Status of Miscible Displacement Fred I. Stalkup Jr., SPE, ARCO Oil & Gas Co.

Summary Methods for miscible flooding have been researched and field tested since the early 1950's. This paper reviews the technical state of the art and field behavior to date for the major miscible processes: first-contact miscible, condensing-gas drive, vaporizing-gas drive, and CO 2 flooding. Important technological areas selected for review include phase behavior and miscibility, sweepout, unit displacement efficiency, and process design variations. COrflood technology is emphasized, and several technical issues are identified that still need to be resolved. Rules of thumb and ranges of conditions are discussed for applicability of each process. A com-parison is made of the incremental recovery and solvent slug effectiveness observed in field trials of the different processes. From the limited data available, there is no clear-cut evidence that field results on average and for a given slug size have been appreciably better or poorer for one process compared with another.

Introduction The search for an effective and economical solvent along with development and field testing of miscible-flood processes has continued since the early 1950's. Early focus was on hydrocarbon solvents, and three types of hydrocarbon-miscible processes were developed: the first-contact miscible process; the vaporizing-gas drive process, often called high-pressure gas drive; and the condensing-gas drive process, sometimes called enriched-gas drive.

First-contact miscible solvents mix directly with reser-voir oils in all proportions and their mixtures always re-main single phase. Other solvents are not directly misci-ble with reservoir oils, but under appropriate conditions of pressure and solvent composition these solvents can achieve miscibility in-situ by mass transfer of oil and sol-01492136/83/00049992$00.25 Copyright 1983 Society of Petroleum Engineers of AIME

APRIL 1983

vent components through repeated contact with the reser-voir oil. Miscibility achieved in this manner is called "multiple-contact" or "dynamic" miscibility. The vaporIzmg-gas drive process achieves dynamic miscibility by in-situ vaporization of the intermediate-molecular-weight hydrocarbons from the reservoir oil in-to the injected gas. Dynamic miscibility is achieved in the condensing-gas drive process by in-situ transfer of intermediate-molecular-weight hydrocarbons from the injected gas into the reservoir oil.

Propane 01:' liquid petroleum gas (LPG) mixtures typically were the solvents used in first-contact hydrocarbon miscible flooding, whereas natural gas at high pressure and natural gas with appreciable concen-trations of intermediate-molecular-weight hydrocarbons were injection fluids in vaporizing-gas drive and condensing-gas drive floods. The high cost of propane, LPG, or enriched hydrocarbon gas dictated that these solvents be injected as slugs, which usually were driven with natural gas. Flue gas and nitrogen also have been found to achieve dynamic miscibility at high pressures with some oils by the vaporizing-gas drive mechanism.

Hydrocarbon miscible processes have received exten-sive field testing since the 1950's, primarily in the U.S. and Canada. More than 100 projects were initiated dur-ing this time period. \-9 The majority were small-scale pilot tests involving one or at most a few injection wells; however, a number of large projects were undertaken in-volving several thousand acres or more (> 4 X 106 m 2 ). A few projects tested flue-gas injection.

Recent miscible flooding interest in the U.S. has centered on the CO 2 process, although use of CO 2 for oil recovery is not a recent idea. Research dates to the early 1950's. CO 2 has several advantages compared with hydrocarbon solvents or flue gas. It often achieves dynamic miscibility at a significantly lower pressure than natural gas or flue gas, so more reservoirs can be

815

'" in

3600

3200

2800

.3 2400 w a:: :::J gJ 2000 w a:: a.

1600

1200

800

SINGLE LIQUID PHASE

;ff: o o

REGION OF UPPER LIQUID IUL) AND LOWER LIQUID ILL)

0% V

REGION OF UL. LL. GAS

0% Ul '----I--.--'l--REGION OF LL AND GAS

90 80 70 60 50 40 30 20 10 2

VOLUME PERCENT LOWER LIQUID PHASE

o 20 40 60 80 100 MOLE PERCENT C02 ADDED

Fig.1-Pressure vs. CO 2 concentration phase diagram for Wasson crude at 105F (after Ref. 19).

miscibly flooded with CO 2 than with these other gases. In addition, both the supply and cost of CO 2 may be more favorable in the future than for hydrocarbon misci-ble solvents. This is because large quantities are available from natural deposits. 10, II Engineering studies show that CO 2 from some of these deposits can be developed and transported to favorably located oil fields by pipeline at acceptable costs. II There has been moderate field testing so far of CO 2 -miscible flooding. 10

There are about 40 projects of all types currently ac-tive. 12 Total production rate attributable to miscible flooding probably is more than 100,000 BID (16000 m3 /d) worldwide. Technical State of the Art Phase Behavior and Miscibility Phase behavior requirements and mechanisms for achieving miscibility in the hydrocarbon processes were generally recognized by the late 1950's. Hutchinson and Braun 13 described how multiple-contact miscibility was achieved in the vaporizing-gas and condensing-gas drive processes and discussed the factors affecting miscibility for all the hydrocarbon processes. Pseudotemary diagrams and pressure-composition diagrams were shown to be useful ways for representing the phase behavior of these systems.

Miscibility between solvent and driving gas normally determines the minimum pressure required for first-contact miscibility. Miscibility pressures generally range from about 1,100 to 1,900 psi (7.6 to 13.1 MPa).

