or more fluid substances (gases or liquids) to form a single homogeneous phase when mixed in all proportions.

For petroleum reservoirs, miscibility is defined as that physical condition between two or more fluids that per-

U.S. DOE during 1973-Sl), several forms of miscible displacement operations currently in use or under con- sideration. The processes include (1) miscible-slug drive for first-contact miscibility, (2) condensing-gas drive for dynamic miscibility, (3) vaporizing-gas drive for dynamic miscibility, and (4) extracting-liquid or critical- fluid drive for dynamic miscibility. A brief discussion of

theoretical aspects and limiting factors of each of se types of miscible displacement, in addition to an line of engineering study basic requirements, are sented on the following pages. Engineering examples presented in the Appendix in conjunction with a cussion of alternative procedures.

eoretical Aspects of Miscible-Phase splacement scible-Slug Process mits them to mix in all proportions without the existence of an interface. If two fluid phases form after some pro- portion of one fluid is added, the fluids are considered immiscible. Figs. 45.1, 45.2, and 45.3 illustrate the dif- ference in immiscible and miscible relations between certain fluids.

Low-molecular-weight (MW) hydrocarbons such as ethane, propane, butane, or mixtures of liquefiable petroleum gas (LPG) are the injected fluids (solvents) that have been used for first-contact miscible flooding.

thetheoutprearedis

ThDiMiChapter 45 Miscible Displacement LeRoy W. Holm, Union oil Co. of California*

Introduction Through research efforts and pilot testing over the past 25 years, miscible-phase-displacement processes have been developed as a successful means of obtaining greater oil recovery in many reservoirs. To understand these processes, it is first necessary to provide a defini- tion of miscibility, particularly as distinguished from solubility. Solubility is the ability of one substance (fluid) to mix with a fluid or fluids and form a single homogeneous phase. Miscibility is the ability of two These solvents in any amount will form a single phase with the oil in the reservoir, so are miscible upon first contact with the oil. Heavier hydrocarbons such as C 5 to C t2 also are miscible with reservoir oils but have not been used as injectants because of their higher costs. However, since solvents like ethane and LPG are abun- dant in most reservoir oil, they can promote miscible displacement when nonoil-miscible fluids such as methane, natural gas, CO*, flue gas, or nitrogen are in- jected to vaporize or extract CZ to C r2 in situ from the

Ortginally. tn 1962 edltlon. this chapter was a part of Chap. 40, Gas-lnpchon Pressure Mantenance and Miscible-Phase Displacement in Oil Reservors. wrWan by James L Moore and FIxhard F. Hinds. oil. This mechanism of in-situ transfer of light hydrocar- bons from the reservoir oil to the injected fluid that forms a mixture miscible with reservoir oil is known as dynamic miscibility or multiple-contact miscibility.

There are, as a result of extensive research and development efforts by the petroleum industry and various universities (much of which was funded by the The sim lest type of miscible drive is the liquid slug process j-4 In this type of miscible drive, a slug of material such as propane or LPG (liquefied petroleum gases C2 to C,) is injected into the reservoir and fol- lowed by a dry gas.* The slug miscibly displaces oil from the contacted portion of the reservoir by virtue of a

Other ngnhydrocarbon flu& such as cenaln alcohols, can be miscible wh reser- voll 011. However. these alcohols lend to promote miscible displacement between 011 and in-situ water so that complex phase and moblfity relationships occur. Pro- hlbltlvefy large volumes of these alcohols are required to mamtain a misctble displacement m the reservoir. As injecte$,soluble oils or oil exIernal microsmulsions also are miscible with the reservoir oil. Since complex phase relationshlps also occur between these fluids and both the oil and water in the reservoir, and because other chemicals are used in conjunction with them. dlscusslon of this displacement process is found in Chap. 47-Chemical Flooding

45-2

OIL OIL (LIQUID) (LIQUID)

Fig. 45.1-Immiscibility of methane (gas) and oil (liquid) at reservoir conditions of temperature and pressure.

*;E;;/;;; 2000 LB L-- J 15OOF

. l l . . I l . l - t l -. . ...Z. ,-.

-0 -

. l

. . l ** .

M & A-NE

1 l -

M EGANE Jr -AC\

(GAS) (LIQUID)

Fig. 45.2-Miscibility of methane (gas) and propane (or LPG) liquid at reservoir conditions of temperature and pressure. Here propane (or LPG) is a gas in presence of gas.

ATMOSPHERIC

p*E PFi

(GAS) (LIQUID\ u-m;:?

(LIQUID) (LIQUID) Fig. 45.3-Miscrbility of propane (or LPG) liquid and oil liquid at reservoir conditions of temperature and pressure. Here propane (or LPG) is a liquid in the presence of a liquid. PETROLEUM ENGINEERING HANDBOOK

solvent cleaning action. For the purposes of discussion, LPG will be used to denote the slug material. In practice, LPG solvents that are first-contact miscible with reser- voir fluids are too expensive to inject continuously. In- stead, the solvent is injected in a limited volume, or slug, that is small relative to the reservoir PV, and the slug, in turn, is miscibly displaced with a less expensive fluid such as methane, natural gas, or flue gas. Ideally with such a process scheme, solvent miscibly displaces reser- voir oil while drive gas miscibly displaces the solvent, propelling the small solvent slug through the reservoir.

Pressure and Composition Requirements. The basic requirement for miscible displacement by the slug proc- ess is that the solvent slug be miscible with both the reservoir oil and the drive gas, which is mostly methane. Miscibility between the LPG slug and the displacing gas requires a certain minimum pressure,s which can be estimated from published data on the cricondenbars of mixtures of pure components (Fig. 45.4). For example, this pressure may be as low as 1,100 psia at the reservoir temperature of 1.50F.9 It is important to note that for temperatures between the critical temperature of LPG and methane, the critical pressure (miscible pressure) is usually much higher than the critical pressure of either fluid. Where additional data are required, these values should be determined in the laboratory.

Equilibrium phase diagrams, previously discussed in Chap. 20, are convenient representations of the ranges of temperature, pressure, and composition within which combinations of phases coexist.

Fig. 45.5 is a triangular phase diagram that illustrates the phase behavior requirement for first-contact miscibility. lo For the pressure and temperature at which this pseudotemary diagram was determined, all mixtures of LPG (Cz to C,) and oil (Cs+ ) lie entirely within the single-phase region. As indicated on the diagram, an LPG slug could be diluted with methane to Composition A and the resulting mixtures would remain first-contact miscible with Reservoir Oil B. Composition A is the in- tersection of the right side of the triangle (methane/LPG compositions) and the tangent to the phase boundary curve that passes through the oil composition.

As the concentration of methane in the injection fluid increases, the pressure (cticondenbar) increases and ultimately becomes impractically high for first-contact miscibility. When this happens, dynamic miscibility can be achieved by the condensing- or vaporizing-gas drive mechanisms.

Condensing-Gas Drive (or Enriched-Gas Drive) A condensing-gas drive is that process of oil displace- ment by gas that makes use of an injected gas containing low-MW hydrocarbon (C, to Cg) components, which condense in the oil being displaced. To effect conditions of miscible displacement, sufficient quantities of low- MW components must be condensed into the oil to generate a critical mixture at the displacing front.

This process was brought to the attention of the in-

dustry in the late 1950s by laboratory investiga- tions, *I2 which showed that the use of condensing gas drives would result in increased oil recovery from many reservoirs during either primary or secondary phases of

MISCIBLE DISPLACEMENT

6000

4000 a

2

-200 -100 0 100 200 300 400 500 600 700

TEMPERATURE OF

Fig. 45.4-Critical loci of binary n-paraffin systems.

production. Laboratory tests were conducted with a wide composition range of injection gases and reservoir fluids, at pressures greater than, equal to, or less than the saturation pressure (bubblepoint pressure) of the dis- placed fluid. One of the principal conclusions from these tests was that high oil recoveries could be obtained regardless of whether the oil was originally saturated or unsaturated with natural hydrocarbon gases at the displacement pressure.

