpt. The paperhas not been peer reviewed.

Fig. 1Contribution from infill wells and well interven-tions on total production potential for the Statfjord fieldduring 2001.

40 JANUARY 2003

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nwith the dynamic floodingstatus, resulting in a distri-bution of the remaining oilaccumulations. Targetingremaining oil results in aprioritized drilling sched-ule. The recommendation-to-drill process formallyjustifies each drilling pro-ject. All work processes arefounded on the drainagestrategy and long-termreservoir-developmentplan for the field.

Geological and Geo-physical Evaluation. Thebasis for reservoir management restson a continuously updated and con-sistent static geomodel. The geomod-el for the Statfjord field is updatedyearly on a field basis. Three 3D seis-mic data sets were acquired for thefield in 1979/80, 1991, and 1997. Thegeomodel is based on interpretation ofthe 1997 seismic data as well asdetailed interpretation of well logs.Petrophysical parameter maps, suchas porosity, permeability, and net sand,also are computed for the stratigraph-ic units from the well logs and formpart of the geomodel. Time variant(4D) seismic has been used in theinterpretation of drainage patternswherever applicable. Plans exist toacquire ocean-bottom seismic overthe entire field.

FFM. To identify remaining reserves,several techniques including reservoirsimulation and 4D seismic modelingwere used. Reservoir simulation mod-els, both element and full-field mod-els, were built for the Brent, Dunlin,and Statfjord reservoirs and are usedin the evaluation of drainage strate-gies. 4D seismic modeling has proveduseful for estimating fluid movementsat the Statfjord field, especially for thethick, laterally continuous sandstonereservoirs. However, the resolution ofthe seismic is too low to identifyremaining reserves in the thinundrained reservoirs.

Therefore, it was necessary to sup-plement reservoir simulation and 4Dseismic modeling with other tech-niques to identify remaining reserves.The link between the static geologicalmodel and the dynamic flooding sta-tus was established with the FFMwork process. This technique requiresa mutual understanding between dis-

ciplines, common work processes, andtools for the integration and visualiza-tion of data.

First, flood fronts are interpreted ina series of geological cross sectionsbased on all available data, includingproduction history, new data acquisi-tion in existing wells, results fromdrilling of new wells, and 4D seismic.Second, the interpreted fluid contactsare digitalized directly into the cross-section data. Third, gridding proce-dures are applied to obtain fluid-frontgrids used to generate oil-thicknessmaps and to calculate oil volumes inplace. The integrated FFM processresults in a fluid-distribution modelthat is updated as new informationbecomes available.

Targeting Remaining Oil. The objec-tive of the annual process is to ensure acontinuous process of maturingdrilling locations, then generatingdrilling projects and a prioritizeddrilling schedule. This process consistsof four phasesprospect, maturing,drilling project, and drilling schedule.

Prospect Phase. This creativeprocess ensures a systematic search forremaining oil in all reservoirs on thebasis of FFM. Based on the existingfluid-distribution model, possibleremaining oil locations are identifiedfor each reservoir in each platformarea. These ideas are subject to areserves estimation, a rough riskassessment, and an evaluation ofdrainage strategy effects. Typically, 40to 50 ideas are identified for each plat-form area, for a total of approximately150 ideas for the field.

A ranking process that reduces thebank of ideas to a group of prospectsis based on volume, risk, anddrainage influence through a well-

defined classification sys-tem. Approximately 15 to20 prospects per platformarea form the starting pointfor the maturing phase.

Maturing Phase. Thisphase quantifies uncertain-ties related to the prospectsselected for each platform.Risked reserves and a most-likely production profile areestablished for each drillinglocation. The evaluationincludes geophysical, geolog-ical, and reservoir technicaluncertainties, as well as oper-ational risk related to both

reserves and the production profile. Drilling-Project Phase. This opti-

mization phase generates drilling pro-jects that represent the most optimalcombination of matured drilling loca-tions, available well slots, and drillingand completion solutions. Well slotsfor sidetracking are identified for eachplatform. This overview of well slots,together with the collection ofmatured prospects, is used to generatepossible drilling projects. Eachdrilling project is assigned a proposedwell trajectory and completion solu-tion with associated costs, as well astotal reserves and an expected pro-duction profile.

