3.2 enhanced oil recovery - · pdf fileoperations apply enhanced oil recovery (eor) ... into...

3.2.1 Processes

At the end of development of a field by primaryprocesses (exploitation of the natural energy) andsecondary processes (water or gas injection todelay depressurizing), the recoveredhydrocarbons seldom exceed 50% of thoseoriginally present (the OOIP, Oil Originally InPlace). To increase final recovery, someoperations apply Enhanced Oil Recovery (EOR)processes, also called tertiary processes becausein the past they were applied in the third phase ofthe productive life of the field.

As illustrated in Fig. 1, over the decades, numeroustechnologies have been developed that are based onconsolidated chemical-physical principles, but which,though they have demonstrated their validity andeffectiveness in recovering hydrocarbons in thelaboratory, have never gone beyond the pilot phase offield application. The complexity of the mechanismsthat characterize these technologies and their costs ofapplication have in fact precluded, or slowed down,their systematic development.

EOR processes are traditionally divided into threemain groups (see again Fig. 1): thermal processes(injection of steam, injection of hot solvents,

209VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY

3.2

Enhanced oil recovery

improved oil recovery

(secondary)

advancedwells

waterinjection

gasinjection

pressure maintenance

gas condensatecycling

enhanced oil recovery

(tertiary)

thermal

steam flooding

cyclic steam stimulation

hot water

in situ combustion

miscible/nearmiscible hydrocarbons

nitrogen

carbon dioxide

flue gas

water-alternate-gas

geologicalsequestration ofgaseous emissions (CO2)

polymer flooding

alkaline/polymer/surfactant

foam

surfactant

microbial EOR

electromagnetic

mechanical (e.g.mining)

gas and watershut-off

gas miscible/immiscible chemical others

Fig. 1. Secondary and tertiary EOR processes.

combustion in situ, etc.); gas injection processes(natural gas, nitrogen, carbon dioxide, etc.); andchemical processes (injection of surfactants, polymers,alkaline solutions, etc.).

Other emerging or niche technologies are dealtwith under the heading of ‘Other processes’ (seebelow). The foremost EOR technologies that have hadpilot applications in the field are described below. Formore complete details about the physical principlesand the results of applications of these processes, referto the bibliography (Donaldson et al., 1985; Green andWillhite, 1998).

Thermal processes with steam injectionThermal processes linked with steam injection

were the first ones to be used in the oil industry, as theearliest fields discovered and saturated by highviscosity heavy oils occurred at depths of just a fewhundred metres. The main objective of these processesis to improve the mobility of the oil by reducing itsviscosity through heat exchange. Steam can beinjected into the well itself (cyclic steam stimulation),which will also function as the production well, or intoa dedicated well, while a second well will act asproducer (steamdrive). A significant example of thistechnology is known as the Steam Assisted GravityDrainage (SAGD) process, and in the last few years ithas been applied with some frequency. The SAGDtechnology is based on drilling two overlyinghorizontal wells: the upper one is used for steaminjection while the lower one drains the hot oil towardsproduction.

With steam injection, the chemical and physicalproperties of the oil (viscosity, density, compositionand phase behaviour) undergo changes, as do alsothe petrophysical properties of the rock (porosity,permeability and compressibility). Also modifiedare properties of the interactions between the rockand the fluids (saturation in residual oil, interfacialtension, wettability, relative permeability, capillarypressures, etc.).

Other parameters that determine the applicabilityof this process, apart from the temperature and thepressure of the field, regard the structuralcharacteristics of the formation such as its thickness,the presence of clay barriers or of heterogeneousfactors that can affect the flow regimes, the geometryadopted for the injection and production wells, and theoperating conditions, such as the quality and quantityof the steam available.

In general, steam injection thermal processes areapplied to fields that are between 150 and about 1,500 mdeep and that are around 20 m thick. Greater depthsincrease heat losses, reduce the benefits of heatexchange between the steam and the field fluids (the

greater the depth, the higher the temperature of thefield), and increase the risks of damage to facilities dueto the effects of the higher temperature and pressurethe steam must possess (optimal values are between150 and 200°C). Ideal candidates are fields having highvalues for permeability (1,000-4,000 millidarcy) andporosity (greater than 20%) and with oil saturationsgreater than at least 40%. The viscosity of the oilshould be between 200 and 1,000 mPa�s and densitybetween 10 and 30°API.

Thermal processes by combustion in situAs opposed to the thermal processes using steam,

those based on combustion in situ offer a broaderrange of applications, although the management ofthese processes is more complex and difficult.

Applications have been made in clastic depositsdown to depths of 2,000 m, with porosity of over 20%and permeability of more than 200 millidarcy. Oilsaturations, the original oil density having beenbetween 10 and 40°API, varied between 30 and 94%.The process is based on injecting into the layer air, or amixture of fuel gas and air, so as to trigger combustionand to control it more easily. If the temperature of thefield so permits (it has to be higher than at least55-60°C), spontaneous combustion can take place afew days after injecting the air. If the conditions forspontaneous combustion are not present, artificialcombustion can be achieved by means of appropriatedevices, such as gas burners or electric heaters, or byusing catalytic systems. Combustion is triggeredaround the injection well and its front is propagatedinto the field and is kept going through air injection.In the combustion zone, the temperature can reach upto 650°C, at which value cracking of the heaviercomponents of the oil and the production of coke canoccur. The viscosity of the oil is reduced by variousorders of magnitude when there is a shift, underpressure from the products of combustion, towards theproducer wells. For better control of the combustion, itis possible to inject air together with a moderatequantity of water (wet combustion) which, in theoilfield, is transformed into superheated steam which,in its turn, after going past the combustion front,mixes with the nitrogen in the air, while the gas (fluegas), represented by carbon oxide and dioxide,displaces the oil and the condensates. A number oflaboratory and field tests confirm that wet combustionis able to improve the areal efficiency of displacementand to reduce the project lifetime, thus implicitlydiminishing the operating costs.

As stated, the process, because of its complexity,has not yet been applied except in a few pilot cases,which moreover have brought to light operationaldifficulties linked with its control (for example, the

210 ENCYCLOPAEDIA OF HYDROCARBONS

NEW UPSTREAM TECHNOLOGIES

plugging of producer wells by the depositionof carbonaceous residues and waxes as a result of theoil cracking process, the failure of the tubing and ofthe lines due to the high temperatures reachedin the producer wells, and the possible explosionof the compressors). Operational difficulties alsoincluded the formation of undesirable products, suchas emulsions which reduce the productivity of thewells, or the production of water with a low pH, rich inions, iron and sulphates, which lead to corrosion andenvironmental problems.

As the combustion process takes place in the upperpart of the formation, the ideal candidates are fields ofmoderate thickness and saturated with oilscharacterized by a medium-to-low API gravity.

Gas injection processesInterest in EOR processes based on gas injection,

in particular natural gas and carbon dioxide, has alsoincreased in the last few years following theintroduction of restrictions on emissions aimed atreducing environmental impact. These restrictions areapplied by the main hydrocarbons producer countries,which demand the reinjection of gas into theassociated reservoirs, if the gas is not of anycommercial value, or the injection of CO2 for thereduction of gaseous emissions (GHG, Green HouseGas) responsible for the greenhouse effect.Experiments have been carried out using variousgases, among them, apart from the already mentionednatural gas and CO2, also nitrogen and LPG(Liquefied Petroleum Gas).

The gas that is injected into the reservoir should bemiscible with oil so that the process of displacement inthe pores of the rock will be really effective. Achievingmiscibility involves in fact a drastic diminution ininterfacial tension, from approximately 2-3 N/m2 tovalues close to zero, and hence the oil-gas capillarypressure tends towards zero. Upon contact between thegas and the oil, a cushion of miscibility is generated inthe reservoir, which favours the displacement of the oiland reduces the mobility of the gas which, having aviscosity some orders of magnitude lower, would tendto precede the oil to the producer wells, leading to apremature escape and a consequent low recovery. Ifthese conditions cannot be achieved, and thus the oildisplacement process is not practicable due toproblems of miscibility, then prior to injecting the gasinto the reservoir, a limited volume of LPG (LPGmiscibile slug), which is miscible with the oil, couldbe injected, or else water, as an alternative for strictlyeconomic reasons. In this last case, the water, beingimmiscible with oil by its nature, serves the functionof controlling the mobility of the gas, as well ascontributing towards the mechanical displacement of

the oil from the pores, because it has a comparablemobility. To achieve this mobility control and toreduce the volumes of gas necessary for fieldapplications, water is also injected in alternation withgas in miscible processes (WAG, Water-Alternating-Gas process).

Gas injection can be applied in both clastic andcarbonaceous non-fractured reservoirs, at depths ofmore than 1,000 m and with a greater than 20-30%saturation in oil. There are no constraints linked withtemperature; indeed the higher it is, the greater theprobability of the miscibility of the gas with the oil.The recommended density and viscosity values of theoil are higher than 22°API and 1.5 mPa�s respectively.

Chemical processesThe EOR processes that use chemical products

require more complex management than do thermalprocesses, regarding both choice of products andassessment of the real performance of fieldapplications. Excluding certain initiatives in progressin China (Daquing and Shengli fields; Chang et al.,2005), applications are few in number or are at thepilot plant level.

The chemical products in use can simply increasethe viscosity of the water used for displacing the oil sothat the mobility (i.e. the relation between thepermeability of the water with polymer and theviscosity of the solution) of the water decreases andthe displacement front is more homogeneous. For thisfunction (polymer flooding), suitable polymers areused, of high molecular weight (around one million),and they may be of either natural or synthetic origin.

Because they have to withstand the reservoirconditions (for example, high temperatures,mineralogy that favors the adsorption of the polymeron the surface of the rock grains, and high salinityvalues of the formation water), the polymers can besynthesized to function in very specific ways, and thisis always costly. To reduce the high costs, the polymerconcentration in the water is not kept constantthroughout the injection phase; rather, theconcentration diminishes with distance from the oil,from its maximum value at the contact front with theoil, down to zero.

Other applications of EOR processes withchemical products involve the use of surfactantsdispersed in water (surfactant flooding), which reducethe water-oil interfacial tension to values near 10�5 to10�4 N/m2, so as to bring the value of the capillarypressure down to zero and help the water force the oilout of the rock pores.

The stability characteristics that surfactants mustpossess are similar to those of the polymers; andsimilarly, they may be prepared on an ad hoc basis to


ENHANCED OIL RECOVERY

match the characteristics of the reservoir. To reducecosts, processes have been tested in the field whichcombine the two actions: that of the surfactant solutiondriven into the formation and that of the polymer(micellar/polymer flooding), yielding even greaterbenefits than from the application of the two separateprocesses. While on the one hand at laboratory scalethe results have been excellent and promising, on theother hand the results of applications in the field havebeen rather disappointing, probably because of thedifficulties of characterizing the formation concerned(type and extent of the non-uniform features of therock texture, in the mineralogy and in the size of thepores; distribution of the water and the oil; hydrauliccommunication between the injection wells and theproducer wells, etc.). The combination of injection ofan aqueous surfactant solution and of a gas cangenerate foam, the purpose of which is to improve theareal efficiency of the oil displacement.

To reduce even further the costs of a process basedon the injection of surfactants, the possibility ofdirectly generating surfactant in the reservoir has beentested by injecting alkaline aqueous solutions (sodiumhydrate, sodium orthosilicate, sodium carbonate,ammonia, etc.) that have a high pH value. Once incontact with the oil, these cause the saponification ofthe acid component and the consequent formation ofsurfactants (alkaline flooding). For these processes,too, there has been study of the combination of aninjection of alkaline solution driven into the reservoirby water thickened with polymer. Although theprinciples put to use in this process are fairlyinteresting, its effectiveness is more difficult todetermine because of the previously mentionednon-uniform features present in all reservoirs. This isespecially true if these reservoirs are in an advancedstate of exploitation and therefore have an oildistribution impossible to assess with present methods.

The fields that can benefit from the application ofchemical processes should be located at a depth of lessthan 5,000 m and at temperatures that should notexceed 90°C. The oil should have a density of morethan 15°API for polymer flooding or 20°API for theother processes, and so the viscosity of the oil shouldbe less than 150 mPa�s for polymer flooding and35 mPa�s for the other processes.

Other processesAs already stated, this definition refers to a series

of technologies still in the experimental phase orapplied to resolve particular production problems. Fig. 1 makes reference to the mechanical recovery ofhydrocarbons, i.e. to the exploitation of bituminoussands in shallow fields, as happens, for example, incertain extensive Canadian deposits. The deposits are

situated at the surface and are worked by mechanicalexcavation. The main treatment consists of the thermalor catalytic cracking of the bitumens, from which isobtained syncrude, a light oil whose commercial valueis far higher than that of the original product.

