Ill. Oil Recovery Potential

Ill. Oil Recovery Potential

The Resource Base

Original Oil In Place

The American Petroleum Institute reports thatas of December 31, 1975, about 442 billion bar-rels of oil had been discovered in the UnitedStates, including the North Slope of Alaska.1 O fthat amount, 109 billion barrels had been pro-duced and an additional 37.7 billion barrels re-mained to be produced at current economic con-ditions and with existing technology. This figureincludes 32.7 billion barrels of proved reservesand 5.0 billion barrels of indicated reserves. Thetotal, 37.7 billion barrels, also includes 1.0 billionbarrels of proved EOR reserves and 1.7 billionbarrels of indicated EOR reserves.2 The remaining295 billion barrels represents the resource basefor enhanced oil recovery (EOR). (The resourcebase includes 11 billion barrels in the North Slopeof Alaska but does not include tar sands and oilshale. Technologies to obtain petroleum fromthese sources are sufficiently different from EORprocesses to deserve separate study.)

Petroleum Reservoirs

Oil is found in porous sedimentary rocks(sandstones and limestones) that were depositedunder water and later overlain by formations thatare impervious to these fluids. Localized ac-cumulations of oil occur in traps (reservoirs) with-in these underground formations, or oil pools. Anoil field is the surface region underlain by one ormore of these separate oil reservoirs or pools.

I Reserves of Crude Oil, Natural Gas liquids, and NaturalGas in the United States and Canada as of December 37,7975. Joint publication by the American Gas Association,American Petroleum Institute, and Canadian PetroleumAssociation, Vol. 30, May 1976.

2Enhanced 0// f/ecov~ry, National petroleum CounclltDecember 1976

Oil is found in such traps at depths of from lessthan 100 feet to more than 17,000 feet.3 A reser-voir may be small enough that a single well issufficient to deplete it economically, or largeenough to cover many square miles and requireseveral thousand wells.

Oil is not found in underground lakes, but inopen spaces between grains of rock; oil is held inthese spaces much as water is held in a sponge,Almost invariably, water is mixed with oil in thisopen space between the grains; natural gas isfound in the same kinds of formations. The dis-tribution of fluids in one type of oil reservoir isdisplayed in figure 2.

Because oil is lighter than water, it tends toconcentrate in the upper portions of a formation,

Figure 2. Close-up of Oil Between Grains of Rock

A thin film of water called connate water clings to the sur-face of the rock grains. This water occupies part of thespace in the rock along with the oil.

Reprinted by permission of the Society of Petroleum Engineers of Al ME

J~~production Depth Records Set in Three Areas, World

oil, p. 103, February 1975.

2.?

24 . Ch. Ill—Oil Recovery Potential

rising until it reaches an impervious barrier thatforms a trap. Common traps include domes(figure 3), faults (figure 4), and salt domes (figure5). An overlying cap rock can also seal off a for-mation in the manner shown in figure 6. Oil occa-sionally lies within sand bodies enclosed within alarger body of impervious shale (figure 7).

Regardless of rock type (sandstone, limestone)or trapping mechanism, there is little uniformity

in the pattern in which different reservoirs con-tain and conduct fluids. This lack of uniformityinfluences both the amount of oil present invarious regions of a reservoir and the degree towhich injected fluids can sweep through a forma-tion, collect oil, and force or carry it toward pro-ducing wells. It is this lack of a common patternthat introduces significant economic risk in everyoil recovery project, including EOR.

Oil Recovery

Primary Recovery

The initial stage in producing oil from a reser-voir is called primary production. During thisstage oil is forced to the surface by such naturalforces as: (a) expansion of oil, expansion of thecontained gas, or both; (b) displacement bymigration of naturally pressurized water from acommunicating zone (i.e., a natural water drive);and (c) drainage downward from a high elevationin a reservoir to wells penetrating lower eleva-tions.

The natural expulsive forces present in a givenreservoir depend on rock and fluid properties,geologic structure and geometry of the reservoir,and to some degree on the rate of oil and gasproduction. Several of the forces may be presentin a given reservoir. Recovery efficiencies in theprimary stage vary from less than 10 percent toslightly more than 50 percent of the oil in place.Estimates of cumulative oil production, cumula-tive ultimate oil recovery, and cumulativeoriginal oil in place for 1959-75 are given in table5.

Secondary Recovery

Most of a reservoir’s oil remains in place afterthe natural energy pressurizing the reservoir has

been dissipated. Several techniques for injectingfluids into an oil reservoir to augment the naturalforces have been widely used for many years.Such fluid injection is generally known as sec-ondary recovery. Fluids, most commonly naturalgas and water, are injected through one series ofwells to force oil toward another series of wells.The pattern of injection and production wellsmost appropriate to a reservoir are a matter oftechnical and economic judgment.

There is nothing inherent in fluid injectionprocesses that requires their use only after thenatural energy in a reservoir is exhausted. Indeed,it is frequently desirable to initiate such proc-esses as soon as sufficient knowledge is availableof the geology of the reservoir and the type ofnatural expulsive forces that are operative.

When water is the injection fluid, the processis commonly called waterflooding. If water isused to supplement a partially active naturalwater drive, the process is classified as a pressuremaintenance project. When natural gas is in-jected, the operation is also called a pressuremaintenance project. Injection of natural gas waswidely used in the era of abundant low-cost gas,but the practice has decreased as the price of gashas increased.

Ch III—Oil Recovery Potential 25

Types of Traps for Oil Accumulation*

Figure 3.

W a t e r

0il accumulation in the top of a dome. Rock overlylng thedome is Impervious.

Figure 5.

h i m p e r v l o u s / Gas

011 accumulation caused by a fault. The block to the righthas moved upward so the oil formation is opposite the im-pervious shale, forming a trap.

Figure 4.+ ~ C a p R o c k

Oil accumulation in a dome at the top of a salt dome andalso in a region on the side of the dome. Salt is Imperviousto the oil.

Figure 6.

ImperviousCap Rock

.

Water

Figure 7.

Oil trapped by overlying impervious cap-rock that inter-rupts lower lying formation of sandstone or limestone.

Oil trapped within larger body of impervious shale. -

“Illustra[lons redrawn and printed with permission of the AmericanPetroleum Instilute I American Petroleum Institute 1971

26 . Ch ///-01/ Recovery Potential

Table 5Historicai Record of Production, Proved Reserves, Uitimate Recovery, and Original Oil

in Place, Cumulatively by Year, Total United States.(Billions of Barrels of 42 U.S. Gallons)

Year

1959 . . . . . . . . . . . . . . .1960 . . . . . . . . . . . . . . .1961 . . . . . . . . . . . . . . .1962 . . . . . . . . . . . . . . .1963 . . . . . . . . . . . . . . .1964 . . . . . . . . . . . . . . .1965 . . . . . . . . . . . . . . .1966 . . . . . . . . . . . . . . .1967 . . . . . . . . . . . . . . .1968 . . . . . . . . . . . . . . .1969 ...., . . . . . . . . . .1970 . . . . . . . . . . . . . . .1971 . . . . . . . . . . . . . . .1972 . . . . . . . . . . . . . . .1973 . . . . . . . . . . . . . . .1974 . . . . . . . . . . . . . . .1975 . . . . . . . . . . . . . . .

Cumulativeproduction

62.364.767.269.872.475.177.880.683.786.890.093.396.699.9

103.1106.1109.0

1975 estimate ofcumulative

ultimate recovery**

122.3123.3123.7124.7125.3126.2127,6128.0128.7139.2139.8140.4140.9141.1141.4141.6141.7

1975 estimate ofcumulative

original oil in place**

384.7387.8389.8392.5394.7397.8402.4404.4407.0432.5434.8437.1438.7439.6440.9441.4441.9

● “For all fields discovered prior to the indicated year in Column 1.“Reserves of Crude OIL Natural Gas Llqu/ds, and Natural Gas in the Uniled States and Canada as of

December 37, 7975, joint publicationby the American Cas Association, American Petroleum Institute, andCanadian Petroleum Association, Vol. 30, May 1976

Secondary recovery is proven technology; in-deed, a recent study indicates that 50 percent ofall domestic crude oil comes from secondaryrecovery operations.4

Waterflooding is inherently more efficientthan gas displacement in pressure-maintenanceprojects and is the preferred process where feasi-ble. Cumulative recoveries by primary and sec-ondary production, where the secondary produc-tion is waterflooding, average between 38 and 43percent of the original oil in place.

Some reservoirs, principally those containingheavy oil that flows only with great difficulty, notonly provide poor primary recovery but often arenot susceptible to waterflooding. Enhanced oil

4Enhanced Oil Recovery, National Petroleum Council,December 1976.

recovery would be especially useful in some ofthese reservoirs.

Enhanced Recovery

Processes that inject fluids other than naturalgas and water to augment a reservoir’s ability toproduce oil have been designated “improved,”“tertiary,” and “enhanced” oil recovery proc-esses. The term used in this assessment isenhanced oil recovery (EOR).

According to American Petroleum Instituteestimates of original oil in place and ultimaterecovery, approximately two-thirds of the oil dis-covered will remain in an average reservoir afterprimary and secondary production. This ineffi-ciency of oil recovery processes has long beenknown and the knowledge has stimulatedlaboratory and field testing of new processes for

more than 50 years. Early experiments with un-conventional fluids to improve oil recovery in-volved the use of steam (1920’s)5 and air for com-bustion to create heat (1935).6

Current EOR processes may be divided intofour categories: (a) thermal, (b) miscible, ( c )

chemical, and (d) other. Most EOR processesrepresent essentially untried, high-risk tech-nology. One thermal process has achievedmoderately widespread commercialization. Themechanisms of miscible processes are reasonablywell understood, but it is still difficult to predictwhether they will work and be profitable in anygiven reservoir. The chemical processes are themost technically complex, but they also couldproduce the highest recovery efficiencies.

The potential applicability of all EOR proc-esses is limited not only by technological con-straints, but by economic, material, and institu-tional constraints as well.

Thermal Processes

Viscosity, a measure of a liquid’s ability toflow, varies widely among crude oils. Somecrudes flow like road tar, others as readily aswater. High viscosity makes oil difficult torecover with primary or secondary productionmethods.

The viscosity of most oi l s dramatical lydecreases as temperature increases, and the pur-pose of all thermal oil-recovery processes istherefore to heat the oil to make it flow or makeit easier to drive with injected fluids. An injectedfluid may be steam or hot water (steam injec-tion), or air (combustion processes).

Steam Injection. —Steam injection is the mostadvanced and most widely used EOR process. ithas been successfully used in some reservoirs inCalifornia since the mid-1960’s. There are twoversions of the process: cyclic steam injection

sseco~~ary anfj Tertiary Oil Recovery Processes, k@-state Oil Compact Commission, Oklahoma City, Okla., p.127, September 1974.

blbid., p. 94.

Ch. Ill--oil Recovery Potential . 27

and steam drive. In the first, high-pressure steamor steam and hot water is injected into a well fora period of days or weeks. The injection isstopped and the reservoir is allowed to “soak.”After a few days or weeks, the well is allowed tobackflow to the surface. Pressure in the produc-ing well is allowed to decrease and some of thewater that condensed from steam during injec-tion or that was injected as hot water then vapor-izes and drives heated oil toward the producingwell. When oil production has declined apprecia-bly, the process is repeated. Because of its cyclicnature, this process is occasionally referred to asthe “huff and puff” method.

The second method, steam drive or steamflooding, involves continuous injection of steamor steam and hot water in much the same waythat water is injected in waterflooding. A reser-voir or a portion thereof is developed with in-terlocking patterns of injection and productionwells. During this process, a series of zonesdevelop as the fluids move from injection well toproducing well. Nearest the injection well is asteam zone, ahead of this is a zone of steam con-densate (water), and in front of the condensedwater is a band or region of oil being moved bythe water. The steam and hot water zonetogether remove the oil and force it ahead of thewater.

Cyclic steam injection is usually attempted ina reservoir before a full-scale steam drive is initi-ated, partially as a means of determining thetechnical feasibility of the process for a particularreservoir and partly to improve the efficiency ofthe subsequent steam drive. A steam drive,where applicable, will recover more oil thancyclic steam injection and is one of the five EORmethods used in this study of the national poten-tial for EOR processes. Illustrations of the opera-tion of cyclic steam injection and steam drive aregiven in figures 8 and 9, respectively.

CornbustiorI Processes. -Combustion projectsare technologically complex, and difficult to pre-dict and control. Interest in the process hasdeclined within the last 6 years relative to otherEOR processes. Active field tests declined from30 in 1970 to 21 in 1976. Eight of the projects

28 . Ch 111—0o; Recovery Potential

Figure 8. Cyclic Steam Stimulation Process*

HUFF PUFF(Production Phase)OIL AND WATER

(Shut-in Phase)

(Days to Weeks) (Days)

LEGEND

Steam Zone

w Hot Oil, Water and Steam Zone

(weeks to Months)

I ICold oil and Water Zone

STEAM

Figure 9. Steam Drive Process (Steam Flood)*

OIL AND WATER

LEGEND8

Hot Water Zone

“Ilhmtraticms radrswn and printad with parmkaion of tha NationalPetroisum Council. @ National Patrokum Council, 1976.

I ]Oi l andWaterZcme

Cit. ///—Oil Recovery Potential ● 29

have been termed successful, nine unsuccessful

and four have not yet been evaluated.7

Injection of hot air will cause ignition of oilwithin a reservoir. Although some oil is lost byburning, the hot combustion product gases moveahead of the combustion zone to distill oil andpush it toward producing wells. Air is injectedthrough one pattern of wells and oil is producedfrom another interlocking pattern of wells in amanner similar to waterflooding. This process isreferred to as fire flooding, in situ (in place) com-bustion, or forward combustion. Althoughoriginally conceived to apply to very viscouscrude oils not susceptible to waterflooding, themethod is theoretically applicable to a relativelywide range of crude oils.

An important modification of forward combus-tion is the wet combustion process. Much of theheat generated in forward combustion is leftbehind the burning front. This heat was used toraise the temperature of the rock to the tem-perature of the combustion. Some of this heatmay be recovered by injection of alternate slugsof water and air. The water is vaporized when ittouches the hot formation. The vapor movesthrough the combustion zone heating the oilahead of it and assists the production of oil. Withproper regulation of the proportion of water andair, the combustion can proceed at a higher ther-mal efficiency than under forward combustionwithout water injection.

Combustion processes compete, at least tech-nologically, with steam and some other EORprocesses, and the choice depends upon oil andreservoir characteristics. The wet combustionprocess is illustrated in figure 10. It is the com-bustion process selected for technical andeconomic modeling in this study.

Miscible Processes

Miscible processes are those in which an in-jected fluid dissolves in the oil it contacts, form-ing a single oil-like liquid that can flow throughthe reservoir more easily then the original crude.A variety of such processes have been developedusing different fluids that can mix with oil, in-cluding alcohols, carbon dioxide, petroleum hy -

7Management p/an for Enhanced Oil Recovery, ERDA77-1 5/2, Vol. 2 (of 2), D . B-7, Februarv 1977.

drocarbons such as propane or propane-butanemixtures, and petroleum gases rich in ethane,propane, butane, and pentane.