Drilling-Schedule Phase. A field-level, prioritized drilling schedule isgenerated with a fuzzy rankingmethod. This method includesweighting of parameters, such as netpresent value, pay-back time, net pre-sent value per rig day, remainingreserves in the slot to be sidetracked,reserves for the new well, initial oilproduction rate, rig days used, degreeof drilling complexity, and drainagestrategy. The selected parameters covereconomic aspects as well as reserves,technical uncertainties, and drainagestrategy associated with each drillingproject. The proposed drilling sched-ule is subject to continuous revisionand optimization; it forms the startingpoint for the preparation of the recom-mendation to drill.

Recommendation to Drill. Theseprocesses formally justify each drillingproject on the schedule. The final quali-fication of the drilling project is adetailed study that includes the technicaljustification, data-acquisition program,well design, completion strategy, welleconomics, and risk assessment. JPT

Fig. 2Reservoir-management work processes for opti-mizing the drilling program.

42 JANUARY 2003

Enhanced Gravel-PackCompletions Revitalize aMature Sand-Producing Field

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Wells in Dulang field offshoreMalaysia were completed withoutsand control measures becausesand production under normaldrawdown and producing condi-tions was not expected. However, inlater stages of the fields life, signif-icant amounts of sand productionbegan. Hydrocarbon productiondecreased, costs increased for rou-tine wellbore sand cleanouts, andplatform shutdowns for surfacevessel sand cleanup were more fre-quent. The combination of sandcontrol and stimulation techniques(frac pack, extension pack, andhigh-rate water pack) has success-fully increased the productivity andprevented sand production in theDulang wells.

IntroductionThe Dulang oilfield is approximately80 miles offshore Kuala Terengganu,Malaysia. Fig. 1 shows the structural-ly complex field. Production began inMarch 1991 with oil production aver-aging 26,000 STB/D and peaked atapproximately 50,000 STBO/D. Themain reservoir comprises Miocene ageDulang E sands. Complexreservoir faults compartmen-talize the field into 16 sub-blocks. Stratigraphically, 20reservoir units have beenidentified. The drive mecha-nism is edgewater and natur-al depletion.

Initial CompletionPhilosophySanding studies of the majorDulang reservoirs indicatedthat although initially theintervals would producesand-free under normaldrawdown operations, sandproduction would probablyoccur with the commence-ment of water production.Despite this understanding,the initial completion phi-losophy was to drain themultiple sand layers through

a dual-selective cased and perforatedcompletion. The selective designprovided flexibility for reservoirmanagement and, at the time, wasdeemed an economical completionfor maximizing recovery.

Sand production was first observedin July 1991, when approximately10 gal of sand was recovered during aroutine pigging operation. Within2 years, sand production was notedfrom the shallower reservoirs. Fig. 2shows a hole in a blast joint eroded bythe sand production. Evaluation of thesoft unconsolidated formation produc-ing the sand showed that a combina-tion of high drawdown, coupled withreservoir depletion, was the majorcause of the sand production fromthese reservoirs.

Opportunity AssessmentIn general, the Dulang field main-tained a high production rate; howev-er, later in the fields productive life,productivity declined because ofexcessive gas, sand, and water produc-tion. As of the end of February 1999,44% (57 strings) of the total produc-tion strings were idle with estimated

locked-in potential of 14,100 STBO/D,of which 6,100 STBO/D could berealized through recompletions andthe remaining 8,000 STBO/D wasdeemed unrecoverable.

To revitalize the field, a wellboreopportunity study was initiated in1999. The objectives of the study were

to identify remaining reservesand apply new completionoptions to maximize produc-tion and accelerate theirrecovery. The study showedthat significant reservesremained in the previouslycompleted reservoirs, someof which had been shut in asa result of sand production.

To evaluate further poten-tial, full-field simulationmodels were constructedwith a scaled-up static geo-logical simulator, which hadbeen initialized and historymatched. Ten wells wereidentified for a workovercampaign, and six wells wereidentified for infill drilling orsidetracks. Some method ofsand control was required in80% of the proposed produc-ing intervals.

This article, written by TechnologyEditor Dennis Denney, contains high-lights of paper SPE 77919,Enhanced Gravel-Pack CompletionsRevitalize a Mature Sand-ProducingFieldA Case Study, by MohamedZaini B. Md Noor and Kasim B.Selamat, Petronas Carigali Sdn.Bhd., and Sharifudin Salahudin,SPE, Halliburton Energy Services Inc.,originally presented at the 2002 SPEAsia Pacific Oil & Gas Conferenceand Exhibition, Melbourne, Australia,810 October.

For a limited time, the full-lengthpaper is available free to SPE mem-bers at www.spe.org/jpt. The paperhas not been peer reviewed.

Fig. 13D visualization of the Dulang field.