The phase relations governing this process are il- lustrated by a triangular diagram in Fig. 45.6. Initially, a rich gas of Composition C is injected into Reservoir Oil A. As indicated by a line joining these two points, some mixture compositions fall in the two-phase region and thus these two components are not immediately misci- ble. However, after several consecutive steps of Gas C contacting the oil, the C2 -to-C6 components condensed out of the gas at each contact are absorbed by the oil until a critical Mixture B is obtained at the miscible front. It is noteworthy that, had Gas C initially fallen to the left of the immiscible-miscible (I-M) line, it would have been impossible to enrich the oil to B. There would not be suf- ficient amounts of the gas-enrichening components in the injected gas to reach the Miscible Point B. The I-M line is referred to as the limiting tie line of the phase diagram.

Limiting Factors (Phase Behavior) Control of Injection-Gas Composition. As indicated in the definition of miscible displacement by condensing- gas drive, the quantity of low MW components in the in-

jection gas is critical. * Also, the actual dynamic or multiple-contact phase behavior may be more com- plicated than shown in the simple pseudoternary diagram 45-3

of Fig. 45.6. Contiguous zones of miscible compositions of bubble- and dewpoint fluids can exist. The bubble- point curve represents the composition of a fluid where the last vapor disappears at a fixed pressure and temperature; the dewpoint curve represents the composi- tion where the first liquid appears at these same condi- tions. Regions of liquid/liquid, liquid/liquid/vapor and liquid/vapor/solid (asphalt) equilibrium have been found in more recent studies. For this reason it is important that

(tlSSLE POINT,

SATURATEO-VAPOR CURVE

CAITICAL MIXTURE AFTER INFINITE

IC~Crj)

I-M OIVIOING LINE

INJECTION-GAS COYPOSITION-C RESERVOIR-FLUID COMPOSITION-A

M MISCIBLE I IMllSClSLE

DRY GAS INJECTION

OIL PRODUCTION LPG BANK

\

TAKEN FROM WELLS lN.OlL BANK

LPG AND OIL MIXING ZONE

Fig. 45.5-Phase boundary curves for the system reservoir oil/LPG/tail gas; 180F-volume percent basis. Fig. 45.6-Illustration of miscible displacement (condensing- gas drive).

45-4

laboratory displacement tests be conducted to determine the gas composition required for miscibility development at a specific injection pressure and reservoir temperature. Such tests also will help to determine when a sufficient transition zone is established at the front, so that dry gas that is miscible with the critical gas mixture immediately behind the transition bank can be substituted for the rich gas. I3 Economic considerations will usually dictate that a minimum amount of rich gas be used.

Reservoir Pressure. When the reservoir pressure is relatively low, a gas very rich in intermediates would be required for miscible displacement. At higher pressures, a lesser quantity of C2 to C 6 hydrocarbons would be needed. Thus pressure as well as gas composition can be adjusted to achieve miscibility. The reservoir pressure required for this process will be at least 1,500 psig.

Oil Gravity. The gravity of the oil (if it is higher than 20API) has little effect on the condensing-gas drive process, although with heavier oil, greater enrichment of the gas and longer contact with the oil are required to transfer the C 2 to C 6 components into the oil. The in- herent higher viscosities of the heavier oils also leads to more unfavorable mobility ratios for the displacement.

Vaporizing-Gas Drive Process High-Pressure Gas Injection. Another mechanism for achieving dynamic miscible displacement relies on in- situ vaporization of low-MW hydrocarbons (C, to C,) from the reservoir oil into the injected gas to create a miscible transition zone. This method for attaining miscibility has been called both the high-pressure and the vaporizing gas process. Miscibility can be achieved by this mechanism with methane, natural gas, flue gas, 0; nitrogen as injection gases, provided that the miscibility pressure required is physically attainable in the reservoir.

The concept was introduced in 195014; the process re- quires a higher pressure than normally used in conven-

GAS DEVELOPED AT

INJECTION GAS COMPOSITION - C RESERVOIR FLUID COMPOSITION - A ENRICHED GAS COMPOSITION - R Fig. 45.7~illustration of miscible displacement (high- pressure gas injection). PETROLEUM ENGINEERING HANDBOOK

tional, immiscible gas drives. The increase in oil recovery at the higher pressures is believed to result from: (1) absorption of injected gas by the oil to cause a volume increase of the oil phase in the reservoir; (2) enrichment of injected gas resulting from vaporization of low-boiling-range hydrocarbons from the oil into the gaseous phase; and (3) reduction in the difference of viscosity and interfacial tension (IFT) between the in- jetted gas and the reservoir oil as a result of mixing of the above fluids.

The mechanism of miscible displacement by high- pressure gas injection has been described in detail by several investigators. 10,15-18 Fig. 45.7 presents a triangular diagram I7 to illustrate the phase relations of this mechanism. Initially, a relatively lean gas of Com- position C is injected into Reservoir Fluid A. A line con- necting A and C intersects the phase-boundary curve EBO, indicating that these two phases are not im- mediately miscible. However, as Gas C moves through the reservoir, it will become enriched because of the ef- fect of vaporization, until it ultimately reaches a critical Composition B. This fluid now is miscible in all propor- tions with Reservoir Fluid A or any reservoir fluid lying to the right of the I-M boundary. Although the basic con- cepts of high-pressure gas injection may be explained with the use of triangular diagrams, laboratory data are required to provide detailed phase relations-particularly with respect to the pressure at which miscibility occurs between the injection gas and the reservoir oil.

Miscibility by the vaporizing-gas drive mechanism also can be developed with nitrogen and flue gas (about 88% nitrogen and 12% CO ) even though these gases have a low solubility in oil. 24 * - Because the criconden- bar pressure for nitrogen and for low- to intermediate- MW hydrocarbons is high, the pressures required for dynamic miscibility are dependent on the methane con- tent of the in-situ oil as well as the concentration of other hydrocatins in the oil. Higher methane concentrations in the reservoir oil reduce the pressure required to attain vaporizing-gas drive miscibility with nitrogen. High reservoir temperatures promote miscibility. The CO2 tends to be partially or completely stripped from the flue gas at the front because it is soluble in the reservoir oil and brine. It has been speculated that the flue gas front may become essentially CO2 -free and develop miscibili- ty in much the same manner and at much the same miscibility pressure as if nitrogen had been the injection gas. l9

Limitations (Phase Behavior) Generally speaking, miscible displacement cannot be achieved by gas injection at realistic pressures unless certain basic requirements are met.

1. Reservoir depths must be sufficient to permit pressures greater than 3,000 psi, usually 4,000 psi at reservoir temperatures.

2. The reservoir fluid must contain sufficient quan- tities of certain (Cl to C,) components before the benefits of vaporization can be obtained. Referring to Fig. 45.7, the reservoir oil composition must lie on or to the right of the limiting tie line for miscibility to be at-

tained by the vaporizing-gas drive mechanism with natural gas that has a composition lying to the left of the limiting tie line.

5-5

0

4 2 MISCIBLE DISPLACEMENT

3. The reservoir fluid must be sufficiently under- saturated with respect to the injection pressure. This fac- tor is very critical. The requirement that the oil composi- tion lies to the right of the limiting tie line also implies that only oils that are undersaturated with respect to methane can be miscibly displaced by methane or natural gas. Thus, oil of Composition F on the bubblepoint curve of Fig. 45.7 could not develop vaporizing-gas drive miscibility with methane/natural gas. Inspection of Fig. 45.7 shows that as the concentration of low-MW hydrocarbons in the reservoir oil decreases, the oil Com- position A moves toward the left side of the pseudoter- nary diagram and higher pressures are required to shrink the size of the two-phase region and to develop miscibili- ty. Increasing pressure both decreases the size of the two-phase region and changes the slopes of tie lines by increasing the vaporization of low-MW hydrocarbons in- to the vapor phase.

4. The density of the reservoir fluid must be suffcient- ly low, as reflected in stock-tank gravities of approx- imately 40API and greater.

Laboratory studies would provide quantification for these requirements.

