v / Societyot PetroleumEngineers I! .SPE 49016

Evaluation of Steam Injection Process in Light Oil ReservoirsKaveh Dehghani, SPE and R. Ehrlich, SPE, Chevron Petroleum Technology Company

COPW9ht fWB, Sociefy of Petroleum Engineers, inc.

ThiSpaper WS praparad fw preaentafim at the 1998 SPE Annual Technical Conferen@ andEWibifion held in New Orleans, Louisiana, 27-30 Seplemkr 19e8.

Tfds papar was seIacfed for presentatim by an SPE Program Committee folloMng ratiew ofinformation contained in an abstract submitted by the author(s). Contents of the pa~r, asprasent~, have not fman revie~d by the Society of Petroleum Engineers and are subpct tornrraction by the author(s). The melerial. as present~, dms not n-ssarily reffecf anyPsitim of the Wefy of Pelroleum Engineers, is officars, or mambers. Papers prasenlad atSPE meeflngs are subject to Wbiicalion retiew by Editorial Ccsnmittees of the Society ofPefrolaum Engineers. Electronic r~rcducfion, distribution, or storage of any part of this paparfar ammerciai purposes tithoul the wiffw asant of the society of Petroleum Engineers isprohibited, PerrnissiM 10 rapreduce in print is reslric!ed to an abstract of not more than 3C0words; illuslrafions may not b copied. The abstract must contain msplcuousa~nowfedgment of where and by ticsn the papar was presented. Write Librarian, SPE, P.O.Sox ~, Richardson. TX 75C83-3S36, USA, fax 01-972.952---

Abstract

Feasibility of steam injection for three light oil reservoirs indifferent geologic settings has been evaluated. These were awaterflooded deltaic sandstone, a water flooded vuggydolomite, and a deltaic sandstone structural trap with a gascap.

Optimization of steam injection to take advantage ofindividual reservoir characteristics is demonstrated.For the deltaic sandstone, selective flooding of channel sandswith upward fining porosity gave the best results. For thevuggy dolomite, a hybrid steamflood-steam stimulationprocess that maximizes conductive heating of bypassed oilwas found to be best, For the structural trap, up-dip steaminjection below the gas cap with down dip producers showedmore recovery over gravity drainage. Sensitivities of eachprocess to uncertainties in geologic and rock-fluid parameterswere also investigated. The most influential parameters wereidentified for examining the quality of input data and theadded value of information to reduce the uncertainties.

Recent advances in reservoir characterization and modelingtools enable us to predict the performance of a Light OilSteamflood (LOSF) more accurately than in the past,considering details of reservoir geology, fluid phase behavior,and displacement process physics. This is demonstratedthrough re-evaluation of a project carried out in 1985 in theBuena Vista Hills field in California where initial modelingusing then current methods predicted a successful project.The re-evaIuation would have correctly predicted failure as aresdt of early steam breakthrough.

Results show that light oil steamfloods can be designed totake advantage of post-secondary oil saturation distribution.The resulting project may be carried out in a considerablydifferent fashion than conventional heavy oil steamfloods.

Introduction

Steamflooding in shaIIow heavy oil sands is a mature,successful technology with large commercial projects in theU. S., Canada, Indonesia, and Venezuela. Light oil reservoirshave had fewer steam flood applications even where depth andother factors are favorable because of the generally lowerpost-secondary oil in place. z

Unlike heavy oil steamflood projects, there are no large-scalecommercial light oil projects to use as analogs for designpurposes. There are, however, a number of field trials in theliterature, which have been reported both as successes and asfailures.

A review of the reported cases reveals some common reasonsfor success or failure. The major successful LOSF field casesare reported in Tables 1-3.3-0 Using steam as a heating agentin heterogeneous or extensively fractured reservoirs has givenpositive results (e.g. Tea Pot Dome Field Wyoming, and LacqSuperior Field in France) ? Also, injecting steam into thickreservoirs with gas caps has resulted in expanding the gas capand accelerating the gravity drainage process (e.g. ShiellsCanyon Field Ca. and Smackover Field, Ark.)~7 When steamwas used for drive only, field trials have been successful onlyin homogeneous reservoirs (e.g. Schoonbeek Field,Netherlands and Brea Field Ca.).34

The major unsuccessful l-s LOSF field trials are shown inTables 4 and 5. One common characteristic of unsuccessfulfield trials have been steam channeling through thief zones(e.g. East Coalinga, CA., Triumph Field, PA., El DoradoField, Kansas, and Buena Vista Field, CA.). 5 Scaling wasanother reason given for project failure (e.g. Elk Hills Ca.). 5

The overall screening criteria for light oil steamflood areshown in Table 6. All the above reservoirs met thesescreening criteria. Although these criteria are a usefulpreliminary guideline, the failed projects show that eachreservoir should be examined individually.