JANUARY 2003 43

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nSand ExclusionEvaluation of appropriatesand exclusion techniques torevive and complete the sand-prone reservoirs was ap-proached with the followingprimary goals.

Maximize productionand accelerate recovery fromthe sand-excluded zones.

Implement appropriatecurrent or new sand-controltechniques.

Most of the prospectiveworkover completion inter-vals had produced sand, andcavities existed behind thecasing, which had to be filledand the formation restressed.A screen hang-off or expand-able-screen installation would reduceproductivity because the annulus andperforation tunnels would fill withformation sand. Also, an increase inmechanical skin would result frominstalling internal gravel packs.

The recommended sand-controlmethod was an extension gravelpack, primarily because the zones tobe packed were discrete units, eachwith a low Youngs modulus, andbecause accelerating recovery wasimportant. The alternative recom-mended method was an acid prepackfollowed by a high-rate water pack(HRWP). An economics evaluationverified that the incremental cost toinstall a fractured or enhanced gravelpack vs. a conventional internal grav-el pack was relatively small withrespect to possible increased produc-tivity. Thus, an extension gravel packcombining sand control and stimula-tion was chosen as the primary meansof sand control for these reservoirs.An HRWP was the preferred optionwhen completion horizons had to becombined, there was insufficientspace to install an individual-zonegravel pack, or there were insufficientreserves to justify completing thezones individually. In addition to theextension pack and the HRWP meth-ods, two zones were selected to befrac-pack gravel packed to gain expe-rience in maximizing sand behindthe perforations.

Reservoir PropertiesThe production intervals are discretesand bodies, 16 to 66 ft thick, withwell defined shale barriers boundingthe sands. No underlying water

zones or overlying gas caps werein close proximity to most of thereservoirs. The original reservoir pres-sures ranged from 1,700 to 1,800 psi,while current reservoir pressuresrange from 1,200 to 1,400 psi.Permeabilities range from 50 to250 md, porosities from 20 to 30%,and oil viscosities from 0.9 to 1.1 cp atreservoir conditions.

Enhanced Gravel-Pack MethodsEnhanced gravel-packed methods pri-marily apply fracturing technology tothe soft high-permeability formationsrequiring sand control. With theadvent of tip-screenout fracturedesigns, fracture length is arrested andfracture inflation occurs, achievingsignificantly higher fracture conduc-tivities on the order of tens of thou-sands of md/ft.

Because high-permeability forma-tions in which sand-exclusion treat-ments were necessary might sustaindamage during the drilling and com-pletion operations, a short, propped,highly conductive fracture resulted inwells with higher productivity andreduced skin values.

Frac Pack. A frac pack is a fractureand gravel-pack technique that uses atip-screenout fracture design to createa short (50 to 100 ft), wide, highlyconductive fracture with the gravel-pack assembly installed across thezone. The goal of the frac-pack treat-ment is to place 500 to 1,200 lbm/ft ofproppant behind the casing.

Extension Pack. An extension gravelpack uses a 20- to 60-lbm/1,000 gal

gelled fracturing fluid.Typically, the treatment isplaced at a rate approxi-mately 3 bbl/min greaterthan the fracture extensionrate. The inefficient fracfluid has extremely highleakoff, which causes frac-ture lengths to be shorterthan 50 ft. Up to 300 lbm/ftof proppant is placed.

HRWP. These fracturetreatments are pumped atfracture-extension rateswith a lightly gelled fluid orbrine. Typically, treatmentsare run with the gravel-pack tool in the squeezeposition. Open perforations

are positioned above the tool, or in thecirculate position (taking approxi-mately 2 bbl/min returns), when along interval is involved. Fracturedimensions obtained with this tech-nique are very small and rarely extendpast the perforation tunnels. Pack fac-tors are usually in the range of 50 to100 lbm/ft.

ResultsTwelve wells and 25 zones were gravelpacked as part of the workover andsidetrack campaign in the Dulangfield. The recompletions were per-formed with a hydraulic workoverunit, while the workovers and side-tracks were completed with a rig.Results obtained and experiencesgained with the enhanced gravel-packmethods were highly commendable.Pack factors obtained, 100 to 500lbm/ft, far exceeded previous gravel-pack methods performed in Malaysia.Oil production from these enhancedgravel-pack zones exceeded expecta-tion by approximately 25%. The actu-al production exceeded expectationsfor most of the wells.