Condensing-gas drive miscibility depends on oil com-position, enriched-gas composition, pressure, and temperature. Miscibility pressure typically is in the range of 1,500 to 3,000 psi (10.3 to 20.7 MPa) for oils of 30 API gravity (0.88 g/cm 3) or higher.

Vaporizing-gas drive miscibility with natural gas depends on oil composition, temperature, and pressure. High-gravity oils are required, generally >40 API

816

100 VOL % C02

SINGLE CONTACT POINTS

6 MULTIPLE CONTACT POINTS

100 VOL % 100 VOL % C 7 L...L--"-----'''-------8.>L-_''----''-_'''--''-_-''-----''-~ Cs

Fig. 2-Composite ternary diagram for the C0 2 IWasson crude system at 2,000 psi a and 105F (after Ref. 19).

0.83 g/cm 3); and 3,500 psi (24.1 MPa) is about the lower limit for miscibility pressure, which may be substantially higher than this. Phase relations with flue gas or nitrogen are more unfavorable for dynamic miscibility than for methane, causing a higher miscibility pressure, although the pressure increase may be small with some oils of high saturation pressure. 14,15

The mechanism by which CO 2 achieves dynamic miscibility is not thoroughly understood at this time. The bulk of evidence to date indicates that a vaporizing-gas drive mechanism prevails when reservoir temperature is greater than about 120F (49C). 1618 However, CO 2 is a much more powerful vaporizer of hydrocarbons than natural gas or flue gas. Hydrocarbons as heavy as the gasoline and gas/oil fractions are vaporized into the CO2 front in addition to intermediate-molecular-weight hydrocarbons, and, because of this, development of vaporizing-gas drive miscibility with CO 2 can occur with little or no C 2 through C 6 components present in the crude oil. 18

At temperatures lower than about 120F (49C) the situation becomes more complex. 17,19,20 This is il-lustrated by the pressure-composition diagram of Fig. 1. At pressures higher than about 1,600 psi (11.0 MPa) for this particular CO2 /oil system, two liquid phases coexist in the multiphase region rather than the gas/liquid equilibrium typical of vaporizing-gas drive systems. At pressures between about 1, 150 and 1,400 psi (7.9 and 9.7 MPa), three phases can be in equilibrium-two liq-uids and a gas. This type phase behavior has been reported in the literature several times. 11,19,21,22

Gardner et al. 19 experimentally determined pseudoter-nary diagrams to investigate the liquid/liquid and three-phase regions of Fig. 1. Their diagrams are shown in Figs. 2 and 3. At 2,000 psi (13.8 MPa), Fig. 2, two liq-uid phases are in equilibrium. For phase behavior of the type shown in this figure, dynamic miscibility can be achieved in a manner analogous to the vaporizing-gas drive miscibility for gas/liquid phase behavior.

JOURNAL OF PETROLEUM TECHNOLOGY

100 VOL % C02

SINGLE CONTACT POINTS

l!:. MULTIPLE CONTACT POINTS

- PLAIT POINT

CRUDE 100VOl%~~~~dL~ __ ~~ __ ~~~~ __ ~100VOl%

Cr Ce

Fig. 3-Composite ternary diagram for the CO 2 /Wasson crude system at 1,350 psia and 105F (after Ref. 19).

Hydrocarbons are extracted from the oil into the COz-rich liquid phase to create a miscible transition zone.

Fig. 3 shows data at 1,350 psi (9.3 MPa), a pressure where three phases were found in equilibrium on the pressure-composition diagram. The pseudoternary diagram hypothesized from these data shows four subregions: three two-phase regions and one three-phase region. Although slim-tube displacement experiments showed that dynamic miscibility could be achieved at this pressure, the exact mechanism has not been defined clearly. A combination of vaporizing-gas drive and condensing-gas drive mechanisms is suggested by the phase behavior depicted in Fig. 3, but more work is needed to verify or disprove this concept.

Miscibility pressure for some oils with CO 2 is as low as 1,200 psi (8.3 MPa) , and miscibility pressure in-creases with increasing reservoir temperature and decreasing oil gravity. 11,23 As a rough rule of thumb, reservoirs deeper than about 2,500 ft (762 m) containing oils of 28 API or higher (0.89 g/cm3 or lower) should be evaluated as potential candidates for CO 2 miscible flooding.

Sweepout Solvents typically are less dense and less viscous than reservoir oils. Laboratory research and field testing have shown that gravity tonguing and viscous fingering are more severe than in waterflooding because of these prop-erties. As a result, sweepout usually is poorer than in waterflooding for equivalent PV of fluid injected.

Sweepout depends on mobility ratio and on the ratio of viscous (horizontal) and gravity (vertical) forces. Four flow regimes are possible in the vertical cross section, depending on the viscous/gravity force ratio.24 This is shown schematically in Fig. 4.