The fluid must be carefully selected for eachreservoir and type of crude to ensure that the oiland injected fluid will mix. The cost of the in-jected fluid is quite high in all known processes,and therefore either the process must include asupplementary operation to recover expensiveinjected fluid, or the injected material must beused sparingly. In this process, a “slug,” whichvaries from 5 to 50 percent of the reservoirvolume, is pushed through the reservoir by gas,water (brine), or chemically treated brine to con-tact and displace the mixture of fluid and oil.

Miscible processes involve only moderatelycomplex technology compared with other EORprocesses. Although many miscible fluids havebeen field tested, much remains to be deter-mined about the proper formulation of variouschemical systems to effect complete volubilityand to maintain this volubility in the reservoir asthe solvent slug is pushed through it.

One large (50,000 acre) commercial project inTexas uses carbon dioxide (C02) as the miscibleagent, Eight other C02 projects covering 9,400acres are. in early stages of development.8

Because of the high value of hydrocarbons andchemicals derived from hydrocarbons, it isgenerally felt that such materials would not makedesirable injection fluids under current or futureeconomic conditions. For this reason, attentionhas turned to C02 as a solvent. Conditions forcomplete mixing of C02 with crude oil dependon reservoir temperature and pressure and on thechemical nature and density of the oil.

A l though there are many poss ib le CO2

sources, the largest source should be naturallyoccurring deposits. Currently known sources ofnaturally occurring CO2 are described in publica-tions of the U.S. Bureau of Mines. A summary ofC O2 source locations is presented by the Na-tional petroleum Council,9 although the actual

8Managemen[ plan for Enhanced Oil Recovery, ERDA77-1 5/2, Vol. 2 (of 2) p. B-4, February 1977.

gEnhanced 0;/ Recovery, Nat ional petroleum COUnCil,December 1976.,, I

—.


Figure 10. In-Situ Combustion Process-Wet Combustion*

OIL AND WATER

Injected Air and Water Zone

Air and Vaporized Water Zone

Cornbustlon Zone [ ‘“J

Steam zone

Hot Water Zone

Oil and Water Zone

“Mwml@nn redrawn 8fKtprklt9dwktl pem8don Gtth8MionatPetmbum CotmciL @ National Petroleum Council, 1976.

amount of CO2 at these locations is unknown.The potential demand for C0 2 is such thatgeological exploration is in progress.

A pictorial representation of a C02 miscibleflood is shown in figure 11. In the past, CO2 hassometimes, been injected into reservoirs in quan-tities and at pressures less than those necessaryto achieve complete miscibility, resulting in lessoil recovery than when complete mixing isachieved. In this assessment, quantities andpressures of CO 2 injected are designed toachieve complete miscibility.

Chemical Processes

Three EOR processes involve the use of chemi-cals—surfactant/polymer, polymer, and alkalineflooding.

Surfactant/Polyrner Flooding.—Surfactant/poIy-mer flooding, also known as microemulsionflooding or micellar flooding, is the newest andmost complex of the EOR processes, While it hasa potential for superior oil recovery, few majorfield tests have been completed or evaluated.Several major tests are now under way to deter-mine its technical and economic feasibility.

Surfactant/polymer flooding can be any one ofseveral processes in which detergent-l ikematerials are injected as a slug of fluid to modifythe chemical interaction of oil with its surround-ings. These processes emulsify or otherwise dis-solve or partly dissolve the oil within the forma-tion. Because of the cost of such agents, thevolume of a slug can represent only a small per-centage of the reservoir volume. To preserve theintegrity of the slug as it moves through the reser-voir, it is pushed by water to which a polymer hasbeen added. The surfactant/polymer process is il-lustrated in figure 12.

The chemical composition of a slug and its sizemust be carefully selected for each reser-voir/crude oil system. Not all parameters for thisdesign process are well understood.

polymer Flooding. -Polymer flooding is achemically augmented waterflood in which smallc o n c e n t r a t i o n s o f c h e m i c a l s , s u c h a spolyacrylamides or polysaccharides, are added toinjected water to increase the effectiveness ofthe water in displacing oil. The change in recov-

Ch. //I--Oil Recovery Potent/a/ . 31

ery effectiveness is achieved by several differentmechanisms, not all of which are completely un-derstood. Improvement in the efficiency ofwaterflood recovery with the use of polymers isrelatively modest, but it is large enough for theprocess to be in limited commercial use. If otherEOR processes are technically possible they offera possibility of both greater oil recovery andgreater economic return than polymer flooding,although each reservoir must be evaluated in-dividually to select the most effective process. Asit is currently in use, polymer flooding is evalu-ated in this assessment.

Alkaline Flooding.—Water solutions of certainchemicals such as sodium hydroxide, sodium sili-cate, and sodium carbonate are strongly alkaline.These solutions will react with constituents pres-ent in some crude oils or present at therock/crude oil interface to form detergent-likematerials which reduce the ability of the forma-tion to retain the oil. The few tests which havebeen reported are technically encouraging, butthe technology is not nearly so well developed asthose described previously. Alkaline floodingwas not quantitatively evaluated in the presentstudy, largely because there is too little informa-tion about key oil characteristics in the OTAreservoir data base which are crucial to a deter-mination of the feasibility of alkaline flooding.Reservoirs not considered for alkaline floodingbecame candidates for other processes.

Other EOR Processes

Over the years, many processes for improvingoil recovery have been developed, a large num-ber of patents have been issued, and a significantnumber of processes have been field tested. Inevaluating a conceptual process, it should berecognized that a single field test or patent repre-sents but a small step toward commercial use ona scale large enough to influence the Nation’ssupply of crude oil. Some known processes havevery limited application, For example, if thincoalbeds lay under an oil reservoir this coal couldbe ignited, the oil above it would be heated, itsviscosity would be reduced, and it would beeasier to recover. This relationship between oiland coal is rare, however, and the process is notimportant to total national energy production.Another example involves use of electrical


Figure 11. Carbon Dioxide Miscible Flooding Process*

CO2 AND WATER OIL AND WATER

v 4

LEGEND

I I Injected CO2 and Water Zone

CO2-Crude Oil Miscible Zone

Oil and Water Zone

Figure 12. Surfactant Flooding Process

INJECTION FLUIDS

w

w

OIL AND WATER

4

LEGEND

I Drive Water Zone Surfactant Slug Zone

Water/Polymer Zone [ “ I Oil and Water Zone

“Illustrations redrawn and printed with permiaaion of the NationalPetrokum Council. @ National Petroleum Counci{, 1976.

energy to fracture an oil-bearing formation andform a carbon track or band between wells. This

band would then be used as a high-resistanceelectrical pathway through which electric currentwould be applied, causing the “resistor” to heatthe formation, reduce oil viscosity, and increaseoil recovery. The process was conceived over 25years ago and has been tested sporadically, butdoes not appear to have significant potential. Athird process in this category is the use of bac-teria for recovery of oil. Several variations havebeen conceived. These include use of bacteriawithin a reservoir to generate surface-active(detergent-like) materials that would performmuch the same function as a surfactant/polymer

Ch. III—0il Recovery Potential . 33

flood. Although some bacteria are able to with-stand temperatures and pressure found in oilreservoirs, none have been found that will bothsuccessfully generate useful modifying chemicalsin sufficient amounts and also tolerate the chemi-cal and thermal environments in most reservoirs.It is uncertain whether nutrients to keep themalive could be provided. Further, any strain ofbacteria developed would need to be carefullyscreened for potential environmental impacts.Finally, even should the concept prove feasible, itis unlikely that the bacteria could be developed,tested, and used in commercial operation in timeto influence oil recovery by the year 2000.

Oil Resource

Data Base

The analytic approach used in

for Enhanced Oil

Theeludes

Recovery Processes

resulting data base for the assessment in-385 fields from 19 States (table 6). These

this assessmentof EOR potential relies on reservoir-by-reservoirsimulations. The accuracy of this approach de-pends on the extent, representativeness, and pre-cision of the reservoir data file. Earlier reports10 11

have been based on data from 245 large onshorereservoirs in California, Louisiana, and Texas. Forthis assessment, additional data were collectedfor onshore reservoirs in those States, for reser-voirs in other producing areas of the UnitedStates, and for reservoirs in offshore areas (pri-marily the Gulf of Mexico). The expanded database for this assessment was acquired fromFederal, State, and private sources. After allavailable data were examined and cataloged,they were edited for volumetric consistency.These data were reviewed by OTA as othersources of information became available. Addi-tional data led to reductions in estimates of re-maining oil in place (ROIP) in California reservoirswhich contained oil with gravities above 25° API.

lfJThe potentja/ and [conomics of Enhanced Oil Recovery,Lewin a n d A s s o c i a t e s , I n c . , f o r t h e F e d e r a l E n e r g y A d -ministration, April 1976.

II Enhanced 0;/ Recovery, National petroleum council,

December 1976.

385 fields (835 reservoirs) contain 52 percent ofthe known ROIP in the United States. The reser-voir data in the OTA data base are representativeof the known oil reservoirs in the United States.

Uncertainty in the Oil Resource

Two EOR processes, surfactant/polymer andC02 miscible, are generally applied after a reser-voir has been waterflooded. A large portion ofthe resource for these processes will be locatedin the reservoir volume which was contacted bywater. The oil remaining in this region is termedthe residual oil saturation.

There is uncertainty in the estimates ofresidual oil saturation and hence in the oil whichis potentially recoverable with surfactant/polymer and CO2 miscible processes. A review ofthe technical literature and discussions withknowledgeable personnel in the oil industry ledto the following observations:

a

b

There are few reservoirs whose estimates ofresidual oil have been confirmed by inde-pendent measurement.

The uncertainty in the aggregate estimate isdue to a lack of confidence in measurement

34 . Ch. ///—Oil Recovery Potential

State

Table 6Extent of the Reservoir Data Base Utilized in ThisAssessment of Enhanced Oil Recovery Potential

Alabama ... , . . . . . . . . . . . . . . . . .Alaska . . . . . . . . . . . . . . . . . . . . . .Arkansas . . . . . . . . . . . . . . . . . . . . .California. . . . . . . . . . . . . . . . . . . . .Colorado . . . . . . . . . . . . . . . . . . . . .Florida . . . . . . . . . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . . . . . . .Kansas . . . . . . . . . . . . . . . . . . . . . . .Louisiana

Onshore. . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . .

Mississippi . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . .New Mexico . . . . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . . . . . . .Oklahoma . . . . . . . . . . . . . . . . . . . .Pennsylvania. . . . . . . . . . . . . . . . . .Texas . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . . . . . . .

Total States covered (MMB) . . . . .

Remaining oilin place(MMB)

51914,827

2,76862,926

3,002556

5,72610,403

13,6967,3492,9883,796

11,2411,849

25,4065,344

100,5912,7252,064

10,628

288,404

Fields

263

4121

38

28

2424111515

633

5111

62

21

385

OTA databaseRemaining oil

Reservoirs

293

6721

39

28

47372

121518

735

6146

62

27

835

in place(MMB)

35414,601

1,32845,125

1,490465

2,4213,345

6,7312,9831,1871,4434,960

5486,5481,077

54,2211,734

1944,543

115,298

Percent ofState

6898487250844232

4941403844302620546 4

943

54

Total U.S. (MMB) 300,338aOTA database is 52 percent of remaining oil in place in the United States.

“This value includes 3.3 billion barrels of oil which are included ln APl lndlcated reserves as recoverable by secondary methods. it doesnot include 1.0 billion barrels of enhanced 011 in the API proven reserves.

techniques compounded by a limited ap- d. Estimates of the oil recoverable by surfac-plication of those methods. tant/polymer and C02 miscible processes

will have a large range of uncertaintyc. The estimates of residual oil saturation may

because of the uncertainties in the esti-be off by as much as 15 to 25 percent (or

mates of residual oil saturation.more).

Ch. //l—Oil Recovery Potential ● 35

Methodology for Calculating Oil Recovery

Estimates of the amount of oil that can berecovered by the different EOR processes werebased upon an individual analysis of each reser-voir in the data file. Results from the individualreservoir calculations were then compiled andextrapolated to a national total. In outline form,the procedure consisted of the following steps.

Technical Screen

A technical screen was established for eachprocess. Reservoir rock and crude oil propertieswere screened against standards which had to bemet before an EOR process could be consideredapplicable to that reservoir. The technical screensfor all processes are shown in table 7. Thesescreening parameters were established after anassessment of current technology and incorpora-tion of expected technological advances. Eachreservoir was compared to the technical screenfor every process and either accepted or rejectedfor each process. A reservoir could be a candi-date for more than one EOR process.

Calculation of Reservoir Productionand Economics

Reservoirs which passed the technical screenwere then analyzed to determine probable pro-duction performance and economics. Thosereservoirs eligible for more than one EOR processwere analyzed for all processes for which theywere technically acceptable. For each process,both an oil recovery model and an economicmodel were established, Oil recovery models,described in appendix B, were used to predict theamount of oil which would be recovered and therate at which the oil would be produced. Theserecovery models all incorporate features whichmade the calculations dependent upon the par-ticular characteristics of the reservoirs.

The economic model described in appendix Bwas used to compute, at a specified oil price, arate of return on investment which would resultfrom application of a selected EOR process to aparticular reservoir. The economic model

allowed for different operating and drilling costsin different geographic regions, different wellspacings, variable EOR process costs, etc. Themodel also incorporated a field developmentscheme. This scheme allowed a specified numberof years for pilot tests and economic andengineering evaluations. It also provided fordevelopment of a field on a set time schedulerather than for simultaneous implementation ofan EOR process over the entire field.12

Final EOR Process Selection forReservoirs Passing More Than One

Technical Screen

For reservoirs passing more than one technicalscreen, production resulting from application of arecovery technique and economic models foreach acceptable EOR process were compared.The process selected was the one which yieldedthe greatest ultimate oil recovery, as long as theprocess earned at least a 10-percent rate of returnon investment at the world oil price of $13.7sper barrel. If no process earned 10 percent at theworld oil price, then the alternate fuels price of$22 per barrel was used, again selecting the proc-ess which yielded the greatest amount of oil.Reservoirs not yielding 10 percent for any processat the alternate fuels price of $22 per barrel wereplaced in the process which appeared to have thebest economic potential. Reservoirs were deletedfrom consideration if the computations at thealternate fuels price resulted in a negative returnon investment.

Ultimate Recovery for the Nation

Ultimate recovery for the Nation was esti-mated by extrapolating the individual reservoir

I ~Our analysis assurnecf that enhanced recovery opera-

tions would be installed before producing wells are pluggedand abandoned. If enhanced recovery operations are begunafter producing wells are plugged and abandoned, oil recov-ery will be slightly more costly ($1 to $3 per barrel) andmost likely delayed because of economics.

