Enhanced oil recovery: Definitions, fundamentals, applications, and research frontiers

RALPH SIMON

Chevron Oil Field Research Company, P.O. Box 446, La Habra, CA 90631, USA

Abstract--This paper describes the highlights of current oil-recovery technology, in- cluding primary, secondary, tertiary, and enhanced recovery processes. Fundamental displacement phenomena are discussed: (1) from a macro-view, such as injection- and production-well patterns, impermeable barriers, and geologic faults: and (2/ from a micro-view, which considers oil displacement on a pore-by-pore basis in a three- dimensional interconnected network of flow channels.

Applications used to illustrate displacement fundamentals include the major features of water, polymer, and micellar flooding; and steam and CO 2 injection.

Also discussed are two principal frontiers of enhanced oil recovery research: defini- tion of the reservoir, and independent measurement of the amount of oil in place.

DEFINITIONS

Oil recovery processes have been defined as primary, secondary, and tertiary. Primary processes produce oil by natural energy when the reservoir is opened to the lower pressure of a producing well. Secondary recovery assists oil to flow by providing energy through injected water or natural gas. Tertiary recovery has come to mean assisting oil production by methods other than water or natural gas injection.

To illustrate further, primary recovery can result from several mechanisms: liquid expansion, rock-pore volume compression, solution gas drive, displacement by water from an underlying aquifer, and a combination of gas-cap expansion and gravity drain- age. For example, when reservoir pressure decreases as oil flows to the producing well, a pressure drop of 68 bar allows a typical liquid expansion of 1 vol.%. Concurrently the rock matrix compacts, compressing the pore volume by 0.5%

When the fluid pressure goes below the reservoir oil bubble point pressure (the vapor pressure at reservoir temperature), gas comes from solution and builds a gas 'saturation'. A 'solution gas drive' results which causes both gas and liquid to flow to the producing well. Typical oil recovery by this mechanism is 15-20% If there is an active aquifer or significant gas cap, these can also supply energy to displace oil. Typical recovery by these mechanisms is 15-20% of the original oil in place.

In secondary recovery, when oil is displaced by injected water, recovery depends on oil viscosity. For example, for viscous California oils, recoveries can range from 20-30%; for less viscous mid-continent oils, from 30-40%, and occasionally as high as 50%. Balancing the volume of water injected and oil withdrawn will maintain the reservoir fluid pressure and the rate of production into the producing wells.

Tertiary processes currently popular inject polymer solutions, steam, micellar solutions (aqueous solutions of surface-active chemicals), or CO2 :

(1) Polymers are used to increase the viscosity of water, enabling the water to displace more oil.

(2) Steam is used primarily to recover dense, viscous oil. As the steam condenses the oil is heated and the net result is a hot waterflood of an oil whose viscosity is reduced.

(3) In micellar processes, injecting surface-active chemicals dissolved in water and/or oil lowers the interracial tension between the solution and reservoir oil, allowing the solution to enter and displace oil from more pores. Micellar solutions are currently considered for recovering light oils from reservoirs having low-salinity connate water.

(4) Injecting CO2 results in several mechanisms that promote oil recovery: COz dis- solves in the oil, swells it, reduces its viscosity, and provides a low CO2-oil interfacial

447

448 R. SIMON

tension (so that the C O 2 c a n enter smaller pores containing oil). In addition, C O 2 at high pressures (> 140 bar) enhances vaporization of the gasoline fraction and carries it to the producing well. This method is used mainly for light, volatile oils in reservoirs having pressures > 140 bar.

REDEFINITION

The above information provides a basis for improving the definition of oil recovery processes: primary recovery describes those that produce oil with natural energy; assisted or enhanced recovery applies to those that supply energy to the reservoir from external sources. Thus, we can group secondary and tertiary together under the term "Enhanced Oil Recovery" (EOR). The use of this term is now generally accepted.

FUNDAMENTALS

Enhanced recovery displacement phenomena are affected by the macro- and micro- features of the petroleum reservoir rock and the properties of the injected and displaced fluids.

Typical macro features are as follows:

(1) Patterns of injection and producing wells. In the 5-spot shown in Fig. 20.1, if the reservoir rock were homogeneous and the displacing and the displaced fluids had equal viscosity, 70% of the pattern would be swept by the displacing fluid. If the viscosity ratio (injected fluid/original fluid) is < 1.0, the swept area will be < 70%.