Extracting-Liquid or Supercritical Fluid Drive CO2 Miscible Process. A fourth mechanism for achiev- ing dynamic or multiple-contact miscibility involves the injection of a solvent gas (such as COZ, ethane, N20, or H2S), which is not first-contact miscible with reservoir oils but is highly soluble in them. Table 45.1 shows the critical temperatures and solubilities of some of these solvent gases for comparison with methane.

The critical temperatures of these gases are close to reservoir temperatures and the gases are very compressi- ble at these conditions (Fig. 45.8).23 CO2, from the standpoint of availability, cost, and operational han- dling, is the most practical of these fluids. As a liquid, or as a dense, critical fluid solvent, CO;? extracts from the oil hydrocarbons of higher MW than the predominantly C2 to Cd hydrocarbons that methane vaporizes. 24 In ad- dition to the C2 to Cd hydrocarbons, these fluids include C5 to C 12 hydrocarbons from the gasoline fraction of the crude and even C t3 to C3c gas-oil fractions of the crude. 1.2

1.1

1.0

0.9

0.6 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 1000 2000300040050607PRESSURE, PSI

Fig. 45.8-Compressibility factor6 for COs. 0 0 00 000 IO(P* 1000 RESERVOIR 011 C5 IO Cx pM SOLYEWT Fig. 45.9-Postulated phase diagram for fluids at displace- 4TABLE 45.1-CRITICAL TEMPERATURES AND

SOLUBILITIES OF SOLVENT GASES

Critical Solubility of Gas

Temperature in a Crude Oil at

1,000 psi and 135OF W) [Cl (scf/bbl) ~ -

Carbon dioxide 88 31 63Ethane 90 32 640 Hydrogen sulfide 213 100 52Methane -117 -82 209

In fact, the C2 to CJ hydrocatbons are not needed to achieve miscibility, so reservoir oils, which arc depleted in methane and the low-MW hydrocarbons (dead oils), are still candidates for CO;! miscible flooding.25 This greatly increases the application potential for miscible displacement. After multiple contacts with the reservoir oil, the hydrocarbon-enriched-CO2 phase miscibly displaces reservoir oil. 26*27

The phase behavior representation of this process is more complicated than the previous hydrocarbon injec- tion processes. Fig, 45. 9 indicates the enrichment in Cs to C30 hydrocarixjns required to achieve the miscible displacement fronts.

Pressure-Comptitioh Requirement. The reservoir pressures at whichmiscible displacement can occur are similar to those,ftithe first-contact or enriched-gas proc- esses (1,000 to 2,000 psi) because of the high solvency of the dense, supercritical CO* at these pressures and most reservoir temperatures (< 200F). Lower miscibility pressures are achieved at lower temperatures. Also, like the dependence of the vaporizing gas process on the C2 toC6 content of the in-situ oil, the CO2 miscible process is dependent on the C5 to Csc content of the oil. At a given reservoir temperature, miscibility displacement with CO2 is achieved at lower pressures where the C5 to C3c content is higher (Fig. 45.10). 28

Recent data indicate that the C5 to C i2 content of the oil has the greatest effect on the miscibility pressure. The heavy portion (C3t +) of the oil also affects this ment front after COP has extracted hydrocarbons in-situ from reservoir oil, contacted at miscible pressure pnr

even the vaporized or extracted hydrocarbon enriched 45-6

Cop DENSITY REOUIRED FOR MISCIBLE

DISPLACEMENT VS. C&-C30 CONTENT OF CRUDE OILS 0 0.9

c I

5 _ m

L+ - 2

0.6

t: - E > 0.7 - k 4 m s 0.6 - z 5 A FARNSWORTH go.5 - 0 WILMINGTON FORD ZONE

0 A WEST POISON SPIOER

Pi -

Cl NORTHUUNOlS 0 GOMINGUEZ

c -

. EANOINI

z 0.4

0 CS-CSOCUI ItdO STRAWN

, 0 REO WASH I I I 40 50 60 70 60 90 100

C5-C30 CONTENT OF OIL, C5430, WT%

cg+

Fig. 45.10~CO2 density required for miscible displacement vs. C, to C, content of various crude oils. MMPs at 165OF for same crude oils.

miscibility pressure. Increased heavy oil components, usually accompanied by lesser amounts of C5 to Cl2 components, require higher pressure to compress the CO2 to a more dense fluid and promote adequate enrich- ment at the displacement front. This means a greater mass of CO2 would be required for miscible recovery of heavy oil with accompanying increased costs.

Process Considerations. To effect a true miscible displacement process, CO* should be injected con- tinuously, or a CO2 slug should be driven by a gas that is miscible with the CO,!. Methane, flue gas, or nitrogen can be used for this purpose. However, because of the improved mobility achieved, water is often used as the drive fluid. Although CO* is soluble in the water, it is not miscible with it, so that the water-driven CO2 slug dissipates by leaving a residual phase. This residual is one of the factors controlling the CO2 slug size required.

CO2 often is available in mixtures with other gases. The effect of these impurities is either to raise or lower Fig. 45.11--Mixing of solvent and oil by longitudinal and transverse dispersion. PETROLEUM ENGINEERING HANDBOOK

the pressure re uired to achieve miscible displacement in a reservoir. B 14,2 ,30 Gases such as nitrogen and methane raise the minimum miscibility pressure (MMP); ethane, propane, or hydrogen sulfide tend to lower the pressure requirement.

Factors Affecting Displacement Effkiency Under the conditions of miscible displacement, nearly all the oil in place within the pore channels contacted will be displaced by virtue of the elimination of interfacial forces between the gas and oi13 and by the absence of relative-permeability effects. As the enriched gas and oil approach their critical mixture, there is a marked reduc- tion in their IFT. Even though miscibility (defined by zero IFT and no interface) has not been reached at this point, improved oil recovery over immiscible displace- ment has been observed in laboratory flooding using such two-phase fluids. Such displacement has been described as near-miscible (incorrectly as partial- miscible) displacement. The actual recovery from the reservoir by miscible and near-miscible floods will be considerably less than that obtained in laboratory floods because of factors affecting pattern and conformance ef- ficiency and dispersion of the miscible slug in the reser- voir. The following discussion of factors which affect displacement efficiency applies to all forms of miscible and near-miscible processes.

Dispersion

Mixing zones form between the reservoir oil and LPG slug (or multiple-contact miscible slug) and between the injected drive gas and the slug. Three mechanisms that contribute to this mixing are molecular diffusion, microscopic convective dis ersion, and macroscopic convective dispersion. 7 2 32 33 3Q Microscopic dispersion is pore-size mixing in excess of that from the random mo- tion of molecules and is caused by convection in the tor- tuous flow through porous media. Further mixing of fluids by macroscopic convective dispersion can be caused by permeability heterogeneities over a larger area of the porous rock34 (Fig. 45.11).

In a relatively homogeneous reservoir, the length of these mixing zones determines the minimum slug size. The slug should not be diluted to such an extent that miscibility is lost before most of the reservoir area is contacted. On the other hand, viscosity and density dif- ferences between solvent and oil, which also affect the slug, may be moderated by diffusion and dispersion, with a decrease in fingering, gravity override, and resul- tant slug-stabilization tendencies.

Laboratory studies have indicated that in linear-flow systems the mixing zone grows rapidly at first, decreases in rate of growth as displacement continues, and even- tually stabilizes in length. A survey of the literature shows that a difference of opinion exists about the stabilizing effect that diffusion and dispersion have on the mixing zone in the reservoir. It is generally agreed, however, that the length of the mixing zone varies

P ro-

portionately with the viscosity of the driven fluid. 4, 6-39 As the viscosities of the injected gases and liquid, and slugs, are low (less than 1 cp), field applications general- ly have been restricted to reservoirs with oil viscosity of less than 5 cp.