Other technologies are based on the application tothe production well of vibrations produced by specificinstruments (whirling orbital vibrators), which generateelastic waves at a low frequency (5-500 Hz) for thepurpose of increasing production. Their principles ofoperation are not yet fully known; some claim there is adecrease in the surface tension between the oil and thesurface of the porous matrix, while others say there is adisaggregation of the liquid films that cover the rockgrains and the coalescence of the oil dispersions. Highfrequencies, generated by ultrasonic devices loweredinto the producer well, are instead used for removingsolid deposits that can hinder production.

To retard the premature arrival of the watercoming, for example, from a drive aquifer,technologies have been developed that are appliedaround the producer well (water shut-off). An aqueoussolution of a polymer and a chemical product (forexample, a trivalent chromium salt), that acts as abridge between the polymer chains (cross-linkingagent), is injected into the formation that produces thewater. The well is closed for a certain period of time(shut-in period) in order to permit the generation of agel whose consistency is such that it clogs the largerpores through which the water was conveyed. The wellis then reopened for production. The placement of thegel around the producer well, its consistency and itsduration in time are the unknown factors thatdetermine the effectiveness of this technology.

Lastly, among the processes that cannot beincluded in the three traditional groups, is MicrobialEnhanced Oil Recovery (MEOR). Although thisprocess has been studied ever since 1926, in reality ithas only recently had some significant application inthe field. It is based on the injection into the reservoirof either extracellular bioproducts derived from themetabolism of certain micro-organisms, or of bacterialstock or spores which develop when provided withappropriate nutrients. Thousands of different speciesof micro-organisms have been identified whosemetabolism can produce polymers (polysaccharidesand proteins), surfactants (lipopolyanions), alcohols,etc., that are useful for the oil recovery process; butalso substances such as methane, nitrogen, carbondioxide and H2S, which can entail operationalproblems not foreseen in the design phase.

The main benefits attributable to the MEORprocess involve the use of bioproducts to improve themicroscopic and areal efficiency of oil displacement.By using these bioproducts, the zones of highest



permeability are plugged, forcing the water to invadeother zones not previously involved. If used inreservoirs of heavy oils, the micro-organisms arepotentially able to transform the hydrocarbons havinga high molecular weight (for example, asphaltenes)into hydrocarbons made up of simpler molecules,which are more easily producible.

As this is a complex and little-known mechanism,even with regard to studies conducted in thelaboratory, this process is unlikely to have generalizedapplications in the field because of the temperature,which must not exceed 80°C, and because of thesalinity of the formation water.

References

Chang H.L. et al. (2005) Advanced in polymer flooding andalkaline/surfactant/polymer processes as developed andapplied in the People’s Republic of China, «Journal ofPetroleum Technology», February, 84-89.

Donaldson E.C. et al. (edited by) (1985) Enhanced oilrecovery, Amsterdam, Elsevier, 2v.

Green D.W., Willhite G.P. (1998) Enhanced oil recovery,Richardson (TX), SPE.

Emilio Causin EniTecnologie

San Donato Milanese, Milano, Italy



3.2.2 Recovery factor optimization

Introduction

In this section we consider possibledevelopments in the technology of Enhanced OilRecovery (EOR). The discussion includes someaspects of the more general topic of recoveryoptimization, which apply to any stage of fielddevelopment. The focus, however, is on EOR, whichis sometimes also called tertiary or improvedrecovery. The resource base to which these recoverymethods can be applied is increasing. In contrast, theresource base for primary recovery (not yetdiscovered fields, and discovered but currentlyuneconomic fields) will at some point, perhaps inthe not-too-distant future, begin to shrink.

Forecasting the future of any technology is arisky venture. Jack Kilby (recipient of the Nobelprize in physics, 2000) said that he knew at the timehe invented the integrated circuit that thetechnology would be important, but that even he didnot foresee how widespread the impact wouldeventually be. Failure to foretell the effects of a newtechnology is a common problem. It can beattributed in part to the difficulty of envisioningdevelopments in other, perhaps unrelated, marketsectors or technologies. When a few key advancesin independent areas are brought together for thefirst time, a new capability or market can emergethat could not have been imagined even by someoneworking in one of those areas.

Such synergies are likely to affect the oilindustry because its central role in fueling the worldeconomy draws attention from many disciplines.Indeed, the industry still exists largely because ithas a long history of technical advances.Technology has enabled operators to continue tomeet rising demand for oil by finding, developing,producing and transporting oil from previouslyunimaginable fields.

In many areas of technology, advances arelimited only by human creativity. What can beimagined can be designed, prototyped, tested,improved, and so on. Yesterday’s wild ideaeventually becomes an indispensable part of modernlife. This phenomenon of ‘boot-strapping’, whereby

a major, completely new industry emerges over afew decades following a handful of key discoveries,is now commonly regarded as the natural course oftechnology. The archetypical examples are personalcomputers and cellular telephones.

In the oil industry, the constraints imposed by thephysical characteristics of reservoirs are severe. Thesimple reality that reservoirs are found in geologicstrata far below the surface of the earth affects everyaspect of producing oil. The challenges are wellknown and have attracted the ingenuity andperseverance of many talented people for decades.In a reservoir, what can be imagined can befrustratingly difficult to design, and even harder toprototype, test, improve, and so on. Moreover, theoil industry already exists and operates at a globalscale, and there is less opportunity forboot-strapping new developments in technologywhen they must compete against long establishedmethods having the same function – in this case,getting oil from the reservoir to a market.

Charting the future of EOR requires a somewhatdifferent perspective from that used for other areas,even though EOR is highly dependent ontechnology. The goal of this chapter is to set outsome basic principles, both economic and technical,that will influence the implementation anddevelopment of EOR processes. These principleswill shape the future of EOR, but they can provideonly a rough guide to the details of future EORprocesses. Indeed, we will see that a shift in at leastone, possibly two EOR paradigms may be necessaryin order for this technology to play a significant rolein the industry in the future.

The discussion will build upon a fundamentalunderstanding of EOR objectives, and so we begin byreviewing them briefly.

EOR is a process that recovers incremental oilfrom a reservoir. In this context, incremental meansnot recoverable by primary or secondary methods,even after arbitrarily long periods of time.

Primary and secondary production can recoveronly a fraction of the OOIP (Original Oil In Place) in areservoir. The reasons for this are purely physical andtherefore inevitable. The oil remaining in place afterprimary and secondary production is the target forEOR processes.



Primary production is driven by an energy sourceintrinsic to the reservoir. These sources include, forexample, compaction of the rock stratum containingthe oil, and influx of water from an aquifer connectedto the reservoir. Secondary production generallymeans injecting water into some wells so as to push oilout of the reservoir through other wells.

A field being operated under primary orsecondary recovery reaches its economic limitwhen operating costs exceed the revenue generatedfrom oil production. The economic limit is reachedbefore the physical limit of production. That is, atthe economic limit, the operator could continue torun the primary or secondary production method,and the method would continue to extract oil fromthe reservoir. The rate of production would be smalland would continue to decrease. But even ifsecondary production were continued indefinitely, asignificant fraction of the OOIP would never berecovered. The existence of a physical limit isfundamental to EOR, even though the limit is neverreached in practice. The future of EOR is tiedclosely to long-term oil demand, and new oil(from newly discovered fields) and incremental oil(from EOR applied to existing fields) are the onlyways to meet that demand.

In this context it is helpful briefly to distinguishprocesses such as well stimulation from EOR. Theobjective of a well stimulation treatment is toincrease the rate of production of oil from a well.In general, increasing the flow rate does not lead tohigher ultimate recoveries during primary orsecondary production. Thus, stimulation may becharacterized as a process that allows one to recoverthe same amount of oil in a shorter period of time.The objective of EOR is to recover more oil thanwould otherwise have been produced, i.e. theincremental oil defined above. In the process ofrecovering that oil, production rates may or may notincrease. The usual observation when EOR isimplemented is that field production rates declineless rapidly than before. For economic reasons, it isof course desirable that production rates increaseduring an EOR project. This point is quiteimportant and is discussed later; here it suffices todistinguish the technical objectives of stimulationfrom those of EOR.

It is also helpful to distinguish EOR inconventional reservoirs from EOR in heavy oilreservoirs, tar sands, bitumen, and oil shale. The lattergroup of resources either have very high oil viscosityor contain kerogen rather than oil. Primary andsecondary recovery from these unconventionalresources is small. Reducing the in situ viscosity ofheavy oil is the classical approach to this problem.

Injecting heat into the reservoir, via steam or hotwater, is the usual mechanism for reducing viscosity.Heat is also necessary for converting kerogen to oil.These thermal processes meet the definition of EORgiven above. Once the oil is mobilized, these reservoirsare subject to the same technical difficulties asconventional reservoirs. However, the differencesbetween EOR in conventional and in unconventionalreservoirs are great enough that competition will arisebetween the two applications. The competition will beextensive, affecting funding for research anddevelopment, capital for field projects, the pricing ofthe recovered oil, etc.

Drivers for EOR

The factors shaping the future of EOR can begrouped into technical, economic and environmentalcategories.

Technical drivers The technical driver for EOR is the physical

limit on primary or secondary recovery described inthe preceding section. This discussion focuseson conventional reservoirs because the essentialdifficulty in heavy oil reservoirs is viscosity.The classical remedy for producing viscous oil is toraise the temperature, and this introduces a differentset of priorities for assessing physical limitson recovery.

In conventional reservoirs, there are two reasonsfor the physical limit on the recoverable fraction oforiginal oil in place. First, the flow properties(permeability) of every oil reservoir vary widelywith the location in the reservoir. This means thatthere is always a path of least resistance between aninjection well and a production well. Water injectedduring secondary recovery inevitably finds this pathand sweeps oil along the path. Subsequently injectedwater will continue along this path, even after theoil has been swept from it. The natural heterogeneityof rock properties thus leads to the problemof poor sweep efficiency: injected fluids do not moveuniformly throughout the reservoir volume.

The second reason is that oil droplets can betrapped in the pores of reservoir rock. Pore sizes insedimentary rocks (the type of rock in which nearly allreservoirs are found) are on the order of 10�6 m.When an interface between two immiscible fluids suchas oil and brine exists in such a small space, asignificant pressure difference arises between thefluids. This pressure difference, known as the capillarypressure, leads to spontaneous disconnection of the oilphase when water imbibes into the pore space of areservoir. The capillary forces on the disconnected


droplets of oil are so large compared to gravity forcesand viscous forces that the droplets cannot bedisplaced from the rock. This is the origin of theproblem of poor displacement efficiency: somefraction of the oil initially present is left behind thedisplacing fluid.

For simplicity, the preceding discussion assumedthe surface of the reservoir rock was water wet. If therock is oil wet or of mixed wettability, the detailschange, but the macroscopic consequence persists. Afraction of the oil will be trapped in pores on the timescales of practical interest.

The technical drivers for EOR are universal. Allreservoirs are candidates for EOR, because primaryand secondary recovery processes have rather poorsweep efficiency and displacement efficiency.Typically one half to two thirds of the OOIP remainsin the reservoir at the end of secondary recovery. Inthis regard, the future of EOR is guaranteed. There willbe no shortage of candidate reservoirs in which sometype of EOR could be implemented.

All processes that have been proposed orimplemented for EOR address the physicalmechanisms underlying poor sweep efficiency ordisplacement efficiency. Future processes must alsoaddress these mechanisms. Whether they adopt similarapproaches will be the focus of our subsequentdiscussion.

Economic drivers The technical factors described in the previous

section are well known in the oil industry. Indeed,efforts to develop EOR processes date back at least tothe 1950s. Field deployment of different processes haswaxed and waned with the price of oil. This leads to

the other key factor influencing the future of EOR:economics. In a global industry that is producing acommodity essential to global economic activity, onecannot make reliable extrapolations about technologywithout considering the influence of economic forcesover longer time periods.

Economic drivers within the oil industry Within the oil industry, the economic driver for

EOR is the certainty of knowing where oil can befound – namely, the reservoirs depleted underprimary or secondary production. In comparison,finding oil by drilling exploration wells is morerisky. This factor simultaneously sets the economicthreshold for EOR. If the finding and lifting costsper barrel of primary or secondary production oilare less than the costs of producing an incrementalbarrel via EOR, then EOR projects will not play asignificant role in the industry. EOR experiencedone sustained growth period in the last severaldecades beginning after the jump in oil prices in1974 and strengthening after the jump in 1980 (Fig. 1). The interest and activity in EOR thendwindled as oil prices settled and as new primaryproduction increased.