At very low values of viscous/gravity force ratio (Region I), the displacement is characterized by a single gravity tongue or finger overriding the oil. The geometry of this finger and vertical sweepout depend on the par-ticular viscous/gravity ratio of the displacement. At higher values of viscous/gravity ratio (Region II), the APRIL 1983

100

80

60

40

LEGEND U . FLUX, 8/0/FT2

i< 0 . VISCOSITY CP X . LENGTH. FT Y HEIGHT. FT K PERMEABILITY, MD tlp SOLVENT -OIL DENSITY

DIFFERENCE. GM CC

I-- III --1--- IV ----

M 65

M 27

~=::-I~I =====r::======- III ---~ IV-10 100 1000

VISCOUS/GRAVITY FORCE RATIO

10,000 u~o' x

2050 K 0tlp Y

100.000

Fig. 4-Flow regimes in a two-dimensional, uniform linear system.

displacement is still characterized by a single gravity finger, but vertical sweepout becomes independent of the value of the ratio until a critical value is exceeded. Beyond this critical value, a transition region is en-countered (Region III), where secondary fingers form beneath the main gravity tongue. In this region sweepout for a given value of PV injected increases sharply with increasing values of the viscous/gravity ratio. Finally, a value of viscous/gravity ratio is reached where the displacement is entirely dominated by viscous fingering, and vertical sweepout again becomes independent of the viscous/gravity ratio (Region IV). The value of viscous/gravity ratio at which transition occurs from one flow region to another depends on the mobility ratio. 24

There are considerable published areal sweepout data for flow dominated by viscous fingers 25-29 and some vertical sweepout data for Region I and II flow dominated by gravity tonguing. 30,31 There are few published data for volumetric sweepout. 30 Data are limited also for slug processes,32 tertiary recovery, 33 and dynamic miscible displacement. 34

Although several methods have been researched for improving mobility ratio and, consequently, the sweepout of horizontal miscible floods, 35-39 alternate in-jection of water and solvent currently is the only method being practiced in the field. 40 Even when gravity causes the solvent and water to segregate partially, laboratory experiments 4 I and reservoir simulations42,43 both show that improved sweepout may result still from alternate solvent/water injection. Solvent/water injection may also be of benefit in tertiary-recovery flooding, even though injection of more water into rock where the oil saturation has already been driven to its residual value, intuitively may seem counterproductive. 42,43 There have been many field projects where operators reported that solvent/water injection was beneficial in moderating pro-duced GOR after solvent and drive-gas break-through. 44-52 Mobility of the solvent/water region was measured directly in a recent field test and found to be about as low as the mobility of drive water in the preceding waterflood. 53 A potential disadvantage of sol-vent/water injection is trapping of oil by water if overin-

817

jection of water should cause a high water saturation at the miscible displacing front. This potential effect should be evaluated carefully in selecting a solvent/water injec-tion ratio.

Factors that affect CO 2 mobility are not completely resolved at this time. Considering viscosity alone, a substantially unfavorable mobility ratio would be ex-pected in CO 2-miscible flooding. However, the com-plex CO 2/oil phase behavior that has been reported at relatively low reservoir temperatures raises the possibili-ty of precipitation of liquid and/or solid phases in the CO 2/oil transition zone that might reduce CO 2 mobility below the level anticipated from normal viscosity and relative permeability relations. Some laboratory flow ex-periments are published that indicate reduced mobility in the multi phase region. 54 Lower-than-expected CO 2 in-jectivity was reported in several field tests,52.55 but whether the field test behavior was caused only by a near-well permeability reduction or whether it was caused by a reduced CO 2 mobility throughout the swept region has not been established conclusively. This is one of the more important technical issues in CO 2 flooding left to be resolved. Unnecessary injection of water or overinjection, if some water should be required, not only increases the complexity and expense of field operation but also decreases injectivity unnecessarily and lengthens project life. Also, water overinjection con-ceivably could trap some oil and render it inaccessible to the CO 2,

Data reported by Giraud 34 indicate that two-phase flow in the miscible transition zone of a vaporizing-gas drive can also reduce gas permeability and mobility below that expected for a first-contact miscible solvent.

Densities of oil and CO 2 are similar at many reservoir conditions, which tends to minimize segregation be-tween these fluids in reservoirs that have not been waterflooded. In reservoirs that have been waterflooded or have had water injected with CO 2 to counteract the effects of viscosity ratio and permeability stratification, the density contrast between water and CO 2 may cause segregation. 42,43

Unit Displacement Efficiency Under some conditions all the oil may not be displaced from a given volume of rock even though the solvent composition and pressure are sufficient for miscibility and even though the rock has been completely swept by solvent. This undisplaced oil left in the solvent-swept rock is analogous to the microscopic residual oil left after waterflooding. In addition to subtracting from total oil recovery, miscible-flood residual oil may cause reduced solvent injectivity but an improved mobility ratio com-pared with complete oil displacement. The causes for a miscible-flood residual oil saturation are primarily (1) trapping of oil by mobile water at water saturations above the irreducible value, (2) bypassing of oil located in dead-end pores and low-permeability occlusions that are not flushed by solvent, and (3) precipitation of hydrocarbons during vaporizing-gas drive or CO 2 flooding as a result of mixing into multiphase regions.

Laboratory tests have shown that in some water-wet sandstones mobile water can trap and shield part of the oil from a miscible solvent. 56-60 Reservoir simulations show that this trapping can significantly reduce oil

818

recovery if water is overinjected during alternate sol-vent/water injection. 43 Several studies with reservoir rocks, however, have found little or no trapping of oil caused by mobile water, at least for the water saturations investigated, perhaps because of the mixed wettability of these reservoir rocks. 49,57,61,62 Nevertheless, evaluation of potential oil trapping is advisable if alternate sol-vent/water injection is planned.