279

2 [K. Dehghani and R. Ehrlich] [SPE 49016]

When reservoir geology and oil gravity are considered, themajor recov~ mechanisms in light oil steamfloods canchange significantly as compared with conventional heavy oilsteamflood. Viscosity reduction may increase recovery byaccelerating the ~avfiy--~rainage process in thick columns forlight crudes of 20-25 API. The beneficial effect of steamspecific to lighter oils is distillation of light hydrocarbonswhich results in very low residual oil saturation where steamdisplacement occurs as well as enhanced solution gas driveand accelerated depletion from zones that are heated but notdisplaced. Because of greater initial fluid mobility in light oilreservoirs, high steam injection rates can be used. The lightoil steamflood projects can benefit from a wider well spacingthan in conventional heavy oil steamfloods.All of these can result in effective projects in a variety ofgeologic settings despite lower oil-in-place than would beconsidered acceptable for heavy oils.

The objective of this work was to examine the feasibility ofsteam injection processes that are optimized to take maximumadvantage of specific reservoir geologic settings. This studywas conducted for three Chevron reservoirs:1. A waterflooded deltaic sandstone reservoir with channel

and bar deposits.2. A water flooded heterogeneous vuggy carbonate reservoir3. A structural trap deltaic sandstone with a gas cap

To help validate the evacuation process, Buena Vista Hills*4, afailed light oil steam field trial reported by Chevron was alsore-evaluated.

DeltaicSandstone

Background.The first reservoir considered for steamfloodevaluation is Minas in Central Sumatra. The reservoir is inearly Miocene sandstones in the S ihapas formation at anaverage depth of 2, 000-ft. subsea with a maximum vertical oilcolumn of 480-ft. Average porosity is 2670. The oil is 360API with an average initial bubble point pressure of 235 psig.Current reservoir pressure is approximately 350 psig.Reservoir temperature is 207 F. The original oil-in-placeestimate is 9 billion barrels.1718

Initial development was on 214 acre spacing. Initialproduction was by aquifer drive that was augmented byperipheral water injection beginning in 1970. Starting in1978, infilling reduced spacing to 71 Acres. In the early1990s, phased pattern waterflood development wasimplemented using 71 Acre inverted seven-spot patterns.This devtipment is approximately 70% complete and istargeted only in the thickest parts of the field. Ultimaterecovery following completion is estimated to be 51 Yo of00IP.

Geologic Setting. The Sihapas group of interbeddedsandstones and shales were deposited as part of a Iarge deltacomplex. Principal sand bodies are channel deposits andsubtidal bar deposits. The channel deposits have an erosivebase overlain by coarse sand and gravel and become finergrained and shaleier upward. The bar sands have agradational base and become cleaner and coarser grainedupward. This is shown in Figure 1.

StearntloodProcess. Both gravity and permeability contrastwill cause water to under-run in the channel sands; creatinghigh oil saturation bypassed zones. Because of the naturaltendency of steam to override, oil from these zones should beswept in a steamflood. It was felt that areas of the field withthe greatest total thickness of these channel sand topslad thebest steamflood potential.

Using well logs, low permeability zones at the top of channelsands representing areas where bypassing will likely occurduring waterflooding were mapped. From this, high-gradedareas were selected representing about 2570 of the field wherenet feet of these bypass zones were highest. These areas werefelt to have the greatest steamflood potential and stillcontained a large resource target.

Methodology. The evaluation plan for the high-graded areaconsisted of the following:1. Construct geological data cubes using existing well log dataand transforms together with geostatistical interpolation.2. Construct a black oil simulation model for a 71.1 Acreinverted seven-spot waterflood pattern by scaling up therespective geological data cube.3. Simulate pattern waterflooding to a 98% water cut.4. Construct a thermal compositional simulation model for aninfilled 23.7 Acre seven-spot steamflood pattern using fluidsaturation distributions at the end of the waterflood.5. Simulate steamflooding to an economic limit.6. Repeat steps 3 though 5 to capture the effects of geologicvariability, rock and fluid properties uncertainty, and possiblevariations in operating procedures on performance.

A typical waterflood model was 15 x 33 x 160 with 58,720active eeIls and a vertical resolution of 1.5 ft. ,. A typicalsteamflood model was 8 x 13 x 120 with 12,480 active cells.The number of vertical cells had to be reduced for thesteamflood simulation in order to manage CPU time.