(2) Impermeable obstacles (lenses). An impermeable obstacle reduces displacement efficiency as shown in Fig. 20.2.

(3) Impermeable barriers. Inclined strata can prevent communication between injection and producing wells (Fig. 20.3).

(4) Faults. Displacement of a stratum at a fault also restricts flow between wells (Figs 20.4 and 20.5).

The micro view of EOR considers oil displacement on a pore-by-pore basis. These pores comprise a three-dimensional, interconnected network of flow channels. The indi- vidual channels have irregular shapes (see Fig. 20.6) and a range of sizes (see Fig. 20.7), making the flow network heterogeneous.

Flow in a heterogeneous network is not uniform. In a simple, equal-viscosity miscible displacement (e.g. water displacing water, or nitrogen displacing helium), the injected fluid advances irregularly ('fingers') through high permeability paths as shown in Figs 20.6, 20.8 and 20.9. This leads to early breakthrough.

1 Producing Well

Fig. 20.1. Plan view of a five-spot showing 70% of the area swept.

Enhanced oil recovery 449

Lens --

injection WEll

Producing Well

Displaced Area

~ ~ --U ptArea ~ ....

Fig. 20.2. Plan view of one-quarter of a five-spot showing the effect of a lens.

The injection fluid mixes with the original fluid at the intersections of high- and low-permeability paths (see Fig. 20.10). Molecular diffusion between the injected and original fluids is relatively small. When the injected miscible fluid is less viscous than the original, fingering, dispersion, and early breakthrough are aggravated. Experience has shown that heterogeneity of the flow network is a prominent factor in determining EOR displacement efficiency.

~ Producing Injection Well

Well

. b , e

Fig. 20.3. Elevation view of inclined strata with an impermeable barrier.

Fault /

4 Corner " tion

icing

aced

Fig. 20.4. Plan view of five-spot with fault.

450 R. SIMON

Fault

Fig. 20.5. Elevation view of fault displaced oil zone.

In an immiscible displacement (e.g. water displacing oil) other factors in addition to heterogeneity affect displacement efficiency. These factors include wettability and entry pressure requirements. If a rock is water-wet, capillary forces attract the water into small pores, displacing oil.

Water can enter and displace oil from larger pores if the flowing pressure gradient exceeds the entry pressure requirement. Entry pressure is expressed as

Pe = 2a cos O/R (1)

. ock

FlOW Channel or Pore

Fig. 20.6. Micro-view of a miscible displacement, 1-early.

30

% of Pore

Volume

20

10 L 10 20 30

Pore Diameter, Microns

Fig. 20.7. Pore size distribution in Navaho sandstone.

Enhanced oil recovery 451

~ \ ' % . ~ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ ~

Fig. 20.8. Micro-view of a miscible displacement, 2-midway.

where Pe = entry pressure (Pa); tr = interfacial tension (N/m); 0 = wetting angle; R = representative radius of a flow channel (m).

These ideas are illustrated on Fig. 20.11. As will be shown later, some EOR processes lower tr, allowing pore entry at lower flowing pressure gradients. Otherwise small pores may be bypassed and their oil not recovered.

From the above we can conclude that oil displacement efficiency is affected by the following: the heterogeneity of the flow channel network, the size distribution of the flow channel radii, the flowing pressure gradient, the viscosity ratio of the injected and dis- placed fluids, and the interfacial tension between these fluids.

D%N

Fig. 20.9. Micro-view of a miscible displacement, 3-breakthrough.

Injected J Fluid

iginal Fluid

ith Higher Than Average V61ocity ith Lower Than Average Velocity

Fig. 20.10. Illustration of mixing.

452 R. SIMON

, Water l

. _ .

C,~.ne,. E t ~ P r e ~ ~ I ~ \ \ \ \ \ \ ~ \ \ \ \ \ \ \ \ \ \ \ ~ ( 4

Large. Non--Water W ~ ~ \ \ \ ~ \ ~ \ ~ \ \ ~ \ \ \ \,. @P ...... Req ....... t ' l \ \ \ \ \ / \ / ~ / / / / / ~

Fig. 20.11. Water immiscibly displacing oil.