Oil can be bypassed by miscible solvents because of dead-end pore structure and because of microscopic-to-macroscopic permeability heterogeneities. Several publications have shown the effect of laboratory core-scale heterogeneities in carbonate cores. 62 ,63 There are no data published so far showing a significant effect of this sort in sandstones. Bypassed oil saturations ranging from 0.13 to 25 % PV were reported for a series of cores from one carbonate reservoir. 62 However, for reservoir times and rates, some of the oil located in core-scale heteroeneities may subsequently be recovered by diffu-sion. 6 Techniques are not well developed for determin-ing the amount of oil that may be permanently bypassed because of pore structure.

Gardner et al. 19 published calculations showing that the magnitude of residual oil saturation caused by liquid precipitation in CO 2 floods depends on the size of the multi phase region and on the degree of fluid mixing dur-ing the displacement. This should be true for vaporizing-gas drives as well.

There have been several field tests published where oil saturations left behind solvent fronts were determined by coring. A core taken 100 ft (30.5 m) from an injector in the Seeligson condensing-gas drive flood showed good permeability zones of this sandstone were essentially swept clean of oil. 64 A pressure core taken behind the enriched-gas front at South Swan Hills found an average 7.9% PV oil saturation in this carbonate formation. 65 Pressure cores taken in the Mead-Strawn sandstone behind a CO2 flood at distances of 50 and 100 ft (15.2 and 30.5 m) from an injection well had average oil saturations of 10 and 5% PV stock-tank oil,66 and a pressure core taken 35 ft (10.7 m) from a CO 2 injector in the San Andres carbonate formation of west Texas found oil saturations that varied from 3 to 30% PV stock-tank oil. 67

Process Design Variations Miscible floods have been designed for continuous sol-vent injection, for solvent slugs driven by a miscible gas, and for solvent slugs driven by water. In addition, many process designs have called for alternate water injection for mobility ratio improvement, either with the drive gas alone or with both the solvent slug and drive gas.

Essentially all first-contact miscible projects have used relatively small slugs of LPG, approximately 1 to 12 % hydrocarbon pore volume (HCPV), driven by natural gas. Laboratory research has shown that mixing of oil/solvent/drive gas by dispersion,68 aggravated by viscous fingering, gravity tonguing, and channeling caused by stratification, can rapidly dilute small solvent slugs to concentrations that are no longer miscible. 69 Fingering can also cause drive gas to physically breach a solvent slug and directly contact oil, with which it is immiscible. 26

Condensing-gas drive projects typically have used JOURNAL OF PETROLEUM TECHNOLOGY

larger slugs than in first-contact miscible flooding, usually greater than 10% HCPV and driven by natural gas. This is partly because the enriched-gas slug is less concentrated in intermediate hydrocarbons and partly to withstand fingering better. There have been several gravity-stable condensing-gas drive projects in pinnacle reefs where gravity was used to advantage to prevent viscous fingering. 70,71 In these projects a primary design consideration was to size the enriched-gas slug to with-stand dilution caused by dispersion and reservoir heterogeneities.

Continuous injection has been the rule in vaporizing-gas drive projects, with produced gases being com-pressed and reinjected.

The trend in CO 2 flood projects has been to drive relatively large CO 2 slugs of 15 % HCPV or greater with water. The objective here is to improve miscible sweepout by achieving a favorable mobility ratio at the trailing edge of the slug. The disadvantage of this method, of course, is that the displacement of CO 2 by water is immiscible, and a residual CO 2 saturation is left in the reservoir. There has been at least one project where CO 2 was driven by a miscible gas. 52 The magnitude of oil recovery improvement attained by miscible-gas drive over water drive and whether or not this improvement justifies the added expense of the drive gas are issues that are not completely resolved at this time. Field Test Behavior First-Contact Miscible Projects There have been more than 50 field tests of this method, the majority being conducted in the 1950's and 1960's. Most were small pilot tests involving one or at most a few injection wells and with test sizes varying from several tens to several hundred acres (50000 to 106 m2), although a few projects were fieldwide in scope and involved several thousand acres. Most tests were in sandstones and most were secondary-recovery floods. The majority of projects were in reservoirs that were essentially horizontal; however, there have been several gravity-stable floods in pinnacle reef reservoirs. 8,9,63,72 Solvent slug sizes were primarily in the I to 12 % HCPV range. Oil gravities have ranged from 30 to 51 0 API (0.88 to 0.78 g/cm 3) with the majority between 36 and 42 0 API (0.84 and 0.82 g/cm 3).

Field experience in secondary-recovery tests has shown that the process will displace oil in reservoirs con-taining an initial gas saturation and bank oil into a secon-dary oil bank.73-75 Response resembles the response to waterflooding - decreasing GaR's and increasing oil productivity when the secondary oil bank arrives at pro-ducing wells. In most projects in horizontal reservoirs, rapid breakthrough of both solvent and lean hydrocarbon drive gas occurred, such as the Pembina and Bisti tests where solvent breakthrough was detected after injection of about 0.1 HCPV of fluids. 76,77 Often, oil bank, sol-vent, and drive-gas breakthrou~hs have occurred within a short time of each other. 4 ,73 In some projects a substantial fraction of the LPG was produced. Alternate injection of water and lean gas slugs was believed to slow the rate of GaR increase after breakthrough in some projects. 44,45

Craig 2 compared recoveries from both LPG and

APRIL 1983

condensing-gas drive projects with recovery expected for immiscible dry-gas injection, and, of 31 projects ana-lyzed, he concluded that about 22 % had recovered an in-cremental volume four times greater than the volume of solvent slug, while incremental recovery did not even equal the solvent slug volume in 26% of the projects. No difference was found between LPG and rich-gas drive projects.