36 . Ch. ///—Oil Recovery Potential

o1 o ’

‘ VI ‘t

t, 1 1

1 1

I I

c. -

I

1

t

,,

o00In

18 t

11 v ‘8 ‘1’ ‘I 1= 1,1 1

It o #o ‘ Al ‘ ‘ ‘ ‘mA

1

I

1

1

#

I

. .● ✎ ✎u“0

Ch. ///—Oil Recovery Potential . 37

performances. Because a significant amount ofthe oil in each oil-producing State was repre-sented in the data base, extrapolations weremade on a district or State basis. Total recoveryfor each State or district, for a selected oil priceand rate of return, was calculated in the followingmanner: The oil recovered from reservoirs in thedata base for that State or district was multipliedby the ratio of total oil remaining in the State ordistrict to oil remaining in the State or districtdata-base reservoirs. (The one exception to thisrule was for West Virginia, where the sample in-cluded only 9 percent of the total oil in the State.For West Virginia, only the oil in the data basewas included in the composite results. Deletionof West Virginia from the extrapolation processhas no significant effect on ultimate recoveryestimates because oil remaining in those reser-voirs constitutes less than 1 percent of the oil re-maining in U.S. reservoirs. ) “Oil remaining, ” asused here, refers to oil remaining after ultimateprimary and secondary recovery. State and dis-trict productions were summed to obtain na-tional production.

Rate of Production for the Nation

The starting date for the development of eachreservoir was determined with the use of a rate-of-return criterion, Reservoirs earning the highestrates of return were assumed to be developedfirst. The schedule shown in table 8 was used toestablish starting dates for reservoir evaluation,i.e., starting dates for pilot tests and economicand engineering evaluations, which were thenfollowed by commercial development. Extrapola-tion of production rates from individual reser-voirs to a State and then to the Nation was ac-complished in the same manner as described forultimate recovery.

This plan for reservoir development recognizestwo factors which influence the application ofimproved oil recovery processes. First, it ac-counts in part for risk in that the highest rate-of-return projects will be initiated earliest when thetechnology is least certain. Lower rate-of-returnprojects would not be started until later dates, atwhich time the technological and economic riskshould be reduced as a result of experiencegained from field tests and commercial opera-tions. Secondly, the timing plan in some measuresimulates actual industry decisionmaking. As a

Table 8Schedule of Starting Dates

Based on Rate-of-Return Criterion

Continuations ofongoing projects New starts

Date rate of return rate of return1977 . . . . . . . . . . . 1 00/0 30 ”/01978 .. . . . . . , . . .1979 . . . . . . . . . . .1980 . . . . . . . . . . .1981 . . . . . . . . . . .1982 , . . . . . . . . . .1983 . . . . . . . . . . .1984 . . . . . . . . . . .1985 . . . . . . . . . . .1986 . . . . . . . . . . .1987 .. . . . . . , . . .1988 . . . . . . . . . . .1989 . . . . . . . . . . .1990-2000 . . . . . .

1 00/010“/0“10“/010%10“/010%10%10%10%1 0 %

10%10%10%

250/o20 ”/019 ”/018%17’YO160/015 ”/014%13“/012“/011 ”/010“/010“/0

Note: In the production models, after It has been decided todevelop a reservoir, time IS allowed to study the reservoir,conduct p i lot tests and do engineer ing and economicanalyses. These studies and evaluations are completedbefore initiating commercial production.

general rule, the most promising projects are ini-tiated first by industry.

Whi le OTA bel ieves the t iming plan i sreasonable, it still is only an approximation ofwhat will actually occur. Other factors such aslevel of technological risk, alternative investmentopportunities, availability of resources requiredfor the processes, etc., will significantly influencethe implementation rate of EOR.

Exclusion of Alaska

The EOR potential of Alaska was not ex-amined, for several reasons. A large portion ofthat State’s oil resource was included in the database (table 6). However, OTA felt that theeconomic data base required for the E O R

economic models was not sufficiently wellestablished. Alaska is a relatively young produc-ing area and most of its oil fields are in a hostileenvironment. Costs are known to be high anddifficult to estimate for future EOR projects. Also,because Alaska is a young producing area andbecause costs are high, EOR projects probablywill not be considered to any significant degreefor several years.

— -——


Estimated Oil Recovery

Definition of Cases

It is not possible to predict with certainty howmuch oil can be recovered in the future with EORprocesses. Therefore, two principal cases wereestablished, covering a range in the technologicalperformance of the different processes. The moreoptimistic of these was labeled the “advancingtechnology —high-process performance case. ”The less optimistic was termed the “advancingtechnology —low-process performance case. ”These cases were designed in an effort to calcu-late realistic estimates of future recovery and atthe same time reflect the uncertainty which existsin OTA’s projection.

In addition to these two principal cases, esti-mates were made of the effects of variations inkey parameters, such as injected chemical (CO2,surfactant) costs, minimum specified acceptablerate of return, and resource availability, on recov-ery. These estimates, in essence, involved exten-sions and modifications of the two principalcases.

A description of the principal cases follows.

Case I: Advancing Technology—High-Process Performance

It was assumed for this case that the EOR proc-esses which are now in their developmental stage(C02 miscible, surfactant/polymer, polymer-aug-mented waterflooding, and in situ combustion)would work as now generally envisioned by thepetroleum industry. The production models forthese processes, which are described in appendixB, were based largely on reported laboratoryresults with limited data from field tests. Thesteam process is the only technique that can cur-rently be classified as a commercial process andas a result its production model is based on morefield experience than the others.

Because of the nature of surfactant/polymerand polymer-augmented waterflood processesand their early stage of development, OTAassumed that certain technological advanceswould occur between now and the year 2000.

In the case of surfactant/polymer flooding, itwas assumed that research and field testingwould lead to a reduction in the volume of oilused in the surfactant slug and the volume ofpolymer needed to displace the surfactant slugthrough the reservoir. Reductions by a factor oftwo were assumed for both oil and polymervolumes from values representative of currenttechnology. Current surfactant formulations aretolerant of total dissolved salt content of about20,000 parts per mill ion (ppm). It was alsoassumed that developments in the formulation ofsurfactant and polymer systems would extendsalinity tolerance to 200,000 ppm. Finally, it wasassumed that technological advances would oc-cur in surfactant/polymer and polymer-aug-mented waterflooding processes which wouldraise the temperature constraint to 250° F. Thetiming of the advances is shown in table 7.

A major technological assumption for the CO2

miscible process was that between 4 and 6 thou-sand cubic feet (Mcf) of C02 would be injectedper barrel of EOR oil recovered. Although currentpilot tests with CO2 indicate that this injection-volume ratio may be on the order of 10 Mcf perbarrel of oil, it was assumed that a technologicaladvance to the above-stated injection efficiencywould be achieved.

The advancing technology-high-process per-formance case was considered to be un-constrained by chemical resource availability.This assumption is also of paramount impor-tance. For example, the amount of CO2 requiredat the world oil price recovery is 53 trillion cubicfeet (Tcf) (not including recycled CO2). This is avery large quantity of C02, which simply may notbe available at CO2 prices used in the calcula-tion. Chemical availability was also assumed forsurfactant/polymer and polymer-augmentedwaterflooding processes.

Technological advances were assumed in thefield application of steam and in situ combustionprocesses. Well-completion technology, whichpermitted selective depletion of each major zonewithin a reservoir, was assumed. All major zoneswere developed sequentially. Methods for con-

Ch I//—Oil Recovery Potential . 39

trolling volumetric sweep efficiency of bothprocesses were assumed to develop so that theprocesses could be applied to 80 percent of thereservoir acreage.

It was assumed in this case that the EOR proc-esses could be made to operate without damageto the environment and that this could be doneat no additional cost. For the thermal processes,in particular, this is an important assumption. Forexample, air pollution limitations now existing inCalifornia would allow little or no new steamrecovery in that State without technological ad-vances to reduce pollutant levels from steamgeneration.

In California, a limited number of refineriescapable of processing heavy oil, an entitlementsprogram, and a prospect of competing crude sup-plies from Prudhoe Bay combine to reduce theState demand for heavy oil production. The OTAstudy assumes that a market exists for all heavyoil produced in California.

Enhanced oi l recovery product ion wasassumed to occur in any reservoir if the rate ofreturn after taxes was greater than 10 percent.This further implies advances in technology toreduce risk of failure, because investments at in-terest rates of 10 percent will only be made forrelatively low-risk projects. Risk has been takeninto account, as explained in a previous section,in that the production timing plan was based onrate of return with the “best” projects being initi-ated first, However, in the calculations a largeamount of oil is recovered at rate-of-return valuesjust slightly above 10 percent,

The advancing technology-high-process per-formance case implies a significant commitmentto a research and development program whichwould be carried out in concert with the com-mercial implementation. The technological ad-vances will not be made, nor will risk be reducedto the level assumed, without such an effort.

Case II: Advancing Technology-Low-Process Performance

Case II is a conservative estimate of futurerecoveries which assumes that no EOR processwilI work as successfulIy as it does in the advanc-ing technology-high-process performance case.

Changes were made in the production modelswhich led to reductions in recoveries averagingbetween 12 and 30 percent for the different EORprocesses. The details of the low-process per-formance case for each process are given in appen-dix B.

Case II essentially assumed that less oil wouldbe recovered by the EOR processes using as largea dollar investment as was assumed in the high-performance case. Resource constraints were notimposed, and the assumption was made that theprocesses would operate without environmentaldamage.

Calculation Results

Low- and High-Process Performance Cases

The results of the high-process performanceand low-process performance cases are shown intables 9 through 14, Table 15 presents ultimaterecovery by State while table 16 shows ex-trapolation proportions for each process underhigh- and low-process performance assump-tions. Table 9 gives the cumulative figures for allprocesses. Individual process recoveries areshown in the other tables. Results are shown forthree oil prices: upper tier ($11.62 per barrel),world oil ($13.75 per barrel), and alternate fuels($22.00 per barrel).

These two cases represent the range of recov-eries considered feasible for EOR technology. Forthese cases, recoveries were not restricted byresource availability and technology to meet en-vironmental protection standards. Markets wereassumed for heavy oi I in Cal i fornia. Thedifference between the cases thus results fromdifferences in assumptions about the technologi-cal performance of the processes.

For the high-process performance case at theupper tier price, it is estimated that approx-imately 21.2 bil l ion barrels of oil could berecovered. The recovery increases to about 29.4billion barrels at the world oil price and 41.6billion barrels at the selected alternate fuelsprice, Corresponding uitimate recoveries for thelow-process performance case are 8.0 billion,11.1 billion, and 25.3 billion barrels, respectively.

40 . Ch. 111—011 Recovery Potential

Table 9Estimated Recoveries for

Advancing Technology-Low- and High-Process Performance Cases

Aii Processes

Low-process performance case High-process performance case

Upper tierprice

($11.62/bbl)

8 0

0.30.40.50,51,1

4001,2002,0002,8004,200

World oilprice

($13.75/bbl)

Alternate fuelsprice

($22.00/bbl)

Upper tierprice

($11.62/bbl)

World oilprice

($13.75/bbl)


($22.00/bbl)

Ultimate recovery:(billion barrels) . . . . . . . . . . .

Production rate in:(million barrels/day)

1980. , . . . . ... . . . . . . .1985. ., ., . . . . . . . . . . . . .1990. . . . . . . . . . . . . . . .1995. . . . . . . . . . . .2000. . . . . . . . . . . . . . . . . .

Cumulative production by:(million barrels)

1980. ...., . . . . . . . . .1985. . . . . . . . . . . . . . . . .1990, ., . . . . . . . .

1995. . . . . . . . . . . . . . . . . .2000. , . . ... , . . . . . . . . .

11.1

0.30.50.71.21.7

4001,3002 ( 3003,8006,900

2 5 3

0.30.91.82.55.1

4001,7004,2007,500

‘1 6,000

— —

21.2

0.40.51.11.72.9

5001,7003,3005 , 6 0 0

10,400

29.4

0.41.01.73.15.2

5002,0004,7008,700

17,300

41.6

0.41.32.86.08.2

5002,4006,200

12,80029,200



Steam Drive Process

Low-process performance case High-process performance case

Upper tierprice

$11.62/bbl)

2.1

0.10 20,20.20.2

200500800

1,2001,600

World oilprice

[$13.75/bbl)

A1ternate fuelsprice

($22.00/bbl)

Upper tierprice

($11.62/bbl)

World oilprice

($13.75/bbl)


($22.00/bbl)



1980. . . . . ., . . . . .1985. .., . . . . . . . . . . .1990, . . . . . . . . ., . .1995. . . . . . . . . . . . .2000, , . . . . . ., . . . . . . . .


1980. . . . . . . . . . . ., . . . .1985. ., . . . ., . . . . . . . .,1990. ...., ., . . . . . . . . . .1995. , . . . . . . . . . . . . . . . .2000. ..., ... . . . . . . . .

2.5

0 10.20.20.30.3

200

500800

1,3001,800

— .

4.0 2.8

o.2

0.20.20.20,3

300

3..3

0.20.20.30.30.4

300800

1,1001,7002,400

6.0

0.20.30.50.40.4

0.30.40.70.70.6

200 I 4001,1002,0003,3004,600

7001,4002,3003,100

8001,1001,4001,900

Ch ///—Oil Recovery Potential . 4 1



In Situ Combustion

Ultimate recovery:(billion barrels) . . . . . . . . . . . . .


1980. . . . . . . . . . . . . . . . . .1985. . . . . . . . . . . . . . . . . . .1990. . . . . . . . . . . . . . . . .1995 .., . . . . . . . . . . . . . . .2000. . . . . . . . . . . . . . .


1980. . . . . . . . . . . . . . . . .1985. . . . . . . . . . . . . . . . . .1990. . . . . . . . . . . . . . . . . .1995. . . . . . . . . . . . . . . . . .2000. . . . . . . . . . . . . . . . . .

Low-process performance case

Upper tierprice

$11.62/bbl)—

1.2

0.10.10.20.10.1

*

300600900

1,000

World oilprice

($13.75/bbi)

1.4

0.10.20.30.10.1

*

300700

1,1001,200


($22.00/bbl)

1.6

0.10.20.30,20.1

●

300800

1,2001,400

High-process performance case

Upper tierprice

($ll .62/bbl)

1.7

0.10.20.30.20.1

●

300800

1,2001,400

world Oi l

price($13,75/bbl)

1.9

0.10.20.30.20.1

●

400900

1,4001,600

•le\~ than 005 mllllon barrels of dally production, or less than 50 mlllmn bwels of cumulat ive product ion.





1980. . . . . . . . . . . . . . . . . .1985. . . . . . . . . . . . . . . .1990. . . . . . . . . . . . . . . . .1995, , . . . . . . . . . . . . . . . .2000. . . . . . . . . . . . . . . . . .


1980. . . . . . . . . . . . . . . . . .1985. . . . . . . . . . . . .1990. . . . . . . . . . . .1995. . . . . . . . . . . . . . . . .2000. . . . . . . . . . . . . . . . .

Surfactant/Polymer

Low-process performance case

Upper tierprice

$11.62/bbl)

1 .0

*+●

*

0.2

*

100100100300

World oilprice

($13.75/bbl)

2,3

***

0.10.2

*

100100200

500

A1ternate fuelsprice

($22.00/bbl)— —

7.1

●

0.10.40.2

1.3

*

200600900

2,700


($22,00/bbll

1.9

0.10.20.40.20.1

*400

1,0001,5001,700


Upper tierprice

$11.62/bbl)

7.2

●

☛

0.20.20.9

●

1 0 0

400700

1,800

- <

W o r l d – o i l

pr ice

( $ 1 3 . 7 5 ‘ b b l )

10.0 ~

●

0.20.40.81.9

●

300900

1,8004,400

Alternate fuels

price

( $ 2 2 . 0 0 / b b l )

12.2

●

0.2().71,32.5

*300

1,0002,0006,200

● less than 0.05 million barrels of daily production, or less than 50 million b.irrc~ls of ( umul,ltlve produ~~ion

—-


ri● ☛☛ 0 0

mr -

0 0 0 0 00 0 0 0 0F a G m V,

. . .