APPLICATIONS

The optimum EOR process should be selected for each reservoir. This involves apply- ing the displacement fundamentals (discussed in the previous section) and economic considerations. A detailed discussion of the economics of each EOR process is not part of this paper. However, in general, the original investment, continuing operating costs, value of the oil produced and taxes must be estimated to determine if the potential rate of return on investment justifies the risk of investing in an oil recovery operation (National Petroleum Council, 1976).

The following section describes the major features of five EOR processes; the displace- ment principles involved, process considerations, potential for oil recovery, and problems that must be solved for a successful operation.

Waterflooding is generally the base case against which other oil recovery processes a r e compared. Injection water displaces oil by two main mechanisms: imbibition of water into pores with water wettable wails; entry of water into pores because the available pressure gradient exceeds the entry pressure requirement.

The principal parameters affecting waterflood efficiency include:

(1) Configuration of the oil deposit (the zone affected by primary-recovery drainage). (2) Amounts of gas, oil, and water in the deposit. High saturations of gas or water are

detrimental to oil recovery. (3) Locations of injection and production wells relative to each other and the boun-

daries of the deposit. The significance of this is indicated in the previous section under Patterns, Obstacles, Barriers, and Faults.

(4) Horizontal and vertical sweep efficiency. Vertical sweep efficiency is that fraction of the vertical cross-section between injection and production wells that is contacted by water. Vertical sweep efficiency is determined primarily by stratigraphic barriers and by varying permeabilities of the horizontal beds.

The horizontal sweep efficiency is the areal fraction of a pattern contacted by water. In a five-spot, the injected water cusps into the producing well (see Fig. 20.1) and does not displace all the mobile oil within the pattern. Horizontal sweep efficiency is controlled by the mobility ratio and the pore volumes of water injected. Mobility ratio is defined as

M = (kw/l~w)/(ko/#o) (2)

where kw and ko are the permeabilities to water and oil and/tw and/t o are the viscosities. For the simplified situation when kw/ko is constant, M oc #o//Z~. Fig. 20.12 (Dyes et at.,

1954) relates horizontal sweep efficiency, M, and pore volumes of water injected. To illustrate: if M = 4, 1/M = 0.25, sweep efficiency at breakthrough equals 53~, and

at 2.5 pore volumes injected it is 92~. Increasing M (i.e./~o//a,,) decreases sweep efficiency, while injecting more displacement volumes of water increases it. The oil that is not displaced, i.e. the residual oil, remains in isolated clusters of pores that have been bypassed by the injected water.

Enhanced oil recovery 453

Sweep ~ "~ .'~ .~ O. ' ' 4 ~ _ ~

~0 i I I t l l l l l 01 0.2 0.4 0.6 0.81.0 2.0 4.0 6.0 8.010.0

Reciprocal Mobi l i ty Ratio, I / M

Fig. 20.12. Effect of mobility ratio on sweep efficiency.

Waterflooding economics are improved at higher injection and production rates, because the return on investment comes sooner. These rates are limited primarily by reservoir rock permeability. A successful waterflooding operation requires maintaining the water injection rate. This can usually be done by removing foreign matter from the injection water and avoiding reservoir rocks with water-swelling clays.

Polymers dissolved in the flood water can increase oil recovery. A polymer such as polyacrylamide increases the viscosity of the water, diminishing its tendency to finger. Adding 0.03 wt.% of polyacrylamide increases the viscosity of water about four-fold. Referring to the previous example and Fig. 20.12, when /~w = 4, M becomes 1.0 and the sweep efficiency at breakthrough is 70%. A five-spot pattern achieves 100% sweep efficiency at 1.8 pore volumes injected.

Polymers have three principal problems that must be considered in designing the flood: biodegradation of the polymer, adsorption of the polymer on rock surfaces, and the incompatibility of some polymers with water containing calcium and magnesium salts. Chang (1978) describes field projects using polymer solutions.

Steam injection is particularly effective in shallow reservoirs containing viscous oils. The performance of a steam injection can be related to a waterflood. Reservoir rock

and oil are heated as the steam condenses, and the result is a hot waterflood. The increased displacement temperature reduces mobility ratio, increasing horizontal sweep efficiency. This is illustrated in Figs 20.13, 20.14 and 20.15.