Figure 2 shows the waterflood and infilled steam patternconfiguration. Figure 3 plots gas saturation profile in a typicalmodel cross-section showing steam chest development at thepoint of steam breakthrough. This demonstrates steamoverride in the channel sands despite lower permeability at thetop of these sands. Figure 4 sh~ws produ~tion/injectionfor a typical 23.7 acre pattern.

..

data

280

[SPE 49016] [Evaluation of Steam Injection Process in Light Oil Reservoirs] 3

Sensitivity to Data and Operational Parameter. Thesensitivity analysis showed that the most influentialparameters affec?ing the uncertainty in performance wereresidual oiI saturation after waterflood (Sorw), gas-oil relativepermeability, andgeologic variability in the high graded area.These uncertainties were used to help assess the risksassociated with commercial steamflood development and todefine monitoring objectives.

ResuIts in Hgure 4 show considerable steam production as theproject matures. In order to improve thermal efficiency, anumber of heat management options were considered. Usingmost likely set of geoIogicaI, rock and fluid properties, anumber of options were examined. The base case was steaminjection in aII layers with a rate of 1.5 BCWE/D per net acre-ft. Optimization cases considered included sequential ratereduction after steam breakthrough, injecting water or wateralternating with steam, total fluid production constraints, andnot completing injectors in high permeability watered outsands that could be potential thief zones. Of these cases, onlythe latter showed significant improvement in projectperformance. The other cases, which represent standard heatmanagement practice in various San Joaquin Valley heavy oilreservoirs, were ineffective+Results from this study showed that a steamflood in Minas haseconomic potetidal. This work has provided data to helpdesign a soon-to-be-implemented field project and has helpedto identify operational uncetinties to be resolved in the earlyphases of that project.

Vuggy Carbonate Reservoir

Background. This field is in the Permian Basin and contains a320 API oil which has a viscosity of 4,5 cp at 88 F reservoirtemperature. Oil production is mainly from heterogeneousdolomite of Grayburg formation. This a large fieldencompassing about 22,400 acres with a cumulativeproduction of 380 million barrels of oil (MMBO), of anestimated 2.2 billion barrels of oil (BBO) in place. A maturewaterflood currently produces approximately 17,000 barrels ofoil per day (BOPD) from this field, Waterflood patterns havebeen changed through major phases of infill drilling.Currently, the field is mostly drilled on approximately 10-acrespacing, although some 20-acre and 5-acre spacing exists insmall areas of the field.

Geologic Setting. Diagenesis and dissolution have generatedthin vuggy zones with high permeability and porosity withinthe pay interval in the central portion of the field considerably.Porosity in this zone varies from 8% to 26 % and permeabilityranges from about I md to very high values. The productionhistory indicates that these vuggy features have contributed toearly water breakthrough, high water cuts, and anomalousdirect connections between injector-producer pairs.

Although waterflooding has been successful in most-of thefield, performance has been poor in this central area. Becauseof poor sweep efficiency, the high remaining oil saturationadjacent to vuggy zones is a potential target For a steaminjection project that could heat these zones despite thepermeability contrast.

Methodology. The evaluation procedure used was similar tothat described for the deltaic sandstone example except thatspecial attention needed to be given to secondary porositygeostatistics and ensuring that primary and waterflood historywas adequately matchedThe urocess was evaluated with the following method:1,

2.

3.

4.

Detailed geostatistical models (106 X- 100 x1OO cells)were constructed separately for the total porosity and forthe secondary (vuggy) porosity. Permeability transformsdeveloped from core data were used for total porosity anda high permeability was assigned to the vuggy porosity.These models were superimposed to obtain a reservoirmodel.This geological model was scaled up to a 12,000 cell (20x20x30) simulation model. Primary and water floodhistory was satisfactorily matched by adjusting thepermeability assigned to vuggy porosity and thecorrelation length of the geostatistical interpolationThe model was used to evaluate steam injectionl Examined the well pattern and spacing. Optimized the processSensitivity of the process performance to uncertainty ingeologic and rwk-fluid p~ameters was investigated andpossible variations in operating procedures wereexamined.