6

0 ● ☛☛ 0 0

— —

r -

2 . :




Polymer-Augmented Waterflooding

I Low-process per formance case

Upper tierprice

($11.62/bbl)

Ultimate recovery:(billion barrels) . . . . . . . . . . . . .

Product ion rate in :

(mi l l ion bar re l s/day)

1 9 8 0 . . . . . . . . . , . . . , . . . .

1985. . . . . . . . . . . . . . . . . .

1990, . . . . . . . . . . . . . . . . .

1995. ......., . . . . . . . . .

2000. . . . . . . . . . . . . . . . .

Cumulative production by:(mill Ion barrels)

1980. , . . . . . . . . . . . . . . . .1985. . . . . . . . . . . . . . . . . .1990. . . . . . . . . . . . . . . . . .1995. . . . . . . . . . . . . . . . . .2000. . . . . . . . . . . . . . . . . .

0.2

*●

0.1*●

100200200200

World oilprice

($13.75/bbl)

0.3

●

●

0.1**

●

100200300300


($22.00/bbl)

0.3

●

☛

0.1*●

*100200300300


Upper tierprice

($11.62/bbl)

0.4

**

0.1**

*

100200300400

World oilprice

($13.75/bbl)

0.4

**

0.1*+

.

100200400400

● Less than 0,05 mlllmn barrels of dally production, or less than sO million barrels ofcurnulatlve product~m.

Table 15Ultimate Recovery by State

High-Process Performance

State

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Alabama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wyoming, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Illinois. . . . . . . . . . . . . . . .Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Offshore Gulf ot Mexico . . . . . . . . . . . . . . . . . . . . . . . . . .

Totals J . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .


($22.00/bbl)

0,4

●

☛

0.1*●

●

100300400400

U p p e r t i e r

pr ice( $ 1 1 . 6 2 / b b l )

6.81.14.71 . 2

3 . 3

1 . 6

0 . 3

0 , 2

0 , 0

0 . 0

0 . 0

0 . 0

0 . 6

0 . 0

0 . 4

0 . 2

0 . 1

0 . 6

21.2

U l t i m a t e r e c o v e r y

(billions of barrels)

world oilprice

($13.75/bbl)

7,81 . 2

7 . 9

1 . 7

4 . 0

2 . 3

0 . 4

0 . 3

0 . 2

0 . 0

0 . 4

0 . 0

1 . 3

0 . 0

0.50,50.10.9

29.4

Alternate fuels

price

( $ 2 2 0 0 / b b l )

11.42.0

11.61.74.82.70.40.40.20.10.40.21 . 4

0 . 20 . 8

0 . 5

0.1

2 . 6

4 1 . 6

“Columns may not add due to roundlng


Table 16Extrapolation of Ultimate Oil Recovery From Data Base Calculations to the Nation

World Oil Price ($13.75/bbl)

(Billions of Barrels)

Low-process performanceProcess Data base/

NationData base Nation percent

Steam drive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .In situ combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Carbon dioxide miscible . . . . . . . . . . . . . . . . . . . . . : . . .Surfactant/polymer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Polymer-augmented waterflood . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1.400.782.110.730.15

5.17

As indicated in table 9, all of this oil would notbe recovered by the year 2000. For example, inthe high-process performance case at the uppertier price, the production rate increases fromslightly more than 0.5 MMBD in 1985 to nearly3.0 MMBD in the year 2000. The daily productionpattern shown results in a cumulative productionby the year 2000 of 10.4 billion barrels, or sO per-cent of the projected ultimate recovery. At theother two oil prices, the production rate also in-creases through the year 2000. The cumulativeproductions by 2000 are 59 and 70 percent ofultimate recovery at the world oil and alternatefuels prices, respectively.

The f ive EOR processes examined y ie ldmarkedly different amounts of oil as indicated intables 10 through 14. This is illustrated by thehigh-process performance case. The COZ misci-ble process contributes about half of the ultimaterecovery at the world oil and alternate fuelsprices. The surfactant/polymer process is esti-mated to contribute about 30 percent of the totalultimate recovery and the thermal processesabout 20 percent.

The only process found to be generallyeconomical in the offshore reservoirs at the worldoil price was CO2 miscible. Other processes werefound to be economical in only a very few reser-voirs, Therefore, C02 miscible flooding was ap-plied exclusively. The results are shown, alongwith the onshore recoveries, in table 13 for thehigh-process performance case. For low-processperformance, offshore development was taken to

I I

High-proc

Data base

1.831.086.654.540.19

14.29

Nation

3.31.9

13.810.00.4

29.4

formanceData base/

Nationpercent

5557484548

49

be marginally economical and therefore unattrac-tive.

Both the high- and low-process performancecases place great demands on resource require-ments. For example, the amount of CO2 thatwould be consumed in reaching the ultimaterecovery at the world oil price is about 53 Tcf inthe high-process performance case. This does notinclude about 18 Tcf of recycled C02. This is avery large amount of CO2, and it is not knownwhether such a supply will be availablecosts assumed in the economic model.

Ultimate Oil Recovery byEOR Processes

Estimates of ultimate recovery were

at the

deter-mined by extrapolating results from the 835reservoirs in 19 States. Of the 835 reservoirs inthe OTA data base, 636 were assigned to one ofthe five oil recovery processes. Nine reservoirs inAlaska were not evaluated for enhanced oilrecovery processes due to insufficient cost data.Enhanced oil recovery processes were not techni-cally feasible in the remaining 190 reservoirs.

The remaining oil in place (ROIP) in the 835reservoirs is 155.3 billion barrels, which repre-sents about 52 percent of the ROIP in the UnitedStates. About 14.6 billion barrels of this amountare in Alaskan reservoirs which were not con-sidered for EOR processes. The ROIP in data basereservoirs which were evaluated for enhanced oilrecovery processes was 140.7 billion barrels.

Net oil recovered from data base reservoirs byapplication of high-process performance modelsis 22.3 billion barrels at $30 per barrel. In estimat-ing the net oil that can be recovered by enhancedoil processes, a reservoir was consideredeconomic if it could be developed and yield a10-percent rate of return at prices of $30 per bar-rel or less. This is about 95.5 percent of the oilconsidered technically recoverable using thesemodels. Oil not recoverable under the high-proc-ess performance models is 133 billion barrels.Distribution of the potential recoverable andunrecoverable oil by process is shown in table17.

Table 18 extends these results to the UnitedStates us ing the extrapolat ion proceduredescribed in the section on Ultimate Recovery forthe Nation on page 35.

The 49.2 billion barrels indicated as net oilrecoverable by enhanced oil processes is an esti-

Ch. 111—011 Recovery Potential .

mate of the upper limit of potential recovery

45

atoil prices of $30 per barrel” or less. This is 95.6percent of the oil considered to be recoverable.The estimate assumes successful application ofEOR processes to all applicable reservoirs in theUnited States. If the EOR processes perform asassumed in the low-process performance case,the net potential EOR oil would be considerablyless.

Unrecoverable oil in table 18 is estimated tobe 248.8 billion barrels or 56.3 percent of the ini-tial oil in place. About 76 billion barrels of oil willbe left in reservoirs where no enhanced oil recov-ery process was considered applicable in theOTA study. Some portion of the 14.8 billion bar-rels which will remain in Alaskan reservoirs notevaluated in the OTA study may be recoverableat $30 per barrel. The approximately 170.4 billionbarrels which remain in reservoirs after EOR proc-esses are applied represent their inherent ineffi-ciencies.

Table 17Summary of Oil Recovery Evaluations

Data Base Resevoirs

Process

Steam drive. . . . . . . . . . . . . . . . . . . . . . . . . .In situ combustion . . . . . . . . . . . . . . . . . . . .C O2 miscible

Onshore . . . . . . . . . . . . . . . . . . . . . . . .Offshore . . . . . . . . . . . . . . . . . . . . . . . .

Surfactant/Polymer . . . . . . . . . . . . . . . . . . .polymer augmented waterflood . . . . . . . . .No EOR . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . . . . .

Reservoirsassigneda

to process

2020

190294

9220

199

835

Remainingoil in place

(millions of barrels)

2 1 , 1 0 7

7 , 5 8 5

5 3 , 2 5 4

2 , 6 9 5

2 4 , 3 8 6

3 , 9 4 9

4 2 , 3 2 2

1 5 5 , 2 9 8

Net oilb

recoverable(millions of barrels)

at $30/barrel

4,0531,126

9,7041,2985,898

1890

22,268

‘Process selected yielded maximum oil recovery at 10-percent rate of return or better at world oil price

Oil considerednot recoverable

(millions of barrels)

17,0546,459

43,5501,397

18,4883,760

42,322

133,030

ho,] used as fuel O’r Inlected as part Of the displacement process was deducted from gross Production ‘0

find net production.‘Includes nine reservoirs in Alaska containing 14.6 billion barrels of remaining oil which were not evalu-

ated due to msufflclent cost data.

.—

46 . Ch. Ill-oil Recovery Potential

Discussion of Results

Table 18 Table 19Projected Distribution of Uncertainty in Projections of Ultimate Recovery for

Known Oil in the United States Advancing Technology Cases

Produced (December 31, 1975) . .Proven reserve (including North

Slope Alaskaa . . . . . . . . . . . . . .Indicated reserveb . . . . . . . . . . . . .Net oil recoverable by

Enhanced oil processes in high-process performance case at$30/barrel. Not included inAPI proven or indicatedreserves. . . . . . . . . . . . . . .

Unrecoverable oilRecoverable at price greater

than $30/barreI . . . . . . . . . .O i l l e f t i n re se rvo i r s a f te r

enhanced oil recovery proc-esses were applied and oilconsumed as part of therecovery process . . . . . . . . .

O i l i n rese rvo i r s where noenhanced oil recovery proc-ess was applicable at pricesof $30/barreld. . . . . . . . . . . .

‘API Proven Reserve (December 31,

Billionsof

barrels

109.0

32.75.0

46.5

2.3

170.4

76.1

442.0

Percentageof original

oil inplace

24.7

7.41.1

10.5

0.5

38.6

17.2

100.0

1975) includes 1.0 billionbarrels from enhanced oil recovery processes.

bApl Indicated Reserve (December 31, 1975) includes 1.7 billlon

barrels from enhanced oil recovery processes.‘Net 011 recoverable in the high-process performance case IS 49.2

billlon barrels. The 2.7 billion barrels included in API Proven and in-dicated Reserves as of December 31, 197s were deducted f romcomputed net EOR oil.

‘{Reservoirs In Alaska which will contain 14.8 billlon barrels of oilafter deduction of Proven and Indicated Reserves were not evalu-ated In this study due to insufficient cost data.

Projections of this study are based on applica-tion of EOR processes to reservoirs in the lower48 States.

I Ultimate recovery

, (bil l ions of b a r r e l s )Oil price Low- High-$/barrel I process process

performance performance

Upper tier ($11.62/bbl) . . . . . 8.0 21.2World oil ($13.75/bbl) . . . . . 11.1 29.4Alternate fuels ($22.00/bbl) . 25.3 41.6

lower and upper bounds of the volumes of oilwhich are potentially recoverable at upper tier,world oil and alternate fuels prices. Thesevolumes, ranging from 8 billion to 42 billion bar-rels, are significant when compared to theAmerican Petroleum Institute (API) proven oilreserves (December 31, 1975) of 32.7 billion bar-rels which remained to be produced from exist-ing fields.13

The wide range in estimates is caused primarilyby uncertainties in projecting oil recovery fromapplication of the surfactant/polymer and C02

miscible flooding processes. Both processes arein early stages of development.

Production Rate

Daily production rates for the advancing tech-nology cases at world oil prices are superim-posed on the projected U.S. decline curve infigure 13. peak production rates are projected tobe the same order of magnitude as the projectedproduction rate from API proven, indicated, andinferred reserves in existing fields. Productionrates in the mid-1980’s are projected to vary be-tween 8 and 17 percent of the projected produc-

Projected Results for the United States

Ultimate RecoveryResults of the advancing technology cases,

summarized in table 19, are estimates of the

I JAn additional s billion barrels are recognized by the Apl

as Indicated Additional Reserves. About 3.3 billion barrelsare projected from secondary recovery. The remainder (1.7billion barrels) are attributed to enhanced oil recovery proc-esses. A total of 31.7 billion barrels of the proven oil reservewill be produced by primary and secondary methods. Onebillion barrels will be produced by EOR techniques at cur-rent economics.

t ion f rom exis t ing f ie lds by convent ionalmethods.

Oil produced by improved oil recovery proc-esses could become an important part of the Na-tion’s oil supply for the period beginning in 1985and extending beyond the year 2000. However,application of EOR technology would not offsetthe decline from existing fields until after 1990.

Uncertainties in Projections

The range of projections for ultimate recoveryin table 19 and production rates in figure 13represents OTA’s judgment of the range of uncer-tainty which exists in the projections, Althoughuncertainties are present in projections of bothultimate recovery and production rate, the esti-mates of ultimate recovery are considered to be

Figure 13. Projected Production From KnownU.S. Reservoirs, 1976-95, by ConventionalMethods and by Enhanced Oil Recovery

at World Oil Price

Increased Production of High-Process Performance~ , Case Over Low-Process Performance Case

7

2

1

Production Basedon Low-ProcessPerformance Case

Production From- Inferred Reserves

(Extensions andRevisions) 2

Proved and Indicated Reserves1

I I I f1976 1980 1985 1990 1995

SOURCES 1 American Petroleum Institute, Reserves of Crude 0//, NaturalGas L/qu/ds, and Natural Gas m the U. S. and Canada as ofDecember 30, 1975 Lewin & Associates, Inc for Federal EnergyAdmlnlstratlon, Oec//rre Curve Ana/ys/s, 1976

z U S Geological Survey, C/rcu/ar 725, 1975

3 Federal Energy Admlnlstratlon, Nat/ona/ Energy Outlook, 1976

Ch. Ill—Oil Recovery Potential . 47

more certain than those for daily productionrates.

Uncertainty in Ultimate Recovery

Projections of ultimate recovery at a specifiedoil price are uncertain because:

1)

2)

3)

Estimates of ROIP volume and distributionwithin a reservoir may be as much as 25percent (or more) in error. Further discus-sion of this problem is included in the sec-tion on the Effect of Uncertainty in theResidual Oil Saturation and VolumetricSweep on Projected Results on page 50.

The ability to predict the oil recovery andthe quantities of injected materials neededto obtain this recovery is different for eachprocess and has wide ranges of uncertain-ty.