As an example, at a reservoir pressure of 1.7 MPa steam condenses at 204C. At this temperature:/% = 0.00162 Pa.s, # , = 0.00015 Pa s,/~o//~w = 10.8, and sweep efficiency is 52% at breakthrough and 86% at two pore volumes injected.

Steam injection has an additional important characteristic. The steam distills the volatile fraction of the crude oil and carries this fraction ahead of the hot water front where the volatile material condenses. This condensate is miscible with the reservoir oil, i.e. it has a zero interfacial tension with the oil. Thus, the entry pressure required by the condensate to enter pores containing oil is zero, and displacement of oil from these pores is enhanced.

Approximately three volumes of oil can be produced for every volume that is burned to supply the heat to make the steam. Gravity tends to make the low density steam flow preferentially along the top of the oil zone, but this disadvantage is outweighed by the advantages of steam injection described above.

To ensure a successful steam injection operation, it is necessary to design for tempera- ture induced expansion and contraction of the equipment in the wells. It is also necessary to prepare for silica dissolution in the hot water. This can result in dissolving the gravel pack in the well and the reservoir rock surrounding the wellbore. Further, dissolved silica

454 R. SIMON

Viscosity, Centipoises

2000

- \ 100 --

10

1.0

' ~ Liquid ~ W a t e r

0.20

0.100 I OF 100 150 C 38

\ \

~I I Oil \

\

\ \ N

I I I 1 I 210 300 400 500 600 99 149 204 260

Temperature

Fig. 20.13. V i scos i t i e s vs t e m p e r a t u r e .

can precipitate in the producing well when the produced water cools. Prats (1978) gives an appraisal of the steam injection process. Over 40 projects are currently in operation.

Micellar flooding is an_other variation of waterflooding. This EOR process has the potential of increasing oil recovery compared to waterflooding by displacing more oil from the swept region, as well as increasing the area swept.

The typical water external micellar solution that is injected includes the following:

(1) Aromatic petroleum sulfonates, used to reduce the interfacial tension between the micellar solution and the reservoir oil. The sulfonates have an equivalent weight range of 250-500. Normally 2-7 wt.% is used. This exceeds the critical micelle concentration. Synthetic alkyl sulfonates are also used.

(2) Co-surfactants such as low-molecular-weight alcohols (e.g. isopropanol) or ethoxyl- ated nonionics (e.g. ethoxylated nonyl phenol). These materials, in concentrations of

10000

1000

/$ Oil///Water 100

10

\ \ \

\ \

li t t I i OF 100 200 300 400 500 C 38 93 149 204 260

Temperatu re

Fig. 20.14. V i s c o s i t y ra t io vs t e m p e r a t u r e .

E n h a n c e d oil recovery 455

100

75

Sweep Efficiency 50

%

At 2 Pore Volumes Injected

0 L I t I OF 100 200 300 400 500 C 38 93 149 204 260

Temperature

Fig. 20.15. Sweep efficiency vs tempera ture .

0.1-1.0 wt.~o, are used to increase the surfactant concentration attainable in the aqueous solution.

(3) Sodium chloride (ranging from 0-2 wt.~o), used to regulate ionic strength and control interfacial tension of the micellar solution/crude oil interface.

(4) Polymer, in concentrations from 0 to 0.2 wt.~o. It is used to increase the viscosity of the micellar solution.

(5) Ionic sacrificial agents such as trisodium phosphate. These reduce surfactant adsorption on the reservoir rock. Typical concentrations range from 0 to 0.3 wt.0/,.

Consideration is also being given to oil-external micellar solutions, but the comments here are limited to the water external type.

The micellar solution in contact with the oil results in an interfacial tension < 10 -4 Nm-1, much lower than the usual water/oil value, ~0.03 Nm-1. The lower value reduces the pressure required to enter pores containing oil (eq. 1). Consequently the micellar solution can displace more oil from small pores than can water alone.

One technique for applying micellar flooding is to inject an amount of micellar solution equivalent to 10~o of the reservoir oil volume. This can be followed by water containing polymer until the rate of oil displacement becomes uneconomic.

Items that must be considered in designing a successful micellar flood include:

(1) Compatibility of the micellar solution with calcium and magnesium salts in the reservoir water. A fresh water "preflush" has the potential of displacing some of the saline reservoir water.

