8/6/2019 SPE19837

1/14

.,

SPESPE 19837A Case Study of Improved Recovery Options in aVolatile Oil ReservoirP.A. Schenewerk and B. Heath, Woods Petroleum Corp.SPE Members x

Copyright 1SS9, Sociefy of PetroleumEngirreere, Inc.Thk paper was prepared forprseentetiorrat the S4thAnnualTechnical Conference and Exhibitionofthe Socimtyof Psfrokum Engineereheld in SanAntonio,TX, Cktober S-11, 16SS.Thle paper wee eeleotedfor presentationby an SPE Program Commlftse followingreview-ofInformationcontainedin an abstractaubmlftedby the aufhor(a).Contentsof the paper,aa presented, have notbean reviewed by the Society Ofpetroleum Enf$nasrandare aublactoCOITS@II by the aut~a). The material. IM p f~tedt *a ~ *ffe@Y r-anyp+alt!emof the Sooletyof PetroleumEnglneera, ifsoffkara, w mernlxa. Pspem pmeented atSPS meetingsare a@acf to pubficatbn rewiewBYEdlforfalCommfftseeofthe SocbfYofPetroleumf%giIWW Parmieeiontocopyk restrictedtoan abatracfofnotma than3(IOworde.ffluatrstkmamaynotbe Coplad.The abaWectShoutdCOfddnc on a p kL w e e Ck r m k dWMfo f wh e r e and by whomthe paper ia presented. Write PublicationsManager, SPE, P.O. Box633S3S, Rkhsrdaon, TX 7SOSMS36. Telex, 730SSe SPEDAL.

Sandstone which is known locally as the hkotaINIROMWfION Sandstone. Structure across the field is uniformW@ South Buck Draw (Dakota) Field lies on the with a southwest dip of approximately 100 feet pertile. Structure does not play a significant roleeastern flank of the Powder River Sasin along the in the production process in the field.border of Converse and Campbell Counties, Wyoming{Figure 1). The reservoirs in the field produce a ltw environment of deposition within thevolatile oil frcm stratigraphic traps tie up of Dakota is varied. In the South Buck Draw Field,flwial channel and marine longshore bar deposits.This paper presents the results f rcaa a field study production is found in both a regioml marinefacies and localized f lwial facies. The regiomlwhich was *de to deter@ne the feasibility of marine facies consists of what are interpreted topartial pressure maintenance -rations for be near ahoreimproved recovery. While it was found that partial rum+arine to marine deposits withthe productive reservoir being located in areas ofpressure maintenance operations could recover in- preservad longshore bars (Figure 2a). fie f lwialcrenbental oil, it was determined that the field facies consists of point, bar deposits in a

would not be amenable to flooding Operationsbecause of reservoir discontinuities, a develop northeast-southwest trending channel which has beenincised in the older narine sediuents (Figure 2b).fracture system and highly unstable oil ~ gas Figure 3 shins the delineation of the regionalprices. .,. atarine and fluvial facies in the field.The study showed that primary recoveiy in Sorda pressure and fluid communication appearsvolatile oil reservoirs can be very gowi, ~generally to exist betw&en the different producing facies,in excess of 20%of the original oil-in-place. It howaver, this seem to be limited to localizedalso showed that estimation of original oil-in- areas of sand on sand contact. Pressure detawasplace for volatile oils is difficult even:when available from a variety of individual well testspressures remain above the bubble point.-Additional as well as two field-wide pressure surveys. ihework, done after the original study, is also pre- field-wide pressure data appeared to indicate thatsented which sh.aws the effects of both full and there were at least two and pussibly three isolatedpartial pressure maintenance operations begun above regions within the flwial facies. Wall control inand kelw the bubble point pressure. Incremental this field is lietited due to the current spacing ofoil can be produced, hgwever, the econ~cs of one well per 640 acres, and as a result, detailedthese projects met be carefully scrutinized. reservoir characterizations are difficult if notiqossible to make.mIm3Y

DEVEU3- H18JX)RYThe Po@er River Basin is located in north-eastern Wycan.ingand soutkastern Hontana. The The South Buck Draw Field Was discovered inbesin was formed as a result of defamation which August 1977, when the Woods Petroleum Corporationsoccurred due to t~ late Cretaceous-early Tertiary Moors-Gibbs No. 9-1 was completed for 705 BOPDandLaramide Orogeny . The field produces from 2,3301WXD.deposits of the Liner Cretaceous Fall River Field developmnt continued throuijh1986. redate, there are 12ws11s coqletsd in theflwial facies and 7 regional marine facies wells.Eef erences and figures at end ok paper.