ConclusionsThe combination of sand control andstimulation techniques (frac pack,extension pack, and HRWP) will beconsidered for sand control in all casedand perforated completions. It has suc-cessfully increased the productivityand prevented sand production in theDulang wells. Formations encounteredin the Dulang field have respondedvery well to the selected techniqueswith an average production rateincrease of approximately 25%. JPT

Fig. 2Hole in blast joint installed across the LD1reservoir caused by sand production.

44 JANUARY 2003

The Griffin DevelopmentFlying High on Infi l l Success

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Drilling, completion, and tieback ofthree Griffin area infill wells and a re-entry campaign has resulted inimproved production rates andincreased reserves. Reprocessing the1991 3D seismic data, combined withreservoir modeling studies, led to theapproval and drilling of two Zeepaardinfill wells in mid-2000. Results of theGriffin infill well changed the under-standing of reservoir sweep in thatfield and led to a re-entry campaign inlate 2000, followed by a second infillwell in early 2002.

IntroductionThe Griffin oil and gas development isin the southern Carnarvon basinapproximately 42 miles offshoreWestern Australia. The facility wascommissioned in 1994 to produce oiland gas from the Griffin, Scindian,and Chinook fields. Each field con-sists of two distinct reservoirs, theexcellent quality main Zeepaard reser-voir and the overlying poorer qualityBirdrong reservoir.

The Griffin field was discovered in1990 by the exploration well Griffin-1,which intersected 112 ft of oil-bearingBirdrong reservoir and 213 ft of oil-bearing Zeepaard reservoir. Threeadditional wells, Griffin-2, Griffin-3,and Ramillies-1, were drilled to delin-eate the Griffin structure.

The Chinook and Scindian fields werediscovered in 1989. The Chinook-1exploration well encountered a 62-ft oilcolumn in the Zeepaard overlain by128 ft of gas-bearing Birdrong.Scindian-1A was drilled in 1990 anddiscovered a similar accumulation. TheChinook and Scindian reservoirs areconnected through the Birdrong oil col-umn but are separate accumulations inthe Zeepaard.

Following the exploration success,development drilling was completedand at first production in 1994 therewere four vertical Griffin Zeepaardwells, one vertical Chinook Zeepaardwell, one vertical Scindian Zeepaardwell, and three sinuous horizontalBirdrong wells. All nine development

wells were subsea, tied back with acombination of flexible and rigid flow-lines to a disconnectable floating pro-duction, storage, and offloading (FPSO)facility. The oil is stored and transport-ed by tanker, the processed gas is dehy-drated and compressed for export intoa natural gas pipeline, and water is dis-posed of overboard. Because the initialnine development wells used all avail-able flowlines and riser slots, infilldevelopment requires manifolding newwells with existing producers and pro-duction prioritization to account forflowline capacity and FPSO gas han-dling constraints.

Production Performance and ModelingFirst production began in January1994 at a maximum rate of 85,000STB/D. Production began to decline in1996 with increasing water cut fromthe majority of the wells. In early1999, a subsurface team made up ofgeoscientists and engineers from theWA-10-L joint venture was formed toevaluate fully the Griffin area fieldsand to identify any developmentopportunities that might exist.

Griffin Zeepaard Reservoir. TheGriffin Zeepaard reservoir has been themost productive, producing to datemore than 100 million STB. By early1999, 5 years after startup, more than70 million STB of oil had been pro-duced from the Griffin Zeepaard.Griffin-4, the most downdip producer,had watered out because of waterinflux from the north, and Griffin-2and Griffin-3 had developed significantwater cuts. Griffin-1, the structurallyhighest well, was still producing25,000 STB/D of dry oil.

The excellent performance fromGriffin-1 was difficult to match withthe existing reservoir model, whichpredicted water breakthrough as earlyas 1996. Water breakthrough actuallyoccurred in July 1999 near the end ofthe remodeling work.

To match the historical performancein Griffin-1, the thin claystones need-

ed to be breached to enable oil inUnit 2 access to the perforations at thetop of the Zeepaard and delay waterbreakthrough in Griffin-1. The clay-stone breaching mechanism was inter-preted to be channel erosion/scouring,or small-scale faulting that was belowseismic resolution.

Updated seismic interpretation indi-cated that there was a high probabilityof an updip accumulation to the eastof Griffin-1, and reservoir modelingindicated that this accumulationwould not be swept effectively duringfield life. Griffin-8 was proposed toaccess this accumulation and moreeffectively sweep the stranded oilbetween Griffin-1 and Griffin-2 andthe eastern bounding fault.