OA AN TA 0 ILITY IO MISCIBLE DISPLACEMENT

Two correlations, based on laboratory data, have been presented in the literature as a means to estimate the minimum slug size required for miscible drive in a homogeneous reservoir. One correlation4 states that the mixing-zone length is related to the ratio of the viscosit difference to the viscosity ratio. The other correlation Y

says that the slug size required for a given path length varies inversely as the square mot of the path length. Laboratory tests 3*4 have indicated that, under ideal con- ditions, a bank of solvent with a volume as low as a few percent of the hydrocarbon pore space is all that might be required to maintain miscibility. However, experience has shown that slug volumes required for practical field operation range from 10 to 30% HCPV in a pattern area to counter the effects of dispersion, gravity segregation, reservoir-rock heterogeneities, well-pattern arrange- ments, etc. s,2

Mobility Ratio

Despite the fact that displacement of nearly 100% of the oil in the contacted area occurs, the overall efficiency of miscible displacement may be lowered by the effect of an unfavorable mobility ratio (defined here as the ratio of the displacing to the displaced mobilities). The sweep pattern in a miscible-slug operation is controlled by the ratio of the displacing gas to the displaced oil mobilities40 which in the swept area will reduce itself to the viscosity ratio of oil to gas4 (Fig. 45.12).

This ratio, of course, is unfavorable when compared with conventional waterflood operations. Laboratory tests have indicated that viscous fingering occurs at un- favorable mobility ratios (Fig. 45.13). This phenomenon has been described as dendritic fingers of solvent (or drive gas) forming and growing in length until they break through the penetrated LPG slug or oil bank. These viscous fingers result in earlier solvent breakthrough and poorer oil recovery after breakthrough for a given volume of solvent injected than would be the case if the displacing front remained stable. The breakthrough oil recovery of miscible floods will be governed principally by the mobility ratio of the injected fluids and reservoir oil, and by the reservoir geometry.

Conformance Effkiency

Assuming that miscible displacement can be achieved by one of the foregoing processes, the greatest single factor that controls maximum recovery of oil from a reservoir is conformance efficiency. For the purpose of this chapter, conformance efficiency is defined as the fraction of the total PV within the pattern area that is contacted by the displacing fluid. The dominating factors that control conformance are the gross sand heterogeneity and size distribution of the rock interstices, which usually are defined in terms of permeability variation or stratifica- tion.42 These factors become particularly critical when effecting the displacement of the higher-viscosity oils. The associated unfavorable mobility ratio, in conjunc- tion with a wide variance in permeability, results in a low conformance. In addition, gravity segregation can

take place in formations possessing vertical permeabili- ty. 43 This adverse effect occurs when the light injection gases or liquids rise to the top of the formation or 100 60 60 40

20 IL INJECT0 HAdOA0 1 I I 0.1 1.0 10 10MOBRAT

Fig. 45.12-Displacement behavior for developed five-spot, data from 0.0047~in. model.

PV c

0.3 0.2 0.1

0.05

M = 2.40

0.15 0.05

M = 17.3

Fig. 45.13-Displacement fronts for different mobility ratios

and injected PV until breakthrough, quarter of a five-spot.

45-0

Fig. 45.14-Combination waterdrivelmiscibledrive project in low-conformance reservoir provides high oil recovery by water in the nonconformance sections and by miscible displacement from the confor- mance sections.

permeable zone and override or bypass the denser reser- voir oil. The combination of these factors in a miscible displacement operation can yield an overall recovery ef- ficiency that is much lower than that of waterflood. This problem has been a principal deterrent to the use of miscible processes.

Improving Pattern and Volumetric Sweep Efficiencies With Water During Miscible Displacement In 1957, a method for improving pattern and volumetric sweep (conformance) in miscible displacement opera- tions was proposed. 4o The method consists of injecting LPG, followed by a bank of natural gas to displace the LPG miscibly, and then natural gas and water simultaneously. The injection of the water reduces the relative permeability to gas in the region swept by the LPG slug and increases the viscosity of part of the displacing phase. These two factors combine to lower total mobility of this system, resulting in improved sweep (Fig. 45.14). Further research and field pilot tests have extended this technique to both the slu and/or drive gas in all types of miscible displacement. $4 Water usually is injected alternately with the drive gas and/or the miscible slug (termed WAG). The injection of water with an LPG or CO2 slug can trap a portion of the oil mobilized by the miscible gas, particularly in reservoirs having strong water-wetting characteristics. A low water-to-gas ratio (0.5: 1) is recommended if WAG is re- quired. Also, this type operation is limited to reservoirs in which sufficient injection capacity is available. A tight reservoir would require too many injection wells to inject the necessary volumes of gas and water to meet desirable oil production rates.

Two other potential problems with this technique are (1) segregation of the injected fluids into different strata and (2) trapping of oil by mobile water. 45 Fluid injection into selected strata and proportioning of the injected fluids within strata may be helpful in such cases. In laboratory studies it is important to use the actual reser- voir fluids and rock to determine the effects of rock wet-

tability on oil mobilization and trapping in the presence of water. Refined oils or single hydrocarbons such as decane do not wet rock to the degree that crude oil does PETROLEUM ENGINEERING HANDBOOK

and, consequently, tend to be trapped to a greater extent by water.

Improving Recovery Efficiency by Gravity Stabilization In reservoirs with dip, gravity segregation of fluids can be used advantageously to prevent viscous fingering or gravity override. This is achieved by injecting the sol- vent andlor gas updip and producing downdip at a rate low enough for gravity to keep the fluids segregated. Fingers of solvent or gas are suppressed and sweepout is improved. Field applications of this method have been

Improving Recovery Effkiency with Foams or Emulsions

The mobility of solvents and gas in porous media can be decreased by foaming or emulsifying them with water containing surfactants. 46 Laboratory studies have shown that these foams form selectively in the highly permeable porous channels and thereby tend to reduce fluid chan- neling. 47,48 Further field testing of this technique is in progress.

Engineering Study Basic Requirements A detailed engineering investigation is necessary to select and to design the miscible displacement operation properly and to ensure that it will be successful. The following information is generally necessary or desirable as a basis for selecting the operation that will be most economically feasible.

Detailed Geology. Core analyses from enough wells are needed to provide adequate areal and vertical distribution of rock properties, fluid saturations, capillary pressure, and waterflood susceptibility data.

Information regarding the reservoir structure, size, shape, and dip with particular emphasis on the definition of stratification or zoning conditions is needed also. If the latter is known to exist, an isometric fence diagram of the reservoir (Fig. 45.15) should be constructed that shows all the details of porosity development, shale con- ditions, etc., which can be obtained from well logs, core analysis, pressure transient tests, and individual well performance. This diagram aids in relating well perfor- mances and spacing with reservoir geometry.

Phase Behavior of Reservoir Fluids. Laboratory analysis of reservoir oil and gas should be conducted to determine such information as differential and flash vaporization data, liquid and gas viscosities, and hydrocarbon compositions over a wide range of pressures. In many instances, it is necessary to know the PVT relationships of the mixtures comprising the reser- voir fluids as well as the possible materials that might be injected.

Laboratory displacement tests should be conducted in sandpacked columns (Berea or native cores) to deter- mine: (1) the pressure required for miscible displacement [although correlations such as Fig. 45.10 and those in

other references are available, laboratory tests (Fig. 45.16) are the most accurate method to find the MMP]49; (2) the displacement efficiencies expected in

ag

0 00 SSURE IG)

evaluated to permit a reliable estimate of future primary recovery. Evaluation of any secondary recovery applica- tion in the reservoir is needed also.

Existing reservoir conditions should be determined. Past performance in connection with reservoir fluid and core analysis will provide an estimation of the state of the reservoir at the initiation of the miscible displace- ment project. This will include such essential items as reservoir pressure, fluid saturation distribution, and modeling or simulation of secondary-flooding history.

General Applicability of Miscible-Displacement Techniques. Knowledge of the previously mentioned factors, such as reservoir geometry and pressure condi- tions, can lead to the selection of the miscible process best suited to the reservoir.

Availability of injection materials and proximity of CO:!, N2, or gasoline-plant facilities may dictate, in the final analysis, the selection of a specific miscible process.

Recovery by Miscible Displacement. Pattern efficiency

Fig. 45.16-Laboratory test results for fixed oil composition and fixed temperature in slim tubes.