67 ,.

8/6/2019 SPE19837

2/14

A CASE STUDY OF IMPROVEDRECOVERYOPTIONS IN A VOLATILE OIL RESERVOIR SPE 1983AS a general rule, the fluvial facies wellstend to M significantly better prcducers due tothe presence of a larger volume of reservoir andbetter resezvoir rock which is enhanced by afracture system Cumulative production frcsn thefluvial tat:swells through 1988 was 3,663 MST8ofoil and 12,409 HMSCFof gas, while the marinefacies prduced 612 MSTSof oil and 3,574 MM8CFfgas. Figure 4 iS a plot of prtiuction fOr thefluvial facies wells.

RSSERVOIRFLUIDSVolatile or near critical oils usually have~1gravities above 40 degrees, gas-oil ratiosabove 2,000-2,500 SCF/STS, and formation volumefactors above 2.0 RS/STS. In addition, theircomposition is made up of 12.5 to 20 mole percentof heptanes pluszwith 35 percent or more of methanethrough hexanes . IWObottomhole fluid sampleswere available for use in the study.The first sample was taken in the S. ArmstrongNo. 1 well in MSy 1981. Laboratory analysis ofthis sample showed that the reservoir fluid wasundersaturated at the original reservoir conditionsof 8,100 psi and 286 degrees F. The formation

volume factor at the bubble point pressure of 4,530psi was 2.314 RB/STS. The initial solution gas-oilratio was found to be 2,034 SCF/STS. A secondsanple, taken in March 1982 from the AndersonFederal No. 1-27, indicated a bubble point pressureof 4,8BT >&i, a formation volume factor of 2.329RS/STS and a solution gas-oil ratio of 2,075SCF/STS. Table 1 shows the compositic.ns of thesesamples. Since a significant auun3nt of reservoirdepletion had occurred between the time the sampleswere taken, the initial sa@e from the S. Arm-strong well was used in the study.RSSERVOIRKXKPROPERTISfj

Seven fluvial facies cores had been taken inthe field and ware available for this study.Routine laboratory analysis were available fdr eachcore. In addition, one core had been preserved andwas mede available for special core analysis.

The routine analysis showed that permeabilityto air ranges from zero to 44 md. The log normalpermeability variation was found to be 0.9, whichis an indication that the reservoir is fairlyheterogeneous. Figure 5 is a plot of the perme-ability distribution for the wells in South BuckDraw. fie average core porosity nthe field is4.78% and the gemetric average s rlneability is0.12 z13. Figure 6 is? Crossplot of permeabilityand porosity for all the core data. In general,the higher pemeabilities and better porositiesare located in the lower portion of the sand bcdywhich is characteristic of this type of flwialdeposit.Vertical fractures are present in about halfof the cores and @onot a~ar to be a product ofthe coring operation. lt3e presence of a developedfracture,system was felt by some to help accountfor the high production rates in what would other-wise be considered very poor reservoir rock. lhereis little widence of fractures on the pressurebuildup tests, but buildup khs tended tobe at

least two and sometimes three times as high as thecore khs.The preserved core material was used.forsteady state gas displacing oil relative &mna-ability tests. Aplot of one of these te~ts isshorn in Figure 7. These tests indicatedlthat theinitial water saturations in the Dakota a$e verylow, less than five percent, which confirmed openhole log calculations. l%e character of ~ tests,coupled with the very low water saturations

present, indicate that the reservoir is iiiter-mediate to oil wet3. Laboratory test datafromasimilar Dakota reservoir off-setting the f$eldsupports this conclusion. !ESTIMATION F ORIGINALOIL-IN-PLACE

The simplest mthod for determi;ling originaloil-in-place (OOIP) is by volumetric analysis.Unfortunately, due to the lack of well control andthe complexity of the depositional system, it wasimpossible to map the reservoir with any degree ofconfidence. Several iterations of the mappingprocess were madeby the operators with widalydivergent results. The resulting maps were plani-metered in order to estimate OOIP. Time estimatet;ranged frrsa 15 to 21 FFISmin place.