Materials used in the surfactant/polymerprocess are either derived from crude oil orcompete with products derived from crudeoil. Therefore, the costs of these compo-nents were increased for the purposes ofthis assessment as the price of crude oil in-creased. The cost of carbon dioxide wasnot varied with oil price. Because none ofthese materials is produced commerciallyin the volumes projected for this study, thecost estimates have some uncertainty. Sen-sitivity calculations described in appendixB show that both processes are extremelysensitive to costs of injected materials. A50-percent increase in the estimated costof chemicals would reduce the oil recoveryfrom the surfactant/polymer process at$13.75 per barrel (high-process perform-ance) from 10 billion barrels to 0.2 billionbarrels. About 9 billion barrels of this oilwould be recoverable at the alternate fuelsprice.

The demand for natural CO2 may be highenough for owners of these deposits tonegotiate prices considerably above theproduction costs assumed in this study. Forexample, a 50-percent increase in the priceof C02 would reduce the potential pro-duction from the C02 process from 13.8


4)

5)

billion barrels at $13.75 per barrel (high-process performance) to 7.0 billion barrels.

It is not known whether large volumes ofinjection fluids, particularly C02, will beavailable. 14 A comprehensive report ofC OZ availability in the United States hasnot been published, although ERDA is cur-rently conducting such a study.

The level of uncertainty is influenced bythe stage of technological development ofeach process. Steam displacement tech-nology has been proven in portions ofseveral California reservoirs. In situ com-bustion and polymer flooding have beentested extensively with mixed results. Sur-factant/polymer flooding and C02 misci-ble displacement are still being investig-ated in laboratory and field tests.

Projected ultimate recoveries for steam dis-placement and in situ combustion are based onselective development of each major zone in areservoir and application of the processes to 80percent of each reservoir area. Selective comple-tion has been used successfully in portions of afew reservoirs in California. There is no reservoirin the OTA data base where steam displacementor in situ combustion has been applied to 80 per-cent of the total reservoir acreage.

The CO2 miscible process model is based onlaboratory data and a number of field tests. Re-cent indications from the field tests are that theratio of C02 injected to oil recovered may rangeabove 10 Mcf of CO 2 per barrel of oil.15 T h eassumption used in the present study for thehigh-process performance case was that this ratiowould generally be reduced to 4 to 6 Mcf of C02

per barrel of oil, with 25 percent of the injectionmaterial being recycled C02. The average valuefor the high-process performance case was 5. IMcf. For the low-process performance case, theaverage ratio was 5.4 Mcf per barrel of oil.

The effect of using a lower CO2 injection ratiois to reduce chemical costs and thereby improvethe economics. As an example, if the cost of in-

14EC)R Workshop on Carbon Dioxide, Sponsored by

ERDA Houston, Tex., April 1977.15[bldt

jected CO2 were increased by a factor of 1.5 forthe high-process performance case, the ultimaterecovery by CO2 miscible at world oil priceswould be reduced from 13.8 billion barrels to 7.0billion barrels. Additional discussion is presentedin appendix B.

Significant technological advances wereassumed in application of the surfactant/polymerprocess. Specific assumptions are compared intable 20. The effect of the assumed technologicaladvances on ultimate recovery for the surfac-tant/polymer process (shown in table 21) resultsin an increase in ultimate recovery from 2.9billion barrels under current technology to 10.0billion barrels at high-process performance atworld oil prices.

Table 20Comparison of Technological Assumptions

for the Surfactant/Polymer Process

Reservoir temperature . . . . . .Oil viscosity, cp. . . . . . . . . . .Salinity, ppm. . . . . . . . . . . . . .Oil content in surfactant slug,

vol. percent. ... , . . . . . . . .Size of surfactant slug, frac-

tion of volume swept bypreceding waterflood . . . .

Size of polymer bank, fractionof (region) volume sweptby preceding waterflood. .

CurrentTechnology

< 2 0 0oF

<20,000”—

20

10

1.0

Advancingtechnology

< 2 5 00F< 3 0<200,000*—

10

10

0.50

*Constraint which could not be applied due to absence ofsalinlty data,

Table 21Comparison of Ultimate Recovery Under Two

Technological Scenarios,Both Assuming High-Process Performance

Surfactant/Polymer Process

Ultimate recovery(billions of barrels)

Oil price Current Advancing$/barrel technology technology

Upper tier ($11.62/bbl) . . . . . 0.2 7.2World oil ($13.75/bbl) . . . . . 2.9 10.0Alternate fuels ($22.00/bbl) . 8.8 12.2

Ch. Ill—Oil Recovery Potential ● 4 9

Uncertainty in Projected Production RatesProduction rate projections are influenced by

the following factors:

1)

2)

A vigorous successful research and develop-ment and commercial exploitation programwas assumed in the advancing technologycases. Time was allotted in the economicmodel for technical and economic pilottesting, which is necessary for fieldwidedevelopment. Each stage of testing wasconsidered successful within a specifiedtime frame. Development of the field wasplanned on a time schedule correspondingto normal oilfield development.

partial success in initial field tests, lowdiscovery rates for natural C0 2, and aslower rate of technological advance in thesurfactant/polymer process are examples offactors which could delay or reduce the pro-duction rates projected in this study.

Production rates presented in tables 9through 14 come from reservoirs whichhave a minimum discounted cash flow rateof return of 10 percent. Full-scale applica-tion of a process in a reservoir was done in amanner which approximates the pattern ofindustry investment decisions. In general,high-risk projects are undertaken early in astage of technical development when therate of return is high. Projects with 10-per-cent rate of return are undertaken when therisk of technical and economic failure isrelatively low.

The timing plan used to construct pro-duction rates for the Nation is dependentupon the projected rate of return for eachreservoir. The economic model assumesthat the reduct ion of technical andeconomic risk will occur at a rate (table 8)which initiates development of low rate-of-return (1 O percent) reservoirs in 1989. Aresult of this approximation is that a largevolume of oil is produced after the year2000 at the world oil price. Earlier or laterreduction of risk could alter the annual pro-duction rates appreciably.

The price of oil affects production rates intwo ways. Higher oil prices encourage initia-

3)

tion of projects at earlier dates. Conse-quently, production from a reservoir whichcomes onstream in 1989 can be obtained atan earlier date and at a higher price if thetechnology is developed. A second effect ofoil price is to add reservoirs at a higher pricewhich cannot be developed economicallyat lower prices.

The rate-of-return criterion is a measure ofrisk in an advancing technology where therisks of technological and economic failuresare high. In these instances, a high rate ofreturn is required in order for the successfulprojects to carry those high-risk projectswhich fail.

Failures of a recovery process are not ex-plicitly accounted for in this study. Thus,the projections of ultimate recovery andproduction rates assume a successful ap-plication of the process to every reservoirwhich meets the technical screen and theminimum after-tax rate of return. Thus, theprojections have a built-in, but unknown,measure of optimism.

This optimism is offset to some extent bythe fact that (1) the cost of failure in techni-cal or economic pilot testing is com-paratively small, and (2) no attempt wasmade to optimize process performance.Failure of a process in a reservoir at thisstage would reduce the ultimate recoveryand the predicted production rate. Overalleconomics for the process would not be sig-nificantly affected, provided other projectswere economically successful.

If risk is reduced at a rate slower than thatprojected in table 8, only those projects andprocesses which have high rates of returnwill be pursued. For example, the majorityof the surfactant/polymer flooding candi-dates have rates of return after taxes of be-tween 10 and 15 percent at the world oilprice for the high-process performance case,The technology is not proven and a 20-per-cent rate of return could be required by in-vestors to offset the possibility of processfailure in a given reservoir. If a 20-percentrate of return is required, few surfac-tant/polymer projects would be initiated.

!36-594 O - 78 - 5


By contrast, steam displacement is arelat ively proven process. Cont inueddevelopment and use of steam would beexpected at rates of return of between 10and 20 percent. The impact of high techni-cal and economic risk on the ultimate recov-ery and production rates for all processes isillustrated by the comparison in table 22 forworld oil prices. Reductions of 61 percent inultimate production and 60 percent inaverage production rate for the time periodfrom 1980 to 2000 are projected underhigh-risk conditions.

4) The production rate for the Nation isaffected by environmental regulations andmarket conditions in California. Current en-vironmental regulations limit the total emis-sions from steam generators and air com-pressors to pollution levels which existed in1976. Under existing laws, the maximum in-cremental production rate from thermalmethods in California will be 110,000 bar-rels per day. The impact of this constrainton the production rate is shown in table 23for the advancing technology cases at worldoil prices, Production rates for the Nationare reduced up to 29 percent for the periodfrom 1980 to 1995 when constraints are ap-plied. Ultimate recovery is not affected asthe remaining oil will be produced after theyear 2000.

A second factor limiting the developmentof thermal methods in California is theavailability of refinery capacity to handleheavy oil. Heavy oil requires more process-ing to produce marketable products than dolighter oils such as Saudi Arabian light orPrudhoe Bay feedstocks. Ample supplies ofthese feedstocks on the west coast couldsuppress the development of heavy oil pro-duction even if environmental constraintswere removed.

Effect of Uncertainty in Residual OilSaturation and Volumetric Sweep on

Projected Results

Residual Oil Saturation

The residual oil saturation in a reservoir follow-ing primary and secondary production sets an up-

per limit to the total amount of oil that could beproduced using any EOR technique, no matterhow good its performance may be. Thus, uncer-tainty about the residual oil saturation will leadto comparable uncertainty in the projected pro-duction from an EOR project, independent of un-certainty about process performance.

Table 22High-Process Performance at World Oil Price

($13.75/bbl)

Ultimate recovery(billion barrels) . . . . . . . . .


1980 . . . . . . . . . . . . . . .1985 . . . . . . . . . . . . . . .1990 . . . . . . . . . . . . . . .1995 . . . . . . . . . . . . . . .2000 . . . . . . . . . . . . . . .

Cumulative production(million barrels)

1980 . . . . . . . . . . . . . . .1985 . . . . . . . . . . . . . . .1990 ... . . . . ., . . . .1995 . . . . . . . . . . . . . . .2000, . . . . . . . . . . . . . .

Standard(1 O-percent

rate ofreturn)

29.4

0.41.01.63.15.2

5002,0004,7008,700

17,300

High risk(20-percent

rate ofreturn)

9.5

0.40.50.71.01.4

5001,6002,7004,1006,800

Table 23Impact of Technological Advances in Emission

Control in California Thermal Recovery Projects onProjected Rates for the United States at World Oil

Price ($13.75/bbl)

+ + +

Low-process per- High-process per-

strained strained strained strained

Ultimate recovery:(billion barrels) . . . . .

Production rate:(million barrels/day)

1980 ....., . . . . . .1985, . . . . .,1990 . . . . . . . . . . . .1995 . . . . . . . . . . . .2000 . . . . . . . . . . . .

11.1 11.1 29.4

0.30.50.71.21.7

0.30.40.51.01.5

0.41.01.73.15.2

29,4

0.30.81.42.84.9

The variations in parameters used to comparethe high- and low-process performance cases forthe surfactant/polymer and C02 miscible proc-esses can also be used to simulate the effects ofuncer ta in t ie s in res idua l o i l sa tu rat ion .Specifically, the low-process performance caseapproximates a high-process performance casewhen the uncertainty in the residual oiI saturationvaries from 15 to 25 percent. As discussed in thesection on Uncertainty in the Oil Resource o npage 33, these figures represent the range of un-certainty which presently exists in the estimatesof the process parameters.

Volumetric Sweep

The fraction of the reservoir which can beswept by the surfactant/polymer and C02 misci-ble processes was assumed to be the regionwh ich was p rev ious l y contacted dur ingwaterflooding. 16 The volume of this region wasassumed to be known with less certainty thanresidual oil saturation.

Two methods have been used to estimate thefraction of the volume of a reservoir that hasbeen swept by earlier waterflooding. Onemethod assigns values to reservoirs based on ex-perience in the geographical region, The secondmethod, used in the OTA study, is based on amaterial balance involving the oil initially presentand the oil produced by primary and secondarymethods.

The effect of these methods of determiningsweep efficiencies was compared for the high-process performance case for a set of reservoirsconsisting of 59 surfactant/polymer candidates

lbother possible interpretations are discussed in appen-

dix B.

Ch. Ill—Oil Recovery Potential ● 5-1

and 211 onshore CO2 miscible candidates. Use ofestimated volumetric sweep efficiencies yielded1.1 billion additional barrels of oil at the world oilprice for the surfactant/polymer process. No sig-nificant difference was noted for onshore C02

results.

Maximum Oil Recovery byEOR Processes

Results of all cases show increased ultimate oilrecovery with increased oil price. Further com-putations for the high-process performance caserevealed that 95.6 percent of the oil consideredtechnically recoverable would be produced at oilprices of $30 per barrel or less. Based on theseestimates of technological advances, thevolumes of oil which may be recoverable byenhanced oil process will not exceed 49.2 billionbarrels for the United States (excluding Alaska).Thus, of the remaining 283 billion barrels of oil inthe United States, excluding Alaska, 234 billionbarrels are not recoverable under the technologi-cal advances assumed in the high-processperformance case, Lower-process performancewould reduce the ultimate recovery appreciably.Process improvements such as optimization ofwell spacing (i. e., infill drilling) and slug size werenot considered in the OTA projections of ulti-mate recovery for the Nation, The effects of theseimprovements are expected to influence the pro-jections less than the uncertainty in process per-formance. This assessment does not consider thepotential of new processes or process modifica-tions which might be developed at prices of $30per barrel. These possibilities are not likely tohave an impact on the Nation’s crude oil supplyduring the period between 1976 and 2000.

52 . Ch. IlI—Oil Recovery Potential

Comparison With Other Studies

Estimates of the potential oil recovery and/orproduction rates resulting from the application ofEOR processes have been published in sevendocument s . 17,18,19,20,21,22,23 Four of these 24,25,26,27 a r ebased on surveys and other subjective methodsand, as such, are considered preliminary esti-mates of the EOR potential for the Nation and notcomparable to the OTA study in methodology,depth of investigation, or policy analysis.

Three of the studies28,29,30 used a methodologysimilar to that used in the OTA study to estimate

1 7 ~~e ~stj~dtecj Recovery Potentia/ o f conventionalSource Domestic Crude Oi/, Mathematical, Inc., for the En-vironmental Protection Agency, May 1975.

IBpro~ect /ndepenc/ence Report , Federa l Ene rgy Ad-ministration, November 1974.

lgP/ann/ng criteria Relative to a National RD T& D Programto the Enhanced Recovery of Crude Oi/ and Natura/ Gas, GulfUniversities Research Consortium Report Number 130,November 1973.

zOPre//m/nary Fje/d Test Recommendations and ~fOSpeC-

tive Crude Oil Fields or Reservoirs for High Priority Testing,Gulf Universities Research Consortium Report Number 148,Feb. 28, 1976.

21 Tbe Potentia/ and Economics of Enhanced Oil Recovery,Lewin and Associates, Inc., for the Federal Energy Ad-ministration, April 1976.

zzResearch and Development in Enhanced Oil Recovery,

Lewin and Associates, Inc., Washington, D. C., November1976.

ZjEnhanced Oil Recovery, National Petroleum council,December 1976.

ZqThe Est imated Recovery Potentia/ of Convention/

Source Domestic Crude Oil, Mathematical, Inc., for the En-vironmental Protection Agency, May 1975.