Continuous Steamflood. The model was used to investigatesteamflood for 20 acre 9 spot, 10 acre 5 spot, and confined single9 spot well configurations. Figure 5 compares the cumulative oilrecoveries and steam oil ratios for continuous steamflood usingthe above well configurations. Although the cumulativeincremental recovery can be as high as 1670 (for the case of 5spot), the cumulative steam oil ratios of greater than 20 showthat steam is only sweeping the already water-swept vuggyarea making the process inefficient for continuous steamflood.A comparison of average reservoir temperature during thecontinuous stearnflood using the 9 spo~ 5spot, and the existingwell configurations is shown in Figure 6. Although thecumulative steam oil ratios for continuous steamflood are notsatisfactory; the increase in reservoir temperature shown in thisfigure indicates that steam is heating the reservoir effectively,

Steam Injection Optimization. Although the existence of anetwork of fractures or vugs is a negative in most floodingprocesses, it provides a large surface area for heat transfer tothe matrix in a thermal process. If steam is injected in anextensively fractured or vugular system, the heat (thermalenergy) transferred to the matrix can be utilized to increaserecovery from parts of the reservoir that could not be accessed

281

4 [K. Dehghani and R. Ehrlich] [SPE 49016]

by water or gas flood. Hgure 7 shows the vapor pressure ofthe depleted reservoir oil versus temperature. This figuresuggests that increase in vapor pressure of heated oil can beutilized as the primary source of energy for a displacementprocess. Heat can increase recovery in this type of light oilreservoirs by enhanced solution gas drive, accelerated gravitydrainage and distillation.

The steam injection strategy considered for this reservoirinvolved a period of steamflooding at high pressure that wasfollowed by production and pressure drawdown through boththe steam injector and the producer. This is shownconceptually in Figure 8. Hot high-pressure water and volatileoil me made to flash during drawdown, resulting in oildisplacement from the low permeability rock into the highpermeability channel by vapor or solution gas drive.

Figures 9a and 9b show cumulative recoveries and steam oilratios for two cases of steam floodlblow-down process in afive-year project time (2.5 years and lyear of flood followedby blow down). These figures clearly shows that for thealternative steamflood/blow-down process, although steam oilratios have improved to be economically viable, the recoveriesare comparable to continuous flood case and well overcontinued waterflood case. A comparison of the distributionsof vuggy intervals, heated zones, and regions of low oilsaturation after the steamflood/blow-down process shows thatheat is successfully transferred from the high permeabilityvuggy steam conduits to the non-vugyy matrix formation(Figure 10). This figure also shows that thermally enhancedsolution gas drive and distillation have been able to producethe heated oil after the blow-down.

Sensitivity to Data Uncertainty and OperationalParameters. Effects of uncertainty in geologic, rock, and fluidproperties on the process performance were examined. Theseparameters were:l Initial oil saturationl Residual oil saturation to steam in both vuggy and non-

vuggy zones. Oil relative permeability exponentl End point gas relative permeabilityl Compositional representation of oil (API gravity)l Vertical to horizontal permeability ratiol Presence of fractures in the geologic model

The ranges of the predicted recoveries resulting fromuncertainties in the above parameters are shown in Figure 11.The results from this study showed that the two mostimportant parameters affecting performance predictions wereinitial oil saturation and oil gravity. These results from thissensitivity analysis were used as a guideline for pilot locationselection and pilot design.Cumulative recovery and steam oil ratio can be optimized bychanging the flood to blow-down time ratio. Figure 12 showsa comparison of recoveries and steam oil ratios for different

steamflood times in a 5-year project. This figure shows thatthe cumulative steam oil ratios can be reduced to economicvalues.Effects of change in operational parameters on the processperformance were also examined. Figure 13 shows thecumulative recoveries and steam oil ratios for the followingscenarios:. Soak after stearnflood and before blow-down. Steam production rate constraintl Multi-flood cyclesl No flood (only injection and blow-down)

DeltaicStructuralTrap

Backgroundand GeologicSetting.This field is located in adeltaic depositional environment. This reservoir is a 6 dipstructural trap of early Miocene and Late Oligocene. Theestimated oil in place for this reservoir is 29 MM STB. Thisreservoir is subdivided into three productive zones, RI, R2,and R3. These zones are separated from each other by twothin shaley layers (less than 10 ft thick). RI sandstone lies atthe top of the reservoir sequence and has a moderate resistivitywith variable gamma ray response, averaging 15-30 ft inthickness. R2 interval is composed of 15 to 25 ft of very cleanwell-sorted sand. The core data shows that the thin shaley unitbetween R2, and R3 is very finely laminated sandstone andsandy shale with moderately good horizontal permeability(300-850 md) and relatively poor vertical permeability (47red). R3 sand with a maximum thickness of 30 ft is laterallyextensive with similar log character to R2. The range ofporosity and permeability for these sands are 0.14-0.25 and4.8-5000 md respectively. The geochemical analysis of oilsamples from these three sand layers is very simiIar showingthe fluid communication between these layers. This reservoiroil is 22 API and has a 2.2 cp viscosity at a reservoirtemperature of 173 F and initial reservoir pressure of 2181psia at a depth of 4900 ft. The solution GOR for this oil is 264SCF/STB. The reservoir has a gas cap and an aquiferassociated with it. History matching suggests an aquifer sizeof 60 times the oil zone. Since the reservoir has a number ofbounding faults with limited transmissibility, aquifer supportmust be provided across one of the bounding faults.