(2) Compatibility of the surfactants with the polymers used to increase micellar solution viscosity.

(3) Behavior of the micellar solution/crude oil system at reservoir temperature. (4) Adsorption of the valuable surfactants on the mineral surfaces of the reservoir rock.

Gogarty (1978) reports 19 miceUar flood field projects in operation. Most of these are considered tests and have not yet been expanded to full-scale commercial operation.

C 0 2 injection is the final EOR process to be discussed. This gas can assist oil recovery by dissolving in the oil, swelling it, reducing its viscosity, enhancing vaporization of volatile components, and improving the displacement efficiency by lowering the inter- facial tension. For high-density oils, swelling and viscosity reduction are the principal benefits. Figure 20.16 illustrates viscosity reduction (Simon et al., 1965). Vaporization of volatile fractions is more important with low-density oils containing appreciable gasoline and kerosene. Figure 20.17 shows vaporization data (Simon et al., 1978).

Figure 20.18 presents interfacial tension information for a CO2/low-density-oil system (Simon et al., 1978). Under some circumstances the CO2-reservoir oil interfacial tension can reach zero, giving a 'miscible' displacement.

456 R. SIMON

10

9

.8

Idm = ViSCosity of Oil .7 Saturated With CO 2

i l/o = Viscosity of Oil .6

# m - - 5 /~o

.4

3

.2 # 0

0 1 PSI A 1000 2000 3000 MPa 6.9 13.8 20.7

Saturation Pressure

Fig. 20.16. Effect of CO2 on oil viscosity reduction.

The above characteristics give CO2 injection the potential for recovering more oil than a waterfiood. Selecting the better of the two for a specific reservoir requires an economic evalution.

The principal technique for applying CO2 to oil recovery involves its injection fol- lowed by water (e.g. 2.0 volumes CO2 per volume of water, both expressed at reservoir pressure and temperature). The water reduces the tendency of the CO2 to finger and increases its sweep efficiency. This cycle, known as water alternating with gas (or WAG), is repeated until the desired amount of CO2 has been injected (e.g. 20% of the reservoir oil volume). When the alternating sequence of CO2 and water is complete, continuous water injection follows until the project is terminated.

The design of a successful CO2 injection project will include:

(1) Insuring adequate reservoir pressure. If initial pressure is too low, water injection can be used to raise it.

(2) Selecting a reservoir having minimum fractures or other high permeability paths. This minimizes early breakthrough into the producing wells, which decreases sweep efficiency.

(3) Obtaining a reliable source of CO2 with > 90% purity. This may involve a pipe- lining system.

(4) Processing the produced gas to separate the CO2 and methane. The methane can then be sold, and the CO2 re-injected.

34.5 5000

130OF (54oc)

Pressure 207 3000

Bubble Point Region

27.6 4000 - - Critical Point 12670 PSIA)

Volume % 40 Liquid 60

80 13.8 2 0 0 0 ~

6.9 1000

I I 4 I < 0 20 40 60 80 ~ Mol Percent CO 2 in Rese~,oir Oil

I " ~ - Dew Point Region

/ '; 5vo, I ~ % Liq

A Solid Phase Precipitated

J at ZCO 2 > 60% 100

Fig. 20.17. Phase behavior of a CO2-crude oil system.

Enhanced oil recovery 457

27.6 4000

Experimental Points Dew Point~ /

20.7 3000 J~O.ieO.775 Citlcal Point 19 /

/

Bubble P o i n t / ~ ' / ~ ~ 13.8 2000 ---- 0.058

0,434

6.9 1000 qnterfacial ~ Tension

Oyne./Cm 10-

o L L I I o~ < 0 20 40 60 80

u~ MOl Fraction CO 2 in Reservoir Oil

130OF (54oc)

I 100

Fig. 20.18. Interfacial tensions of a CO2-crude oil system.

(5) Considering operating problems such as corrosion and carbonate scaling, which are more severe with CO2 injection than in a waterflood. The corrosion will affect steel tubing, casing, and pumps. The scaling can be caused by precipitation in the producing well of carbonates that have been dissolved by the acidic CO2-in-water solution.

Stalkup (1978) discusses six CO2 field projects, both commercial and experimental.

