Surfactant-Based Mobility Control - ACS Publications - American

Chapter 18

Carbon Dioxide Foam Flooding Downloaded by UNIV OF CALIFORNIA SAN DIEGO on July 16, 2016 | http://pubs.acs.org Publication Date: July 20, 1988 | doi: 10.1021/bk-1988-0373.ch018

Laboratory Model and Computer Simulation of the Process E. L . Claridge, Β. M . Lescure, and M . W. Wang

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Chemical Engineering Department, University of Houston, Houston, TX 77004 Injection of carbon dioxide as a foam or emulsion is under investigation as a means of reducing the mobility of the low-viscosity carbon dioxide and thus of increasing theoilrecovery inoilfield enhanced oil recovery floods. The prior method is alternate injection of water and carbon dioxide. In the work reported here, laboratory model results previously reported have been simulated using a finite difference computer program called Multiflood. The need for simulation of surfactant adsorption required that the components usually assigned to water phase oroilphase in using this program had to be reversed, and the role usually played by the mixing parameter in simulating effects of viscous fingering was replaced by partial solubility of carbon dioxide in the aqueous phase, while the surfactant was given a fictitiously high viscosity in its blend with water in order to match the viscosity of foam. With these adjustments, it was found possible to match the laboratory experiments with fair accuracy with a carbon dioxide solubility in the oil phase of 70-90 mol percent (the remainder having gas relative permeability and viscosity). It is believed that until computer programs specifically written to enable simulation of foam flooding become available, this simulator and method will be helpful in making preliminary estimations for field projects. Enhanced oil recovery by injection of a slug of carbon dioxide, followed by water to complete the process, under conditions of temperature and pressure such that the carbon dioxide is apparently miscible with crude oil, is becoming a wide-spread process in the UJS.A., particularly in west Texas but also in certain other regions (lzu). Carbon dioxide is not unconditionally miscible with most crude oils; this is discussed below. 1

Current address: Petroleum Engineering Department, University of Texas, Austin, TX 78712 0097-6156/88/0373-0359$06.00/0 • 1988 American Chemical Society Smith; Surfactant-Based Mobility Control ACS Symposium Series; American Chemical Society: Washington, DC, 1988.

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Downloaded by UNIV OF CALIFORNIA SAN DIEGO on July 16, 2016 | http://pubs.acs.org Publication Date: July 20, 1988 | doi: 10.1021/bk-1988-0373.ch018

Miscibility and Phase Behavior In most cases, the temperature and pressure of application exceed the c r i t i c a l values for carbon dioxide, but the temperature i s lower than the average c r i t i c a l temperature and above the average c r i t i c a l pressure of the crude oil components. Hence, under conditions of use the carbon dioxide i s a f a i r l y dense fluid which i s neither a liquid or a gas, but the crude oil i s a l i q u i d . There i s also salty water present in the oil reservoir in a l l cases, and water i s used to drive a slug of carbon dioxide through the reservoir from injection to production wells which are typicAlly arranged in five-spot or ninespot patterns. In general, the o r i g i n a l r e s e r v o i r temperature i s not s i g n i f i c a n t l y changed during the process, but the pressure may be varied from the original level. In most cases, primary recovery by pressure depletion as well as subsequent secondary recovery by water flooding has already occurred. The carbon dioxide flooding process i s then a t e r t i a r y recovery process. By control of the input and output during the waterflood, the pressure may be adjusted to the pressure required for apparent miscibility between the carbon dioxide and the remaining crude oil. This pressure i s usually ascertained by displacements of crude oil by carbon dioxide in long, slim tubes at a series of pressures. The oil recovery at breakthrough of carbon dioxide at the outlet, or at some designated amount of throughput such as 1.2 pore volumes, varies from about 40-60 % at low pressures to over 95 % at high pressures. The break i n the curve at which the oil recovery approaches the 95 % level i s taken as the apparent miscibility pressure (1Q). This i s termed the apparent miscibility pressure because there i s a considerable amount of evidence that asphaltenes, which are c o l l o i d a l l y dispersed i n most crude o i l s , w i l l aggregate under appropriate dilution conditions and precipitate, so that the physicochemical definition of miscibility (single-phase for a l l proportions of the f l u i d s i n question) i s not realized. There are also conditions, p a r t i c u l a r l y found i n oil reservoirs at temperatures below about 135°F, at which two liquid phases, or two liquid phases plus a gas phase, appear i n addition to an asphaltene precipitate (11=13). In general, however, this does not prevent the attainment of 95 % oil recovery or more in slim-tube tests at the same pressures at which these multiple phases appear. Hence, the process i s deemed "miscible," for a l l practical purposes.

ELuiâ Mechanics Effects Either the asphaltene precipitation or the multiple phase behavior of the process under "miscible" conditions appears to cause a certain extent of reduction of the mobility of the carbon dioxide, as compared to the mobility which would be calculated from the relative permeability of the carbon dioxide divided by i t s viscosity (lizlfe). However, i t i s usually considered that t h i s i s not s u f f i c i e n t to resultinafavorable mobility ratio (a ratio of carbon dioxide mobility to crude oil mobility less than one). When the mobility ratio i s greater than one, viscous instability ensues during displacements in systems of sufficient width O10 cm) to permit the formation and propagation of viscous fingers. These

Smith; Surfactant-Based Mobility Control ACS Symposium Series; American Chemical Society: Washington, DC, 1988.