It must be noted, however, that in the assumption of a pattern efficiency, the effect of unconformities and stratification must be considered.

Volumetric sweep efficiency, defined previously, is calculated from the knowledge of the stratification, ver- tical and area1 variation of the rock properties, and mobility ratios of the displacing fluids to that of the displaced oil. There are several methods being used by engineers. 52 One of these methods is illustrated in the example calculation (see Appendix) with reference to alternative procedures.

Displacement efficiency should be determined from laboratory studies. This factor represents the percent recovery from the conforming volume of the reservoir and may range from 80 to 100%. As mentioned MISCIBLE DISPLACEMENT

Fig. 45.15-Three-dimensional (fence) dithe conforming areas for the LPG, condensing gas, high- pressure gas, etc; and (3) injection techniques at the desired operating pressure, temperatures, and for vary- ing concentrations (or compositions) of injected materials.

Compatibility of injected materials with reservoir fluids should be determined. COz, LPG products, or other light hydrocarbons will precipitate heavy paraffinic or asphaltic material in certain types of crude oil and may cause a reduction in permeability and a viscosity change in the oil.

Past Reservoir Behavior and Estimation of Primary and/or Conventional Secondary Recovery. The natural reservoir recovery mechanism should he is defined here as that area1 coverage of the reservoir through which the displacing fluid moves from its source to the producing wells. This factor may be estimated from laboratory model studies or from the literature. 5oS 45-9

ram illustrating general reservoir complexity.

L 1 I I , I I , 900 1100 130015017TESTPRE(PSpreviously, it is important to study the actual reservoir rock and fluids when possible to determine the rock wet- ting characteristics and their effect on displacement efficiency.

Fi -

18 0.514 4.8 0.011 0.885

19 0.543 4.7 0.011 0.896 20 0.571 4.5 0.011 0.907

21 22 23

f2

0.600 0.629 0.657 0.686 0.714

4.5 0.011 0.91 a 4.1 0.010 0.928 3.6 0.009 0.937 3.5 0.008 0.945 3.4 0.008 0.953

26

:i 29 30

0.743 2.9 0.007 0.960 0.771 2.9 0.007 0.967 0.800 2.6 0.006 0.973 0.829 2.5 0.006 0.979 0.857 2.1 0.005 0.984

31 32 33 34 35

Total

0.886 2.0 0.005 0.989 0.914 1.3 0.003 0.992 0.943 1.3 0.003 0.995 0.971 1.2 0.003 0.998 1.000 0.8 0.002 1.000

419.7 g. 46.17-Assumed reservoir for gas injection (inverted ninespot pattern).

TABLE 45.2-CALCULATION OF CAPACITY DISTRIBUTION FOR EXAMPLE RESERVOIR

Cumulative Thickness

(fu 1 2 3 4 5

h k c CCnl -83.00.19B- 0.198 0.029 0.057 0.086 0.114 0.143

41.0 0.098 0.296 39.0 0.093 0.389 31.0 0.074 0.463 26.0 0.062 0.525

6

ii 9

10

0.171 23.0 0.055 0.580 0.200 19.0 0.045 0.625 0.229 17.0 0.040 0.665 0.257 17.0 0.040 0.705 0.286 14.0 0.033 0.738

11 0.314 13.0 0.031 0.769 12 0.343 10.0 0.024 0.793 13 0.371 7.9 0.019 0.812 14 0.400 7.0 0.017 0.829 15 0.429 6.5 0.015 0.844

16 0.457 6.4 0.015 0.859 17 0.466 6.2 0.015 0.874 PETROLEUM ENGINEERING HANDBOOK

All the oil that is displaced in a miscible flood may not be produced. The ability of producing wells to capture the mobilized oil must be considered.

Total recovery factor, or percent recovery of oil from the entire reservoir, represents the product of the pattern, conformance, displacement, and capture efficiencies.

Injectivity and Productivity of Wells. These affect project life and have a significant effect on economics. Injectivity tests in the field or extensive relative permeability measurements may be necessary.

Mathematical Simulation. This may be used in pro- jecting reservoir modified black-oil s

erformance. Finite-difference,53

simulators55,56 4 finite-element and compositional

ha(le been developed for predicting or history matching flood performance. Streamtube models57,58 and scaled physical models59 also have been developed and may be informative.

Program Design. Design of production and injection facilities should be coordinated and used with current operations to the fullest advantage.

Economic Evaluation and Comparison. The miscible drive operation and other competitive methods60*6 should be evaluated and compared on an economic basis. This analysis generally governs the final decision.

Pilot Operation and Evaluation of Results. In many cases where waterflood operations appear very com- petitive with miscible drive, a pilot injection program is recommended if a suitable area in the field can be located. The selection of the ultimate program of opera- tion may be delayed pending the results of the pilot, thus reducing the risks inherent in such operations.

Field Experience Since the first miscible flooding projects of the early 1950s, there have been many applications throughout the world of all the miscible processes. Some of the best documented of each of these processes and their varia- tions are listed under General References for Applica- tions of Miscible Processes. More complete information on these is found in the publications listed under General References for Field Tests of Miscible Processes.

APPENDIX Engineering Examples As indicated in the previous sections, oil recovery and related performance in miscible drive operations will de- pend mainly on the degree of stratification and permeability distribution existing in the reservoir. Con- sequently, engineering calculations generally will be reduced to a function of estimating conformance efficiency.

In the following examples we have assumed a reser- voir under an inverted nine-spot well pattern (see Fig. 45.17), with an average permeability protile and capaci- ty distribution as indicated in Table 45.2. The procedure

followed is a modification of a standard water-cut recovery calculation, 62 which is based on the vertical distribution of productive capacity. The calculations for

MISCI

these flow miscibconstaing wequalsk,/k, definivoir oGOR

High-Cond

For togeth45.3. place tion assumthe reTable

0.40

11

0.10 0.830 0.075 0.75 0.350 0.64 0.170 0.256 0.426 0 0.43 0.120 0.215 0.335 0 0.33 0.083 0.198 0.281 0 0.25 0.054 0.175 0.229 0 0 5 5

9 x

x 1.

aalre1.

) 301124638411873079

56 46

197 30

75 34

.26

.22

29 22

.74

.15 1.0 0.50 0.60

0.10 0.880 0.050 0.50 0.450.10 0.917 0.037 0.37 0.55

0.70 0.10 0.946 0.029 0.29 0.650.80 0.10 0.972 0.026 0.26 0.750.90 0.10 0.990 0.018 0.18 0.850.95 0.05 0.997 0.007 0.14 0.921.00 0.05 0.000 0.003 0.08 0.97

HI@-pressure gas inpction et original pressure F= 1.0 x 0.2610.02Condensing-gas drive at saturation pressure F= 1.0 x0.22/0.022

(l&7)

(11) 0.111 0.158 0.183 0.239 0.316 0.447 0.558 0.666 0.779 0.852 0.916

CF at Original Pressure

(12)

CF at Saturation Pressure

(13) - -

1.624 1.206 2.740 2.036 5.683 4.222 8.829 6.559

12.787 9.499 15.324 11.384 16.847 12.515 17.861 13.269 18.612 13.827 19.201 14.264

GOR OriginPressu

(12)1(8)+

(141.12.94.39.0

16.735.763.6

100.2149.90.955 0.967 0.977 1 .ooo

19.729 14.656 20.094 14.927 20.236 15.033 20.297 15.078 0.18 0.028 0.144 0.172 0.15 0.010 0.135 0.145 0.13 0.003 0.124 0.127 0.00 0.000 0.000 0.000

1.675k.74 = 20.3 McWSTB.

734/1.15= 15.1 McflSTS.

t GOR at Saturation Pressure 13 (13)/(8)+1.13

(15) 1.130 2.441 3.534 7.058 12.768 26.830 47.596 75.848 111.706 BLE DISPLACEMENT

examples are carried out assuming (I) linear fluid with no crossflow, (2) distance of penetration of the le front being proportional to permeability, (3) nt pressure drop between the injection and produc- ells, (4) S,, (residual oil saturation) behind front zero, (5) SCF (free-gas saturation) equals zero, (6)

(relative-permeability ratio) equals one, thereby ng the mobility ratio as the viscosity ratio of reser- il to the displacing gas, and (7) abandonment at a of lC0,OOCVl.