There are only a few published attempts to compare performance of secondary recovery first-contact miscible flooding proiects with anticipated waterflood perfor-mance. 44,45,18 In these instances the miscible floods were believed to have recovered from 8 to 35 % more oil than would have been achieved by primary production followed by waterflooding.

Ultimate recovery for the Wizard Lake gravity-stable flood is anticipated to be about 84% OOIP. 63 ,72 By late 1980, oil recovery had reached 61 % OOIP, about equal to the recovery expected for continued primary depletion by immiscible gas expansion and water drive.

Floods in waterflooded or partially waterflooded reser-voirs give a relatively direct measure of incremental recovery over waterflooding. Table I summarizes results of seven tests of this type where data are available from publications. 80-85 Slug sizes ranged from 4 to 12 % HCPV, and incremental recovery actually measured at the time the project analysis was published ranged from 3.7 to 13.5% OOIP at discovery. In one project in-cremental recovery was projected by decline-curve analysis ultimately to be as high as 34% OOIP. Oil recovered per gross barrel of LPG injected varied from about 0.5 to 1.5 STB/RB (1.5 stock-tank m3/res m3), and although data were not always available on LPG production and recovery, ratios of oil recovered per net barrel of LPG injected were in the range of 1 to 2 STB/RB (l stock -tank m 3 !res m 3) for the few tests where this information was available.

All the tertiary recovery tests of Table I except in the Phegly Unit were relatively small pilot tests involving at the most a few injection wells. The entire 785-acre (3.2 x 106 m2) Phegly Unit was flooded through II injec-tion wells, and because of its size, this test may have the greatest validity. 82 Incremental recovery was 3.7 % OOIP for the 4 % HCPV LPG slug driven by alternate lean-gas/water injection.

Breakthrough behavior for solvent and lean gas was generally similar to the behavior found in secondary-recovery floods. Rapid breakthroughs were typical, and often both solvent and drive gas appeared at producing wells almost simultaneously with first response of ter-tiary oil or at least shortly thereafter. 81-84

Field test conditions were too varied to establish anything but the roughest of correlations between slug size and performance. Fig. 7 shows incremental recovery vs. slug size for the tertiary-recovery tests. Secondary-recovery tests at Pembina and Millican fields performed poorly with slugs of I to 3 % HCPV and 1.5 % HCPV, respectively. From the bulk of field experience, a slug size of 4 to 5 % HCPV seems to be about the minimum required for prudent design.

Condensing-Gas Drive Projects There have been at least 19 condensing-gas projects. 9,46-49,64,70,71,86-90 A few began in the

819

TABLE 1-FIRST-CONTACT MISCIBLE TERTIARY RECOVERY TESTS

Oil Oil Viscosity Slug Incremental Recovery' (%OOIP)

Year Type Gravity Viscosity Ratio Depth Thickness Area Size' OillGross Slug Oil/Net Slug ~_F_iel:-:-d-,----- _O_pe_ra_to_r _St_art_e_d --=-=-P_ro'-:ciec_t-,-,-,-- (OAPI) ~ ~ ~ _(_11)_ (acres) (% HCPV) Burkett Unit Phillips 1958 LPG~G~W 42 25 2,100 30 10 10

(STB/RB) (STB/RB) 7.0 0.67

(KS) Johnson Ohio 1958 37 1.1 18 4,600 10 164 5.5 5 to 34" >0.9

(NE) South Ward

(TX) Atlantic 1959 35 4 40 2,400 32 10 7.5 11.5 1.5 2.2

Adena Clar A (CO)

Union 1962 44 0.42 6.5 5,500 28 7 0.46 2.2

Adena Hough A (CO)

Union 1963 44 0.42 6.5 5,500 28 80 12.5 0.6 1.2

Hibberd Pool South Cuyama

Atlantic 1963 35 1.7 23 4,300 60 80 7.4 13.5 1.6 >3

(CA) Phegly Unit Mobil 1964 37 3 30 4.900 8 785 4 3.7 0.85

*Treated area . Ultimate estimated from decline-curve analysis.

mid-1950's, but the majority of projects started during the 1960's and early 1970's.

Most of these tests were larger in scope than the bulk of first-contact miscible tests, often involving hundreds or occasionally thousands of acres. Some examples of relatively large floods in horizontal reservoirs include Seeligson [877 acres (3.5 X 106 m2)]64 and Lilliedoll [640 acres (2.6 x 106 m 2 )] 90 in sandstones, and Ante Creek [6,000 acres (24 X 106 m2)), 47 South Swan Hills [830 acres (3.4 x 106 m 2)), 49 and Levelland [1,190 acres (4.8 X 106 m2)]48 in carbonates.

The condensing-gas drive projects have been secondary-recovery floods predominantly. Oil gravities ranged from 30 to 50 API (0.88 to 0.78 g/cm3), and oil viscosities generally have been less than about 2 cp (0.002 Pa' s). Slug sizes have ranged from 2 to > 50 % HCPV and were > 10% HCPV in the majority of projects.