Realizing the inherent limitations of thetraditional black oil material balance equation(?4BE) in volatile oil systems, its use in esti-mating 00IPwss consider~~limited and wasapproached with caution . At the tim of t heoriginal study, it was believed that as long as threservoir presurd was above the bubble point, thenthe MEEweuld give satisfactory results. Usingthis approach, however, led toestimtes of ~IPwhich ranged from15 to 32 HM819withthemstlikely value being 21.51wIsIs.This wide range of OOIP estimates frmthe Mis not surprising and arises frcmtwo sources of

error. Itw first, uncertainty in the value ofaverage reservoir pressure, is codrmn to most allapplications of the W approach. The secondproblem ismre difficult since it arises frcmthenature of the reservoir fluid and the producingmchanis3ss in the reservoir. Maile the averagereservoir pressure may be well above the bubblepoint, it is still possible for the flowing bottmhole pressures in the producing wlls tobe sig-nificantly below the bubble point. As a result ofthe two phases flowing in the vicinityof thewellbore, sane compositional e ffe c t s c an occur.This will becw s30re pronouncedas the reservoirpressure falls closer to the bubble mint pressure.Secause there was a lack of confidence in bot

the volumetric and MSEmt.hods, another approachwas used to estimte OOIP. A-single well radialcompositional nodal using equation of state para-meters derived frcez the S. AmetrongNo. 1 fluidstudy was developed and used to estimate pe r c e n t a gof C J 3 1 Pproduced versus the associated pressuredrop. Using the single well mdel, the comp-ositional effects o f producing wells fknting belowthe bubble point cOUMbe accounted for.It iswell luxnm that single txill mdels arefraught with danger erdsust be tmdwithcautions.

.-S74 ..,=.