Pressure Gas Injection and ensing-Gas Drive

comparison these two processes are calculated er using the basic reservoir data presented in Table High-pressure gas injection is assumed to take

at the initial reservoir pressure, whereas the injec- pressure for the condensing-gas-drive process is ed to be at saturation pressure. The calculation of covery and producing GOR data are presented in 45.4. From this table the fraction of cumulative

ht Curve

(1)

0.00 0.01 0.02 0.05 0.10 0.20 0.30

45-

TABLE 45.3-BASIC RESERVOIR DATA FOR HIGH-PRESSURE-GAS-INJECTION AND CONDENSING-GAS-DRIVE EXAMPLES

Original reservoir pressure, psig Saturation pressure, psig Reservoir temperature, OF Original solution GOR, scf/bbl Formation volume factor (reservoir oil)

At original pressure At saturation pressure

Reservoir oil viscosity, cp Al original pressure At saturation pressure

Injection-gas viscosity, cp At original pressure At saturation pressure

Formation volume factor for injection gas, bbl/Mscf At original pressure At saturation pressure

kg/k,o at displacing front

TABLE 45.4-CALCULATION OF RECOVERY AND PRODUCING GOR DATA (High-Pressure Gas Injection and Condensing-Gas Drive)

C k, 1-C k,h, k,h,+(l -C) Ah Curve AC &2) - CuNe 1 - (3) (7) x(l) (9) + (8) (2) (3) (4) (5) il (7) (8) (9) (10)

-0.000--y - ---c&i 1.ooo- 0.000 1.000 0.01 0.080 0.080 8.00 0.005 6.20 0.920 0.062 0.982 0.01 0.135 0.055 5.50 0.015 5.30 0.865 0.106 0.971 0.03 0.280 0.145 4.83 0.035 3.80 0.720 0.190 0.910 0.05 0.435 0.155 3.10 0.075 2.61 0.565 0.261 0.826 0.10 0.630 0.195 1.95 0.150 1.50 0.370 0.300 0.670 0.10 0.755 0.125 1.25 0.250 0.95 0.245 0.285 0.530

4,32,4

1,1

1.61.7

00

0.00.0

01

.l 0 0 0 .l .2 .3 A .5 .6 .7 .8 .9 1.0 h - FRAC. OF CUM. THICKNESS

Fig. 45.18-Permeability and capacity distribution vs. sand- thickness fraction.

thickness, h, is plotted as a function of dimensionless permeability, kD, and fraction of total capacity, C. These data are illustrated in Fig. 45.18. The recovery and GOR data are shown in Fig. 45.19. Note that, at an assumed abandonment ratio of 100,000 scf/bbl. recovery by condensing-gas drive was indicated to be 74.2% of the oil existing in the pattern area. The corresponding recovery for high-pressure gas injection was found to be only 66.5 % . The difference in recovery between these two methods is essentially a result of the difference in the compressibility factors of the displacing gas at the two pressures.

Time-Rate Performance. Time-rate performance was not calculated for all the examples presented since it would be a function of the well productivity. However, it must be pointed out that the excess pressure available in the high-pressure gas-injection process would yield higher well productivity and a shorter life, which could lead to more favorable economics.

Recovery of LPG Products. Recovery of LPG products contained initially in the injected gas under the condensing-gas-drive process was not illustrated. This item, however, would be a function of the following fac- tors: (I) percent recovery from the reservoir (estimated

TABLE 45.5-BASIC RESERVOIR DATA FOR MISCIBLE- SLUG INJECTION EXAMPLE

Reservoir pressure, psig Saturation pressure, psig Reservoir temperature, OF Formation volume factor for reservoir oil, RBlSTB Solution GOR, scf/bbl Stock-tank oil gravity, API Reservoir oil viscosity at 1,500 psig, cp injection gas viscosity at 1,500 psig, cp Formation volume factor for injection gas, RB/Mcf k,/k, at displacing front Reservoir-gas saturation. o/o Interstitial water saturation. O/O

11197

1.218 330

35 0.70

0.015 1.966

1.0 15 22 45-12

10.0

9 Producing GOR at initiation of injection, scf/bbl Es;m$d;PG slug volume for sweep pattern area,

3,000

5 PETROLEUM ENGINEERING HANDBOOK

OIL RECOVERY-PER CENT

,500 ,500

0 10 20 30 40 50 60 70 8090100 Fig. 45.19-Comparison of oil recoveries by high-pressure gas

injection and condensing-gas drive vs. producing GOR.

from GOR and oil-recovery data), (2) gasoline-plant recovery efficiency, and (3) plant ownership of recoverable liquids.

These factors, in addition to the high cost of LPG, become critical in an economic comparison of recovery processes.

Volume of Gas Injected. The volume of gas injected is estimated on a reservoir volume in/reservoir volume pro- duced basis. The volume of rich gas injected in condensing-gas-drive operations will depend on an evaluation of performance as related to the zones of stratification. To achieve the maximum effect from miscible displacement it is necessary to inject sufficient rich gas to establish a miscible front in the least permeable zone.

Miscible-Slug Injection To illustrate the miscible-slug process the reservoir in the previous examples was assumed to have been depleted to 1,500 psig. Table 45.5 presents a list of the pertinent reservoir data that existed for this condition.

The recovery and GOR performance was calculated using the capacity distribution data (Cols. 1 through 11) in Table 45.4 and the A factor, as calculated from the fluid data. These results are summarized in Table 45.6 and illustrated in Fig. 45.20. It is noted that the recovery at a GOR of 100,000/l was found to be 58.2% of the oil existing in the pattern area. This is a somewhat lower value than those indicated for high-pressure gas injection and condensing-gas drive. The difference is attributed to the more unfavorable mobility ratio at the lower pressure.

In this example, the GOR has decreased to approx- imately solution ratio as breakthrough was approached. It was assumed that all the free-gas saturation was pm- duced during this interval.

The size of the LPG slug injected was assumed to be 5% of the HCPV in the pattern area. This volume is within the range (2 to 10%) dictated by economics but

does not include a substantial safety factor. The volume of LPG slug produced was not calculated for this exam-

drive processes. 63-68 Other authors have presented their tre an pl an prpe

f ca ha s di ra pe

de bl intio dosim

Natments with respect to gas cycling, which in itself is example of miscible displacement. 69-72 For direct ap-ication to miscible drive operations, theoreticalalyses and equations for linear displacement have beenesented that offer a direct means for describing rformance. 68.73 An excellent example that compares the results olculated and actual performance of a pilot LPG floods been published. 21 In this example the reservoir wavided into several zones of varying permeability withdial-flow forms of Darcys law used to calculaterformance. Mathematical simulators commonly arc used today forsigning and predicting reservoir performance of misci-e floods. Two examples are (1) a vaporizing gas drive a moderately stratified reservoir by use of a composi- nal simulator74.75 and (2) a condensing gas drive in awnward displacement in a reef by use of a black-oil ulator. 76

omenclature C = capacity, fraction of total capacity MISCIBLE DISPLACEMENT

TABLE 45.6-CALCULATION OF RECOVERY AND PRODUCING GOR DATA MISCIBLE-SLUG-

INJECTION EXAMPLE

C Curve* 1-C N,* 0.000 1.000 0.111 0.080 0.920 0.158 0.135 0.865 0.183 0.280 0.720 0.239 0.435 0.565 0.316 0.630 0.370 0.447 0.755 0.245 0.558 0.830 0.170 0.666 0.880 0.120 0.779 0.917 0.083 0.852 0.946 0.054 0.916 0.972 0.028 0.955 0.990 0.010 0.967 0.997 0.003 0.977 1.000 0.000 1.000

CF*

2.312 3.902 8.092

12.572 18.207 21.820 23.987 25.432 26.501 27.339 28.091 28.611 28.813 28.900

From Table 45 4 i==l x0.7010.015x 1.218/1.966=26.9 MCWSTE tR D = Fourth CoLlSecond 201. + 33011,000

RPt 0.330 2.843 4.841

11.569 22.581 49.538 89.391

141.430

ple, but it can be estimated by multiplying the confor- mance efficiency at abandonment by the volume of slug injected. The net recoverable LPG, similar to that of condensing-gas-drive operations, would be reduced by the gasoline-plant recovery efficiency and plant- ownership percentage.