Most current operators have prospered or atleast survived without resorting to EOR. They haveavoided EOR because most EOR processes arerelatively costly. The price of oil has not stayedhigh enough for a sufficiently long time for EORprojects to be economically attractive. The increasein oil price in 1973 led to nearly twice as manyEOR projects active at the end of the 1970s. Afterthe increase in oil price in 1979-80, the number ofEOR projects more than doubled by the



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mid-1980s. The collapse in prices in 1986immediately reversed the trend, with one third asmany projects operating by the end of the 1990s.Because the timescale for recovering oil in an EORproject is long, or at least longer than the timebetween peaks and valleys in oil price during the lasttwenty to thirty years, it can be difficult to sustain anEOR project long enough to fully evaluate itspotential. (The application of steam flooding toheavy oil reservoirs is exceptional in that it has beenless vulnerable to swings in oil price).

The same prices that make EOR attractive alsomake it attractive to increase exploration activityand to develop previous discoveries that were noteconomically viable at lower prices. This is ofcrucial importance. This development makes iteven more difficult for EOR projects to survive.(This argument is a variation of the position thatmarket forces will always act to prevent the arrivalof a peak in global oil production.) The economicadvantage of EOR lies in the known remaining oilin place, but this advantage only appears valuablewhen primary production is decreasing and newdiscoveries are not being made. As long astechnical advances, such as 3D seismic andultra-deepwater exploration and productiontechnologies, continue to arrive, industry willcontinue to be able to meet increases in demandwith primary and secondary recovery. This hasbeen the case for several decades. Moreover, theconcept of a ‘swing producer’, a country that canadjust its production rapidly to make up shortfallsor absorb gluts of the order of several millionbarrels a day, now appears to be taken for granted,as Saudi Arabia has played that role for nearlythirty years. These experiences lead manyforecasters looking five, ten, and even twenty-fiveyears ahead to predict that the trend of increasingproduction will continue. From this perspective,the greatest successes of EOR will always be aboutten years in the future.

Oil production from marginal wells is often aproblematic issue for industry and for government inmature oil provinces. These wells produce oil atsmall rates, typically less than ten barrels per day,accompanied by fifty or one hundred times as muchwater. In aggregate, production from marginal wellsis a non-negligible contribution to overall supply.Revenue from individual fields is small, andoperating costs such as electricity to run pumpsmake the economics of these fields marginal,especially when oil prices are low. Shutting down amarginal field by plugging and abandoning its wellsis the only alternative when the field is no longereconomically viable.

The disposition of marginal wells has asignificant impact on the future of EOR. Althoughthe oil production rates are small, the reservoir stillcontains large amounts of oil, all of which is inprinciple a target for EOR processes. The cost ofimplementing EOR in an existing, operating field ismuch less than in an abandoned field. Resumingoperations in an abandoned field requires drillingnew wells. Because the field’s primary energy hasalready been depleted, a large number of wells willbe needed. The capital investment required tore-establish flow from (and into) the abandoned fieldfor an EOR project thus becomes prohibitively large.Keeping marginal fields in operation preserves aresource base for the eventual application of EOR,while abandoning them essentially precludes the oilremaining in place from ever being extracted.

Maintaining marginal operations keeps anadditional option open for long-term energy supplyplanners. Until that option is exercised, however,industry, government and society must decide howto pay for those marginal operations. If oil pricesremain high for extended periods of time, then thedecision is likely to be easy, as operators will be ableto make a reasonable profit, assuming that the costsof equipment, workovers, and other operationsremain roughly constant. The difficulty arises whenoil prices are flat and the profit margin becomesunsupportably small for the operator. Then agovernment that wishes to keep the fields operatingfor long-term strategic motives faces the dilemma ofwhether to intervene in the market. The merits ofsuch intervention are typically hotly debated,particularly when the intervention affects somethingso central to economic growth and the environmentas energy supply. The debate over marginal fields iseven more complicated because the time whensociety may benefit from the marginal fields isimpossible to predict, and the technology needed toexploit those fields cost-effectively is not obviouslyavailable. If the balance of opinion shifts towardshort-term expediency or a non-intervention policy,then the future of EOR will be constrained by asmaller set of candidate reservoirs than wouldotherwise be available. Whenever the time finallycomes to consider the broad application of EOR,only the fields still operating will be candidates.

The rate of production required to qualify amarginal field as economically viable may belarger if the operating costs are also larger, as is thecase in offshore or remote locations. Thus anargument similar to the above can apply to fieldsnow producing at relatively large rates, if they havelarge operating costs, and may apply increasinglyoften in the future.

Economic drivers from outside the oil industry From the perspective of the global economy, the

economic driver for EOR is clear. Economic growth isinextricably tied to energy consumption. For most ofthe Twentieth century, fossil fuels were the mainsource of energy. In the last few decades, the balancebetween fossil fuels has shifted to oil and gas fromcoal. Moreover, total energy consumption has growninexorably for more than thirty years despite priceshocks and economic downturns. With a few relativelybrief exceptions, oil consumption has also grownsteadily for many decades (Fig. 2).

There is nothing to indicate that the trend ofincreasing demand for oil will change significantly inthe next several decades. One compelling reason is thecorrelation between national prosperity (as measuredby per capita GDP, Gross Domestic Product) and percapita oil consumption (Fig. 3). Presently, the countrieswith the largest populations are also relatively poor, asindicated by the points in the lower left corner of Fig.3. Some three billion people live in the six countrieshaving per capita GDP less than 5,000 dollars. Severalof these countries are well on the way to developingtheir economies, however, and in today’s worlddevelopment entails hydrocarbon consumption. Thus,even if energy efficient technologies are rapidlytransferred to these nations, an increase in global oildemand will accompany the development of thesecountries. A harbinger of this trend is that China isnow imports more oil than any other country exceptthe United States, yet per capita consumption in Chinais fifteen times smaller than in the United States.

The trend for increasing petroleum demand may beweakened by several factors in the coming decades.Even so, the sheer scale of the global economy will bemore than sufficient to sustain interest in EOR.Suppose for example that a series of dramatic changes

led to a reduction of 50% in demand for oil (anunprecedented reduction; the biggest drop in worlddemand in the last forty years was 8% during the early1980s).The world would still be consuming over 40million barrels a day (given that global demandexceeded 80 million barrels per day in 2004).Supplying that much oil remains a prodigiousenterprise, and eventually production fromconventional sources (primary and secondary recovery)will decline for a sustained period of time. Thus fromthe perspective of demand growth, the question aboutthe future of EOR remains ‘when’ rather than ‘if’.

During 2004-2005, the price of oil increaseddramatically. In constant dollars, the increase up to thetime of this writing is comparable to the increases in1974 and 1980, i.e. an increase by a factor of two tothree in money of the day. Will this price escalationlead to an increase in EOR projects, as it did in thepast? On the one hand, industry veterans whoremember the rise and fall of EOR in the 1980s arecautious about embarking on that course again. Somecompanies are currently reviewing the state of the artin EOR, but it is too early to tell whether those surveyswill lead to the sanction of new projects. Companieshold different portfolios of operating assets and thusmay have very different assessments of the potentialvalue of EOR.

On the other hand, the fact that the rate of globaloil consumption is one third larger in 2005 than it wasat the time of the last price escalation in 1980 meansthat continuing to meet demand will be that muchharder. If this pressure is reflected in a sustained highprice for oil, then EOR will certainly receive muchmore interest.

Over the longer term, the possibility of a gapopening between demand and supply fromconventional production is the single biggest



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influence on the future of EOR. As long as noserious gap emerges, there is little market-driven orshort-term incentive for implementing EOR, and theinvestment decisions will probably be based onexpectations of oil prices. Organizations that expectoil prices to remain high for long enough time willconsider EOR seriously.

If a gap does emerge, it is likely that EOR willbe a priority of government and industry, along withunconventional resources, gas-to-liquids conversion,etc. This ties the future of EOR to the muchdiscussed question of peak oil, the moment inhistory that – in retrospect – will prove to have beenthe time when global oil production reached itsmaximum rate. Unfortunately, efforts to forecast thetiming of global peak oil production have neveryielded a consensus. It is instructive, however, tonote the current situation in the major producingregions. Nineteen countries produced at least onemillion barrels a day in 2004, together accountingfor five sixths of all production (Fig. 4). Four ofthese countries – the United States, UnitedKingdom, Norway and Indonesia – are now on atrend of declining production rates. The trend is wellestablished in the USA and Indonesia, while the UKand Norway peaked only in the last few years.Except for some variations due to politicalinstability or war, each of the other fifteen countriesshows either steady or increasing production rates

over the last few years. Eventually each of thesefifteen will join the ranks of countries withdeclining production. But current trends suggest thatin the near term, a gap between supply and demandis not likely to be a driver for EOR.

For political reasons, some nations from time totime declare a preference for domestic production tomeet their energy needs. This preference supportsEOR; in fact, EOR is the only way for severalnations to increase domestic production, or at leastslow down the rate of at which their production isdeclining. Because there is a higher cost for EOR, itis difficult to sustain this preference for very long.

Environmental drivers Environmental considerations can also influence

the future of EOR, but their effect is likely to besecondary to the technical and economic influencesdiscussed above. The relevant environmental issuescan be categorized as conservation, biospheredisruption, and greenhouse gas mitigation.

Conservation Energy conservation has two connotations, and

each has a different effect on oil demand. Someuse conservation to mean never using a commodity.This obviously reduces demand for the commodity. Historically, this type of conservationhas not affected oil demand significantly. Once an

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industrial economy has been built on oil, mostconsumers and businesses continue to use oil. Theamount used may vary in response to price, butdeciding not to use oil at all is rare enough not towarrant further analysis in this context.

The other connotation of conservation isachieving the same level of economic activity withless energy. By this measure, technologicallyadvanced countries have been engaged inconservation for at least thirty years, for theirenergy efficiency has increased steadily over thatperiod. The motivation for these gains is economicrather than environmental, but the macroscopiceffect is the same: this type of conservation slowsthe rate at which oil demand increases. If theseefficiency improvements had not been achievedand implemented in industry, business, andconsumer uses, the current level of global economicactivity would demand a substantially larger rateof oil production than the 80 million bbl/d usedin 2004. Overall demand has increased steadily inthe last couple of decades primarily becauseoverall economic activity has outpaced the gainsin efficiency.

In this context it is instructive to consider thedeliberations of the USA National Academy ofSciences during a 1974 forum on energy futurealternatives and risks (NAS, 1974). In the aftermathof the Arab oil embargo of 1973-74, the discussionsfocused upon whether consumers would adjust theirlifestyles to fit available energy supplies, and howsoon energy alternatives such as nuclear, solar, andoil shale would meet the gap between oil supply andthe demand expected in the year 2000. Many, but byno means all, speakers anticipated major changes inthe way the USA and the world obtained and usedenergy. In a similar vein, the Five year outlook forscience and technology prepared by the NationalResearch Council (USA) in 1975 and again in 1980(but published in 1982) noted the importance ofconservation, energy efficiency, and development ofsynthetic fuels.

As has often been the case in energy studies,the future turned out to resemble the past muchmore closely than expected; the similarities areperhaps even less surprising when expectations areformed in the aftermath of rapid increases in oilprice. Oil, natural gas and coal dominate theenergy supply in 2005 just as they did thirty yearsago, and transportation demand is still being metalmost entirely by petroleum. The only substantivechange has been an increase in the share of nuclearenergy. Significant investments were made in oilshale in the USA, but large scale development ofthat resource never materialized. Production of

renewable energy increased, and some sectors suchas wind generated energy have increased rapidly inthe recent past. These sources nevertheless amountto a small fraction of the total energy supply.Meanwhile, oil demand in absolute terms hasdoubled during the past forty years. It seems likelythat expanding economic activity will continue tooutpace efficiency gains as well as adjustments toconsumers’ lifestyles that affect energy use.Demand for transportation fuel seems to beprice-inelastic when viewed over longer periods oftime. Voluntary conservation measures did occur inthe 1970s, but the general slowing of the globaleconomy during that period was the primaryinfluence on oil demand. As the price of oildropped, growth in oil consumption resumed.Conservation per se is thus unlikely to affect thefuture of EOR.