Gravity-stable displacements in reefal buildups have been an important aspect of condensing-gas drive field experience. Examples include Golden Spike 70 and various pools of the Rainbow field,9,71 all in Alberta, Canada, and the Intisar D reef in Libya. 79,92,93

The Ante Creek, South Swan Hills, Levelland, Cen-tral Mallet, 91 Intisar D,79 and Rainbow field projects were still active in 1981. Most of these projects were 7 to 13 years old at that time.

The character of response to enriched-gas injection has been similar to that observed in first-contact miscible floods. In secondary-recovery floods, GOR decreases as the secondary oil bank arrives at producing wells and then increases as solvent and drive gas break through. Limited tertiary recovery testing shows the process will displace waterflood residual oil to producing wells. 90,91

Rapid breakthroughs generally have been observed in horizontal floods - after only 0.05 HCPV of injection at South Swan Hills and Levelland. Average breakthrough sweepout at Seeligson was about 23 %. Gas production after breakthrough was moderated in some projects by alternate injection of enriched-gas and water. 46,48,49

There has been a considerable range in observed/ estimated incremental oil recovery for condensing-gas drive projects. From calculations and comparisons with waterfloods in similar reservoirs, the 52 % HCPV slug injected in the Seeligson secondary-recovery project was 820

estimated to have recovered 5 to 10% OOIP.64 On the other hand, operators of the South Swan Hills and Levelland secondary-recovery projects used reservoir simulators to project incremental recoveries of 20 and 27% OOIP for slug sizes of approximately 15% HCPV. 48,49 A later comparison of South Swan Hills performance with waterfloods in similar fields did not contradict the original projections. 65 A somewhat lower recovery is anticipated currently for Levelland as a result of recent, unpublished studies. The South Swan Hills and Levelland floods are no more than half completed, and it remains to be seen whether or not the projections will be achieved.

Results are available also from several tertiary-recovery tests. Incremental recovery in the Central Mallet pilot test is 6 % OOIP after injection of about 20 % HCPV slug. 91 Incremental recovery varied considerably among the four patterns ultimately flooded at Lilliedoll with a 15% HCPV slug, ranging from 0.2 to 1.6 STB/gross RB (0.2 to 1.6 stock-tank m3/gross res m3) of enriched-gas injected and averaging 0.8 STB/RB (0.8 stock -tank m 3 Ires m 3).90, *

Generally, the gravity-stable floods in the Canadian pinnacle reefs appear to be performing satisfactorily, and operator evaluations have ranged from "promising" to "successful. ,,9 Projections made with a reservoir simulator indicate that ultimate recovery for the Intisar D reef in Libya could be 70% OOIP, or nearly 20 to 30% OOIP higher than would be achieved by waterflood-ing. 79 The Golden Spike flood in Canada was not suc-cessful. Performance was severely affected by permeability barriers to vertical flow that were un-suspected when the project was begun but discovered later by infill drilling. A subsequent analysis showed the 7.8% HCPV slug had only increased ultimate recovery by about 3 % OOIP. 70

Vaporizing-Gas Drive Projects At least 11 projects of this type can be identified in the literature. They typically have been large-scale floods in-volving thousands of surface acres. 94,96-104 Eight proj-ects had more than 3,000 acres (12 X 106 m'2) under flood, 94,96-100, 102, 103, 105 and as many as 22,600 acres

'Previously unpublished data. ARCO Oil & Gas Co. (1972).

JOURNAL OF PETROLEUM TECHNOLOGY

TABLE 2-RESUL TS FROM SELECTED CO 2 FLOOD TESTS

Incremental Gross Slug Size Breakthrough Recovery C0 2 /0il Ratio

Project (% HCPV) (% HCPV) (%OOIP) (Mcf/STB) SACROC main flood 12 to 15 2 to 5 7' 6 to 7*

Phases I and II SAC ROC tertiary 10 to 18 5 3.5 15 to 20

pilot Willard Wasson 20 10' 8 to 12' 5 to 7* Slaughter Estate 26 10 to 15 18 and 5 and

increasing decreasing Twofreds 25 and 5 3 and 26

increasing increasing Little Creek' , 160 15 18 24 Levelland 736 50 and 15 to 20 6 and 29 and

increasing increasing decreasing Calculated with miscible flood simulators utilizing test data.

"Based On total HCPV in test area including pinchout volume.

(91.5 X 106 m2) are being flooded in the Fairway field in east Texas. 96 Many of these projects have also been operated for a long period of time. Six of the currently active floods are more than 10 years old, three are more than 14 years old, and the Block 31 flood has been in operation for 29 years. All published vaporizing-gas drive projects to date have tested secondary recovery. Oil gravity typically was >40 0 API 0.83 g/cm3).

For those projects where assessments by the operator are available, the majority are considered to have per-formed successfully. 6,9,94,96-99 Exceptionally high ultimate recoveries will be achieved in several projects. Recovery of more than 50% OOIP has been attained in the Block 31 94 and Raleigh floods, 101 and this level of recovery may be met or exceeded at Fairway. 96 An ultimate recovery greater than 50% OOIP has been pro-jected in at least three other projects. 102-104 Estimates of incremental recovery over waterflooding are not available. Some projects were in reservoirs that were not considered particularly good candidates for waterflood-ing because of low permeability and low water injectivi-ty. Floods that were considered successful by the project operator have been conducted in highly stratified car-bonate and sandstone reservoirs as well as in less heterogeneous reservoirs.