RESEARCH FRONTIERS

The research frontiers of EOR are in two principal categories. One is reservoir definition: measuring the size and shape of the oil zone; its porosity

and permeability; the dimensions of its barriers and faults; and its petrophysical proper- ties, such as wettability of the mineral surfaces and the nature of the clays. Advances in geology, seismology, and physical chemistry are needed to improve our ability to define these characteristics for each reservoir.

The other involves oil saturation: determining the abundance and location of oil in known fields. This can be measured by three methods: (1) examination of cores from the reservoir; (2) interpretation of logging measurements, including formation resistivity, neutron decay time, dielectric properties and nuclear magnetism (IOCC, 1978, Chapter V); and (3) injection of chemical tracers that react in the reservoir to form products whose rate of return when the well is produced can be related to the oil and water saturations (IOCC, 1978, Chapter VII).

None of these three methods is considered fully reliable. Confidence in the measured results depends on obtaining independent confirmation from several sources. Applying the principles of physics shows promise in defining oil saturation.

There is also a third category of research-extension of current work. This includes theoretical and experimental studies to: (1) predict chemical interactions between the fluid and rock constituents and between the injected fluid and the reactive compounds in the petroleum; (2) evaluate the heterogeneity of flow through the network of pores; (3) select additives that enhance the effect of steam injection; and (4) prepare better macro- molecules for polymer and micellar floods.

All three categories are receiving attention because of the worldwide demand for oil. Important technical advances are likely to result.

REFERENCES

CHANG H. L. (1978) Polymer flooding technology--Yesterday, today, and tomorrow. J. Petrol. Tech. 30, 1113-1128.

DYES A. B., CAUDLE B. H. and ERICKSO~ R. A. (1954) Oil production after breakthrough-- as influenced by mobility ratio. Trans. A I M E 201, 81-86.

458 R. SIMON

GOGARTY W. B. (1978) Micellar/polymer flooding--an overview. J. Petrol. Tech. 30, 1089-I 101. IOCC (1978) Interstate Oil Compact Commission, Determination of Residual Oil Saturation, Library of

Congress Number 77-78927. NATIONAL PETROLEUM COUNCIL (1976) Enhanced oil recovery, an analysis of the potential for enhanced oil

recovery from known fields in the United States--1976 to 2000, Library of Congress Number 76-62538. PRATS M. (1978) A current appraisal of thermal recovery. J. Petrol. Tech. 30, 1129-1136. SIMON R. and GRAVE D. J. (1965) Generalized correlations for predicting solubility, swelling and viscosity

behavior of CO2--crude oil systems. J. Petrol. Teeh. 102-106. SIMON R., ROSMAN A. and ZANA E. (1978) Phase behavior properties of CO2-reservoir oil systems. Soc. Petrol.

Engineers J. 20-26. STALKUP F. I. (1978) Carbon dioxide miscible flooding--Past, present, and outlook for the future. J. Petrol.

Tech. 30, 1102-1112.

DISCUSSION

ROEDDER: Could you give us an idea of the maximum temperature and pressure ranges that you

encounter in reservoirs?

SIMON: The maximum reservoir pressure we encounter today is 1300bar; the maximum

temperature is 200C.

KESTIN: From what I have read, I retain the following figures, perhaps you could correct them

and comment: that normal recovery releases about 3070 of the oil underground, second- ary recovery will give another 3070 and tertiary recovery at most another 107O.

SIM ON: Primary recovery might give in the order of 15 or 207O, and a water flood might give as

high as 40-507O, but generally about 307o. So if I am going to do a secondary or an enhanced recovery, with just water I could hope to get somewhere between 30 and 50%. Now with a more sophisticated process like CO2 or steam I would perhaps hope to get as high as 60 or 70%. Fig. 20.12 may be a little misleading to the casual glance: you can reach 100% 'displaced area' values but the water will only push out 30% of the oil.

KE STIN: At the present moment in the U.S., how much of the oil available undergound has

already been taken out?

SIMON: There have been in the U.S. 430 billion barrels of oil discovered, 110 billion barrels

produced and 30 billion barrels are considered 'certain reserves'. So we still have another 430 - 110 - 30 = 290 billion barrels. It's that 290 that is my personal target.

KESTIN: That 290 still represents twice as much oil as has ever been taken out in the U.S. Well,

I suppose the compelling question is, why do we have a crisis?