Chinook and Scindian ZeepaardReservoirs. Reservoir modeling indi-cated that Chinook-1 had been posi-tioned optimally at the top of thestructure, and would drain approxi-mately 60% of the oil reserves initiallyin place in the Chinook Zeepaardreservoir. The Scindian-1A well wouldrecover only approximately 40% of theScindian Zeepaard reserves because itwas located within a graben of theScindian structure. The Scindian-3infill opportunity was identified toaccess reserves in the Scindian Westblock, updip of Scindian-1A.

This article, written by AssistantTechnology Editor Karen Bybee, con-tains highlights of paper SPE 77920,The Griffin DevelopmentFlyingHigh on Infill Success, by L.J.Workman, SPE, T.V. Slate, and B.F.Oke, BHP Billiton Petroleum Pty. Ltd.,originally presented at the 2002 SPEAsia Pacific Oil and Gas Conferenceand Exhibition, Melbourne, Australia,810 October.

For a limited time, the full-lengthpaper is available free to SPE mem-bers at www.spe.org/jpt. The paperhas not been peer reviewed.

JANUARY 2003 45

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nBirdrong Reservoir. Griffin-5(H) andGriffin-6/ST(H) are both sinusoidalhorizontal wells draining the GriffinBirdrong reservoir. Griffin-5(H) startedcutting water in May 1996, but Griffin-6/ST(H) remained relatively dry.Griffin-6/ST(H) production has de-creased because of poor aquifer sup-port and declining reservoir pressure.These two wells are forecast to recoverapproximately 30% of the oil-in-placein the Griffin Birdrong reservoir.

Scindian-2/ST(H) is a sinusoidalhorizontal well in the Chinook/Scindian Birdrong reservoir. The wellis subject to gas and water coning asthe high-mobility Scindian Birdronggas cap is drawn into the well.Scindian-2/ST(H) is forecast to recover15% of the oil in place.

Seismic 2D Reprocessing. TheGriffin 3D survey was acquired andprocessed in 1991. No further process-ing was performed on this data untilmid-1999 when selected 2D lines werereprocessed (time and prestack depthmigration) for optimizing the Griffin-8and Scindian-3 infill well locations.The 2D reprocessing demonstratedthat significant improvement in seis-mic data quality was possible. Animportant result of this work was thatthe Griffin-8 well was relocated from alikely downside fault location, saving amultimillion-dollar sidetrack.

Infill 2000The two proposed infill wells,Griffin-8 and Scindian-3, were drilledand completed in April to June 2000.The infill wells came on at high rates,producing clean oil, and increasingtotal Griffin area production from30,000 to more than 55,000 STB/D.

Griffin-8. Griffin-8 intersected the topZeepaard approximately 62 ft lowerthan projected, reducing the updipattic to only 4.6 ft. The well intersect-ed a 207-ft oil column, 141 ft morethan expected. Griffin-8 pressure datashowed differential depletion hadoccurred in the Griffin Zeepaard, withincreasing depletion toward the top ofthe reservoir. Griffin-8 came on pro-duction at 26,000 STB/D. Water cutincreased very quickly, and the welldeclined rapidly.

Scindian-3. As predicted, Scindian-3intersected a 102-ft hydrocarbon col-umn with a 10-ft gas cap. Scindian-3

was perforated in the gas, and thesmall gas cap was blown down duringthe first few months of production.The well started up at 10,000 STB/D,which quickly increased to 17,000STB/D as the gas/oil ratio of the welldecreased. The well produced clean oilfor 6 months and has produced6.5 million STBO to date.

Re-Entry Program 2000/2001The unexpected results of Griffin-8changed the understanding of reservoirdynamics in the Griffin Zeepaard reser-voir. The concept of a single water/oilcontact (WOC) moving uniformlythrough time with local coning effectsat the wells had to be discarded, giventhe extent of the oil column found inGriffin-8. The structural informationfrom Griffin-8 was incorporated into anew top structure map, and the reser-voir model matched to the Griffin-8results by modeling water movementthrough Unit 1. The thin claystoneswithin the unit were sealed and thenbreached at specific locations to matchwater cut development of all producersand the Griffin-8 pressure results. Thisresulted in a bottom water and anenhanced edge waterdrive mechanismwith water moving through the reser-voir along the top of claystones, leavingbehind trapped accumulations of oilbelow the claystones in crestal loca-tions. All production wells were stud-ied as possible re-entry candidates,looking for unswept volumes in Unit1B and Unit 2, which initially were notperforated in all wells.