8/6/2019 SPE19837

3/14

..SPE ?9837 P. SCHENEWERKand B. HEATH 3Ho#ever, in the older portion of Sou th Buck Drak partial pressure maintenance might onlyba con-Field, production frcmthe wells had established sidered where there is the possibility of forming awell defined no flow boundaries between the secondary ga s cap up-structure frc6n the producingprducingwell,ii. In addition, the production from wells. In this field, the volatile nature of thethewellswas not influenced by outside mechanisms fluid was seen as an asset in a reservoir Whki?such as watez encroachment or gas migraticn due to lacked sufficient structure to forma secondary gasstructural di,?. As a result, the single wall model cap. ilte recovary process envisionedby thecan be used. operators was one in which pressure decline wnuldbe slowed and reservoir liquids would be re-lhe well .phosen for history matching was the vaporized as they casm into contact with theAnderson Federal NO. 1-27. lhiswll hada injected dry gas.sufficient mount of pressure data, both flowingbottm-hole and buildup, to justify confidence inthe history matched model results and subsequent Apcocess mdel was constructed in order topredictions. The wll was history matched using evaluate the effect of partial pressure suiintenanceflowing bottm-hole pressure &ta to match in- operations in the South Buck Draw Field. Thestantaneous end cumlative production of gas and process model was a vertical cross section throughthe reservoir in the preferential direction ofoil. Once the history match was obtained, the flow. A full fieldmdel was not consideredpressure versus percentage recovery data was used because the quality of the reservoir descriptionto eSti=te the OOIP. Using this method, the OOIP did not justify it and the coarse grid size thatwas estimated to @ 15.4 MFIBmwhich confirmed thelower values of both the volmet[ic and MBEmethods would be required would have had significantnumerical dispersion problemaio.of evaluation. The 45X3 cross sectional model was fullyM additional benefit of the radial model coaqnxitional using the ~ equation of &atestudy was that by running a pressure depletion parameters previously used in the radial model.case, it provided an estimate of primary recovery The cross section was 4,500 ft. long and hadefficiency. The model suggested that primary uniform thickness of 25 ft. lhe reservoir wasrecovery would be on the order of 23.5% of t h e layered using the pammbilityd istributionda-OOIP. This confirmd previous studies7 . This fined in Figure 5. This layering scheae resultedresult was iapxtant in that several operators in in three layers with the properties shown in fablethe field felt that primary recovery would h low 2. The layers wre.orderedwith the highastpersx+due to adverse gas-oil relative pemmbility ability on thebottoleandthe lowest ontha top.effects below the bubble point. Their reasoning In Bouth Buck Draw Field, t-here are no correlateblewas based on the fact t hat once t he reservoir began zones o f uniform reservoir rock properties. tiproducing a free gas phase, the relative pers6e-abilityto oil wuld decrease rapidlyid oil pro- layer ordering that was chosen reflects the generalduction would fall off dresatically. *is, porosity andpersmbility trend associated with theflwial type deposits in the field. Itahould alsohowever, does not appear tobe the case as canbe be noted that this type of ordering gatirallyseen in Figure 8 which is a plot of historical oil yieldamre conservative results than wouldaproduction-gas-oil ratios for the?loore+ibbs heterogeneous (iei rersha) ordering sch.No* 9-1. This plot shows there is no significantchange in the oil production decline as the The cross sectionas described here re-reeervoir,pressure falls beknv the bubble point.It is mcertiin exactlyuhy this occurs, but it is pze~:nted approxirntely 1%o f t h e t X)IP in South BuckDcaw. Ml the simlation reaults were SCaled Up toISOStlikely a combimtion of Iiquid production from full field vohswes using this ratio. The mdelthe pr03uced gas phases and a grevity-segregationbetween Iayemwhich can occur in these type only amounts for vertical areal sweep efficienciesand, therefore, the recoveries ahouldbe reduced toreservoirs . account for less than 100%areal swap efficienciesIn the work reported here, eweepefficienq is ~~HmOvED~Y@TIW AND~ assumed to be 100%. Another area where cautionahouldbe exercised is the useof modelsof thisAt th time of the original evaluation, onlythe fluvial facies were considered to be a can- type for obtaining actual field ratesmd projectdesign parameters. lhese type ofmdels ahouldbedidate for iaproved recovery. %iaterfloodinghadbeen suggested as a possibility, however, because considered useful as pert of a design process whichhelps the engineer understand the productionof the fields depth (13,000 ft.) and the fact that ~imas ina resemoir and not necessarily thethe reservoir wes potentially oil *t, this process details of injection Operations G.was tied out. The general concensus of thefields qrators was that hydrocxbcm gas in- MmELRE8U!TSjection offered the only real possibility as anisproved recovery-chaniam A pressure depletion run w as made using t hemdel croae-section. :Ilu3 results oi *is run~reAt the tinm5 of ti original study, portions ofthe 8mth Buck Draw Fhld -Fe already below the used to estimte the primary perfommca for cm -tile point (4,530 psi). zheoperators elected to perison of incrmmtal secondary recoveries.Priiasry recovery frmthe cross section was 21%ofevaluate the feasibility pf partial p r e ss u r e IMi .p - the OixP. -tanance by injecting produced gas. Ztwas feltt h a t t h is procese offered the leaste~c risk - caaeo f partial preseuremaManencesince it did not require the purchase of m a ke -u p starting belcw the bubble point at 4322 psi w asga s fo r injecticm into what was aaenasaultipl: the only scenario avaluatal in the original stxsiy.reservoirs within the fluvial facies. usually, Additional caaesswc* run bytfoode for t heppoea. .

C7.

8/6/2019 SPE19837

4/14

.A CASE STUDY OF IMPROVEDRECOVERY4 OPTIONS IN A VOLATILE OIL RESERVOIR SPE 1983of studying volatile oil reservoir behavior. The as the previous case. Unlike the previous case,cases which were evaluated are: the average gas injection requiremnt per barrel oincreaumtal oil is 27.2 MSCF, of which 8.9 MSCFis1. Partial Pressure Maintenance Above the make-up. A plot of cumulative oil productionBubble Point versus cumulative gas injection is shown in Figure2. Partial Pressure Maintenance Below the 10.Subble Point3, Full Pressure Maintenance Above the DISCUSSIONBubble Point4. Full Pressure Maintenance Below the In the case of partial pressure maintenance,Bubble Point the earlier the process is initiated the better th