Methodology. The evaluation method was conducted by asimulation model constructed as follows:l Using log and core data a 360x120x73 cells detailed

geostatistical model of the porosity and permeability wasconstructed. This model was scaled-up to 50x30x24 forthermal compositional runs

l The production data was history match for aquifer size,fault transmissibility, and K/Kh and used for steaminjection evaluation.

Steam Injection Process. Looking at the reported field trials,this dipping reservoir with a limited aquifer support, a gas cap,and good vertical communication, would be a proper

282

[SPE 49016] [Evaluation of Steam Injection Process in Light Oil Reservoirs] 5

candidate for updip steam injection for accelerating gravitydrainage.

The evaluation assumed steam injection into four updip wellsfor 3.75 years after a primary gravity drainage production of10.4 MM BbIs. Steam was injected at bottom hole conditionsof 70% quality, 662 F (2400 psi). The comparison showsthat the steam injection process adds -2.8 MM STB toproduction during this time (Figure 14). Figure 15 shows thatsteam injection will decrease the producing gas oil ratio. Thisfigure also shows that the cumulative steam oil ratio for theincremental oil recovered over continued gravity drainage is7.2 after 3.75 years. This corresponds to a maximum fuel oilratio of 3.6 MSCF/bbl of oil (assuming 2 MSCF/ CWE bbl ofsteam). Hgure 16 shows that steam injection by updip steaminjectors was able to heat the oil column and redistribute thegas saturation for a lower vaIue of gas oil ratio.

Considering the depth and the cumulative steam oil ratio, thisproject may be considered economically marginal. Steamprojects to date have been mostly targeted for depths less than3000 ft. However, since this reservoir is considerably deeper(4900-5 100 ft), feasibility of the project as far as the effects ofdepth on heat losses and displacement efficiency, andestimated fuel requirements had to be examined.

Oil production from oil fields in this area involves producing alarge amount of associated gas, over-supplying the marketdemand. This was recognized as an excellent opportunity toutilize the gas.

Figures 17 shows the results of heat loss calculations for highrate steam injection into reservoirs of vmying depth. The heatloss is calculated for a typical Light Oil Steamflood rate (5000B~, 4 tubing and 7 casing without any insulation).Figure 17 shows that heat losses for injection into deepreservoirs are greater that what would be seen in a typical1000 or 2000 deep steam project but are probably tolerable.Fractional quality changes are higher for deep reservoirsbecause heat of vaporization is a smaller fraction of the totalavailable heat in wet steam at higher pressures.

The critical pressure of steam (3198.8 psia corresponding toabout 7350 ft at hydrostatic pressure) sets an absolute upperlimit to depths at which steam injection can be beneficial.Practically, there may not be much benefit below 6000 ft.

These deep projects would not be economic if gas had to bepurchased at world prices but may be worth considering if gasis available that would otherwise be flared.

Buena Vista Hills LOSF Fieid Triai He-Evacuation

Looking at the all the unsuccessful reported field triais, weconcluded that lack of understanding of the reservoir geologyand more importantly inability to represent it in the evaluation

phase has been the main reason for optimistic predictions.With the new methods in reservoir and fluid characterization,and fluid flow modeling our capability and confidence inscreening a bad project in the evaluation phase has improvedsignificantly.

Despite this apparent trend, we feit that a better test of ourability to predict performance of a new project was necessary.We chose to look at Chevrons Buena Vista (BV) Hills projectand attempt to predict the performance of that project usingstate-of-the-art-modeling methods but with only that data thatwas avaiiable before the project started.

The Buena Vista Hills 12 pattern Wilheim Sand LOSF fieldtrial was conducted from April 1985 to January 1987. Earlybreakthrough and generally lower than expected recovery wasobserved. These were attributed to reservoir geology wherealmost all of the steam channeied through an unexpected thin,high permeability thief zone. This behavior was notanticipated in modeling work carried out before the projectwas started .14 That recovery prediction is compared withobserved recovery in Figure 18.

Fine-grid geostatistical models (80 x 60 x 100 layers) wereconstructed which honored permeability contrasts shown inwelI-log data. These were scaled-up and rock and fluidproperties added to create 40 x 30 x 12 layer thermalcompositional simulation models. These were run withconstant injection rates to predict oil recovery and steam-oiiratios.