Griffin-8 was re-entered inNovember 2000. Logging indicatedUnit 1 was still full of oil and Unit 2had only a few feet of oil remaining.The existing Unit 2 perforations werepartially shut off, and perforationswere added in Units 1A and 1B.

Griffin-1 was re-entered in the samecampaign. The results confirmed thatthe thin claystones within Unit 1 hada major effect on the productiondynamics of the reservoir. Oilcolumns were found beneath watered-out zones; an 18-ft unswept oil col-umn was seen in Unit 1B beneath a2-in.-thick claystone, identifiable onlyby core. The claystone was interpretedas extending for several hundreds offeet, trapping oil in the crestal locationbut breached by channel scour withinthe oil column. Perforations wereadded in Griffin-1 to both the Unit 1Band Unit 2 sands. The re-entry pro-

gram increased production by 30,000STB/D to more than 65,000 STB/D.

Seismic 3D ReprocessingIn the Griffin area, depth conversion ofseismic two-way time data is compli-cated by shallow high-velocity carbon-ates that are variable in thickness andlateral extent. Where present, thehigher velocities cause diminisheddata quality of underlying sections.After drilling Griffin-8 and Scindian-3,it was recognized that remainingpotential infill opportunities requiredsignificant improvements in seismicdata quality and greater certainty indepth structure mapping for optimumwell placement. Griffin 3D seismicdata was reprocessed with 3D prestacktime migration in early 2001, and theresults were impressive. Reprocessedseismic data improved seismic resolu-tion, reduced lateral zone of uncertain-ty for major faults, and allowed use ofadvanced workstation techniques.

Infill 2002Results of the re-entry campaign pro-vided a better understanding of reser-voir dynamics in the Griffin Zeepaard.A remodeling program was undertak-en to incorporate the new top struc-ture map from the reprocessed 3Dseismic data to match the WOC resultsseen in the re-entry program. Thiswork indicated further potential forinfill drilling of unswept oil volumesto the north of Griffin-8, updip ofGriffin-2. Griffin-9/ST1 was drilledand completed in December 2001with first oil in February 2002. Thewell intersected a 125-ft oil column(79 ft vertical) in Unit 1 with smalleraccumulations in Unit 2. The wellcame on production at 27,000 STB/Dclean oil and once again increased pro-duction to more than 60,000 STB/D.

ConclusionsProduction has been boosted substan-tially on a number of occasions bydrilling infill wells and re-entry opera-tions. Opportunities for these wellswere identified by use of productionhistories, improved mapping of the topstructure, and improved understand-ing of reservoir flow dynamics. Fromthe improved understanding of reser-voir dynamics that resulted from infor-mation provided by infill wells camethe ability to model reservoir perfor-mance, optimize reserves, and forecastproduction more accurately. JPT

46 JANUARY 2003

Fracture StimulationOptimization in a MatureWaterflood Redevelopment

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The full-length paper is a case histo-ry describing fracture optimizationof low-permeability, highly strati-fied stacked turbidite sandstonereservoirs of the B interval in the ElkHills field. Occurrence of high-per-meability, high-pressured water-sat-urated sands immediately aboveand/or below the objective oil sandsposes a major challenge. Resultsfrom surface tiltmeter measure-ments completed during 26 fracturestages were used with downhole tilt-meter data and reservoir characteri-zation to optimize the ongoing rede-velopment from a peripheral water-flood to a pattern flood.

IntroductionElk Hills field produces oil and gasfrom several reservoir intervals.Production depths range from 1,100to 9,500 ft. In 1941, Stevens sands ofthe Upper Miocene Montery forma-tion were found to be productive onthe 31S structure, the largest of threedeep structural anticlines at Elk Hills.Primary Stevens reservoirs on the 31Sfeature include the Main Body B(MBB) and Western 31S (W31S) of theB interval and the younger, prolific26R pool.

MBB/W31S reservoirs occur atapproximately 6,500 ft and exhibit2,800 ft of vertical closure between theupdip pinchout of the sands near theanticlinal crest and the water/oil con-tact (WOC) at 6,800 ft subsea depth.These zones have abnormal reservoirpressure, good permeability, and thicknet-pay development. MBB produc-tion was held in reserve with only peri-odic tests until the energy crisis in themid-1970s. In 1976, the U.S. Dept. ofEnergy began producing the intervalat initial rates ranging from 500 to2,000 BOPD per well.