incremental recovery will be. Additionally, theIn each of the cases, the mod?l was m to a earlier gas injection begins, the less gas in-preset condition of field oil productim rate or a jection will be required per incremental barrel ofproducing GORwhch was not necessarily related to oil recovered. A third run of the partial pressurethe economic limit. These projections are con- maintenace mdel at a lower reservoir pressure ofsidered to be naxinnnas for the system under dis- 3785 psi confirmed this trend and is also shown incussion. However, the oil production resulting Figure 9.from the blowbwn of the reservoir is not includedin these results. Sach case is described below: For full pressure maintenance operations, itappears that incremental recovery will be similarCase 1 whether the process is initiated above or FS1OWth-al Pressure Maintenace Above Bubble Point bubble point. In both the cgwes evaluated, the gashandling requirements were similar. Mre mke-upIn this case, partial pressure ~htWWiCe gas is require~ for operations initiated atoperations were initiated at a reservoir pressure pressures belm the bubble point. lhis trend wasOf 5,251. pSi . CMIly85% o f t h e produced gas was confirmed by an additional mdel run at 3785 psi,reinfected to account for shrinkage due to gas the results of which are also included in Figureprocessing. Incremental recovery from this run was 10. While the handling of additional gas is not35.6% of the CX)IP. On average, 14.4 MSCFof gas advantageous, the fact that equivalent recoverieswas injected for each barrel of incremental oil. can be >btained at lcwer initiation pressures isFigure 9 shows a plot of cumulative oil prduction quite beneficial information. In the case inversus cumulative gas injection. Rpoint, field lopmmt twk 9 years and thereservoir p sure had fallen below the kbbleCase 2 point. In a better defined reservoir and under-al Pressure 14aintenance Belcn+Bubble Point nmre favorable economic conditions, it might havebeen possible to initiate this type of flood andPartial pressure maintenance was initiated in still obtain reasonable recoveries.the reservoir at an average reservoir.pressure of4,322 psi for the base case. AS in Case 1, only It is clear that in each of the projects85%of the produced gas was reinfected. This run evaluated, incresmtal oil is recovered. Whetherresulted in an incremental recovery of 30.9% of the they wuldbe economical is largely beyond theOOIP. Figure 9 shows a plot of cumulative oil pro- GCOp of this work. In order tomske thisduction versus cumulative gas injection. In this evaluation, the effects of areal aweep efficiencycase, 16.2 M$CFof gas.ms injected on average for { would have to be accounted for, then the projecteach incremental barrel of oil produced. would be subject to the vagaries of oil and gasproduct prices, market availability and compressioCase 3 costs . M a general rule, it is better to initiate~Pressure Main.tenance Atmve Bubble Point these projects as earlyas reasonably possiblesince this will result in higher initial rates andFUll pressure maintenance operations were a shorter project life.begun at a reservoir pressure of 5,251 psi. AS inthe previous cases, 85%of the produced gas is CCNCLUSICFJBreinfected along with as nu.ichmake-up gas as isrequired to maintain the reservoir pressure. The South Buck Draw Field Was not unitized foIncremental secondary recwery in this case is51.l%of the C%)IP. secondary recovery.Figure 10 is a plot of The operators concluded thatdue to the uncertainties in the resewoir des-cuadative oil production versus cumlative gasinjection. The average gas injection requirement cription (ie., the presence of multiple reservoirswithin the fluvial facies), the presence of aper barrel of secondary oil is 27.5 MSCFof which fracture syetemandmsrginal incremmtal ecommics7.7 MSCF is make-up gas. due tolm product prices, they could not justifythe investsmt required for the project. BowaverCase 4 the studies did reveal the following:WPressure Maintenance Below Bubble @int 1. Primsry recoveries invcilatile oil reservoirsIn this case, fu?,l pressure maintenance was canbe very good. In the case o f South 8uck Dinitiatedat a reservoir pressure of 4,322 pai for primary production wasestirmted kobe inthe base run. mke-upgas alongwith85% of t he excess of 23% of CX31P.Ms.hss w been con-produced gas was r*injected to maintain the firaedbyactual fia.ldqlmducti.on.reservoir pressure. lhisprqcess reciwers 50.9% of 2. Oil production in wells producing volatile oilthCX)IPonan incremmtal bssiswhich is the aaam does not undergoa drastic &clinewhen reservpressure falls below the bubble point.