25 Project, /dependence Report, Federal Energy Ad-ministration, November 1974.

26~/ann/ng criteria Relative to a Nat;ona/ RDT&D Programto the Enhanced Recovery of Crude Oil and Natural Gas, GulfUniversities Research Consortium Report Number 130,November 1973.

ZTPre//mjnary Fie/d Test Recommendations and Prospec-

tive Crude Oil Fields or Reservoirs for High Priority Testing,Gulf Universities Research Consortium Report Number 148,Feb. 28, 1976.

Z19 The poCentia/ and Economics of Enhanced Oil Recovery,Lewin and Associates, Inc., for the Federal Energy Ad-ministration, April 1976.

2qResearch and Development in Enhanced Oil Recovery,


jOEnhanced 0// Recovery, National petrO!eUWI COUnCil,

December 1976.

EOR potential. These studies are (1) the pro-jections of enhanced oil recovery for California,Texas, and Louisiana, prepared by Lewin andAssociates, Inc., for the Federal Energy Ad-ministration (FEA) (April 1976);31 (2) the researchand development program prepared by Lewinand Associates, Inc., for the Energy Research andDevelopment Administration (ERDA) (November1976); 32 and (3) an analysis of the potential forEOR from known fields in the United States pre-pared by the National Petroleum Council (NPC)for the Department of the Interior (December1976).33

The methodologies of these studies areanalogous in that the potential oil resource wasdetermined us ing a reservoir-by-reservoiranalysis. Each reservoir in the respective database was considered for a possible EOR project.One or more EOR process was assigned to thereservoir. Oil recovery and economic simulationswere made in a manner closely approximatingcommercial development in the oil industry. Ulti-mate production and production rates fromeconomically acceptable reservoirs were used toextrapolate to the State and national totals.

Data bases varied somewhat between studies.The Lewin FEA and NPC studies used a commondata base consisting of 245 reservoirs fromCalifornia, Texas, and Louisiana. This data basewas expanded to 352 reservoirs in 17 oil-produc-ing States by Lewin and Associates, Inc., for theirERDA study. The OTA study incorporated,revised, and expanded the Lewin ERDA data baseto 835 reservoirs containing 52 percent of theROIP in the United States, as described in thesection Original Oil in Place on page 23.

Cost data for development and operation oftypical oilfields were obtained from the U.S.

M The potentja/ and Economics of Enhanced Oi/ Recovery,

Lewin and Associates, Inc., for the Federal Energy Ad-ministration, April 1976.

jzResearch and Deve/oprnent in Enhanced Oi/ Recovery,


jjEnhanced 0// Recovery, National petrOleum CoUnc il,

December 1976.

Ch. III--Oil Recovery Potential . 53

Bureau of Mines34 for all studies. Adjustmentswere incorporated to account for price changesbetween the reference dates for each study.

Results of these studies are compared withOTA projected results in table 24 for 1976 uppertier and world oil prices. There is agreement Inthe order of magnitude of the ultimate recoveryamong all the studies. The NPC projections in-clude a base case which represents best esti-

JqResearch and Development in Enhanced Oil Recovery,Lewin a n d A s s o c i a t e s , I n c . , W a s h i n g t o n , D . C . , N o v e m b e r

1 9 7 6 .

mates of process performance and associatedprocess costs, and a range of uncertainty in thebase case estimates due to poorer or better thanexpected process performance. Estimates fromthe OTA low-process performance case are with-in the NPC range of uncertainty for all oil prices.The OTA high-process performance case esti-mates more oil recovery than the upper estimatesof the NPC study. At the world oil price, the OTAestimate is about 24 percent higher. The LewinERDA cases for upper tier price and $13 per barrelare close to the range of OTA values. The OTAprojections are lower than the Lewin FEA resultsfor California, Texas, and Louisiana, even if oil

Table 24Projections of Ultimate Recovery and Production Rate From the

Application of Enhanced Oil Recovery Processes

Study

O T ALow-process performance. . . . . . . . . . . . . .

High-process performance . . . . . . . . . . . . .

NPC’Poor performance . . . . . . . . . . . . . . . . . . . .Expected performance (base case) . . . . . . .Better performance . . . . . . . . . . . . . . . . . . .

Poor performance . . . . . . . . . . . . . . . . . . . .

Expected performance (base case) . . . . . . .

Better performance . . . . . . . . . . . . . . . . . . .

E R D Ab

Industry base case**. . . . . . . . . . . . . . . . . . .

Industry base case w/ERDA R&D** . . . . . . .

FEACalifornia, Texas, and Louisiana . . . . . . . . .

Lower Bound, . . . . . . . . . . . . . . . . . . . . . .Upper Bound. . . . . . . . . . . . . . . . . . . . . . .

Referencedate

1976

1976

1976

1975

Minimumrate of

return forprojection

10 %

10 %

00/0

20%80/0

Oilprice

($/bbl)

11.6213.75

11.6213.75

10.00

15,00

11.6313.00

11.6313.00

11.2811.28

Potentialultimaterecovery(billionbarrels)

8.011.1

21.229.4

3.17.2

13.4

6.313.226.9

11.913.1

26.230.1

15.6***30.5.

Potentialproduction

rate in 1985(million

barrels/day)

0.40.5

0.51.0

0.4

0.40.91.6

0.60.6

1.72.1

1.02.0

‘“current tax case, 10-percent investment credit and expensing of injection materials and intangibles, with current environmental con-straints,

“**Reserves added by the year 2000.‘Enhanced Oil Recovery, National Petroleum Council, Decemberl 976.h~e~earch and Deve/oPmenl in ~nhanced Oi/ Recovery, Lewin and Associates, Inc., for the Energy Research and Development Administration

I

November 1976.‘ The Potential andEconomtcs of ErrbarrcedOllRecovery, Lewinand Associates, Inc., for the Federal Energy Administration, April 1976.


price, rate of return, and costs were placed on thesame basis.

Estimates of producing rates in 1985 varywidely between studies. In general, the OTAprojections are within the range of the NPC base-case study results and the Lewin industry base-case simulation. The OTA results are lower thanthe Lewin ERDA research and development caseand the Lewin FEA projection for California,Texas, and Louisiana. The apparent agreement inproducing rates between the OTA high-perform-ance case and the Lewin ERDA case does notconstitute confirmation of projections from inde-pendent studies for reasons outlined in a latersection.

OTA-NPC Results

The OTA study team was provided access toall reports, oil recovery models, cost data, andresults from the NPC study. Comparisons of pro-jected ultimate recovery and production rateswere made on a reservoir-by-reservoir basis. Thesame reservoirs which were included in the NPCbase case for C02, surfactant/polymer, steam,and in situ combustion processes were studied indetail using NPC models and OTA models. Alldifferences between OTA and NPC results can betraced to differences in recovery models, suppliesof injected materials, costs of injected materials,and, in some cases, the timing plan used in thesimulation to initiate projects.

The NPC study included a geological screen inwhich individual reservoirs were judged as good,fair, poor, or no EOR, based on qualitative infor-mation on the geology of each reservoir gatheredfrom industry sources. The OTA study assumedall reservoirs had the same quality since geologi-cal information was available on only a small por-tion of the reservoirs in the data base. No reser-voir was rejected for geological reasons, with theexception of those with a large gas cap whichmight prevent waterflooding.

The distribution of oil in a reservoir wastreated differently in the OTA models. The OTAmodels assume 95 percent of the remaining oil islocated in 80 percent of the reservoir acreage. Alloil produced by. EOR processes is developed

from the reduced portion of the acreage. Thisassumption was implemented by increasing thenet thickness in the region developed. The use ofeconomic models to determine the EOR processwhen two or more processes were possible led todifferent assignments of many reservoirs in theOTA study.

Major differences between the NPC and OTAresults are:

a. Recovery from application of C02 displace-ment in the OTA high-process performancecase exceeds NPC estimates by a factor ofabout two at all oil prices for which calcula-tions were made. Comparable recoverymodels were used and the agreement inultimate recovery for reservoirs common toboth studies is reasonably close, In Texas,the OTA recovery at world oil price by C02

flooding is about 5.6 billion barrels. The cor-responding NPC recovery is a little over 4.0billion barrels.

The NPC geological screen eliminatedcertain reservoirs in Texas from their studywhich OTA’s study calculated would pro-duce about 0.5 billion barrels of oil with theC02 process. When extrapolation was madeto the entire State, this amounted to about0.9 billion barrels. Considering the Texasresults, as well as the entire Nation, the NPCgeological screen accounts for part of thedifference but is not considered the majorfactor,

Expansion of the data base to other oil-producing States and offshore Louisianaresulted in more reservoirs as potential can-didates for C02. A result was that considera-bly more oil was produced from States otherthan Texas, California, and Louisiana in theOTA study than was projected in the NPCreport. In addition, in the OTA study at theworld oil price, an ultimate recovery of 0.9billion barrels was projected to be producedfrom offshore reservoirs that were not in theNPC data base (table 13).

Oil recovery for the NPC C0 2 m o d e l svaried according to geologic classificationsof good, fair, and poor. The OTA recoverymodels were designed to represent an

“average” reservoi r . The use of th is“average” reservoir in the OTA study mayaccount for a significant portion of thedifference in results for the three States ofCalifornia, Texas, and Louisiana.

Significantly different pricing plans for theC O2 resource were used by OTA and NPC,Prices used were similar in geographicalareas such as western Texas, which have ahigh probability of obtaining supplies ofnatural C02 by pipeline. However, for otherareas such as Oklahoma and Kansas there isless certainty of carbon dioxide pipelinesand the pricing plans were quite different. Ingeneral, the NPC study used a significantlyhigher cost for C 02 in these areas. This isconsidered to be a major reason for thedifference in results for the Nation. TheOTA C 0 2 pricing model is given in a p p e n -

dix B.

b. Oil recovery from OTA surfactant/polymerprojections for the low-process perform-ance case at $13.75 Per barrel (2.3 billionbarrels) is bounded by the NPC base case(2.1 billion barrels) and the NPC 5-year proj-ect life case (5.6 billion barrels) at $15 perbarrel. (The NPC base case used a 10-yearlife while OTA models assumed a 7-yearlife.) The OTA high-process performancecase at world oil price (10.0 billion barrels)p r o j e c t s a b o u t 1 . 0 b i l l i o n b a r r e l s I e s s o i l

recovery than the NPC better-than-ex-pected performance projections (1 1.2billion barrels) at $15 per barrel.

Two factors are the primary contributorsto the slight differences in results of the twostudies. First, more than twice as many OTAreservoirs were assigned to the surfac-tant/polymer process as in the NPC study.Forty-five percent of these reservoirs werenot in the Lewin FEA data base used by NPC.

A second difference in the results wasdue to NPC’s assignment of higher chemicalcosts to reservoirs which were ranked poorin the geologic screen. The OTA studyassumed all reservoirs were of the samequality. Comparable projections of ultimate

c.


recovery at a specified oil price were ob-tained on individual reservoirs which hadthe same geological ranking and sweptvolume in both studies. Sensitivity analysesshow agreement of the low-processperformance projections and projectionsmade by increasing chemical costs so thatall reservoirs were “poor.”

Some differences were attributed to theapproaches used to estimate the volume ofeach reservoir swept by the surfactantflood. A discussion of this is included in thesection on Volumetric Sweep on page 51.No offshore reservoirs were found to beeconomically feasible for application of thesurfactant/polymer process in the OTAstudy. The NPC results included an estimateof 261 million barrels from offshore Loui-siana reservoirs at $15 per barrel,

The OTA estimates of oil recoverable bythermal methods are within the range of un-certainty projected in the NPC study. TheOTA low-process performance estimatesare within 0.4 billion barrels (12 percent) ofNPC base-case projections at prices be-tween $10 per barrel and $15 per barrel.Projections for the OTA high-process per-formance case at these prices are about 1.0billion barrels less than performance fromthe NPC high-recovery estimates. Com-parisons by process are included in appen-dix B.

Oil recovery models for thermal proc-esses in the NPC study were developed forareas with uniform reservoir properties.Projected recoveries from reservoir-wideapplication of these models were adjustedto account for variation of reservoir proper-ties and process performance. This wasdone by reducing the ultimate recovery foruniform reservoir and process performanceby factors of 0.7, 0.6, and 0.5, correspond-ing to the NPC geological screen of good,fair, or poor. Large reservoirs were sub-divided into two or three areas judged tohave different quality. Multiple-zone reser-voi rs were developed s imultaneously.Crude oil consumed as fuel was deducted

56 ●

d .

e.

Ch. 111—011 Recovery Potential

from gross production prior to computationof royalty and severance taxes.

The OTA thermal recovery models weredeveloped to represent the average reser-voir performance. Reservoirs were notassigned geological rankings based on reser-voir quality. Multiple-zone reservoirs weredeveloped zone by zone. Royalty andseverance taxes were paid on lease crudeconsumed as fuel. This is a significant cost,as about one-third of the production insteam displacement projects is consumed asfuel.

polymer flooding models in both studiesproduce comparable results when polymerinjection is initiated at the beginning of awaterflood. Some differences exist forwaterfloods which have been underway forsome period of time. The NPC recoverymodel projects a decline in oil recoverywith age of waterflood, while the OTAstudy does not. Polymer flooding does notcontribute much oil in either study.

The NPC study projected recovery froma l k a l i n e f l o o d i n g . T h e O T A s t u d yacknowledges the potential of alkalineflooding for selected reservoirs but did notinclude the process for detailed study.Reservoirs which were alkaline-flood candi-dates in the NPC study became candidatesfor other processes in the OTA study.

OTA-FEA, ERDA Results

The OTA study used the economic programsand timing plans for reservoir developmentwhich were used to produce the results for theLewin and Associates, Inc., studies for FEA andERDA. Oil prices and a minimum acceptable rateof return (1 O percent) were selected for the OTAstudy. Costs of injected materials were obtainedfrom both Lewin and NPC studies. Oil recoverymodels for the OTA study were developed inde-pendently of previous Lewin studies. The FEAstudy reported projections for three States;California, Texas, and Louisiana. The ERDA resultsinclude data from 17 oil-producing States whilethe OTA results use data from 18 oil-producing

States. Projections for the Nation in the OTA andERDA studies were obtained by summing Statetotals.

The OTA advancing technology cases assumea vigorous research and development program,although the stimulus for the program was notidentified. Lewin and Associates, Inc., ERDAprogram assumes all improvements in recoveryover an industry base case comes from an exten-sive ERDA R&D program which removes environ-mental and market constraints for thermal opera-tions in California, results in improved recoveryefficiencies for processes, and extends the proc-esses to reservoirs not considered candidates inthe industry base case. Targeted R&D projectswere identified for specific reservoirs.

The documentation of anticipated improve-ment in the various processes is described in thereport. 35Incremental process costs and processperformance associated with proposed processimprovements were not identified. Conse-quently, there is no basis for a direct comparisonwith the Lewin ERDA projections resulting froman extensive R&D program. The agreement be-tween OTA projections and the Lewin ERDAprojections should not be considered confirma-t i o n o f e i t h e r s t u d y b y i n d e p e n d e n tmethodology.