A peripheral waterflood pilot wasinitiated in 1978 and expandedaround the entire 31S structure by1983. Injection wells near the WOCwere perforated in all MBB/W31Sreservoir-quality sands, and injectionvolume was tracked by layer by peri-

odic injection profile logging.Development wells were drilled aheadof the flood front to capture oil bankedby water moving up the structuralflanks. Wells that watered out as theflood front advanced were either shutin or recompleted to shallower zones.Under this reservoir managementstrategy, the MBB/W31S zones wereinactive in wells on approximately60% of the originally productiveacreage when the current operatorassumed operation of Elk Hills inFebruary 1998. Shortly thereafter, afew wells were drilled behind the floodfront to evaluate the remaining oilpotential. New logs revealed unsweptzones in the MBB, and current devel-opment is largely focused on bypassedoil in lower-permeability sandstone orlaterally discontinuous sands not incommunication with the peripheralwaterflood injectors.

Before the acquisition, high produc-tion rates from better-quality sands ofthe Upper MBB (UMBB) and W31Sreservoirs precluded stimulation, withthe exception of occasional acid jobs.Hydraulic-fracture stimulation wasused on fewer than a dozen comple-tions on the 31S structure in the lower-quality sandstones of the Lower MBB(LMBB) and Upper W31S on the east-ern nose of the structure. The previousoperator had recognized that theLMBB was not fully processed byperipheral waterflooding, and conver-sion to pattern flooding was anticipat-ed. While continuing LMBB stimula-tions, testing of hydraulic-fracturestimulation techniques in the W31Ssands on the northwest nose and low-permeability MBB sand in the north-flank tight-rock area began in mid-1998. Only recently have fracturestimulation techniques been appliedto better-quality MBB sands and tointerbedded sands and siliceous shalesof the B shale interval.

The major challenge of recent frac-ture stimulations is to contain treat-ments within the objective sandstonelayers and avoid propagating into thehigh-permeability, higher-pressured

water-swept sands immediately aboveand/or below.

To evaluate fracture orientations andcalibrate the fracture design model,surface and downhole tiltmeter mea-surements were made during severalrecent fracture treatments. Resultsshowing higher-than-expected frac-ture vertical height growth promptedmodification of the fracture model bychanging stress values in several layersto better reflect measured fracturegrowth. This, in turn, resulted inchanges to fracture design, perforationstrategy, and pumping schedules tolimit height growth.

Tiltmeter fracture mapping resultsalso are important for redevelopmentof the MBB waterflood from peripher-al to a 20-acre pattern alignment.Because measured 450-ft fracture half-lengths have been observed, fractureorientation may influence sweep effi-ciency given the 5-acre well spacingfor infill development of lower-perme-ability layers.

In the last year, 49 MBB stages werepumped in 40 wells, placing 7.2 mil-lion lbm of proppant. Average prop-

This article, written by AssistantTechnology Editor Karen Bybee, con-tains highlights of paper SPE 76723,Fracture Stimulation Optimization inthe Redevelopment of a MatureWaterflood, Elk Hills Field, California,by Tom Walker, SPE, Shawn Kerns,SPE, Dick Scott, SPE, and PaulWhite, SPE, Occidental of Elk HillsInc.; John Harkrider, SPE, ApexPetroleum Engineering; CraigMiller, SPE, BJ Services Co.; andTarlochan Singh, SPE, PinnacleTechnologies Inc., originally presentedat the 2002 SPE WesternRegional/AAPG Pacific Section JointMeeting, Anchorage, 2022 May.

For a limited time, the full-lengthpaper is available free to SPE mem-bers at www.spe.org/jpt. The paperhas not been peer reviewed.

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npant per well was 180,000 lbm, withthe largest treatment placing 433,000lbm at 60 bbl/min. Initial post-stimula-tion production rates averaged 250BOPD, compared with 50 BOPD forunstimulated completions in MBB.

Fracture History in MBB ReservoirLimited stimulation efforts before1998 focused on hydraulic fracturingof low-permeability LMBB sands onthe eastern nose of the 31S structure.The success or failure of these earlystimulations relied on the contain-ment qualities of the BCA shale tolimit fracture growth into the overly-ing higher-permeability, water-sweptUMBB sands. Incremental productionresulting from this stimulation pro-gram was inconsistent with post-frac-turing rates ranging from less than 10BOPD to more than 150 BOPD.

With increased understanding ofbypassed oil potential, drilling,workover, and stimulation effortsshifted to the UBB3 and UBB4 layers atthe base of the UMBB. An effectivefracture stimulation technique for thelower-quality sands and siliceousshales of this interval could enhancethe value of this secondary objectivethat has experienced an erratic devel-opment history.