$?$

8/6/2019 SPE19837

5/14

,...SPE 19837 P. SCHENEWERKand B. HEATH s3. Process amdels can yield reasonable results and Paper SPE 18305, pceaented at the 1988 Annualare appropriate in situations where there is SPE Technical Conference and Exhibition,insufficient tim or data for full field modeling Houston, October 2-5.or where n~rical dispersion might be a problemdue-to large grid sizes. Results from these 7.models should be used with caution. Y s, R.W.: Case History of ReservoirPer rmance of a Highly Volatile ~4. Partial pressure maintenance operations will Oil ReservoirWt TRANS.AXME.204.recover incremental oil in volatile oil reser-voirs without the aid of structural dip. 8. Cordell, J.C. and Ebert, Cl ! A Case5. Recovery efficiencies for partial pressure History - Ccsqx4risonof Predicted andmaintenance operations improve as the pressure ACtMl Performance of-ameservqir Pro-

at which the process is initiated gets higher. ducing volatile Crude OilW, JPT (NOV.1965)6. Incremental recoveries for full pressure 1291-1293.maintenance operations in volatile oil systemsare similar whether they are initiated above 9. Posten, S.W. and Gross, S.J.: Numericalor below the bubble point. Simulation of Sendstone Reservoir Models,7. GSS handling and make-up gas requi~enwntsincrease as the project initiation pressure SPEReseWoir Engineering, (JUIY 1986)423-429.decreases in full pressure maintenanceoperations. 10. Carey, J.P. and Plnanuel, A.S.: EffectNOMEWLAnms of Grid Size in the Compositional Simu-lation of C02 Injection, Paper SI?E6894

- Permeability Thickness presentedat the 1977 Annual SPE TechnicalConference and Ehibition, Denver, Octobers. - Millidarcies 9-12.M - ThousandMM - MillionRs- ReseNoir Sarrel S1 MEl?RICCCWVERSIONSSCF - Standard Cubic FeetSIB - Stock Tank Sarrel Acre * 4.046 856 E+03 = X2Sarrel * 1.589 873 E-01 = M3ACKrKWLm3mENTS cuFt * 2.831 685 E-02-PfFoot * 3,048 E-01 = M

The authors thank woods PetroleumC orporation ~ * 9.869 233 ~04 BAHZfor permission to publish this paper. The assis- Mile * 1.609 347 E+03 = Mtance of Kim Adcock and Paul Green for drafting the Ps i * 6.894 757 E+1OO= kpafigures and Sharon Wood for typins the manuscriptis also acknowledged and appreciated.REFERmWES1. Rice, D.D., General Characteristics ofthe Cretaceous Western Interior Seawayand 8asins in PAITEIWSOFSEDIMENITATICW,DIAGENESIS,AND~ WCUMULATI@lIN CREIACEDJSROCKSOFTHEROCKYNS,Sot. Econ. Paleontologists, Mineralogists,Short Course NO. 11, 1983 2-1 - 2-27.2. Moses, E.L.: R3gineering ~licationsof Phase Behavior of Crude Oil and Con-densate Systems, JPT (July 1986) 715-723.3. OWenS~W.W. and Archer, D.L.: TheEffect of Rock Nettability on Oil-waterRelative Permeability Relationships,JPT (July 1971) 873-878.4. Jacoby, R.H. and Ser~, V.J.: AMethodfor Predicting Depletion Performance of

a ReseNoir Producing Volatile Crwe Oil,lRAWS.AIME. 210.5. Reudelhuber, F.O. and Hinds, R.F.:Compositional Material Salance Xethodfor Predictionof Recovery fro333VolatileOil Depletion Drive Reservoirs, TSANS.AIME. 210.6. Saleri, N.G. and IYmnyi, R.M.: Engineer-ing Control in ReSerVOir Simulation: Part I,

8/6/2019 SPE19837

6/14

Hydrogen SulfideCsrbon DioxideNit rogenMetheneEthenePropaneIso-ButaneN-ButeneIso-PentaneN-PentaneHexeneHeptenes Plus