Continuous injection of solvent is an important dif-ference between the vaporizing-gas drive field trials and the condensing-gas and first-contact miscible field trials. This is perhaps the single most important reason for the relative success of vaporizing-gas drive floods. Because solvent is injected continuously, there is no loss of miscibility caused by breakdown of a small solvent slug, and miscibility cannot be lost unless pressure at the gas front falls below miscibility pressure. Overall viscosity ratio between oil and driving gas has been more favorable on average in vaporizing-gas drive floods than in other hydrocarbon-miscible projects because higher API gravity oils are required for miscibility, and this un-doubtedly has also contributed to the relative success of vaporizing-gas drive floods.

Alternate injection of water to reduce mobility ratio was practiced in at least four projects 95,96,98, 100 and was considered by the project operator to have a beneficial effect on flood performance in three of these. 96,98,100

APRIL 1983

CO 2 Miscible Projects There have been at least 36 tests of this process in the U.S., and in early 1982 there were at least 28 active proj-ects. With one exception, all were started in the 1970's and 1980's. 5,6,9,12,50-52,55,66,91,106-117 Most projects were small-scale tests of less than 100 acres (405 000 m2), although three were large enough to be considered commercial-size floods rather than pilot tests. 50,55,108 Unlike the hydrocarbon-miscible processes, the majority of CO 2 floods have tested tertiary recovery. Two of the largest floods, however, are predominantly secondary-recovery floods: SAC ROC [33,000 acres (133 x 106 m2)]50 and Crossett [1,700 acres (6.9 X 106 m2)].55

CO2 was injected continuously or in very large slugs in at least five projects, similar to continuous injection of the high-pressure l1;as solvent in vaporizing-gas drive projects. SS, 106,108, ITo,114 Moderate slug sizes were in-jected in the other projects, but in most of these tests no attempt was made to achieve miscible displacement at the trailing edge of the slug. 50,51,66,109,1l1-113 Instead, the CO 2 slug was immiscibly driven with water, leaving a residual CO 2 saturation in the reservoir. Alternate in-jection of water with the CO 2 slul1; was tried in about half the projects. IO,50-52,91,107,111-IT3 Most floods have been in low-relief, essentially horizontal reservoirs, although two projects were carried out in high-relief reservoirs and were designed to be gravity-stable. 110,114 Projects have been about equally divided between sand-stone and carbonate formations. Oil gravities generally have been in the range of 30 to 50 API (0.78 to 0.88 g/cm 3) with viscosities less than 2 cp (2 mPas).

Field trials have shown that C02 miscible flooding is a method for both secondary and tertiary oil recovery. At Crossett, oil was displaced and banked by CO 2 flooding in a reservoir that had been produced by solution-gas drive and contained a free gas saturation at the start of CO2 injection. 55 The ability of CO 2 to displace and to recover some of the residual oil left after waterflooding has been demonstrated by such tertiary-recovery field tests as the Little Creek, 106 SACROC, 109 and Slaughter Estate pilot tests,52,91 and by the Twofreds project. 108

Most projects, both secondary- and tertiary-recovery floods, have experienced early CO 2 breakthroughs, usually after injection of 0.05 to 0.2 HCPV total fluid

821

0 w 60 f-a w x.

30 a. 0 25 0

LEGEND:

FIRSTCONTACT MISCIBLE ";? RICHGAS DRIVE >-' .? C02 FLOOD a: 20 w > 0 () 15 w a:

.? ? ESTIMATED FROM SIMULATIONS 1 OR COMPARISONS BUT NOT .

.? MEASURED DIRECTLY

1 DIRECTION OF INCREASE ...J I- 10 z

. .?

.1 .?

w ~ w 5 a: ()

. ? 1 . 1 .- 1 .-. .

~ o

o 10 20 30 40 50 60 70 150 160 SLUG SIZE, % HCPV

Fig. 7-lncremental recovery from miscibleflood field tests.

effectiveness should decrease with increasing slug size, and these concepts are roughly supported by Figs, 7 and 8.

It should be kept in mind that incremental recovery and slug effectiveness depend on many other variables besides slug size, such as reservoir heterogeneity, temperature and pressure, crude oil composition, and flow regime, to mention just a few. These conditions varied widely between the tests shown in these figures, which should introduce a substantial data-point scatter, even for projects of a given process type, when results are plotted as a function of slug size only, Comparisons are further clouded because there is little overlap be-tween slug sizes used in the first-contact miscible floods and the other processes. Within the data scatter there is no clear-cut evidence that on average a given process is technically performing appreciably better or worse than the others for a given slug size. This is not to say that one process may not actually perform superior to the others for given reservoir conditions, but no overall trend is evi-dent in the composite field data.

The data of Fig. 8 suggest that enriched-gas slugs are performing as effectively as would the same size first-contact miscible slug. Admittedly the data to support this conclusion are extremely limited, but if true, the LPG is being utilized more effectively in the enriched-gas slugs since they contain only 30 to 50% LPG.

Conclusions 1. After 30 years' research, there is a considerable

body of knowledge concerning the mechanisms of miscibility and fluid flow. Even so, advances are needed in a number of important areas such as: improved understanding oflow-temperature CO 2-flood miscibility and of the factors affecting CO 2 mobility; improved understanding of sweepout for tertiary recovery, slug processes, and dynamic miscibility; and improved predictive methods and/or guidelines for slug processes for selecting between a miscible and immiscible drive fluid and for estimating optimal slug size.