The volume of dry gas injected is estimated on a reser- voir volume in/reservoir volume out basis.

Alternative Calculation Procedures Alternative procedures for predicting performance of miscible drive operations are found in the literature. Several investigators have presented solutions to the permeability-stratification problem in the analysis of waterflooding which may be modified to fit miscible- C L771 = cumulative capacity, fraction of total capacity

CF = equivalent gas production 45-13

80

60

F= h=

k&,, XCLJCL~ XBJB, cumulative thickness, fraction of total

thickness h= average cumulative thickness, fraction of

total thickness k= permeability, millidarcies

kD = AC/Ah =dimensionless permeability N, = [kDh +( 1 - C)]lk~ = fraction of total oil

PM = R, =

R., = l-C=

recovery miscible pressure, psia CA/( 1 -C) +R, =producing gas-oil ratio,

Mcf/STB solution GOR equivalent oil production

0 10 20 30 40 50 60 70

OIL RECOVERY-PER CENT

Fig. 45.20-011 recovery vs. producing GOR for LPG slug injection.

References I.

2. 3

4.

5.

6.

I.

a.

9.

Clark, N.J. et al.: Miscible Drive-Its Theory and Applica- tion, J. Pet. Tech. (June 1958) 1 I-20. Morse, R.A.: British Patent No. 696524 (1953). Koch, H.A. Jr. and Slobod. R.L.: Miscible Slug Process. Truns.. AIME (1957) 210, 40-47. Hall, H.N. and Geffen, T.M.: A Laboratory Study of Solvent Flooding, Trarzs.. AIME (1957) 210, 48-57. Gatlin. C. and Slobod, R.L.: The Alcohol Slug Process for In- creasing Oil Recovery. Trans., AIME (1960) 219. 46-53. Gogarty, W.B. and Tosch, W.D.: Miscible-Type Waterflood- mg: Oil Recovery With Micellar Solutions, J. Pet. Tech. (Dec. 1968) 1407-14: Trans., AIME, 243. Helm. L.W.: Use of Soluble Oils for Oil Recovery. J. Pet. Twh. (Dec. 1971) 1475-83; Trans., AIME. 251. Craig, F.F. Jr. and Owens, W.W.: Miscible Slug Flooding-A Review. J. Pet. Tech. (April 1960) 1 I-15. Brown. G.G. tr al.: Natural Gasoline and the Volatile Hydrocar- how, Natural Gasoline Assn. of America (1948). IO.

Il.

Hutchmson, C.A. Jr. and Braun, P.H.: Phase Relations of Miwble Displacement in Oil Recovery, AlChEJ. (1961) 7, 64 Stone. H.L. and Crump. J.S.: Effect of Gas Composition Upon Oil Recovery by Gas Dnve. Trurts., AIME (IY56) 207. 105-10.

6645-14

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Kehn. D.M.. Pyndus, G.T.. and Gaskell, M.H.: Laboratory Evaluation of Prospective Enriched Gas Drive Projects, Trans., AlME (1958) 213, 382285. Clark, N.J., Schultz, W.P.. and Shearin, H.M.: New Injection Method Affords Total Oil Recovety, Pet. Engr. (Oct. 1956) B-4.5. Wharton. L.P. and Kieschnick. W.F. Jr.: Oil Recovery by High Pressure Gas Injection, Oil and Gas J. (April 1950) 48, 78-89. Katz, D.L.: Possibility of Cycling Deep Depleted Oil Reservoirs after Compression to a Single Phase, Trans., AIME (1952) 195. 175-82. Griffeth, B.L. and Hollrah, V.M.: Report on Field Trial of High Pressure Gas, Oil and Gas J. (June 1952) 86-93. Slobod, R.L. and Koch, H.A. Jr.. High Pressure Gas Injec- tion-Mechanism of Recovery Increase, Drill and Prod. Prac., API (1953) 82. Wilson, J.F.: Miscible Displacement-Flow Behavior and Phase Relationships for a Partially Depleted Reservoir, Trans., AIME (1960) 219: 223-28. Koch, H.A. Jr. and Hutchinson, C.A.: Miscible Displacements of Reservoir Oil Using Flue Gas, J. Pet. Tech. (Jan. 1958) 7-19; Trtins., AIME (1958) 213. Blackwell, R.J., Rayne, J.R., and Terry, W.M.: Factors In- fluencing Efficiency of Miscible Displacement, J. Per. Tech. (Jan. 1959) l-8; Trans.. AIME (1959) 216. lusten. J.J. ef al.: The Pembina Miscible Displacement Pilot and Analysis of Its Performance. J. Per. Tech. (March 1960) 38-45; Trans., AIME, 29. Rushing, M.D. et al.: Miscible Displacement with Nitrogen, Pet. Eng. (Nov. 1977) 26-30. Sage, B.H. and Lacey, W.N.: Some Properties of the tighrer Hydrocarbons, Hydrogen Sulfide, and Carbon Dioxide, Monograph, Research Project 37, API, Dallas (1955). Helm. L.W. and Josendal, V.A.: Mechanisms of Oil Displace- ment by Carbon Dioxide, J. Per. Tech. (Dec. 1974) 1427-35; Trans., AIME, 257.

25. Helm. L.W. and Josendal. V.A.: Discussion of Determination and Prediction of CO> Minimum Miscibility Pressure. J. Per. Tech. (May 1980) 870-71.

26. Orr. F.M. Jr. and Silva. M.K.: Eouilibrium Phase Compositions of CO? /Hydrocarbon Mixtures-Part I : Mixtures Measurement bv Continuous Multiple Contact Experiment, Sot. Per. Eng. J. (April 1983) 272-80:

27. Shelton, J.L. and Yarborough. L.: Multiple Phase Behavior in Porous Media During CO, or Rich Gas Flooding, J. Per. Tech. (Sept. 1977) 1171-78.

28. Helm. L.W. and Josendal. V.A.: Effect of Oil Composition on Miscible-Type Displacement by Carbon Dioxide, Sot. Pet. Eng. J. (Feb. 1982) 87-98.

29. Metcalfe. R.S.: Effects of Impurities on Minimum Miscibility Pressures and Minimum Enrichment Levels for CO, and Rich- Gas Displacements, Sot. Per Eng. J. (April 1982) 219-25.

30. Jacoby. R.H. and Rzasa. M.J.: Equilibrium Vaporization Ratios for Nitrogen. Methane. Catbon Dioxide, Ethane and Hydrogen Sulphide in Absorber Oil-Natural Gas and Crude Oil-Natural Gas Systems. Trans.. AIME (1952) 195, 99-110.

31. Simon, R.. Rosman, A., and Zana, E.: Phase Behavior Pmper- ties of CO?--Reservoir Oil Systems. Sot. Pet. Eng. J. (Feb. 1978) 20-26.

32. Perkins, T.K. and Johnston, O.C.: A Review of Diffusion and Dispersion in Porous Media, SOL-. Pet. Eng. J. (March 1963) 70-84: Trans.. AIME. 228.

33. Blackwell. R.J.: Laboratory Studies of Microscopic Dispersion Phenomena, Ser. Per. Eng. J. (March 1962) 1-8; Trans., AIME, 225.

34. Warren. J.E. and Skiba. F.F.: Macroscooic Distxrsion. Sot. Per. Eng. J. (Sept. 1964) 215-30; Trans..AIME,231.

35. van der Poel, C.: Effect of Lateral Diffusivity on Miscible Disolacement in Horizontal Reservoirs. Sot. Per.. Enp. J. (Dec. 1982) 317-26: Trans., AIME, 225.