Fracture Objectives and TechniquesDetailed in-situ stress profiling, perfo-ration placement options, andhydraulic-fracture modeling wereintegrated to develop a completionand stimulation strategy that mini-mized fracture conductivity into thewater-bearing intervals. By use of apseudo-3D hydraulic-fracture stimu-lator, stress and leakoff profiles wereinitially calibrated by history match-ing previous MBB treating pressureresponses. From this preliminaryunderstanding of stress contrast, iter-ations were performed to maximizetreatment design size while alteringperforation placement strategy withinthe objective bypassed sands.Modeling also provided a predictionof fracture height growth and an indi-cation of contact with adjacent water-bearing intervals.

Front-end diagnostic injection testswere incorporated into the designsand executed ahead of the proppant-laden stages. These injections wereuseful in refining the stress and

leakoff profiles, determining qualityof the near-wellbore connection, andproviding an estimate of the overallfracture geometry created. Forwardmodeling sensitivities based on thefracture complexity and leakoffresponse were performed to evaluatethe upward and/or downward frac-ture growth. These sensitivity runsguided modification of pad and prop-pant-laden stages to avoid propagat-ing into water-bearing intervals. Real-time assessment of proppant distribu-tion pattern was managed to limitoverall net pressure development andminimize vertical fracture growth.Several recently completed fracturestimulations on the southeast nosethat targeted a specific bypassedoil zone have improved oil produc-tion dramatically.

Tiltmeter Fracture MappingPrimary measurements from surfacetiltmeter mapping are fracture orienta-tion (azimuth and dip) and horizontalfracture component. Fracture azimuthis useful for waterflood pattern layout,especially in low-permeability reser-voirs where required well spacing maybe close to fracture length. Fractureorientation behavior is a leading indi-cator of asymmetric pore pressurechange, which influences fractureazimuth and dip and increases thehorizontal fracture component.

Twenty-six fracture treatments havebeen mapped with surface tiltmetermapping. Fracture azimuth resultsfrom the UMBB treatments in the sec-tion 35S wells are fairly consistent.Overall field mapping results indicatea high degree of fracture azimuth vari-ability in the MBB as well as significantfracture growth in multiple verticalplanes for several treatments.Variations in fracture orientation andthe possibility for unexpected futureorientations will affect future water-flood plans for the MBB. The lowdegree of variability in the fracture dipindicates that vertical stress is alwaysthe maximum stress.

The horizontal component is thefracture volume percentage containedin horizontal fractures. Generally, therelative impact of the horizontal com-ponent increases as pore pressure dif-ferences in the formation increase. Forthe MBB treatments, the horizontalfracture component has ranged fromnegligible to almost 35% of the totalfracture volume.

Fracture Model OptimizationDuring the last few years, a wealth ofdata has become available from directfracture diagnostics, such as tiltmeterfracture mapping and microseismicfracture mapping in many differentareas. Experience gained throughmany direct measurements of fracturegrowth at Elk Hills field has con-tributed significantly to that knowl-edge base. These direct measurementshave been incorporated in the initialsettings of a fracture growth modelbeing used for other areas and forma-tions. Matching fracture geometry pre-dicted from modeling with observedfracture geometry improves modelingand achieves better predictions of frac-ture growth under comparable cir-cumstances. Reliable predictions offracture stimulations enables evalua-tion of economic tradeoffs betweenstimulation and completion designalternatives. Though tiltmeter datasuggest some fracture complexitiesthat are not anticipated in the fracturemodel, fracture upper and lowerbounds are being reliably modeled.

ResultsThe majority of recent fracture treat-ments performed in new infill wellsand existing-well workovers haveshown excellent results. Responsefrom recent development of bypassedoil targets has doubled the daily pro-duction rate in the southeast nosearea, while water increased by only40%. This has led to a significantincrease in expected ultimate reserverecovery as well as reserve additionsfrom the MBB/W31S reservoirs.

Conclusions1. Limiting fracture height and effec-

tive length are critical to effective water-flood redevelopment and recovery.

2. Downhole and surface tiltmetermapping results are valuable in under-standing actual fracture geometry.

3. Downhole tiltmeter data can beused to calibrate the 3D fracture modeland achieve increased confidence inmodel output.

4. Fracture azimuth in the MBBreservoir is variable because of region-al tectonic stresses, low differences inhorizontal stress, and reservoir porepressure variations.

5. Asymmetric pore pressure deple-tion and waterflood pressure chargingcan cause fracture reorientation fromthe predicted trends. JPT