Resuits consistently showed early steam breakthrough (Figure19). Although there was uncertainty in the predicted outcomeas a result of uncertainty in input data (e.g. porositypermeability transforms and gas-oii relative permeabilitycurves), steam-oil ratios were consistently high (12 or more).Despite this uncertainty, the modeling process capturedenough geoiogy to predict that LOSF would not have beeneconomically viable for the Wilhelm reservoir. 19

Conclusions

l

l

l

Consideration of the details of reservoir geology is criticalfor evaluation of light oil steamflood projects. (This wasdemonstrated with Buena Vista Hills Project Re-evaluation)

Light oil steamflood projects can be designed for high-graded parts of a field to take advantage of geology andpost-secondary residual oil saturation distribution. (Thiswas demonstrated with deltaic sandstone and vuggycarbonate examples)

The resulting steam projects may be considerablydifferent in their implementation from conventional heavyoii steamfloods in :

283

6 [K. Dehghani and R. Ehrlich] [SPE 49016]

l Injection rates and well spacingl Process optimization

Acknowledgement

Authors wish to thank Cedric Cease and Minhtrang Doan forconducting the simulation runs for the Minas and BV Hillsresemoirs.- The supplemented material and the geologic modelof the deltaic structural trap from David O. Johnson are greatlyappreciated. We also like to thank Kelly Edwards, Alan Reed,Mitch Harris for constructive comments.

References

1.

2.

3.

4.

5.

6.

7.

8.

9.

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Van Dijk, C., Steam-Drive Project in the SchoonebeekHeld, The Netherlands, J. of Pet. Tech. March 1968,295.

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Bakersfield, CA, 8-10 February 1993.

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...

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284

[SPE 49016] [Evaluation of Steam Injection Process in Light oil Resewoirs] 7

Table 1- Successful LOSF Field Trials Table 4- Unsuccessful LOSF Field Trials

rFiaid &fkhoon~Fhfd f4,fh.m. v.~nduhrddh Mlj,Oijk)1964 Flcld& @so h P Oapt Dip Appllcatiort R06uffs & CommentsOwator [U ~ h /tt) OaaEast ~alinga, 0.16 so 300 4oo- 14 -Rapaafad 5-SpGfs -Staam ChsnnallngCa. (Shell) 2200 -P*rrrl 0.6-100 -only Succ. Aftar-700 Seras tinvaraion to Hot-16 to 30. API WatsrflaodTrtumph Fkdd, 0.02 10 0 6oo- - 2 Uwonf. *spots -Uris.o 750 -Penn O.~ D -SteamChanrralirtg~Jaml Oil -41 API ta the 30P GasPrGducar Irlz.) Saturatsd

an~EldGrsdo Fletd, 0.1 17 - 650 - 4 Urlconf. S-spots -Uris.Kans. -Partn0.S-0.6 -Stasm Wnrteiing(CitiesSsrvke -37APf

01 1.6~af.Suatlavista 0.1 45 500 3000 4 12 (s-spat PItot)HiI16, Ca

-Staam Chsnnallng lnd-Penn. 0.02D

[Chawon)LGwVarocal*waap

-zr Apt -Parmeabillfydamage-5 Scras -High 636CMIflj.Pf06s.

-High cum. SOR of 22.1-C02 producffon-LGwear lt tha swept

lvso

TP 09pm6/

120 2400

Lvp

tt

Ap@lc8ffGrl Resuffs aComnrwrfs

3(5 lpot) -S- flm Updlpmd 1(4mt) .Gmvltyovurfbh- .R= 23% of OIPsxfmnd9d -cum.SORtd2.74.5 lcrDI.PuM1.1oD-23.APl*IW*

6

FBrn Fidd, ti.(sMl)1ss4

SnuckemFWd Ark.(Philll~~~hum Co.)

110 as -Cum.SORofS-SOrI* 3%.4.c.wk~h.dhighInj. Prns.

7 .ln\. S-m S0-s*.Haatconducti toonk

t

0,11 *33

0.2s SO.140softWocfaGoc

-UpdipInJ..Pwm 0.07n

+ndsd.P8rmSD-22acm-m. wu. 7sw

Table 2- Successful LOSF Field Trials (Continue) Table 5- Unsuccessful LOSF FieId Trials7(psi

--t-t

Field &So h& (rf)

tFrankllnHvy 0.0S 70Pool,Pa.(P*n.zOit)12s6

t

Depth DIP(tY)

4s- -

I Application Results &Catnmonts

-T.chnlully Incr.ss.dRmovuy

.EcOnOmlMlfyIJns.