MISCIBLE DISPLACEMENT 45-15 69.

70.

71.

72.

73.

74.

75.

76.

Muskat. M.: Effect of Permeability Stratification in Cychng Operations. Trans., AIME (1949) 179, 313-28. Lindbad, E.N., Standing. M.B., and Parsons, R.L.: Calculated Recoveries by Cycling from a Retrograde Reservoir of Variable Permeability, Trans., AIME (1948) 174, 165-90. Hurst, W.. and van Everdingen, A.F.: Performance of Distillate Reservoirs in Gas Cycling. Trans., AIME (1946) 165, 36-51. Sheldon, W.C.: Calculating Recovery by Cycling a Retrograde Condensate Reservoir, J. Pet. Tech. (Jan. 1959) 29-34. Gardner, G.H.F.: Equations of Motion for A Linear Miscible Displacement, PAPER 902-G presented at the 1957 SPE Annual Meeting, Dallas, Feb. 24-28. Warner, H.R. Jr. ef al.: University Block 31 Field Study: Part I-Middle Devonian Reservoir History Match, J. Per. Tech. (Aug. 1979) 962-70. Warner. H.R. Jr., Hardy, J.H., and Davidson, C.D.: University Block 31 Field Studv: Part 2-Reservoir and Gas Plant Perfor- mance Predictions,J. Per. Tech. (Aug. 1979) 971-78. Gillund, G.N. and Patel, C.: Depletion Studies of Two Con- trasting D-2 Reefs. paper 80-31-37 presented at the 1980 Annual Technical Meeting of the Petroleum Sot. of CIM. Calgary. May 25-28.

General References Applications of Miscible Processes Baugh, E.G.: Performance of Seeligson Zone 20-B Enriched Gas-

Drive Project. J. Per. Tech. (March 1960) 29-33.

Blanton. J.R., McCaskill, N., and Herbeck, E.F.: Performance of a Propane Slug Pilot in a Watered-Out Sand-South Ward Field, J. Pet. Tech. (Oct. 1970) 120914.

Christian, L.D. ef al.: Planning a Tertiary Oil-Recovery Project for JayiLEC Fields Unit, J. Per. Tech. (Aug. 1981) 1535-44.

DesBrisay. C.L. et al.: Miscible Flood Performance of the Intisar D Field, Libyan Arab Republic, J. Per. Tech. (Aug. 1975) 935-43.

DesBrisay, C.L. et al.: Review of Miscible Flood Performance, In- tisar D Field, Socialist Peoples Libyan Arab Jamahiriya, J. Per. Tech. (Aug. 1982) 1651-60.

Hansen, P.W.: A CO;, Tertiary Recovery Pilot, Little Creek Field, Mississippi, paper SPE 6747 presented at the 1977 SPE Annual Techmcal Conference and Exhibition, Denver, Oct. 9-12.

Herbeck, D.F., and Blanton, J.R.: Ten Years of Miscible Displace- ment in Block 31 Field, J. Pet. Tech. (June 1961) 543-49.

Helm, L. W. and OBrien, L.J.: Carbon Dioxide Test at the Mead- Strawn Field, J. Pet. Tech. (April 1971) 431-42.

Helm, L.W.: Propane-Gas-Water Miscible Floods in Watered-Out Areas of the Adena Field, Colorado, J. Pet. Tech. (Oct. 1972) 1264-70.

Jenks, L.H., Campbell, J.B., and Binder, G.G. Jr.: A Field Test of Gas-Driven Liquid Propane Method of Oil Recovery, Trans., AIME (1957) 210, 34-39.

Kane, A.V.: Performance Review of a Large Scale CO,-WAG Enhanced Recovery Project, SACROC Unit-Kelly Snyder Field, J. Per. Tech. (Feb. 1979) 217-31.

Lackland, S.D. and Hutford, G.T.: Advanced Technology Improves Recovery at Failway, J. Pet. Tech. (March 1973) 354-58.

Marts, D.G.: Field Results of Miscible Displacement Program Using Liqmd Propane Driven by Gas, Parks Field Unit, Midland County, Texas, J. Pet. Tech. (April 1961) 327-32. Gemet. J.M. and Brigham. W.E.: Meadow Creek Unit Lakota B Combination Water-Miscible Flood, J. Per. Tech. (Sept. 1964) 993-97.

Glasser, S.R.: History and Evaluation of an Experimental Misctble Flood in the Rio Bravo Field, Prod. Monthly (Jan. 1964) 17-20.

Griffith, J.D., Baiton, N., and Steffensen, R.J.: Ante Creek-A Miscible Flood Using Separator Gas and Water Injection, J. PH. Tech. (Oct. 1970) 1232-41.

Griffith, J.D. and Cyca, L.G: Performance of South Swan Hills Miscible Flood, J. Pet. Tech. (July 1981) 1319-26.

Griffith, J.D. and Home, A.L.: South Swan Hills Solvent Flood, Proc., Ninth World Pet. Cong.. Tokyo (1975) 4. 269-78.

Harvey, M.T., Shelton, J.L. and Kelm. C.H.: Feld Injectivity Ex- periences with Miscible Recovery Projects Using Alternate Rich Gas and Water Injection, J. Per. Tech (Sept 1977) 1051-55.

Kloepfer, C.V. and Griffith, J.D.: Solvent Placement Improvement by Pre-Injection of Water, Lobstick Cardium Unit Pembma Field. paper SPE 948 presented at the 1964 SPE Annual Meeting. Houston Oct. 1 I-14.

Lane. L.C., Teubner, W.G., andCampbell. A.W.: Gravity Segrega- tion in a Propane Slug-Miscible Displacement Project, Baskington Field, J. Per. Tech. (June 1965) 661-63.

Macon, R.S.: Design and Operation of the Levelland Unit CO> In- jection Facility, paper SPE 8410 presented at the 1979 SPE Annual Technical Conference and Exhibition. Las Vegas. Sept. 23-26.

Meltzer, B.D., Hurdle, J.M.. and Cassingham. R.W.: An Efficient Gas Displacement Project-Raleigh Field, Mississippi, J. Pet. Tech. (May 1965) 509-14.

Palmer, F.S., Nute. A.J., and Peterson, R.L.: Implementation of a Gravity-Stable Miscible CO, Flood in the 8000-Foot Sand, Bay St. Elaine Field, J. Pet. Tech. (Jan. 1984) 101-10.

Pottier, J. ef nl.: The High Pressure Injection of Miscible Gas at Hassi-Messaoud, Proc., Seventh World Pet. Gong., Mexico City (1967) 3, 533-44.

Thrash, J.C.: Twofreds Field-Tertiary Oil Recovery Project, paper SPE 8382 presented at the 1979 SPE Annual Technical Con- ference and Exhibition. Las Vegas. Sept. 23-26.

Tittle. R.M. and From, K.T.: Success of Flue Gas Program at Neale Field, paper SPE 1907 presented at the 1960 SPE Annual Meeting, Houston, Oct. l-4.

Pontious, S.B. and Tham, M.J.: North Cross (Devonian) Unit CO, Flood-Review of Flood Performance and Numerical Simulation, J. Pet. Tech. (Dec. 1978) 1706-14.

Sessions. R.E.: Small Propane Slug Proving Success in Slaughter Field Lease. J. Per. Tech. (Jan. 1963) 31-36.

Field Tests of Miscible Processes Bleakley, W.B.: Journal Survey Shows Recovery Projects Up. Oil

urn! Gus J. (March 1974) 69-78.

Brannan, G. and Whittington. H.M. Jr.: Enriched Gas Miscible Flooding-A Case History of the Levelland Unit Secondary Misci- ble Project, J. PH. Tech. (Aug. 1977) 919-24.

Burt. R.A. Jr.: High Pressure Miscible Gas Displacement Project, Bridger Lake Unit. Summit County, paper SPE 3487 presented at the 1971 SPE Annual Meeting. New Orleans, Oct. 3-6.

IntroductionTheoretical Aspects of Miscible-Phase DisplacementEactors Affecting Displacement EfficiencyNomenclatureReferencesGeneral References