2. All the miscible processes are applicable for both secondary or tertiary recovery in sandstone or carbonate reservoirs.

3. In horizontal floods, relatively early solvent and drive-gas breakthroughs should be expected for all proc-

APRIL 1983

0--In ~a: a:cn

C) 2 1 :::la: ...JC) ~, ...J1n -I-o~

LEGEND:

FIRST CONT ACT MISCIBLE RICHGAS DRIVE C02 FLOOD ? ESTIMATED FROM SIMULATIONS

OR COMPARISONS BUT NOT MEASURED DIRECTLY

1 DIRECTION OF INCREASE

O~--L---~--~--~--~--~--~~--~~ o 10 20 30 40 50 60 70 150 160

SLUG SIZE, % HCPV

Fig. 8-Slug effectiveness in miscible-flood field tests.

esses, with production of the bulk of incremental oil con-currently with solvent and drive gas.

4. Greatest field trial success to date has been achieved with the vaporizing-gas drive method, probably because the miscible fluid has been injected continuously rather than as a slug and because mobility ratio for these floods has been more favorable on average. The process has had limited application, however, because of the high miscibility-pressure requirement.

5. A low miscibility-pressure requirement often is a significant advantage of COrmiscible flooding. This process could have significant future application in areas with economical CO 2 supplies from natural deposits or surface sources.

6. Incremental recovery ranged from about 3 to 20% OOIP for 16 first-contact miscible, condensing-gas drive, and CO 2-flood projects where this quantity could be estimated from field data. Slug sizes of the miscible injection fluids in these projects ranged from 4 to 160% HCPV, and with few exceptions incremental recovery was less than 1 STB/ gross RB (1 stock -tank m 3 / gross res m 3) of miscible fluid injected, even for the smallest slug sizes.

7. Within the data scatter for these 16 projects, there is no clear-cut evidence that on average one process has performed appreciably better or worse than another for a given slug size.

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823

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824

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APRIL 1983

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825

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112. San Filippo, G.P. and Guckert, L.G.S.: "Development of a Pilot Carbon Dioxide Flood in the Rock Creek-Big Injun Field, Roane County, West Virginia," Proc., ERDA Symposium on En-hanced Oil, Gas Recovery, and Improved Drilling Methods, Tulsa (1977).

113. Beeler, P.F.: "West Virginia CO 2 Oil Recovery Project Interim Report," Proc., ERDA Symposium on Enhanced Oil, Gas Recovery, and Improved Drilling Methods, Tulsa (1977).

114. Goodrich, 1.H.: "Review and Analysis of Past and Ongoing Car-bon Dioxide Injection Field Tests," paper SPE 8832 presented at the 1980 SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, April 20-23.

115. Palmer, F.S., Nute, A.J., and Peterson, R.L.: "Implementation of a Gravity-Stable, Miscible CO 2 Flood in the 8000-Foot Sand, Bay St. Elaine Field," paper SPE 10160 presented at the 1981 SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 5-7.

116. Watts, R.J. el al.: "A Single CO 2 Injection Well Minitest in a Low-Permeability Eastern Carbonate Reservoir," 1. Pel. Tech. (Aug. 1982) 1781-88.

117. Desch, J.B. el al.: "Enhanced Oil Recovery by CO 2 Miscible Displacement in the Little Knife Field, Billings County, North Dakota," paper SPE 10696 presented at the 1982 SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, April 4-7.

118. Crockett, D.H.: "A Profile Control Program Utilized in the SAC ROC Unit CO 2 Injection Program," Proc., 22nd Annual Southwestern Petroleum Short Course, Texas Tech. U., Lubbock (1975) 159-64.

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119. Frey, R.P.: "Operating Practices in the North Cross CO 2 Flood," Proc., 22nd Annual Southwestern Petroleum Short Course, Texas Tech. U., Lubbock (1975) 165-68.

120. Adams, G.H. and Rowe, H.G.: "Slaughter Estate Unit CO 2 Pilot - Surface and Downhole Equipment Construction and Operation in the Presence of H 2S," 1. Pel. Tech. (June 1981) 1065-74.

121. Newton, L.E. Jr. and McClay, R.A.: "Corrosion and Operation Problems, CO 2 Project, SAC ROC Unit." paper SPE 6391 presented at the 1977 SPE Permian Basin Oil and Gas Recovery Conference, Midland, March 10-11.

SI Metric Conversion Factors API 141.5/(131.5+ API) g/em 3

bbl x 1.589 873 E-Ol m 3 ep x 1.0* E-03 Pa's

ell ft x 2.831 685 E-02 m 3 ft x 3.048* E-Ol m

of (OF-32)/1.8 C psi x 6.894757 E+OO kPa

sq ft x 9.290304* E-02 m 2 *Conversion factor is exact. SPEJ

Original manuscript received in Society of Pelroleum Engineers office Aug. 31, 1981. Paper accepted for publication Dec. 14, 1982. Revised manuscript received Feb. 9, 1983. Paper (SPE 9992) first presenled at the 1982 SPE IntI. Petroleum Exhibition and Technical Symposium held in Beijing, China, March 18-26.

JOURNAL OF PETROLEUM TECHNOLOGY