SIMON: The answer contains political considerations. I am going to avoid it.

FRANCK: Looking at the next 10 or 20 years, which way would you consider the most promising

in enhanced recovery: the use of steam or CO2, or rather improving and advancing the surfactant application, or something entirely different?

SIMON: Well, first may I say that continued exploration is very critical and I'm sure we're

going to find lots more oil. However, to specifically answer your question, each reservoir has its own optimum process. By this I mean that steam is the only thing we consider for heavy viscous oil, for example, or that for those reservoirs that are high pressure and

Enhanced oil recovery 459

which have a great field of clean CO2 next door, that would be an obvious choice. 'Micellar' (i.e. the use of surfactants) has the advantage that it will work in all the lighter less viscous oils. It has the disadvantage that the effectiveness of a 'micellar' injection is affected by the salinity of the water, the nature of the rocks, and the temperature of the reservoir and this is where our research is taking us. I think we are becoming better able to apply 'micellar'. So, as far as the next 10 years 'micellar' will probably be what is new.

HELGESON: You failed to mention anything about pollution consequences of the different methods

of enhanced recovery.

SIMON: For water flooding a pollution consequence is that we usually re-inject the produced

water, which is of course a brine. We must therefore be extremely careful that on the way down it doesn't get into a drinking water aquifer. In those cases offshore where produced water is re-injected, one must be careful that the re-injected water won't enter the sea and have an adverse effect on the biota.

In the case of polymers I see no different pollution problem to those I have just described. In the case of steam we are severely limited by air pollution requirements. We have to burn the oil to make the steam and burning the oil gives a combustion gas which can contain nitrogen and sulfur oxides. So scrubbing these out of the boiler stack is important. For 'micellar', I see no particular problem because those chemicals I described will essentially not get into any drinking water aquifers or into any rivers or oceans. I don't see any particular disadvantage with CO2. We use a big compressor to drive the CO2 to wherever we want it to get and those compressors use internal combus- tion engines and so again we are faced with the problem of nitrogen oxide.

HELGESON: There is, of course, a long term pollution consequence of water flooding because the

water will ultimately get into rivers and oceans.

SIMON" My hope and my confidence there is that essentially all the low concentration and

undesirable constituents of the water will be adsorbed on the rocks during migration from a 10,000-feet-deep aquifer before it reaches the shallower depths. We have some evidence that that will occur. But if you are talking about hydrologic flow over geologic time, I see no significant difference from a pollution standpoint than existed before oil was discovered.

BUBACK: Can the oil reservoir really be looked upon as a large sealed autoclave? You have one

hole and you drill another and you introduce some material and get out some other material. Can there be severe leakage problems?

SIMON: Indeed the oil trap can be considered as an autoclave. There is a definite trap, the top

is sealed or the oil couldn't be there in the first place.

BUBACK: Does this mean that there will always be a primary recovery?

SIM ON: There can always be a primary recovery. The reason we try not to rely on primary, for

example, is if the pressure lowers too far, then flow to the surface can stop. If you are on an offshore field, the idea of putting pumping in is prohibitive. So we immediately start pressure maintenance. We drill another well and force in some fluid, generally water, possibly gas, and maintain the pressure. Essentially every reservoir could be produced in a primary way, but it is very important to maintain the pressure, so secondary recovery will almost always be used.

460 R. SIMON

YODER: It is a reservoir but it should not be considered an open cavern, where you have a layer

of water and a layer of oil. We have the same problem with magma chambers where people draw cartoons of a cavity that is filled with magma, but which is actually fluids dispersed in very heterogeneous rocks with various permeabilities and porosities. I think your pictures of the channels would represent exactly the magrnatic situation. Channels would be developed where the permeability is high. How valuable are your electrical conductivity measurements in actually tracking where these channels are after you have put in the five drill holes?

SIMON: Up to today we haven't been very successful in determining the heterogeneity of the

reservoir with these physical measurements. Of course we model it on our computers and use simulation techniques making guesses from the data we have. We are not confident that our models are very good.

YODER: But you have five drill holes to work with?

SIMON: It just makes it a little better than having only one. We are still a long way from

getting a good model. Our crutch in that case is history-matching. We take 2 years of history, place it in the computer model and when the predicted and the observed match we say we've got a good model, and we will predict for another year.