Although the ultimate recoveries and ratesfrom the Lewin studies are close to the OTAresults, there are significant differences in theassumptions which were used to develop theresults. Distributions of oil recovery by processare also different. Principal differences betweenthe OTA and Lewin studies involve the projectedrecovery for each process.

The Oil recovery models used by Lewin andAssociates, Inc., for the FEA and ERDA studieswere reviewed on a reservoir-by-reservoir basis.Comparisons between OTA recovery models andLewin models produced the following observa-tions:

a. Recoveries from the C02 flooding processare comparable in specific reservoirs. The

jSResearch and Development in Enhanced Oil Recovery,


OTA high-process performance case, at theworld oil price, projects about a 40 percentgreater ultimate recovery from CO2 than thetotal for the Lewin ERDA research anddevelopment case plus the industry basecase. A primary reason is the presence of ad-ditional reservoirs in the extended data baseof the OTA study. The OTA low-processperformance result is about half the LewinERDA value at world oil price. Costs ofmanufactured COZ in some areas are higherthan in the Lewin study and this contributesin a minor way to the differences.

There are large differences between pro-jections of ultimate recovery from the steamdisplacement process. The ERDA industrybase case estimates ultimate recovery to be66 billion barrels at $13 per barrel. lncre-mentaI oil expected from proposed ERDAR&D,, , programs 8.2 billion barrels at thesame price. Thus, an ultimate recovery of14.8 billion barrels is projected from steamdisplacement as a result of ongoing industryactivity and proposed ERDA R&D programs.

The OTA study projects an ultimaterecovery of 3.3 billion barrels from steamdisplacement processes at $13,7’5 per bar-rel. This projection is lower than the ERDAindustry base case by a factor of 2, and islower than the ERDA industry base casewith ERDA R&D by a factor of 4.5. The OTAand ERDA projections of ultimate recoveryfrom steam displacement vary over a largerange because of differences in specifictechnological advances which were incor-porated in the displacement models. Majordifferences are discussed in the followingparagraphs.

About one-third of the oil produced in asteam displacement process is consumed togenerate steam. The amount of steam pro-duced by burning a barrel of lease crude isnot known with certainty. The OTA com-putations assumed 12 barrels of steam wereproduced per barrel of oil consumed, whilethe ERDA models assume 16 barrels ofsteam per barrel of oil. Applying the ERDAfactor to OTA computations would increasethe ultimate recovery about 10 to 15 per-

Ch. ///—Oil Recovery Potential ● 57

cent. Differences of this order of magnitudeare not considered significant.

Replacement of crude oil by a cheapersource of energy such as coal is a proposedERDA steam program. Incremental produc-tion of 1.0 billion barrels was expected fromthis program. A successful program could in-crease the net crude oil produced by a fac-tor of one-third in fields where it could beimpIemented. However , w idespreadsubstitution of coal for lease crude wouldhave to be done in a manner which wouldsatisfy environmental constraints. 36 T h eO T A s t u d y d o e s not eva luate th i spossibility.

One ERDA program for steam projects anultimate recovery of 1.8 billion barrels fromlight-oil reservoirs (less than 25oAPI) inTexas, Louisiana, and the midcontinent by asteam distillation process. This process wasnot considered in the OTA study. imple-mentation of steam disti l lation on aneconomic scale requires development of afuel for steam generation which is less ex-pensive than lease crude oil. These reser-voirs were assigned to other processes inthe OTA study.

The principal difference between ERDAand OTA projections is in the recoverymodels for the steam displacement process.The ERDA steam model was developedusing data from current field operationswhich are generally conducted in the bestzones of a reservoir. Every part of the reser-voir is considered to perform like theregions now under development. Steamdrive was limited to depths of 2,500 feet inthe ERDA industry base case. Increase in thedepth to 5,000 feet added 1.6 billion barrelsin the ERDA R&D case. The ERDA R&Dprogram includes anticipated improvementsin recovery efficiency for reservoirs whichare less than 2,500 feet deep. The eventual

MERDA Workshops on Thermal Recovery of Crude Oil,

University of Southern California, Mar. 29-30, 1977.~71bid.


R&D goal for these reservoirs was to im-prove the overall recovery efficiency ofsteam drive by 50 percent. Incremental ulti-mate recovery for this program was ex-pected to be 2.3 billion barrels.

The OTA steam displacement models arebased on development of the entire reser-voir using average oil saturations and recov-ery efficiencies. All reservoirs 5,000 feet indepth or less were developed. The OTAmodels underestimate recoveries from thebetter sections of a reservoir and overstaterecoveries from poorer zones. OveralIrecovery from the OTA models is believedto be representative of the average reservoirperformance.

Closer agreement between the ERDA in-dustry base case and the OTA projections atthe world oil price can be obtained byreducing the ratio of injection wells to pro-duction wells, thereby reducing the capitalinvestment. The ERDA industry base caseassumes fieldwide development on thebasis of 0.8 injection well per productionwell. The OTA advancing technology casesused 1.0 injection well per production well.Reduction of the number of injection wellsto 0.3 per production well in the OTA com-putat ions makes steam displacementeconomic in several large California reser-voirs at the world oil price. Ultimate recov-ery at this price increases from 3,3 billionbarrels (one injection well/production well)to 5 .3 b i l l ion bar re l s (0 .3 in ject ionweIl/production well). Producing rates in-crease correspondingly. This comparison in-dicates potential improvements could resultfrom optimizing well spacing. Additionalresults are included in appendix B.

In summary, steam displacement pro-jections in the ERDA industry base case andERDA R&D case assume more technologicaladvances than judged to be attainable in theOTA study.

c. OTA surfactant/polymer projections forboth low- and high-process performancecases fall between the projections from

Lewin’s ERDA industry base case andLewin’s FEA results for California, Texas, andLouisiana, for different reasons. Projectedsurfactant recoveries in the Lewin FEA studyranged between 3.8 billion barrels and 8.8billion barrels at $11 per barrel. These pro-jections are larger than OTA projectionsunder the same economic conditionsbecause the recovery models are based ondifferent representations of the displace-ment process.

The industry base case for ERDA limits ap-plication of the surfactant/polymer processto shallow homogeneous reservoirs in themidcontinent. Ultimate recovery was esti-mated to be 0.6 billion barrels at $13 perbarrel. This corresponds to the OTA pro-jected recovery of 2.3 billion barrels at theworld oil price for the low-process per-formance case and 10 billion barrels for thehigh-process performance case. The ERDAR&D program for the surfactant/polymerprocess projects an ultimate recovery of 1.4billion barrels at the world oil price.

California reservoirs, which are major sur-factant/polymer contributors in the OTAstudy, were excluded from the ERDA indus-try base case by assuming that technologywould not be developed in the absence oft h e E R D A R & D p r o g r a m . T h e O T Amethodology resulted in assignment ofmore reservoirs to the surfactant/polymerprocess than in the ERDA cases. A majordifference exists in volumes and costs ofchemicals used in the ERDA calculations.These volumes approximate those whichhave been tested extensively in shallowreservoirs in Illinois. The OTA advancingtechnology cases project technological ad-vances which would reduce the volumes ofchemicals required. This has a profoundeffect on the development of the surfac-tant/polymer process, as the projectedrecovery for the high-process performancecase at the world oil price is reduced from10 billion barrels to 2.9 billion barrels whenOTA current technology surfactant andpolymer slugs are used in the economicmodel.

d


Ultimate recovery from polymer flooding polymer model projects less recovery thanvaries from 0.2 billion to 0.4 billion barrels the Lewin mod-cl ‘for specific reservoirs.at the upper tier price in the OTA pro- There were more reservoirs assigned to thejections compared to 0.1 billion barrels in polymer process in the OTA methodology.the ERDA industry base case. The OTA

Technological Constraints to EOR

Technological constraints are only one ofseveral barriers to widespread commercializationof EOR38 that include economic risks, capitalavailability, and institutional constraints. Theseconstraints are coupled, and all must be removedor reduced to achieve major oil production fromEOR processes.

The following section identifies and discussesthe technological constraints that must be ad-dressed in order to achieve the rate of progressthat is postulated in the advancing technologycase.

The technological constraints on EOR havebeen grouped in the following categories:

1. Resource availability.2. Process performance,3. Reservoir characteristics.4. Materials availability.5. Human resources.6. Environmental impact.7. Rate of technological evolution.

Resource Availability

The magnitude of the oil resource for EOR isnot certain. The uncertainty is estimated to be 15to 25 percent. Although this range may not seemlarge for the national resource, variation amongreservoirs probably is larger. Furthermore, a smallreduction in remaining oil in a reservoir maymake it uneconomical to apply a high-cost EORprocess at all, thereby leading to a disproportion-ate reduction in economically recoverable oil,The difference may be as high as the differencebetween the advancing technology-high- and

38&janagement plan for Enhanced Oil Recovery, ERDA,Petroleum and Natural Gas Plan, ERDA 77-15/1, p. 11-1,February 1977.

low-process performanceto 18 bill ion barrels at

cases, which amountsthe world oil price,

equivalent to about half the current U.S. provedreserves.

Resource uncertainty represents a major tech-nical and economic risk for any EOR project inany reservoir. Reduction of this risk would needhigh priority in any national program to stimulateEOR production.

Sampling a reservoir through core drilling, log-ging, and other well testing is an expensive, inex-act, developing technology. The problem is thatof finding methods which will probe outward asufficient distance from a well bore to determineoil content in a large fraction of the regiondrained by the well. A further complication existsin that oil saturation variations occur bothhorizontally and vertically within a reservoir.Determinations at one well may not be applica-ble at other well sites.

A program to stimulate EOR production shouldcontain a major effort to promote measurementof residual oil saturations in key reservoirs untilconfidence is gained in methods to extrapolatesuch data to other locations in the same reser-voir and other reservoirs. Equal emphasis shouldbe placed on the gathering of such data and onthe improvement of measurement methods.

Process Performance

Process Mechanisms

Enhanced oil recovery processes are in variousstages of technological development. Eventhough steam drive is in limited commercialdevelopment, the outer limits of its applicabilityare not well understood. Steam drive can proba-bly be extended to light oil reservoirs but it has

60 . Ch. ///—Oil Recovery P o t e n t i a l

not been tested extensively. Larger gaps inknowledge exist for other processes and processmodifications which are in earlier stages ofdevelopment. Field tests have consistently beenundertaken with incomplete knowledge of theprocess mechanism. Most laboratory tests ofprocesses are done on systems of simple geome-try (generally linear or one-dimensional flow),leaving the problems that occur because of themore complex flow geometry to field testing.

As indicated in the section on Process FieldTests on page 61, extensive field testing of EORprocesses will be required. As more field projectsare undertaken, the tendency of industry is toshift research personnel from basic and theoreti-cal studies to development activities. If this effortis widespread it may limit the ability of com-panies to undertake fundamental EOR research. Ifthis trend continues, additional public supportfor basic research applicable to EOR may becomeadvisable.

A major industry /Government coordinatedeffort is needed to thoroughly define the processmechanisms for each of the recognized basic EORprocesses and process modifications, This effortwould need to be initiated immediately and toproceed at a high level of activity for at least 5years if the postulated rate of EOR applications isto be achieved.

Volumetric Sweep Efficiency

Recovery efficiency of all processes dependsupon the fraction of the reservoir volume whichcan be swept by the process, i.e., sweep efficien-cy. Thus a strong economic incentive exists forimprovement of volumetric sweep. Research inthis area has been carried out for a number ofyears by many sectors of the oil production, oilservice, and chemical industries. The importanceto EOR success of improving sweep efficiencyhas been confirmed in a recent assessment ofresearch needs.40

MERDA workshops on Thermal Recovery of Crude oil,University of Southern California, Mar. 29-30, 1977.

JO~eC~~jCa/ plan for a Supplementary Research ProgramTo Suppor t Deve lopment and field Demons t ra t ion o fEnhanced Oil Recovery, for U.S. Energy Research & Develop-ment Administration, Washington, D. C., GURC Report No.154, Mar. 17, 1977.

Despite the long-term effort on this problem,success has been limited. Solutions are notavailable for each process. Improvements areneeded for each individual process and eachprocess variation as well as for major classes ofreservoirs. Progress will be difficult and will re-quire major field testing supported by extensiveprior laboratory work. This research effort, bothbasic and applied, must be significantly stimu-lated in the next 3 to 6 years in order to approachthe estimated EOR production potential for theperiod between 1976 and the year 2000.

Brine-Compatible Injection Fluids

Enhanced oil recovery processes will be usedlargely in those parts of the country that face in-creasing shortages of fresh water. For surfac-tant/polymer and polymer flooding, relativelyfresh water is still needed both for the polymerand surfactant solut ions and for reservoi rpreflushing. Even where fresh water is availablefor preflushing, it is often not efficient in displac-ing brine. Consequently, injected fluids in suchreservoirs must be brine compatible. Continuedlaboratory and field research is needed todevelop surfactants and other oil-recovery agentswhich are brine compatible.

In the present study, brine compatibility of in-jected fluids was assumed in the advancing tech-nology cases. Data were not available in the OTAdata base to assess the importance of thisassumption, but it is known to be significant.

Development of Additional ProcessesApplicable to Carbonate Reservoirs

Although carbonate reservoirs represent ap-proximately 28 percent of the initial oil in placein the United States,41 the C02 miscible process isthe only EOR process currently applied to suchreservoirs, There is a possibility of using steamflooding in some carbonate reservoirs,42 a n dother processes or process modifications should

41 Reserves of Crurje Oi/, Natural Gas Liquids, and Natural

Gas in the United States and Canada as of D e c e m b e r 31,7975, Joint publication by the American Gas Association,American Petroleum Institute, and Canadian PetroleumAssociation, Vol. 30, May 1976.

JZEnhanced Oi/ Recovery, National Petroleum COUncil,

December 1976.

Ch. III-Oil Recovery Potential ● 6 7

be tested for carbonate reservoirs because of thepossibility of C02 shortages and because of thehigh cost of delivering CO2 to areas that mightnot be served by pipelines.

Operating Problems

Operating problems of EOR are more severe,less predictable, and certainly less easily con-trolled than operating problems one faces in aplant making a new chemical product, but the in-dustr ial sector i s equipped to solve suchproblems. For example, steam is now generatedfrom high-salinity brines, a process that onceseemed to pose serious technical problems. Mostsuch problems, however, must be solved withinthe next 6 to 8 years if the potential productionrepresented by OTA’s advancing technologycase is to be achieved.

Some problems exist where Governmentassistance could be beneficial. Design of steamgenerators for steam-drive projects that will meetenvironmental pollution-control standards anduse cheaper alternate fuels (heavy crudes, coal,etc.), as well as large-scale steam generation, areareas that have been recently highlighted.43

Equipment for retrofitting existing generators topermit them to meet new standards and lowertheir unit pollution level is also needed.