ApplicationI

Ra*ults a Comments

r1Unconf.S-SpOl.Perm 0,6D->>20.API-1 lcm -C02 predu.tlon lwallboradam.ga-Incroacein .API lndltriValof haatfront,-Outsidep*r@haral patfmrnr*spOns*.-P*ak Ineltnroductlon

.Porm1D-27. API-16.3leraspilotArea~.p. 47Cp

Up.dlpIj..Pwm.0.14D-34. AM

.SXwndlngGastipOrlv,-Cum.SOR4.2S-Sor 780 >20ft 5

B~~Wa IBblz/Acrc- fi A g;

rt

AG1676

Table 3-Successful LOSF Field Trial(Highly Fractured Reservoirs)

~annelGammaIsw

Deposit Bsr Deposit-ma R9y +

b[ j

:< =b*- Lifology

Sand & : ShaleShais

S6nd

SandSand &

Erosks Base:: ----- shah

- Sh6k

ha - shale

;

P DapthEl fe

t40 250

B2 2000

DIP Appllcatlon

lnv.5 & 9 Spafs andLine ~w6-P6rm 0.01-0.W D-32 API-10-20 8crarpst-1so actaatotal-Uppar srtdIowarShannon sand

-off6hGrabar sand-Highly faultad-ExtiOIWSlyFtmcturad

Unconf.7 SpedTWOF6c*.Hlghly FracturedDOtmitolmdand15%o-CakSm0U8 tOCk6l-10 Md6nd20%$.22API-40 acres-. 77.s Cp

DSo

0.1

Results &Comrnants

-Tfw Yrachwonetworkbeinghelpful.-SOR momfavorabkofar theuppar Shannonformation (highlyYractursd)

NPR-3,ToaptdDatnaFiald,Wyoming(DOE)(Sandatona)1S66-S2

s

FhtiUpwwd

LLscqSuparteur,Franc.(Carbanata)

D.11

-Productionlncrasso-SOR n 6.52-C02 productt~:-OscompositiorratCalcamoua rock.

Upwatd -

Figure 1- Schematic Diagram of Channel and Bar Deposit(After Allen et al.)

285

8 [K. Dehghani and R. Ehrlich] ~SPE49016]

cSF*M WlcSP

WC Wlc

S1- New SF In]eotor WIC- WF Injector Converted to SF P@ucerSP- New SF Pducer WP- WF Producer Converted to SF Producer= .tesmflood ~ Waterflood

Figure 2-23.7Acre Stemflood Pattern Infilled in 71.1 AcreWaterflood Patter22

Producer Injector Producer.--

Figure 3- Gas Saturation Distribution for a Typical MinasSteamflood Simulation Run

100 L : Ie 200 400 600 800 low 1200 1400

Time (oeys)

Figure 4- Production Cuwes for a Typical MinasSimulation Run

0- =1.~ Sxi8ting Wdi

1so % +Ilwmmmtal conrlmJd9spotSJg - Cum W SxistingWet18t

- - Cum W9Sp0t40

- - Cum SKt5Spt

m - Cum W COnfimd 9 Spo

o so lam low m

b

Figure 5- Continuous Steamflood of Vuggy Reaewolr withDifferent Patterns

OJ I

o 365 720 10% 1400 1s25

D8p

Figure 6- Average Resewoir Temperature During theContinuous Steamflood of the Vuggy Carbonate Reservoir

+ Depleted Oil to 200 psi

- Depleted oil to 100 psi

,.

A. .. -A-..J

o 100 2CSI 300 400 500Temperature Deg. F

Figure 7-Vapor Pressure of the Depleted Oil in the VuggyCarbonate Reserovir Versus Temperature

286

[SPE 49016] [Evaluation of Steam Injtilon Process in Light 011Reservoirs] 9

End of Waterflood End of Steantftood.

------- . .. .--

.-.. .. . . .-- :t---! f$_+zG+_e].?~??*_~ . ---.. \..-- ---------..- ,

~:.,1,. Y.. .. . .

.,.

.,, ..,.

> __.______ .. . .. . -:

.

.

-t ,,, ., >: >,.,.., :, . . .