Biosphere disruptionThe effect of oil exploration and production

activities on the biosphere – surface water,groundwater, wildlife habitats, local ecosystems –has long been a matter of contention. Thecontention sometimes leads a society to restrict orforbid exploration and production in certaingeographic areas. Whether these restrictions aregood or bad is not the issue here. Rather, the keypoint is that the restrictions are rarely accompaniedby a decree which reduces oil demand. Thus, thepart of demand that putatively would have beenmet by production from the restricted area mustcome from somewhere else. In principle, thisincreases the attractiveness of EOR, because it canbe applied in already developed fields. In practice,a policy link between forbidding development inone area and promoting EOR in a mature area hasnot been tried. There has been nothing to preventindustry from carrying out EOR in existing fields.One may therefore conclude that EOR would havebeen implemented had it provided a suitable returnon investment, or a return comparable to thatanticipated from exploration in the forbidden area.Imposing EOR by fiat to make up for foregoneexploration opportunities would therefore be metwith resistance from many stakeholders.

Greenhouse gas mitigation Oil is produced for a range of applications, in

which transportation dominates. Most of eachbarrel produced is burned in internal combustionengines, boilers, and jet engines. The energycontent of coal and natural gas is likewiseharnessed by burning. The result is the emission oflarge quantities of CO2 to the atmosphere, more





than 20 billion tons in 2001. Mitigating the effectof CO2 and other greenhouse gases is now animportant political issue. It may soon become aneconomic issue, if carbon taxes are imposed andinternational carbon trading schemes emerge.

A broad portfolio of strategies for reducingCO2 emissions has been proposed. Somestrategies, such as replacing gasoline and dieselwith low- or zero-carbon fuels, will reduce oildemand. Others, such as the capture and storage ofCO2 from coal- and gas-fired power plants, wouldnot directly affect oil demand. They would howeverallow demand to increase without incurring a netincrease in emissions, and thus they wouldindirectly make EOR more attractive. The energyrequired for current capture technologies issubstantial. A large coal-fired generation plantwould need additional energy input of around 30%of the plant output to separate CO2 from the fluegas. The implementation of capture and storageschemes would therefore increase overall energyconsumption. The accompanying price pressurescould conceivably shift the balance betweenprimary energy sources, but the effect on EORwould not be large.

A more direct effect of carbon managementupon EOR is that one of the first mitigationstrategies that is likely to be adopted is storage inoil reservoirs. Using mature fields to store CO2

while simultaneously recovering incremental oil isa natural marriage of a long-standing EOR method(miscible and immiscible CO2 flooding) withsubsurface sequestration. Along with using CO2

for enhanced coal bed methane recovery and forpressure maintenance in natural gas reservoirs, thisstrategy is one of the few that produce revenuewhile reducing CO2 emissions to the atmosphere.Selling the incremental oil or methane will offset,and conceivably could even pay for, the cost ofCO2 capture, transport, and injection. This isparticularly true in geographic areas containingnumerous fixed sources of CO2 (power plants,refineries) and mature reservoirs, such as the TexasGulf Coast and parts of the Middle East. In thoseareas, the existing infrastructure could beharnessed relatively cheaply with small incrementsof pipeline capacity and compression facilities.

Operating an EOR project that issimultaneously a CO2 storage project will requirere-evaluation of the traditional approach to EOR.Large amounts of CO2 are recycled in a typicalEOR flood. In contrast, a storage scheme in areservoir would presumably stop injecting whenCO2 reaches production wells. Because the CO2 ispurchased, operators track CO2 usage closely. Yet it

is usually difficult to reconcile the mass of CO2

injected with the mass of CO2 produced and themass of CO2 held in the reservoir (in the voidspace formerly occupied by oil and dissolved intoreservoir oil and brine). Accounting for the actualamount of CO2 stored in order to receivegreenhouse gas emission credits may therefore beproblematic. If these credits are a significant partof the project economics, then this impetus forEOR will be reduced.

Nevertheless, the advent of carbon taxes,carbon trading, cap and trade policies, and the likewill transform a niche industry into a worldwidecommodity business. The volume of material beinghandled would approach that of the oil and gasbusiness. This might spawn a revolution inmiscible flooding for EOR. Historically, projectshave depended heavily upon the proximity ofnatural sources of CO2 because the costs ofpipeline construction and CO2 transport are keyfactors in the decision to proceed with this type ofmiscible flooding.

The net effect of greenhouse gas mitigationpolicies on the future of EOR will change withtime, in correspondence with the balance betweenthe different strategies described above. In the nearand medium terms, the push to reduce CO2

emissions will increase the attractiveness of EOR.In the long term, EOR will be less attractivebecause the upward pressure on oil demand willdecrease.

Historically, environmental considerations havehad a second order effect on oil demand, and thuson the attractiveness of EOR. In global terms,economic activity has the first order effect ondemand. As discussed in the previous section, thisstate of affairs is likely to continue for theforeseeable future. Oil demand will continue toincrease, and thus EOR will eventually becomeattractive. However, the wider implementation ofEOR will depend on whether other advancesenable other resources to meet demand. Suchadvances might include new discoveries ofconventional oil, new methods to develop currentlymarginal conventional reservoirs, andcost-effective methods to produce crude fromheavy oil, oil shale, tar sands, etc. (see below).

Oil industry technology developmentsfor EOR

Overview EOR is not a new process. The physical basis

for small sweep efficiency and small displacementefficiency is well known and has been studied for

decades. Mechanisms for addressing these lowefficiencies are also known. For example,increasing the viscosity of the water injected into areservoir improves sweep efficiency; this is thebasis of polymer flooding. Reducing the interfacialtension between the injected water and residual oilin the reservoir increases displacement efficiency;this is the basis of surfactant flooding. Injecting afluid that is miscible with the oil also increasesdisplacement efficiency; miscible floodingtechniques include the injection of CO2 at highpressures. The viscosity of crude oil usuallydecreases as temperature increases, so thatproduction rates increase proportionately; this isthe basis for steam flooding in reservoirs of veryviscous oil.

Other EOR methods are variations on orcombinations of the above. Air, nitrogen, flue gas,and lean gas (recycled light hydrocarbonsproduced from the reservoir) have been injected.CO2 injection is usually alternated with waterinjection. There is a history of efforts to placemicrobes into reservoirs, where they couldgenerate recovery-enhancing chemicals whenappropriate nutrients are injected. Recently thefeeding of indigenous microbes within a reservoirwas reported to improve the sweep efficiency of awaterflood, as the multiplying microbes filledpores and reduced the permeability of rockcontacted by water. Micellar-polymer andalkaline-surfactant-polymer floods, sometimesaugmented by microbes, have been applied in thefield. The in-situ generation of foam can improvesweep efficiency.

All these methods are known. Most have beenat least pilot tested in the field; several have beenapplied to full fields for long times. All have someadvantages and disadvantages, and certainlyimprovements in all of them are possible, as nomethod yet recovers all the remaining oil in place.Some methods are mature technologies. Others,such as foam and surfactant flooding, havematured considerably in the last decade outside theoil industry, having been applied to the remediationof soils and aquifers contaminated with NAPL(Non Aqueous Phase Liquid). For example, it ispossible to tailor a surfactant molecule to aparticular oil and reservoir, and to manufacture thatmolecule for a competitive price.

The key lesson from this brief overview is thatthe EOR in the future may look very similar toEOR in the past.

This rather mundane conclusion does notreflect researchers’ lack of ingenuity or interest inthe problem. Rather, it is another manifestation of

the economic drivers outlined above. Technologiesfor EOR have not been widely deployed (except forsteam flooding) because they are costly, notbecause they fail to recover incremental oil. Only ifoil prices remain high for an extended period oftime does widespread EOR implementation makesense. But it has proved difficult to sustain for longperiods of time a high price for a commoditysupplied in such extremely large quantities. Indeed,price movements more often reflect perceptions ofgluts and shortages than actual differences insupply and demand. This makes it quite difficult toimplement existing EOR methods, and practicallyimpossible to introduce new methods. Moreover,any new method of EOR necessarily addresses thephysical mechanisms that govern sweep efficiencyand displacement efficiency, which are exactly thesame mechanisms addressed (with varyingsuccess) by existing methods. A new method alsohas to compete with established methods intowhich decades of research, development, andapplication have been invested. Thus a revolutionin EOR technology, or at least a period of dramaticinnovation, does not seem likely.

The periodic upswings in oil price that tend togenerate discussion of EOR implementation alsotend to generate more primary and secondaryproduction, thereby reducing the need for enhancedrecovery from existing fields. One measure of thisprinciple is that a little over three hundred EORprojects are reported in a worldwide survey(Moritis, 2004). The number of such projectspeaked at just over five hundred during the mid1980s. This is a small fraction of the total numberof fields in the world. For reference, oil wasproduced during the last decade from thousands offields in Texas alone. Worldwide, there is a verylarge number of candidate fields for EOR, but veryfew of them have actually implemented an EORprocess. Moreover, of the currently active EORprojects, 40% are steam floods. All the steamfloods are applied to reservoirs containing oilwhose viscosity is too large for any other methodto work. Thus the fraction of conventional oilreservoirs in which EOR is being applied is evensmaller.

The primacy of production rates Why do so few EOR projects get implemented,

when so many candidate reservoirs exist? The scaleof global oil demand has one other implication thatneeds to be considered: production rates matter agreat deal. Indeed, for future EOR projects theproduction rates will be more important than theextent of incremental recovery.





The capital investments required to compete inan 80 million bbl/d global business are very large.An attractive return on large investments requireslarge production rates very early in the projectlife, even when oil prices are high. Here EOR is ata distinct disadvantage compared with primaryproduction. The target oil for incremental recoveryis either located in hard-to-reach places (the sweepefficiency problem) or distributed as myriaddroplets in pore space (the displacementefficiency problem). Using EOR to move thistarget oil into a coherent bank that will flow intoproduction wells at large rates has proven difficult.EOR usually has the advantage of existinginfrastructure, built for primary or secondaryrecovery processes or both, and so is not as capitalintensive. But the typical candidate reservoir hasoperating costs approaching revenues fromproduction, so the need for increased productionrates remains.

Declaring that large production rates are thecentral challenge for any EOR method, current orfuture, constitutes a shift in paradigm. Rate is notexplicitly mentioned in the traditional statement ofthe challenge for EOR. The technical objective ofEOR has always been to recover residual oil andbypassed oil. The measure of technical success isthe fraction of remaining oil in place that isrecovered. In the future, however, when the gapbegins to widen between oil demand and oilproduction from conventional reservoirs, theoverriding measure of performance for a projectwill be the rate of oil production.

The definition of ‘large production rates’depends on the magnitude of global oil demandand on the rates achievable from other fields; thusit can change with time, as the number and type offields in production changes. Historically, thestandard has been set by new discoveries operatingunder primary production. As the difficulty andcost of finding and developing new fields hasincreased, so has the economic pressure to obtainlarge production rates from those fields.

The difficulty in obtaining large productionrates is highlighted by recent statistics. The EORprojects active in 2004 produce altogether around2 million bbl/d, which is between 2-3% of globalproduction. In mature areas such as e.g. the UnitedStates, EOR projects are contributing a largerfraction of total production, currently about 10%.One quarter of the global EOR production is fromjust three projects, all of which are steamfloods.One third of all EOR comes from these threesteamfloods and two miscible floods usinghydrocarbon injection. This implies that most of

the EOR projects produce at much smaller rates.The mean of the field production rates reported in2004 for polymer floods is 1,300 bbl/d, 2,800 bbl/dfor CO2 miscible floods, and 7,600 bbl/d forhydrocarbons miscible. The median productionrates are even smaller: 600 bbl/d for polymer, 930bbl/d for CO2, and 1,000 bbl/d for hydrocarbonsmiscible.

For conventional oil reservoirs, the mostcommon EOR method in 2004 was miscibleflooding, followed by polymer floods. 40% of theEOR projects involved injection of miscible gases,mostly CO2 or light hydrocarbons. Together theseproduced about 600,000 bbl/d during 2004. Morethan half this production was from just eight of the137 miscible flooding projects.

The situation in EOR, in which a very smallfraction of the fields produces the majority of theoil, mirrors the situation in primary and secondaryrecovery. For several decades, a small number ofvery large fields has contributed the majority of oilproduced worldwide. In 2000, 68 million barrelswere produced. Simmons (2002) estimated thatnearly half of this production came from 116 fields;20% came from just fourteen fields. The last field toproduce 1 million bbl/d was found in the 1970s.These observations are usually the background fordiscussion of the peaking of oil production, but theyreinforce the question of which fields should receivehigher priority for EOR.