Process Field Tests

The current ERDA field testing program is avital step in accelerating EOR process commer-cialization, If the upper targets of any of the re-cent predictions of EOR potential are to beachieved, a significant increase is needed in therate of technical progress. To achieve this, thelevel of field tests needs to be significantly in-creased. While OTA did not attempt to estimatethe optimal number, a study by the Gulf Univer-sities Research Consortium (GURC) estimated100 as a target group.44 It is important that ERDA-sponsored field tests be part of an EOR researchstrategy designed to complement industry’s

AJERDA Workshops on Thermal Recovery of Crude Oil,

University of Southern California, Mar. 29-30, 1977.44A Survey of ~je/cf Tests of [nhanced Recovery Methods

for Crude Oil, for FEA and the National Science Foundation,Washington, D. C., GURC Report No. 140-S, Nov. 11, 1974.

efforts and to provide information that can begeneralized to a variety of classes of reservoirs,The status of current field tests taken from theLewin ERDA report45 is shown in table 25.

There are at least three levels of field tests:minitests, single- or multi pattern-pilot tests, andfieldwide commercial testing.

Single- and multipattern-pilot tests should bedirected at determining potential economic suc-cess and to thoroughly defining the technical per-formance. To maximize the value of such fieldtests, extensive pre- and post-test well coring,logging, fluid analysis, and laboratory tests are re-quired to understand the process well enough toprovide a strong knowledge base for operating atfull scale in test reservoirs. Data acquisition is ex-pensive and time consuming, and the record indi-cates that too little data are being gathered.Government support for such activities may berequired if the postulated rate of technologicaladvance is to be achieved.

Special consideration should be given to test-ing more than one process in a reservoir and toundertaking processes in reservoirs that offer newranges of application of the process.

There is some current concern about the rela-tive merits of minitests (one to two well tests atsmall well spacing) compared with larger single-or multipattern-pilot tests. Both can be helpful.The minitest is faster, less expensive, and may behelpful in initial process or reservoir screening.However, its lower cost and greater simplicity donot substitute for the greater degree of under-standing that can come from multi pattern tests.

The number of projects that should be under-taken for fieldwide commercial demonstration isnot easily determined. A case can be made for atleast one such test for every major process thathas not yet reached commercialization. The op-tions of cost sharing, risk sharing, and/or supportthrough special price or tax provisions should allbe considered. Considerations of the merits ofsuch alternatives, the scale of operations, and theapplicable processes were outside the scope of

ASReSearCh and Development in Enhanced Oi/ Recovery,

Lewin & Associates, Inc., Washington, D.C. Part 1, p. III-2,November 1976.

—.


Table 25Field Activity in Enhanced Oii Recovery

Technique

Steam drive. ., . . . . . . . .In situ combustion . . . . .C O2 miscible and

nonmiscible. . . . . . . . .Surfactant/polymer. . . . .polymer-augmented

waterflooding . . . . . . .Caustic-augmented

waterfloodlng . . . . . . .Hydrocarbon miscible . .

Totals. . . . . . . . . . . .

Technical

1Total

1717

512

3

59

68

lots

Current

133

410

0

17

44

Number of EOR Proiects

Economicpil

Total

156

67

14

26

57

ots

Current

145

67

9

05

47

Fieldwldedevel

Total

1519

22

14

010

62

]ment

Current

1510

22

11

08

48

Acreage undercurrent

development

15,6824,548

38,6181,418

14,624

6356,782

131,735

“From Research and Development in Enhanced Oil Recovery, Final Report, Lewin & Associates, Inc., Washington, D. C., ERDA 77-20/1,2,3,December 1976.

this study. However, the issue needs to be ad-dressed within the next year or two. This testprogram is a facet of the Government programthat deserves a major emphasis.

Reservoir Characteristics

Uncertainty concerning the physical andchemical nature of an oil reservoir is one of themost severe technological barriers to EOR proc-esses . 46 Not only are reservoirs significantlydifferent among themselves, even within thesame geological class, but the place-to-placevariations in thickness, porosity, permeability,fluid saturation, and chemical nature can be dis-couragingly large. The present ability to describe,measure, and predict such variability is extremelylimited. Knowledge to measure and predict thisvariability within a reservoir is vitally importantfor forecasting fluid movement and oil recoveryefficiency. Research efforts have so far beendirected toward studying portions of individualreservoirs intensively, with little attention givento generic solutions.

46 Technjca/ p/an for a Supplementary Research prOgram

To Support Development and Field Demonstrat ion ofEnhanced Oil Recovery, for U.S. Energy Research andDevelopment Administration, Washington, D. C., GURCReport No. 154, Mar. 17, 1977.

Any major governmental research effort to ac-celerate oil production from EOR processesshould include development of methods tomeasure, describe, and predict variations in prop-erties throughout a reservoir. Extensive field andlaboratory studies are warranted.

Raw Materials Availability

Enhanced oil recovery processes use bothnatural and manufactured raw materials.. Short-term shortages of manufactured materials couldexist for all EOR processes if a vigorous nationalprogram were launched to produce EOR oil.

The supply of two natural resources, freshwater and C02, may limit ultimate recovery fromsteam injection, surfactant/polymer, and C02

miscible processes. Local shortages may developfor adequate supplies of fresh or nearly freshwater in some areas in which polymer flooding orsurfactant/polymer flooding is initiated. Mostareas of known fresh water shortage either haveor are developing criteria for allocation of thescarce supply among competing classes of use. Amajor technological challenge for EOR lies indevelopment of economic means for using waterwith higher saline content for all processes inwhich water is needed. The problem seems tohave been solved for steam generation. Brine ofup to 20,000 ppm can be used successfully.

Carbon dioxide availability is central to anymajor expansion of C02 flooding. As mentionedpreviously, the quantity needed (a total of 53 Tcfin the advancing technology-high-process per-formance case at world oil prices) is a volumealmost three times the annual volume of naturalgas consumed in the United States.

The economic potential of C02 flooding is sogreat that a Government effort to accelerate EORproduction should include not only locatingnatural sources of carbon dioxide but also explor-ing ways to produce it economically from large-scale commercial sources. Locations of known,naturally occurring C O2 sources are summarizedin the recent NPC study of EOR.47 The magnitudeof the reserves of CO2 at these locations is notknown. ERDA is currently involved in a nation-wide survey of CO2 availability.

Human Resources

Shortages of technically trained people tooperate EOR projects may exist temporarily if amajor national EOR effort is undertaken. Nationalprojections of needs for technically trained peo-ple have not been highly accurate. Data are notreadily available on industrial needs since manyfirms do not make formal, continuing, long-rangepersonnel forecasts. The efforts of ERDA andother agencies in national manpower forecastingcould be encouraged.

All EOR processes are extremely complex com-pared to conventional oil recovery operations.Because of this technical complexity, highly com-petent personnel must be directly involved ineach EOR project on a continuous basis at themanagerial, developmental, and field operationslevel. Without close monitoring by qualifiedtechnologists, the odds for success of EOR proj-ects will be lower, There currently is a mild short-term shortage of persons to work on EOR proj-ects. National forecasts48 of the number of availa-ble college-age students (all disciplines) indicate

qTf~~a~Cecj 0;1 Recovery, N a t i o n a l p e t r o l e u m Council,

D e c e m b e r 1 9 7 6 .qa~rojectfon of [durational Sta[lstics to 7985-86, National

Center for Educational Statistics, Publ. NCES 77/402, p. 32,1977.

Ch. ///—Oil Recovery Potential ● 63

a significant enrollment decline over the periodof greatest potential EOR activity. The supply oftechnical people (engineering, science, and busi-ness) available for EOR operations will cruciallydepend upon the economic climate in other sec-tors of the economy. In a generally favorableeconomic climate, increasing competition forqualified personnel could develop.

Environmental Effects

For most EOR p r o c e s s e s a n d i n m o s tgeographical areas, accommodation to environ-mental protection regulations will not be a criti-cally restrictive requirement. Details of environ-mental impacts and an estimate of their severityand magnitude are described in chapter VI of this

r e p o r t . T h e e n v i r o n m e n t a l e f f e c t s t h a t p o s e m a j o r

t e c h n o l o g i c a l p r o b l e m s i n c l u d e the need fo remission controls in California thermal EOR proj-ects, the possibility of fresh water shortages, andthe need to protect ground water.

The need to develop an economically accepta-ble means of meeting the air pollution require-ments for thermal processes has become criticalin California. Further expansion of the thermalprocess in California awaits this development.

The requirements placed on EOR processes bythe Safe Drinking Water Act (P.L. 93-593) arecritical for their long-term development. Accom-modation to the Safe Drinking Water Act is notso much a technological problem as it is a humanand administrative matter. The need is one ofestablishing acceptable guidelines that will pro-tect fresh water sources and still allow EOR proc-esses to proceed. The record of compatibility ofthese two goals through the long period of sec-ondary recovery in the United States suggeststhat this can be accomplished. This is discussedfurther in chapter VI.

The Rate of Technological Evolution

All estimates of potential recovery from ap-plication of EOR processes are based on a postu-lated rate of technological evolution. There isconsensus among personnel in industry, Govern-ment, and academic institutions who are

64 ● Ch. Ill—Oil Recovery Potential

knowledgeable in enhanced oil recovery proc-esses that much research and field testing isnecessary to bring EOR technology to the pointwhere commercialization is possible for all proc-esses except steam displacement.

The suggested components of research anddevelopment programs to stimulate EOR produc-tion have received significant appraisal andmodification within the last 4 years. Between1973 and March 1977, the Gulf UniversitiesResearch Consortium (GURC) issued a series offive reports 49,50,51,52,53 detailing the need for fieldtests, their number and character, and the basicresearch needs. In addition, Lewin and Associ-ates, lnc,54 prepared a major study for ERDAwhich recommends specific research targets(process/reservoir type). Further details of theERDA program are outlined in the ERDA Manage-ment Plan for EOR.55

The GURC and Lewin documents representcompilations of existing industrial viewpointsconcerning research targets and types ofprograms that are appropriate. This gathered con-sensus has been supplemented by a series ofERDA-sponsored workshops on ERDA research

targets 56,57 at which modifications to the programwere suggested through public forums.

Although there is agreement concerninggeneral research and development needs, there isa decided difference of opinion regarding the fac-tors which will stimulate this needed researchand development. The Lewin ERDA study58 pro-posed an extensive Government research anddevelopment program, justified in part by resultsof an industry survey which indicated thatresearch would not be greatly accelerated withinthe current set of constraints (economic, techni-cal, and institutional). The National PetroleumCouncil’s EOR study concluded that “Govern-ment policy with respect to oil price and otherfactors influencing EOR profitability is the domi-nant factor in establishing the level of R&D fund-ing and the rate of evolution of technology. ”

The OTA assessment did not attempt toresolve these positions because there appearedto be no meaningful way to predict what industrywould do a) if the price of oil produced by someEOR processes was allowed to rise to free marketprices as proposed by FEA, orb) if the price of allEOR oil were decontrolled. as proposed in thePresident’s National Energy Plan.

The ERDA Programs

The Energy Research and” Development Ad- ment of EOR processes. The general thrust of theministration has developed programs which are ERDA programs, including field testing and con-directed at stimulation of research and develop- tinued industry/Government interaction, is good.

i ’ ~P/a r m ing Cri(erla Relative to a Nationa/ RDT&E ProgramDirected to the [nhanced Re(okery of Crude Oil and NaturalGas, for U.S. Atomic Energy Commission, Washingtcm, D. C.,GURC Report No. 130, Nov. 30, 1973.

~OAn /investigation of Prirnw-y Factors Affecting Federal Par-

ticipation in R&D Pertaining to [he Accelerated Productionof Crude Oil, for the National Science Foundation, Washing-’ton, D. C., GURC Report #1 40, Sept. 15, 1974.

51A Survey Of flcld Tests of Enhanced Recovery Methodsfor Crude Oil (supplement to GURC Report No. 140), for theNational Science [oundation and the Federal Energy Ad-ministration, Washington, D. C., GURC Report No. 140-S,Nov. 11, 1974.

Szpreliminary Fie/d Tes( R~~cornrnendatlons and prospec-

tive Crude Oil Fields or Reservoirs for High Priority F/e/dTesting, for (J.S. Energy Research and Development Ad-ministration, Washington, D. C., GURC Report No. 148, Feb.28, 1976.

53 Technica/ Plans for a Supplementary Research program

to Support Dcveloprnent and F ie ld Demons t ra t ion o fEnhanced Oil Recovery, for U.S. Energy Research andDevelopment Administration, Washington, D. C., Gl_JRCReport No. 154, Mar, 17, 1977.

jiResedrch and Development in Enhanced Oi/ Recovery,

Lewin & Associates, Inc., Washington, D.C. Part 1, p. III-2.ss~~anagement P/an for Enhanced 0// Recovery, ERDA,

Petroleum and Natural Gas Plan, ERDA 77-15/1, p. 11-1,February 1977.

56ERDA workshops on Thermal Recovery of Crude oil,University of Southern California, Mar. 29-30, 1977.

5TEOR Workshop on Carbon Dioxide, sponsored byERDA, Houston, Texas, April 1977.

~8Research and Development in Enhanced Oi/ Recovery,

Lewin & Associates, Inc., Washington, D. C., Part 1, p. III-2.

Ch. III—Oil Recovery Potentlal . 65

The ERDA management plan for EOR 59 i sdirected at maximizing production in themid-1980’s. However, short-term needs shouldnot overshadow long-term national needs of in-creasing oil recovery. The OTA analysis indicates

that a long-range program is needed to st imulate

the development of processes, such as the surfac-tant/polymer process, which have the potentialfor greater oil recovery in the mid-1990’s,

There does not seem to be adequate basic andapplied research in the ongoing ERDA program.This has been recognized by ERDA, and an exten-sive research program has recently been outlinedby GURC60 for ERDA. This research program sup-plements the programs outlined in the ERDAmanagement plan.61

The largest amount of basic and appliedresearch has come from the integrated major oilcompanies and the serv ice sector of thepetroleum industry. The largest amount of exper-tise also resides in the industry. Basic and applied

research done by industry and research institu-tions should be coordinated so that Governmentprograms complement rather than duplicateprograms underway in industry. This subject doesnot seem to be covered formally in the ERDAdocuments, and is particularly crucial since evenunder Government sponsorship a large portion ofthe basic and applied research is likely to bedone in industry laboratories and oilfields.

The OTA assessment did not determine thelevel of ERDA or industry effort required toachieve the postulated technological advances orthe cost of the necessary research and develop-ment. (Other studies have shown that the cost ofresearch and development is on the order of afew cents per barrel of ultimate recovery.)However, the level of effort and funding in R&Dmust clearly be significantly increased over cur-rent levels by both industry and Government inorder for the evolution of technology to ap-proach the technological advances postulated inthis assessment.

sgManagemen[ p/an for Enhanced 0// Recovery, ERDA,Petroleum and Natural Gas Plan, ERDA 77-1 5/1, p, 11-1,February 1977.

60 Tecbn;caj Plans for a Supplementary Research Pmgrmto Support Development and Field Demon5(ratlon ofEnhanced Oil Recovery, f o r 1.1.S. E n e r g y R e s e a r c h a n d

D e v e l o p m e n t A d m i n i s t r a t i o n , W a s h i n g t o n , D . C . , CiURC

R e p o r t N o . 1 5 4 , M a r . 1 7 , 1 9 7 7 .61 ~anagement p/dlJ for Enhanced 0// Recovery, ERDA,

Petroleum and Naturdl Gas Plan, ERDA 77-1 5/1, p. 11-1,February 1977.

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