Leyer

sw 1983? -lmSLE1

s. ArmstrongNo. 1 tirson Fe&r& No. 1-27Hole percent Ible Percent

0.002.300.4554.9010.115.610.982.340.971.201.7919.35100.00

Thickness(Pt. ) Porosity(%)

1 13 .042 6 .063 6 .08

R74W

0.002.550.4657.839.975*ZO0.902.040.581.091.9717.41100.00

PemMhility(d. )

.022

.181.5 ;=-

WYOMrio

I I I I I I Fig. l-1.ocetion of the $ouNI Bush Drew W.,m

8/6/2019 SPE19837

7/14

WE 19832MAXIE FEDERAL #22-25SECTION 25-41N-74W

.- %

TOP OF DAKOTASAND.

a) MARINE FACIES

MOORE-GIBBS #9-1SECTION 9-40N-74W

GAMMA RAY

b) FUiVIAL FACIES

Fig. 2-F&cies i dmt i f i ca t ion .. . %79 .-

-

8/6/2019 SPE19837

8/14

Lq.. . *

*E 19837 q

R74W! 19 d 21 22 23 24

q

* * q30 29 28 25

. -. *

f 20 21 22 23 P4

q

*

/

q

29 22 27 26 23

* * a,. *

32 33 34 35 36*

* * *

- REOIONAL MARINg FACIES fLWiAL FACIES

T40N

Fi g. 3 -Fa c i es RNp.

m . -_

8/6/2019 SPE19837

9/14

10000

1000

ai::\-i--l-~.~~-.-l~~!~~f~~l~~........+...........+..........+....}.....+..-..--.........}....4 ... . . . . . . . .+. . . . ----- . ..+... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -J... . . . . . - .-A-.-

+-M+-- ---:--:--+...a. .: .- . +..... .. . ... . .J ,. . . . . . . . . . . :.. : ; ;----. . . . . . . . . . . . . . . .. .*... . . .< . .. . . . . . . . . . -.4 . . . . , .. .L. . . . ..? ... . . . . . . . . . . . . . . . .. ..1 ... . . . . + .. . . . . } . . ! . . .+... . .. .} .. -. .+.. . . . . . . . .+...

;

. +. .. , . . .+. . . . . } . .< . ..+. .. . . . . . . . . . ..+. .- , .. ., .. . . . .*. .. . . ..+... ,.., . . . .. . . . . . . . .+. .. . ...} .. . . .+.... . . . . . . . . . . . . . . . . . . . . . .+ ..IK!ti"-"lt"il+.-+i""i"""t""+""t--"!.""t--+".t"..i.""l.""+..t.""!.."l""-+""t--i"-"t"".!"-"i.,.-. ...T..+...f...~..*..+...~ . . . . . ..+..+...~..l...+..+ . . . . . ..t...*.+:i... &./ . . . . . . b .. . . . . . . . y... , . . . . . . . . ..+.. , . . . . . . . +.. : . . . . . .. - . . . . . . . . ...9... . . .*... . . . . . . . . . . . . . . .: ~.

. . . .- . . :... . . . . . . . . - 4... ........ ...4............ ................ ................ ........, .:.. . ... . . :... , ...... ...

8/6/2019 SPE19837

10/14

COF 10 JIZ?

ww

mwmm w u

m

8! u w: H wn *8X . w x~ mm ww w x =!(S* s= .. *m

u n 5:-W**Ww wn

M

M

.i

M

u9

WW.m xI i-w .n

w u

*ti 7 2cow AllllW3W13d

qqqq

q Oq *.0q

qq

q

q

(M Alll10VWU3d.

8/6/2019 SPE19837

11/14

SPE 19837

Krg

IIo 10 20 30 40 50 00 70 80 90 n

GAS SATURATION, PERCENT PORE SPACE

Fig. 7Gaa/ol l relathm permeab i l i t y .

4 t 8 -

8/6/2019 SPE19837

12/14

10000

1000

100

,..=..-__.=-..=... _, ,...:.

8/6/2019 SPE19837

13/14

.

I .:

SPE 19837

2806 . .

8/6/2019 SPE19837

14/14

..SPE 1983?

(dosww)NOU031NI SVD 3AllVlllUNft3

686

0