The imbalance in the distribution ofproduction rates among EOR projects raises aninteresting choice for the future development ofEOR technologies. Should research focus on thefew very large fields, where success or failure ofany individual project would have majorimplications? Or should research focus on themany smaller fields, where a certain fraction ofthe projects could be technical failures withoutjeopardizing overall production? In very largefields it is not unusual for operators to applyseveral EOR techniques one after another,sometimes even simultaneously in different partsof the reservoir. This suggests that current EORmethods are not particularly effective in thesefields and that there is scope for improving EORperformance in large reservoirs. Of course, thisperception of a general problem may be due toproblems specific to each of the reservoirs inquestion, in which case there is some chance thatthe optimal technology for one reservoir wouldnot be transferable to another field.

In fact, EOR by means of CO2 injection hasbeen practiced in the giant fields of west Texassince the 1970s. The SACROC (Scurry Area

Capital Reef Operations Committee) unit wasflooded with CO2 alternating with water withvarying degrees of success, and recently a newoperator has announced its intention to re-establishan extensive CO2 flood there. The Yates field has asimilar history: several EOR techniques havingbeen applied, none of which yielded long-termproduction rates comparable to those obtainedduring primary recovery. In general, misciblefloods with CO2 achieve oil production rates onethird of that obtained earlier in the field life.

This is not to say that these projects wereunsuccessful, technically or economically. Acommon occurrence is that the rate of decline inproduction decreased as a result of the project. Thiscan pay out the cost of the project. But the overallrate of production typically continued to decline,even in these giant fields. In terms of meeting theanticipated increases in demand in the future, theseexamples are not encouraging.

It can be argued that the problem lies in thelack of long-term commitment to EOR in these(and other) fields because more attractive returnsare available from new fields. Except for a briefperiod in the mid 1970s, global oil production hasrisen steadily for many decades. For an individualfield, production rates typically ramp up to aplateau that extends for some period of time,followed by a steady decline. Given this behaviourof individual fields, overall production cancontinue to increase only if new discoveries arebrought onstream faster than the existing fieldsdecline. In such an environment, most operatorswill have a choice: they can invest in explorationand develop new fields, or they can invest inrecovery methods that will slow down the rate atwhich production declines from mature fields. It isnot surprising that most choose the former option.

There is another possibility that must beconsidered. Implementing an EOR project in thefield is a technical challenge that requires carefuldesign; a solid understanding of the geology,petrophysics, geochemistry and reservoirengineering characteristics of the field; andexperience with the EOR method being applied.The time required for the first two items in this listis usually longer than the time available forbusiness and investment decisions. This isespecially likely if the anticipated production ratesfrom the project are not large, as is frequently thecase with EOR. The ownership of many maturefields has changed several times, making it hard toaccumulate or to preserve a sufficiently deeptechnical understanding of the asset. The lastrequirement in this list, EOR experience, is now in

short supply after nearly two decades of attrition inthe industry. Indeed, difficulty in finding enoughpeople with appropriate expertise, or the timerequired to develop a new generation of experts,may prove to be the single greatest barrier toimplementing EOR in the medium term.

A large number of fields producing at smallrates does add up to a significant contribution tooverall production. Such an aggregation may alsoallow another response to emerge to therequirement for large production rates. In someoil-producing regions such as the USA, the vastmajority of wells produce at very small rates. Overthe last fifty years, the USA has had around half amillion oil wells operating at any given time. Theaverage production rate per well has varied over aremarkably narrow range, between 10 and 20barrels per day. The arithmetic mean hides anunderlying bimodal distribution: a handful of wellsproducing at large rates, and several hundredthousand wells producing just a few barrels a day.

For an operator working entirely in anenvironment dominated by the low-rate wells, anEOR process that could sustain an increase to, say,10 bbl/d per well for a period of years would bequite attractive. A process that yielded 50 bbl/dmight seem miraculous. But such rates in factwould be achievable by any EOR method whichdeveloped a true oil bank. This is because manylow-rate wells are also producing about 100 bbl/dof water, water that is being injected elsewhere inthe field. In other words, the fluid throughput inthe reservoir is large, even though the oilproduction rate is small. Establishing an oil bankahead of water being injected at these rates wouldtherefore result in oil production rates of tens ofbarrels a day.

Whether such rates are achievable warrantsfurther discussion and perhaps a change inparadigm. This is discussed in more detail insubsequent sections. Here we remark upon theother consequence of operating in a low-rateenvironment: the need to contain operating costs.Producers are now long accustomed to having littlecapital for field development when well rates areso small. New EOR technology that might deliveran oil bank thus faces a dilemma. Without a trackrecord, it will be impossible to get operators inlow-rate fields to invest their scarce capital.Operators with a wider portfolio of fields mayhave more capital available, but don’t need thetechnology in their high-rate fields, and in any casewould prefer to invest it in other prospects.

Focusing on small fields has some advantages.One is that industry would be able to rebuild a





broader base of expertise in EOR methods.Another is that modifications to existing methods,or new methods, could be tested more rapidly andwith smaller economic risks. On the other hand,suppose that a method was implemented in a smallfield that recovered 20% of the remaining oil inplace over a ten year period, doubling the fieldproduction rates during much of that decade. Thiswould be an obvious technical success and a likelyeconomic success. But if the field produced only1,000 bbl/d at the beginning of the project, theincreased rate would not have much effect onglobal supply. To achieve the rates needed to makea difference, the challenge would be to deploythousands or tens of thousands of EOR projectsmore or less simultaneously. Whether the capitalnecessary for a venture of this magnitude could beobtained may become the critical question.Nevertheless, getting a modest increment of 500bbl/d from each of 10,000 fields would offsetsubstantial declines in production from largefields. Is this achievable with existing EORtechnologies? The answer lies in the role ofreservoir heterogeneity (see below).

If oil rates are critical, then EOR will not betaken seriously until a few years after the infamouspeak in global oil production arrives. At that point,all operators will have a narrower spectrum ofinvestment options: which existing fields toattempt to maintain production from, and whichabandoned fields to attempt to resuscitate. Eventhis scenario assumes that operators are onlyconcerned with conventional oil. If other primarysources such as heavy oil, tar sand, and oil shalecan be developed fast enough to keep up withdemand, then in effect the peak in global oilproduction will have been deferred yet again.Bringing on new production, even from moredifficult and expensive unconventional sources,will be more attractive than investing in assetsfrom which production will continue to decrease.

Extensions of existing EOR methods The limitations of existing EOR methods have

been described in some detail in the literature. Thedescriptions indicate several areas in whichincremental advances in the technology would bebeneficial. For example, chemicals that withstandhigher temperatures and salinities would extend theapplicability of polymer and surfactant floods andenable mobility control in miscible floods in deepreservoirs. However, this document will omit acatalogue of the other areas for likely developmentin favour of a surprising but far-reachingobservation: a large number of reservoirs, perhaps

as many as half of them, are not good candidatesfor any of the existing methods. The potentialimpact of incremental advances should thereforenot be underestimated.

This observation is based on the sets ofscreening criteria that have been developed formost methods. Reliable screening will be essentialif EOR is to contribute cost-effectively to overallproduction, and there is sufficient experience withmost methods for reasonably good criteria to havebeen developed. Now, a common measure of thepotential benefit of EOR is the amount of targetoil. The usual calculation of the target volumeapplies typical sweep and displacementefficiencies to the original oil in place in allexisting reservoirs, without applying anyscreening. If many of these reservoirs are not infact amenable to EOR, this points to a researchpriority: what methods might be developed to workin these reservoirs?

This point is implicit in the National PetroleumCouncil (United States) report on EOR carried outin 1984. The working group estimated that nearly15 billion barrels of oil could be recovered byimplementing then-available technology, and thatalmost twice that amount would be recoverable ifadvanced technology were developed and applied.The estimates included a careful accounting foreconomic factors, not just the technical issues. Thetotal resource base on which the analysis wasapplied amounted to more than 300 billion barrels,of which about 200 billion would have been inplace when the EOR methods were applied. Thusthe estimates of oil economically recoverable byEOR represented a small fraction of the remainingoil in place, around 10%. Assuming typicalrecovery efficiencies for the EOR methods, thissuggests that less than half, perhaps less than onethird, of the reservoirs passed the screeningcriteria. It follows that more casual estimates ofEOR potential, derived from accumulating the oilremaining in place in reservoirs worldwide andmultiplying by a reasonable average recoveryfactor, will be more optimistic. More importantly,these estimates highlight the need for EORtechnologies that are applicable to more types ofreservoirs. It is important to note that the criteriafor applicability are not just technical (e.g.maximum reservoir temperature, formation brinesalinity, oil viscosity) but also economic.

While screening criteria are useful, it isaxiomatic among EOR workers that any methodmust be carefully tailored to an individualreservoir. In other words, there are no ready-maderemedies or methods. The properties of the oil, the

production history, the type of secondary recoveryprocess (if any), the presence or absence of aquifersupport and gas caps, the heterogeneity of thereservoir, the chemistry of the formation water, themineralogy of the formation, the pattern of wells,the temperature and pressure of the reservoir, allcan influence the design of an EOR process.Implementing EOR requires expertise in classicalreservoir engineering as well as in the principles ofenhanced recovery. It also requires time: time forlaboratory studies to support the design work, timefor characterizing the reservoir and its history, timefor designing and pilot testing the process. Sinceeach reservoir project requires the dedication ofexpert staff, a large scale effort in EOR will requirea major investment in human resources by theindustry. Even if relatively simple and low costmethods can be established, such as improvingsweep efficiency by adding nutrients for reservoir-indigenous microbes to the injection water in awater flood, applying those methods to a largenumber of fields will still represent a significantinvestment. This presents once again a competitionwithin the industry for capital and resourceallocation between EOR and new sources ofprimary production. The future of EOR in the nearto medium term will depend upon this competitionas much as upon the merits of individual EORprocesses.

The combination of technologies is the mostlikely new approach for EOR in the future. Forexample, the advent of permanent sensors thatprovide real-time, downhole data makes itconceivable to operate an EOR process in the sameway that large scale engineering facilities areoperated on the Earth’s surface. Injection rates andvolumes and concentrations of injected chemicalscould be varied in response to observed rates andpressures in wells so as to optimize oil recovery.The missing link here is a predictive model of thereservoir. The control loop requires us to predictrather accurately the response of the productionwells to variations in the injection well conditions.It remains to be seen whether the reservoir can becharacterized well enough to enable this prediction.

These capabilities are emerging for applicationto primary and secondary recovery projects, andare adaptable to EOR. On the other hand,time-lapse seismic monitoring offers the prospectof tracking injected and displaced fluids and isparticularly suited for gas injection because of thedensity contrast with brine and oil. It could helpoptimize the operation of an EOR project, if thecost of data acquisition can be reduced. Anotheradvance in the seismic monitoring of EOR would

be higher spatial resolution. The ability to tracksweep efficiency would undoubtedly lead to betterunderstanding of the strengths and limitations ofexisting EOR processes.

Incorporating advances in drilling technologycould dramatically alter the future of EOR, eitherby making it unnecessary or by making it muchmore efficient. Drilling advances will not be drivenby EOR considerations, but practitioners alert tothe implications of these advances for sweepefficiency could usher in a new era.

The most fundamental difficulty with oilreservoirs is that they are located hundreds orthousands of metres below the earth’s surface. Themeans for getting the oil to the surface has notchanged since the inception of the industry:drilling a well from surface to reservoir. Themethods of drilling have of course changeddramatically during the last century, but the ratio ofwellbore diameter (a few tens of centimetres) toreservoir extent (a few kilometres) has not. Evenwith the advent of horizontal and multilateralwells, even in fields with densely spaced wells,nearly all the oil in the reservoir must travelthrough tens or hundreds of metres of rock to reacha wellbore.

A much larger gradient in potential is necessaryto move oil through rock than to move it through awell. More critically for EOR, rock properties canvary over length scales as small as a fewcentimetres. Fluids travelling tens of metres willtherefore encounter a significant range ofheterogeneity. Consequently injected fluids willfind preferential flow paths, and the greater thetravel distance between injector and producer, thelarger the volume of rock that is not on these paths.Being able to place wells closer together reducesthis volume and increases the sweep efficiency ofthe displacement.

An alternate statement is that closer spacingallows the operator to impose a larger localpressure gradient in regions that would have hadsmall fluid velocities (and therefore be poorlyswept) at larger spacing. Because most EORprocesses involve injection, the improved sweepefficiency offered by closer spacing would alsoincrease the effectiveness of these processes. Thecost of drilling wells is therefore quite important tothe future of EOR, though as discussed below,drilling costs also affect exploration anddevelopment of fields during primary recovery.