_____ . . .. __:_e_ ,_ ___> .=-..:- -.-.:,I

Dunnethe Blow Down A

lViscosity ReductionlSolvent ExtracfionlSolution Gas DrivelHot }\7aterFlashoOil Expansion@rav@

Figure 8- Summary of Steam Injection Recovery Mechanisms During Flood/Blow-Down Process In Vuggy CarbonateReserovir

20

16

14

6

4

2

0

--1 Yr Flocd Cum Oil -1P2..5 Yrs Flood Cum Oil %OOIP

+ Cont. W.F. Cum

0 500 1000 1500 2000tlay8

Figure 9a- Comparison of Two Cases Steamtlood/Blow-down Cumulative Recoveries

0 620 1000 1500 2oatm

Figure 9b- Comparison of Two Cases of Steamflood/Blow-down Cumulative Steam Oil Ratios

287

10 [K. Dehghani and R. Ehrlich] [SPE 49016]

Distributionof HighTemperatureRegions Zones of Oil Saturation< Sor8AfterSteamflood AfterBlow-Down

Figure 10-Distributions of Vuggy Zones, Heated Zones and Regions of Low 011 Saturation for in the Steamflood/1310w-downProcess of the Vuggy Carbonate Reservoir

ao~hrrwa

W.F. e.za 0.54UII amq 30.1 32.s

FmduNCiuziU m

F~bT w

Wml O.mN O.m

~ErdW 0.s n N 0.s

Ko ~ 1.s I m 3,s

- 0.06

180.46 16

22s 14

W F- 12

NoFruluIw 100.3a 8

0.7 6

253 4

0.10

Figure 11- Sensitivity of the SteamflooW1ow-DownProcess to the Geologic, Rock-Fluid, and Fluid Properties

n Cum Steam 011 Ratio 5 Yrs.I

Figure 12-Optimization of Steamtloo~low-down intheVuggy Carbonate Reservoir with Steamflood Time

288

[SPE 49016] [Evaluation of Steam Injection Process in Light Oil Reservoirs] 11

Pigure 13-Effectsof Changein the OperationalParametem on the Cumulative Recovery and Steam OilRatio of Steamflood/Blow-down Process in VuggyCarbonate Reservoir

2.4E+07

2.2F&07

1.0E+07 ~ 4i 5;0 10;0 1s00

Tim. (Days)

2.0E+04

1.8E+04

1.6E+04

1.4E+04

1.2E+04

1.0E+04

9.0E+03

@.0E+03

4.0E+03

2.0E+03

O.OE+OO

nDcum. 011Dopl.tlonXCum. 011Steam In}.AOII Rat* d*pletlon0011 Rate St.am In].s

$Q

450 k *8

.7

.6

-5

.4

3 160. 8X.3

~ 100a I .2

50 s u .1

Pigure 14-Comparisonof CumulativeProductionandRateof oil Recovery for Up-dip Steam Injections VersusGravity Drainage in the Deltaic Structure SandstoneReservoir

roGaa011RatioDepletionq Gas Oil ratio

Steam

xCum. S/0 forIncremental OilOver Continued

I Gravity Drainagao 500 1000 1500

Time (Daye)

Pigure 15-GasOil Ratiosfor Steam Injection and Gravity Drainage and Cumulative Incremental Steam Oil ratio for the Up-dip Steam Injections in the Deltaic Structure

289

12 [K. Dehghani and R. Ehrlich] [SPE 49016]

Pl, P*, pg

Debit Structure

*I[iNJ2 NJ3

NdIJ~,

,..~

I

Regions of Sg >0.1Before Steam

Regions of Sg >0.2Before Steam

Regions of Sg >0.2After Steam

~gure 16-TemperatureandSatrationDistributionsfor the Up-dip Steam Injection in the Deltaic Structure Sandstone Trap

0.70

0.65

0.60

.

**$~*~i~iii;yiji::..+. ~~-***++* z~

::;***:**.+**:::;::..*

l **

:0M- **::.:*.tawR - 0.- l::. 4000l*::*.tin- tun l.+*+**amen- Zw-R - ;74m l.* *.* +*++ 5000WR -am-R- Utn l* . .l . +l* l* l* l*. ;60004{

.

1000 2000 3000 4000 5000 6000Depth (ft)

Figure 17- WelIbore Heat Loss Calculations for 5000 CWE Bbls/D of Steam (4 Inch Tubing)

290

(SPE 49016] [Evaluation of Steam Injection Process in Light Oil Reservoirs] 13

2500

ri

Observation

1984 1986 1986 1987Comparison of Performance

Wilhem

{i T z E : :

Sand 108 Kavg = 88 md

ft. ~ = 34%SO=32Y0

Figure 18- Prediction of Buena Vista LOSF Pilot with the Older Tools Initial Simulation Study

3 0.(

SteamProduction

) . 1.0 1.5 2.0 2.5 x

Figure 19-Re-evaluation of the Buena Vista Hills Steamtlood LOSF Pilot

291