Geometrically, wellbores are essentiallyone-dimensional objects within athree-dimensional reservoir. Mathematically,wellbores can be approximated as line sinks and





sources. One way to avoid the limitations describedin the preceding paragraph is to increase thedimensionality of the well. This is the premise ofhydraulic fracturing: by establishing atwo-dimensional aperture within the formation, theflow field sees a plane of small potential near thewell, rather than a line of small potential. Thisincreases productivity of the well because more oiltravels through less rock to reach the wellbore. To asmall extent, the shorter travel path may alsoincrease the sweep efficiency of a displacementprocess, but this is offset by the greater probabilitythat encroaching or injected water will reach thefracture sooner.

These considerations lead to the question ofwhether new ways of establishing hydrauliccommunication with reservoirs that would improvesweep efficiency can be developed. If so, the effecton EOR is likely to be negative. This is becauseoperators could obtain greater recovery duringprimary and secondary recovery from existing andnew fields. This would reduce the need to recoveroil from already depleted reservoirs. In a field thathas already been swept using conventionalline-source and line-sink wells, it will be moredifficult to realize retroactively the benefits ofwells that are not line sinks.

Oil and gas regulators place limits on thedensity of conventional wells in a field. Evenwithout this constraint, the large cost of drillingwells has driven operators to develop fields with asfew wells as possible. Thus the potential technicalbenefit (increased sweep efficiency) of a large welldensity has not been tested in practice. The conceptof microhole drilling has been advocated to reducethe cost of drilling conventional wells. The idea isto extend the notion of drilling from coiled tubingunits until boreholes two inches in diameter can beconstructed. The goal of current development isthat the microholes would cost half as much asconventional well construction. Should thistechnology be successfully deployed, it could openthe path to the low cost construction of drainholes:many small diameter holes extending longdistances into the reservoir from a singleconventional well. This idea is not new, but itcannot be implemented to the extent needed toincrease sweep efficiency appreciably until the costdrops substantially. Even with recent advances indownhole motors, geosteering, etc., wellconstruction is still very dependent upon largecapital investment.

The evolution of long-reach horizontal andmultilateral drilling gives some indication of thetime required for practical and economically

feasible technology to be developed. Only in thelast decade or two have horizontal wells becomewidely utilized. They still cost several times asmuch as a vertical well. The driver for horizontaland multilateral well construction has always beenthe increase in production rates, which can be anorder of magnitude greater than a vertical well. Thelarger productivity justifies the greater investment.This consideration will be one of the difficultiesfor the drainhole concept. While a dense array ofdrainholes emanating from a well will reduce theaverage distance traveled by oil and therebyimprove sweep efficiency, the incremental increasein productivity will become progressively smalleras the number of drainholes increases. Near-termproduction rates dictate the economics of fielddevelopment, not long term recovery factors. Thusit will be difficult to justify this type of wellconstruction unless the incremental cost and timerequired to construct a drainhole is very small.

Improving sweep efficiency without drilling The preferential flow paths that cause poor

sweep efficiency are the inevitable consequence ofhaving a relatively small number of line sourcesand sinks (wells) in a three-dimensional rockstratum that has heterogeneous permeability.Unless and until drilling costs drop by at least anorder of magnitude, traditional approaches toimproving sweep efficiency will probably continueto be applied in the future.

The basic idea of these approaches has been toamend the injected fluid so that the preferentialflow paths become less attractive. This has usuallymeant reducing the mobility of fluid in thepreferential paths, for example by injecting apolymer solution or foam rather than brine. Thisimproves the ratio of the mobility of the displacingfluid to the mobility of the displaced fluid, thusreducing the instability of the interface between thefluids and hence the tendency to form preferentialflow paths. Promoting the growth of indigenousmicrobes by adding appropriate nutrients to theinjected brine has the same objective but employs adifferent mechanism: reducing the mobility of fluidin the preferential flow paths that have already beenswept. Nutrient preferentially arrives in those paths,and the growth stimulated by the nutrientsdecreases the permeability of the rock. Recentlydeveloped, advanced polymers that change theirmorphology in response to changes in temperatureor brine composition also reduce mobility in thewater-swept rock.

The common characteristic of these methodsfor improving sweep efficiency is that, when

applied, they increase overall resistance to flowthrough the reservoir. It follows that it will be evenmore difficult to obtain large production rates fromthis class of EOR methods. This is inevitable sincethe methods force displacement to occur withinnon-preferential flow paths. In contrast, a methodthat pulls the oil into the preferential flow paths,rather than pushes it through the regions of smallerpermeability where the oil originally resides,should be able to produce at much larger rates. Nosuch method is known, but the situation isanalogous to naturally fractured reservoirs. Forthose reservoirs, the idea of spontaneousimbibition of brine into the matrix blocks isattractive, because direct displacement of oil byflow through the matrix blocks is not required. Thedisadvantage is that the rate at which oil isdisplaced from the matrix into the fracture is slow,because it is governed by gradients in capillaryforces. Methods to speed up this displacementwould be of great benefit to EOR.

Mechanisms in EOR processingIt is commonly observed, in miscible and

in surfactant floods that the injectedrecovery-enhancing chemical arrives at producingwells simultaneously or even ahead of the oil.Increased oil production does occur, but the oil iscommingled with the injected components. Thisbehaviour is not what simple theory predicts, andthe discrepancy may reveal a fundamental insightinto the future of EOR.

A common conceptual picture of the processesthat increase displacement efficiency, such asmiscible flooding and surfactant flooding, derivesfrom fractional flow theory. The theory assumesone-dimensional flow and shows that the couplingbetween phase saturations and phase relativepermeabilities gives rise to a set of fronts (changesin saturation or composition or both) thatpropagate through the reservoir. The front with thelargest velocity is the oil bank, a region of mobileoil at saturations appreciably above the residualsaturation. The bank is formed from oil mobilizedby the injected solvent or surfactant. Fractionalflow effects cause the velocity of this mobilizedoil phase to be larger than the velocity of the otherphases and components, so that solvent orsurfactant travel more slowly.

Why then do solvent and surfactant not arrivelater in the field? A likely explanation isheterogeneity, though the instability known asviscous fingering also contributes. By definition,one-dimensional flow cannot account for either ofthese phenomena. Yet the guaranteed existence of

preferential flow paths in any reservoir wouldnaturally result in rapid arrival of injectedcomponents along those paths. If those pathsoccupy a relatively small fraction of the reservoirvolume, the amount of oil mobilized along thepath will also be small. This suggests that much ofthe oil produced by these EOR methods in thefield is not being displaced by the solvent orsurfactant. Instead it is being dragged along withthe injected fluid. More precisely, oil orcomponents of the oil phase are transferring fromvolumes of bypassed or residual oil into the streamof solvent or surfactant solution flowing past. Thismechanism has been used very effectively inenvironmental applications. After a high viscosityfuel oil had contaminated a fractured rock withsmall matrix porosity, a specially designedsurfactant solution was injected through thefracture network. The surfactant solubilized theheavy oil, creating a low-viscosity emulsion. Avery large recovery efficiency was accomplishedeven though the process never induced the oilphase itself to flow.

The implications of this assertion are profound.Foremost is that the rate of production will belimited by mass transfer, not by the rate at whichfluid is injected. If oil is being extracted into theflowing fluid, banks of large oil saturation cannotform and move ahead of the injected fluid. Rates ofproduction and incremental recovery estimatedfrom one-dimensional experiments and theorieswill be optimistic. This makes maintaining sweepefficiency at least as important to technical successas the factors influencing phase behaviour, whichtraditionally receive more attention in miscible andsurfactant flooding. This is not to suggest thatthose methods do not employ mobility control. Onthe contrary, it was recognized very early thatsurfactant injection without polymer is futile; andthe problems with gravity override andunfavourable solvent-to-oil mobility ratio are nowwell known in miscible flooding, and have led to avariety of process improvements. The point here isthat reservoir heterogeneity is the single greatestobstacle that is common to many EOR methods.Injected fluids find the path of least resistance to aproduction well and in so doing never contact thegreater part of the oil remaining in the reservoir.Because achieving the desired phase behaviourbetween crude oil and solvent or surfactantgenerally assumes good mixing between the fluids,these methods are doomed to be much lessefficient if preferential flow occurs.

This line of reasoning leads to another proposition:since preferential flow seems inevitable with current





technology, the design basis for miscible andsurfactant floods should be revised. Instead of thetraditional approach of tailoring compositions toachieve optimal phase behaviour while flowingthrough the rock containing oil, the compositionshould be designed with the assumption that the slugwill flow past the oil-containing rock. It may be thatthe optimal compositions for the latter type ofextractive recovery mechanism would be quitedifferent from compositions optimal for adisplacement-based mechanism.

Agents for mobility control are necessary formiscible floods and surfactant floods, and thesemethods achieve 10% to 15% recovery ofremaining oil in place. But much larger recoverieswould likely be attainable if better sweep could beimposed. Indeed, one of the reasons that thermalrecovery of heavy oil is generally more successfulthan other methods, typically recovering more than50% of the oil in place, is that to a great extent itrelies on the conduction of heat into the formationand the oil, not on advective transfer. Conductionis almost completely insensitive to variations inpermeability, and thus the injected thermal energyis not channeled into preferential paths.

Despite being widely recognized, poor sweepefficiency is the oil recovery problem on which theleast progress has been made. The main methodsthat address it are polymer flooding andwater-alternating-gas injection in miscibleflooding. Polymer flooding remains one of theleast successful methods in terms of average rate ofproduction per project, 1,300 bbl/d in the mostrecent survey (Moritis, 2004), and in terms of thefraction of remaining oil in place recovered,typically 5%. These methods actually address theissue of viscous fingering, the instability inherentwhen a fluid of greater mobility (CO2, water) isinjected into a formation containing a fluid ofsmaller mobility (oil). The instability evolves localpaths (fingers) of preferential flow. But fingering isonly part of the cause of poor sweep efficiency.The existence of paths that connect a series ofregions of (locally) larger permeability between aninjector and producer is inherent in anyheterogeneous reservoir, and these preferentialflow paths will dominate the behaviour whetherviscous fingering occurs or not.

Methods that address the problem ofpreferential flow paths have not been widelyimplemented. Once the preferential paths haveformed, one strategy is to inject a slug of fluid thatenters these paths, just as previously injected fluidhas. The chemical composition of this slug ischosen so that the slug reacts once it has filled the

preferential flow paths. The reaction either reducesthe permeability of the rock within that path, forexample by precipitating a solid onto rock grainsurfaces, or increases the viscosity of the carrierfluid, for example by crosslinking a polymer. Bothchanges have the same result: the path occupied bythe slug is no longer one of least resistance.Subsequently injected fluids – which can be water,solvent, or chemicals, depending on the recoveryprocess – will tend to flow around the affected rockvolume. New preferential flow paths will of coursearise, but these will pass through rock thatpreviously had seen little or no injected fluid. Oilin these paths will be displaced, and the processcould then be repeated, in principle displacingnearly all the oil in place, but at production ratesmuch larger than are typical of mature waterfloodsand many EOR processes.

The technical challenges for this strategy arenumerous. Foremost is designing a chemical trigger.The ideal slug must propagate with little resistanceto flow so that it can fill most of the existingpreferential flow path. Failing to fill the existingpath compromises the beneficial effect, for theunfilled part will certainly be found by subsequentlyinjected fluids. Water-like flow resistance isimportant during placement. Otherwise injecting asufficient volume of slug will either require muchlonger than operators are likely to wish to wait, orwill require injection above the parting pressure.This resulting fracture would create a preferentialpath that occupies little rock volume and thus islikely to defeat the purpose of the treatment. Theactive agents in the slug should propagate withoutinteracting chemically with the rock or theformation fluids. Even a small degree of interactionper unit volume would lead to large losses of agentsbefore the slug reached the far end of thepreferential path.

The chemical trigger would then be activated in acoherent way, so that mobility decreases by a largefactor (say 10 or more) simultaneously throughoutthe filled path. If mobility decreases in part of thefilled path sooner than in other parts, thensubsequently injected fluid will push the still-mobilepart of the slug around the region of low mobilityand into previously unswept regions of the reservoir.When this diverted material eventually causesmobility to decrease, oil in those regions will beshielded from subsequently injected fluids.

Once the mobility reduction has occurred, it shouldbe long-lasting. The subsurface is a hostileenvironment. Degradation of materials such aspolymers is a serious problem, especially in deep, hotreservoirs. Finding a material or a method that

satisfies these severe performance requirements wouldhave a tremendous impact on the future of EOR.

An alternative view of sweep efficiency Because the achievable production rates from a

project, whether EOR or primary recovery, willbecome ever more important in the industry, it isimportant to realize that the paradigm implicit in allcurrent technologies addressing sweep efficiencyhas a fundamental flaw. In every case, the goal ofthese technologies is to reduce mobility in some partof the reservoir. This means that, to the extent theprocess succeeds in achieving this technical goal,the rates of throughput – fluid moving to producersfrom injectors – will decrease. This is self-defeatingin economic terms, unless the improvement in sweepefficiency leads to significant oil banks beingformed. Smaller flow rates containing largerfractions of oil could easily lead to larger revenues,since many EOR candidate fields produce at verysmall oil cuts. But as noted above, such oil banks arenot commonly observed. Moreover, severaliterations of plugging preferential flow paths andcreating new ones is likely to be needed to recoversignificant fractions of the remaining oil. Unless oilis recovered as a bank or slug of large saturationfrom each new preferential path – and perhaps evenif a bank does form – the achievable productionrates will decrease with each iteration. It follows thata critical requirement for the future of EOR is thedevelopment of methods to improve sweepefficiency that also reliably establish oil banks.

It would be possible to mitigate the decrease inthroughput caused by mobility-reducing EORmethods by adjusting bottomhole pressures.However, a slug that effectively blocked most of apreferential flow path could easily reduce the wellinjectivity by half. Doubling the difference betweeninjection and production wells would compensate,but injection pressure is constrained by the partingpressure of the formation. This remedy can only beapplied until that limit is reached, and it willincrease operating costs. Reducing the bottomholepressure in production wells will also help, but aswith injectors there is not much room foradjustment. The costs of artificial lift would offsetthe revenue from larger production rates.

Is a paradigm shift possible for methods thatincrease sweep efficiency? For example, instead ofblocking the best paths in the reservoir in order toforce fluid through the next-best paths, why notcause oil to be fed into the best paths? As notedabove, this may in fact be the way in which manymiscible and surfactant floods work in the field,though they are not designed to work that way.

The key problem with extracting oil from theunswept regions in this way is that production ratesare likely to be small. This is because the drivingforce for oil movement is likely to be small. If theoil is not being moved as a bulk phase out of theunswept regions by viscous forces, then onlygradients in capillary pressure, chemical potential,surface energies, or other diffusion-likemechanisms are available. Such gradients may beoperating, for example, during waterfloods infractured carbonate reservoirs. Waterspontaneously imbibes into matrix blocks, causingoil to drain into the fracture network and to beproduced. If these gradients can be made largeenough, for example by altering the salinity offormation brine or wettability of the reservoir rock,it is conceivable that production rates couldincrease accordingly. In the case of sweepefficiency, however, the overall production rate willbe proportional to the area of the mathematicalsurface separating the volume of a preferentialflow path from the rest of the formation. This islikely to be much smaller than the area forimbibition in a fractured reservoir, and thus therates observed or inferred in those reservoirs maynot be achievable for extractive recovery fromunswept regions.

Preferential flow paths arise because of wellplacement. Another way to change the sweepefficiency paradigm therefore would be to createnew best paths by shutting in all existing wells anddrilling a new set of injectors and producers indifferent locations. This is a radical idea in anindustry where the cost of well construction islarge. Indeed, as noted above, infill drilling, whichdoes not require abandoning existing wells, is awidely practiced method for extending the life of areservoir, and probably would be practiced stillmore if drilling costs were smaller. But if drillingcosts were to decline by, say, two orders ofmagnitude, imposing a new well pattern on a fieldcould be the simplest way to obtain better sweepefficiency with no decrease in production rates.

Heterogeneous permeability in a reservoirhandicaps any recovery method in which fluids arepushed into the reservoir from one set of wells, whilefluids are withdrawn from others. This includeswaterflooding as well as all non-thermal EOR methods.

Technology developments outsidethe oil industry and EOR

Overview Developments external to the oil industry can

affect the future of EOR in two ways. One way is to





substitute for hydrocarbons in end-use applications.The other is to enable new methods of producing oil.We consider both possibilities in this section.

Around two thirds of each oil barrel is used for themovement of goods and people. The substitution ofother fuels for gasoline, diesel, fuel oil, jet fuel, etc.will of course decrease demand for oil, but because ofthe sheer scale of the current hydrocarbon-fueledeconomy, any substantial substitution will take a longtime. Moreover, substitution may be difficult orimpossible in some sectors (aviation, maritime,long-distance trucking). These applications require a few tens of millions of barrels of oil perday and are expected to grow. It is conceivablethat this level of production could be sustainedover the course of a few decades without resortingto EOR. For this to happen, production fromunconventional sources would have to increasefairly rapidly during the transition to this lowerlevel of demand. The increase must make up thedifference between demand and supply fromconventional sources, and this difference isexpected to increase rapidly.

A substitute for gasoline would have the greatestimpact on oil demand, because nearly half of everyoil barrel goes to gasoline. Furthermore, fuelsubstitution is feasible in automobiles, as shown byexperience with ethanol, biodiesel, liquefiedpetroleum gas and compressed natural gas; andwith electric motors and gasoline/electric hybrids.None of these alternatives presently account for alarge share of the market, however. One reason isthat gasoline internal combustion engines have setthe de facto standard for consumers’ expectations ofperformance. A more pragmatic reason that also hasbroader implications is that consumers are reluctantto leave the existing infrastructure that supportsgasoline-powered automobiles. Gasoline is widelyavailable, thanks to decades of investment inrefineries, pipelines, and surface distributionnetworks. Establishing a replacement will requireestablishing a distribution system comparable tothat for gasoline. This is an extraordinaryrequirement, given that more than ten millionbarrels of gasoline are produced, distributed, andconsumed daily in the United States alone. Theinfrastructure for electricity is large enough,making electric cars and gasoline/electric hybridsthe external technologies most likely to affectgasoline demand and hence EOR.

Development of alternative fuels may behastened by long periods of relatively expensive oiland gasoline. Such periods are inevitable if EOR andsources of unconventional oil cannot be developedrapidly enough to fill any shortfall between demand

and production from conventional sources. Thustransportation requirements are driving a feedbackloop that could settle into either of two quitedifferent states. In one, cars and light trucks run onnon-hydrocarbon fuels and oil demand is about halfof what it would otherwise be. In the other, EOR,unconventional sources, and exploration for newfields enable the consumption of acceptably pricedoil to continue to increase.

Arriving at either state requires prodigiouscapital investments. If the evolution towards onestate or the other is left to market forces, then thepace of technology development will be crucial. Ifconsumers can maintain their mobility innon-hydrocarbon fueled vehicles at costscomparable to historical levels for hydrocarbonfuels, then the incentive for EOR declines. On theother hand, if EOR plays a role in keeping the costof hydrocarbon fuels at levels acceptable toconsumers, then the incentive for large-scalealternate fuels declines. In this respect, EOR hasthe advantage of several decades of research anddevelopment, plus the existing infrastructure forhydrocarbon processing.

Whether the evolution will be left entirely tomarket forces is another matter, of course. In thatdiscussion, policymakers’ perceptions regardingthe capability of EOR to deliver oil at significantrates would be pivotal. The questions discussedabove regarding sweep efficiency and oil bankswill thus remain in the spotlight.

Microdevices and nanodevices As discussed above, the physical cause of

residual oil is the predominance of capillary forcesat length scales of order 10�6 m, the size of typicalpore throats in reservoir rock. It is now possible toconstruct Micro-Electro Mechanical Systems(MEMS), devices whose parts are measured inmicrons. Can such devices be useful for EOR?

One way to answer this question is to build adevice that mimics the behaviour of existingdevices, a common approach to introducing newtechnologies. In the case of EOR, the existingdevices are usually chemicals. Polymers are a goodexample. Increasing the viscosity of water byadding polymer to it is a way to improve sweepefficiency. Further improvement is possible if thepolymer solution is shear-thickening. If such asolution is travelling rapidly through a rock, itsapparent viscosity increases. This behaviour willcounteract the tendency of polymer solution totravel preferentially within already-swept regions.

One can imagine a device which mimicsshear-thickening behaviour. If the device senses

that it is travelling rapidly, or is experiencing largeshear rates, then it would extend amicro-mechanical arm. If the device senses that itis travelling slowly, the arm would be retracted.These actions would change the effective size ofthe device, so that the apparent viscosity of thewater containing the devices would change.

This is a simple example of a smart fluid, theproperties of which change in response to itsimmediate environment. The technical utility ofsuch fluids is not in doubt. The key question fortheir future use in EOR is economic. The unit costof a manufactured device will have to be extremelycheap, almost infinitesimal, in order to competewith existing fluids. The number of polymermolecules used in a polymer flood is astronomical.A typical slug size is one tenth of the volumeoccupied by oil in reservoir. For an averagereservoir, this volume might be of order 106 m3. Ifthe concentration of polymer in the slug is 0.01%by weight – a dilute concentration – then the massof polymer required would be 102 t. Assuming apolymer with average molecular weight of105 g/gmol, this amounts to 1027 polymer molecules.Polymer costs are on the order of $2 per kg, or$10�22 per molecule, so acquiring the necessarynumber of molecules for the polymer flood wouldcost $200,000. Acquiring the same number ofMEMS devices for the same price will requiresignificant advances in self-assembly technology.

This comparison assumes a one-to-onereplacement of each polymer molecule by ananodevice. Suppose instead that a single devicewere as effective as, say, one million polymermolecules at changing the viscosity of the carrierfluid. The smart fluid injection process would stillhave to deploy 1021 devices at a cost of $10�16

each in order to be competitive. Clearly thisrepresents a significant barrier for small devices toenter the EOR market.

It is worth noting the root cause of thisproblem, namely the large scale of the oil industry,producing tens of millions of barrels daily fromthousands of fields around the world. Any widelymaterial used in this industry must be available inlarge quantities. This results in extraordinarypressure to reduce the cost of that material or todevelop less expensive substitutes. The benchmarkthat determines what is expensive is the price ofoil, the commodity being produced. The morecostly the material used in an EOR process, theless of it one can use in that process. (This is whypolymer and surfactant floods for EOR use smallslugs of those active ingredients.) Theseobservations are not profound, but their

implications regarding the entry barrier for newtechnologies are significant. The economies ofscale from which existing chemical devices benefitare not yet available for nanodevices.

In contrast, MEMS and nanodevices cancertainly make feasible new or specialtyapplications, notably in the medical field, forwhich no alternatives exist. Such applications canbe pursued more readily since no benchmarkcost-to-capability ratio exists. Eventually one ofthese applications may mature into a globalcommodity industry, and at that point it will beeasier to determine whether small devices couldmake a comparable difference in EOR. In themeantime, it is difficult to envision any seriousapplication of this technology for EOR.

Given the economic disadvantage of buildingdevices that mimic behaviour of existingchemicals, the obvious choice is to develop devicescapable of doing things that have not been possibleto date. Here again any new technology has adisadvantage. The mechanisms responsible forpoor displacement efficiency and poor sweepefficiency are well known and small in number.Thus almost every possible combination ofmechanisms has been implemented in someprocess at some time in the last fifty years, thoughwith widely varying success. A potentially fruitfulapproach would therefore be to identify acombination of mechanisms for which an efficientprocess has not yet been implemented, and then todevelop a device that addresses that combination ofmechanisms. An example is in situ production ofrecovery enhancing chemicals (polymers toimprove sweep efficiency, surfactants to improvedisplacement efficiency, diluents to reduce oilviscosity, etc.). A process that created theseexpensive compounds within the reservoir shouldhave much smaller logistics and materials coststhan a process that procures these compounds fromsurface factories and injects them into thereservoir.

Microbes living within the reservoir offer atantalizing opportunity to implement EOR with insitu production of the relevant chemicals. However,despite half a century of research and development,very few commercial successes of microbial EORhave been reported. One reason is the relativelysmall rate of reaction in microbial systems. Amicrodevice that produced chemicals faster, withmore complete conversion of reactant to productand greater specificity (fewer byproducts), wouldhave a significant advantage over its biologicalcounterpart. Such a device is at least conceivable,given the advent of lab-on-a-chip devices. Making





them economic is a tremendous challenge, giventhe small cost of microbes.

A counterargument to this rather pessimisticoutlook is the remarkable decline in the prices ofsemiconductor devices during the last two or threedecades. The first commercial microprocessorcontained 2,300 transistors and cost about 1,000dollars when it was introduced in 1971. Moderndevices may contain a hundred thousand times moretransistors yet cost ten times less. Theprice-to-performance ratio for MEMS devices andmicrofluidic reactors may follow a similar trajectoryover the next twenty years. If so, would not thesedevices be poised to revolutionize EOR?

The answer will depend on how muchmacroscopic effect can be obtained per device. Forexample, an individual microbe may convertnutrients into recovery-enhancing chemicals veryslowly, but 1 m3 of rock can easily contain a billionmicrobes. Field scale trials of this type of microbialEOR use bacteria in hundreds of cubic metres ofrock. If one device could produce 1,000 times asmuch recovery enhancing chemical per unit time asa single microbe, then hundreds of millions ofdevices would be required to achieve the samemacroscopic effect as the microbes. To date,microbial EOR has not been commerciallysuccessful. Presumably an order of magnitude moredevices would be needed for effective recovery. At aprice of 0.01 dollars per device, the materials costfor a field implementation would be of the order of10 million dollars. At this cost, it is conceivable thata field trial could be conducted. However, thedevelopment time for a 10 mm device with thisprice-to-performance ratio must be measured indecades. Current trends in device development arenot focused on obtaining large fluid throughput ratesor on aggregating many devices to produce bulkquantities of reaction product.

The size restriction to 10 mm is crucial if thedevices are to be deployed far enough into thereservoir to establish an effective chemicalproduction region. The farther the region extendsfrom the wellbore, the longer the time that reactantspecies in the injected water will spend in theregion. The longer the residence time, the smallerthe rate of reaction necessary to produce the desiredconcentration of recovery enhancing chemicals inthe fluid leaving the reaction zone. Smaller reactionrates are of course easier to achieve, especially forthe complex compounds to be produced and in thesmall devices to be deployed. Thus there is strongincentive to make the devices small enough to movethrough typical pore throats in a formation, whichmay be 10 mm or less.

In any practical application, these reactionzones will be established around injection wells.The large scale of oil field operations means thatlarge injection rates are needed in these wells. Thusto gain an appreciable residence time, the reactionzone needs to extend metres or tens of metres fromthe wellbore. This places demanding performancecriteria on the devices. Propagation of particles,whether microbes, fine silt, or other colloids,through porous media is not a trivial exercise,because a very wide range of behaviour is possible.Particles can be strained by size exclusion whenthey encounter a constriction smaller than theirdiameter. They can be filtered onto the surfaces ofgrains in the porous medium by a combination ofshort-range forces. These processes have beenstudied for over a century in diverse contexts,including water purification, riverbank filtration,and formation damage to reservoirs by finesmigration. Even so, the subject remains an activearea for research, especially when immisciblefluids occupy the porous medium, which is thecondition relevant in all reservoirs. For example,the movement of bacteria in porous media has beenwidely studied, and observed behaviour rangesfrom complete trapping as soon as the bacteriaenter the porous medium to transport acrossinterwell distances. Another avenue of researchseeks to explain the long-standing observation thatparticles too small to be strained and too large tobe filtered nevertheless do become trapped in aporous medium. As a result, most models ofcolloid transport at field scales are essentiallyempirical. The parameters in the models may berelated to mechanistic descriptions, butascertaining the values of these parametersrequires experimentation. Thus, obtaining a robustmodel for the placement of microdevices in areservoir will be a research challenge in itself. So,even if researchers complete the daunting task ofbuilding a device that rapidly converts incoming,simple chemical species to complicatedcompounds useful in oil recovery, it cannot betaken for granted that the device will work in afield implementation of EOR.

Nanoparticles The cost of micro- and nanodevices that would

be useful for EOR will be large, at least for thefirst several generations of devices, because theyare engineered. In contrast, nanoparticles andnanostructured assemblies (clusters of particles)can be useful by virtue of their size, not necessarilybecause of functionality built into the particle.(Surfactant molecules form micelles in aqueous

solution; and in this respect EOR has been usingnanostructured devices for decades.) Consequently,these would be cheaper to produce and deploy, andwould be a more attractive first step towardsemploying nanotechnology in EOR.

An example of the application of nanoparticlesfor EOR would be chemical catalysis at theoil/water interface within the reservoir. Submicronparticles could be propagated long distances withinthe formation. The tendency of particles toaccumulate at fluid/fluid interfaces is well known.If the particles contain appropriate metals, theywill have some intrinsic catalytic activity. Thepresence of such particles at the oil/water interfacemay promote the breaking of long chain moleculesinto shorter chains, decreasing the viscosity of theoil phase. This effect would be enhanced at higherreservoir temperatures. If combined with additionof heat to the reservoir, as in heavy oil and tar sandapplications, the effect might be substantial. Withsuitable additives in the water, it may be possible toconvert some hydrocarbon molecules intorecovery-enhancing chemicals. If highertemperatures are necessary to make these reactionsoccur at economic rates, the greater thermalconductivity of metal-bearing particles willpromote heat flux through the formation.

The principal challenge in this application isdetermining whether any reactions that would beuseful for EOR are feasible. A secondary challengeis achieving sufficiently rapid reaction rates.Catalytic reactors generally immerse the reactiveparticles, so that the resistance to mass transferbetween the bulk fluid and the reaction sites is assmall as possible. In the reservoir, the particles willcongregate at phase interfaces, increasing masstransfer resistance. As with all EOR methods, theparticles must be easily separated from theproduced oil, or designed not to interfere withrefining operations. This is not a trivialrequirement given the scale of throughput atrefineries.

Engineered microbes Biotechnology is a rapidly growing field. While

biotechnology applications to date have notfocused on petroleum recovery, the techniques ofgenomic engineering and metabolic engineeringmay be useful in EOR. The goal would be toimprove upon the current state of the art in MEOR(Microbial Enhanced Oil Recovery).

Currently, the most robust application ofMEOR is to promote the growth of indigenousorganisms by adding nutrients to a waterflood.Injected water invariably establishes preferential

flow paths, reducing the sweep efficiency of therecovery process. The added nutrients causebiomass to grow in the preferential flow paths. Theincrease in biomass occludes pore throats,decreasing the permeability. Subsequently injectedwater is diverted away from these paths and intoregions where little water has previously gone.

A less successful version of MEOR attempts touse in situ microbes to convert nutrients in theinjected water and a carbon source intobiopolymers, biosurfactants, or otherrecovery-enhancing molecules. One of the mostsevere performance constraints on the microbes isreaction kinetics. The microbes are placed in thereservoir in the vicinity of the injection well.Radial flow means that the injected nutrients (andthe carbon source, if injected) pass through theregion containing microbes in a short time. Thefaster the microbes consume the nutrients, thesmaller the region that must be inoculated withmicrobes.

Another constraint is specificity. If theobjective is to produce biosurfactant, then it wouldbe preferable to produce only biosurfactant.Microbes tend to produce a wide range ofproducts, however.

Yet another constraint is robustness. Manymicrobes that make a recovery enhancing chemicalare not well adapted to the higher temperatures orsalinities of reservoirs.

Genomic engineering could address theseconstraints. Instead of culturing strains of naturallyoccurring bacteria known to create useful productsand attempting to adapt them to reservoirconditions, one could identify genes in anymicrobe responsible for expressing a desiredproduct. Placing those genes in a thermophilicbacterium could yield a strain with much better insitu performance. As techniques for suchidentification and manipulation continue todevelop, it could be possible to improvesubstantially upon previous MEOR performance.The potential tradeoff is that the engineeredbacteria would be released into the environment.Though the release would be controlled, obtainingapproval might nevertheless be difficult. Thepossibility that the engineered microbes wouldreach the production well would lead to additionalpermitting and approval hurdles.

Metabolic engineering offers a less drasticapproach to overcoming the constraints. The idea isto identify the metabolic pathway – the loop ofsequential reactions – by which a microbe convertsan organic molecule into a desired product. Byexamining this pathway and its relationship to





other pathways in the organism, one may identifycompounds that could accelerate the desiredpathway, or inhibit other pathways that compete forthe same carbon source, or convert it to productsother than the desired compound. The microbeitself is not altered genetically, perhaps alleviatingsome of the regulatory issues associated with usingit in the subsurface.

It remains to be seen how much improvement inperformance under field conditions could beobtained in these ways. Laboratory and field resultswith non-engineered microbes suggest thatincreasing the rate and specificity of the conversionof the carbon source would be a desirable target, atleast as a first step. However, this may be beyond thelimit of metabolic engineering. The microbialmachinery may not be able to run that fast. It is notobvious that genomic engineering would be anefficient means of developing strains that convertnutrients more rapidly, though it should be quiteeffective at developing more versatile microbes.

Prognosis

The future of EOR in the next few decades willresemble its past in that economics will dominatetechnical issues. EOR has been studied andimplemented for several decades, but the number ofEOR projects has always been a very small fraction ofglobal activity. A sustained high oil price will makeEOR more attractive, but implementation ofnon-thermal EOR is unlikely to be widespread until agap emerges between demand and the supply capacityfrom conventional and heavy oil reservoirs. That gapmay arrive soon, though many previous predictions ofits arrival have been proven wrong. Until this event,there is unlikely to be enough incentive withinindustry or government to seek major innovations inEOR. In this sense, the future of EOR will againresemble its past, as incremental improvements totested methods gradually extend their applicability tomore fields.

A principal reason for the lack of widespreadimplementation of EOR in the past is that themethods did not yield large production rates. Therates have usually been much smaller than previouspeak production rates from a field, and muchsmaller than rates from primary production in newfields. Hence investment in the industry tends togo to projects other than EOR. If EOR is to make asubstantial contribution in the future – and such acontribution may be a matter of great internationalimportance if a gap emerges between supply anddemand – then a shift in paradigm is needed.Rather than focusing on the traditional objective of

recovering incremental oil, EOR should focus onachieving large production rates. This is feasible inprinciple, if oil banks can be formed; but in factmost projects have only slowed the decline inproduction rate from the field, rather thanincreased the rate substantially.

EOR processes in conventional reservoirs usuallydo not result in the arrival of oil banks at productionwells. The banks are expected on the basis oflaboratory behaviour and classical theory, and if theydo not materialize then small production rates areinevitable. The heterogeneity of flow propertiescommon to all oil reservoirs is the main reason for theabsence of oil banks, and hence for the lack ofimplementation of EOR. This is hardly a hereticalstatement, but too little has been accomplished inresponse to this observation. Indeed, all approachesproposed and tested to date for improving sweepefficiency are designed such that they make it harderto increase oil production rates, because they all hingeon reducing mobility along preferential flow paths inthe reservoir. Only if the approach successfullyestablishes an oil bank can the production rateincrease, and this rarely occurs. Thus, there is arationale for another shift in paradigm.

Rather than implementing methods that obstructthe best flow paths in the reservoir, methods should besought that take advantage of these paths, causing oilto move into them from elsewhere in the formation.Methods designed under the assumption that injectedfluids will flow through the oil-containing rock areunlikely to be optimal in the situation that often arisesin the field where injected fluids flow around and pastthe oil-containing rock.

Technology developments outside the oil industryare unlikely to change the future of EOR in the nearto medium term, with the possible exception of thereplacement of gasoline and diesel automobiles withelectric or hybrid vehicles. The technology within theoil industry most likely to affect the future of EOR isdrilling. If the cost of placing a well of any diameterin a reservoir could be reduced by one or two ordersof magnitude, it would revolutionize all stages ofrecovery, but it would advance EOR in particular.

Bibliography

Everdingen A. van, Kriss H. (1980) A proposal to improverecovery efficiency, «Journal of Petroleum Technology»,July, 1164-1168.

Holm L. (1972) Residual oil: can we recover it economically?,Society of Petroleum Engineers, SPE 4495.

Lake L.W. (1989) Enhanced oil recovery, Englewood Cliffs(NJ), Prentice-Hall.

Lake L.W. et al. (1992) A niche for enhanced oil recovery inthe 1990s, «Oilfield Review», January, 55-61.

National Research Council (1979) U.S. energy supplyprospects to 2010: the report of the Supply and deliverypanel to the Committee on nuclear and alternative energysources, Washington (D.C.), National Academy of Science.

Netschert B. (1958) The future supply of oil and gas, Baltimore(MD), Johns Hopkins Press.

Stalkup F. (1983) Status of miscible displacement, «Journalof Petroleum Technology», April, 815-826.

References

Moritis G. (2004) EOR continues to unlock oil resources, «Oiland Gas Journal», 102, 45-52.

NAS (US National Academy of Sciences) (1974) Energy: futurealternatives and risks, Cambridge (MA), Ballinger.

National Petroleum Council (1984) Enhanced oil recovery,Washington (D.C.), National Petroleum Council.

National Research Council (1982) Outlook for scienceand technology: the next five years. A report of theNational research council, San Francisco (CA), W.H.Freeman.

Simmons M. (2002) The world’s giant oil fields, M. KingHubbert Center for Petroleum Supply Studies, Golden (CO),Hubbert Center Newsletter #2002/1.

Steven L. BryantDepartment of Petroleum and Geosystems Engineering

The University of Texas at AustinAustin, Texas, USA



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