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C0 Foam Flooding: Laboratory Model 2

projections of the more mobile displacing f l u i d through the less mobile f l u i d being displaced can occur either with miscible or immiscible fluids U i l S ) , and result in much lower production of the fluid being displaced at any given throughput after breakthrough of the displacing fluid. It i s therefore much to be desired to attain a mobility ratio of one or less, from the standpoint of oil recovery. In order to reduce the carbon dioxide mobility s t i l l further, i t i s often planned to i n j e c t the carbon dioxide slug i n small increments, alternated with similar small increments of water. This procedure, c a l l e d WAG (water-alternating-gas) has been tested i n comparison to straight slug injection (non-WAG) i n laboratory model studies conducted at the university of Houston (12) with a glass bead pack i n the form of a five-spot well pattern, with the beads in a relatively water-wet condition and in a relatively oil-wet condition. In the water-wet condition, i t was found detrimental tooilrecovery to use WAG, while an optimum WAG ratio (of water to C0 ) in the range of 0.5 to 2.0 was found for the oil-wet condition. These two wetting states are thought to correspond approximately to the wetting states of sandstones (mostly watwr-wet) and carbonate rocks such as limestones and dolomites (mostly oil-wet, or partiallyoilwet). The density of the water involved (salt content 1-15%) i s s l i g h t l y over 1.0 g/cc (1000 kg/m ). That of the crude oil i s about 0.7 g/cc, and the density of the carbon dioxide i s usually s l i g h t l y lower or s l i g h t l y greater than that of the crude oil, at t y p i c a l temperatures and pressures of application. Even i f m i s c i b i l i t y of carbon dioxide and crude oil i s assumed, this does not mean that they are totally mixed as the carbon dioxide i s injected in the reservoir. Separation by density i s therefore possible even with miscible fluids when there i s a density difference. In most cases, there i s sufficient density difference between the carbon dioxide and the oil for t h i s to occur i f the i n j e c t i o n rate i s slow enough to allow gravity force to predominate over viscous force. The r a t i o of gravity force to viscous force i s small near the i n j e c t i o n wells (where the viscous force i s large) but usually becomes greater than one at some distance from the injection wells, out in the middle of the well patterns. Of course, the density difference between injected water and either carbon dioxide or crude oil i s sufficiently great that gravity segregation begins at a much shorter radius from the injection wells. Such gravity segregation leads to early breakthrough of the injected fluid, compared to the case of no gravity segregation. Even more serious, when simultaneous flow of water and non-aqueous fluids over the same cross-sectional area i s desired for control of the mobility of the non-aqueous f l u i d , e.g. carbon dioxide, the separation by gravity negates the mobility control over much of the reservoir volume. Thus, both gravity segregation and viscous fingering hinder the attainment of good sweep efficiency of the well patterns. A t h i r d major factor adversely affecting oil recovery i s the heterogeneity of the r e s e r v o i r , as expressed i n v a r i a t i o n s of p o r o s i t y and permeability. In most cases, the heterogeneity i s not random but i s mostly present as layers of different permeability. In the present work, t h i s i s not dealt with; work i s i n progress on a layered laboratory model, however. A fourth factor affecting sweep efficiency i s the use of well patterns. The f l u i d s are injected at 2

3



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what are p r a c t i c a l l y point sources into rock formations which are usually much greater in areal extent than they are thick, and fluids are produced from point sinks i n the areal system. With multiple patterns, symmetry elements result which a i d i n confining f l u i d s within the patterns. However, the existence of relatively long and short streamline flow paths in these symmetery elements results in considerably less than 100% sweep efficiency when the injected fluid appears at the producers along the shortest paths. This areal sweep efficiency i s about 71% for equal mobility injected and displaced f l u i d s for the five-spot well pattern, and i t varies strongly with the mobility ratio (20). Recently, use of a surfactant in the injected water such that a foam or emulsion i s formed with carbon dioxide has been proposed (2ÎL2D and research i s proceeding on finding appropriate surfactants (22z2A). The use of such a foam or emulsion offers the p o s s i b i l i t y of providing mobility control combined with amelioration of the density difference, a combination which should y i e l d improved oil recovery. Laboratory studies at the University of Houston (25) with the same five-spot bead-pack model as used before show that this i s so, for both the r e l a t i v e l y water-wet and r e l a t i v e l y oil-wet condition. We have now simulated, with a finite-difference reservoir process computer program, the laboratory model results under non-WA3, WAG, and foam displacement conditions for both secondary and tertiary recovery processes. This paper presents the results of that work. Laboratory Model Results The model results (12^25) are presented below i n Table I. The design of the model and the fluids used are discussed briefly below. The model i s 15" square and 1" thick (38x38x2.5 cm), with an injection well in one corner and a production well in the diagonally opposite corner, thus forming a symmetry element of 1/4 of a f i v e spot well pattern. It i s f i l l e d with a log-normal d i s t r i b u t i o n of glass beads ranging in size from 10 mesh to 280 mesh (approx. 1 mm to 0.05 mm); the porosity i s close to 0.3 and the permeability i s in the range of 4 to 8 darcys (4 to 8 E-12 square meters; different values found i n successive packings). An appropriate feed system and a production system including an automatic phase separator and methods of distinguishing "carbon dioxide" from oil were provided. For waterwet beads, the i n i t i a l bead coating to prevent caking was removed with an aromatic wash followed by acetone, then de-ionized water, then dilute hydrochloric acid followed again by de-ionized water. For the oil-wet condition, DuPont Quilon i n iso-propyl alcohol solution was injected into the water-wet pack u n t i l a l l water was displaced, allowed to stand for some hours, then displaced again with water. This l e f t the glass beads rather strongly oil-wet, but not as completely as would be obtained by baking the Quilon coating on the surface (2£). In order to avoid the necessity of operating at the high pressures typical of carbon dioxide flooding (1500-3000 psig, or 1020 MPa), which would require heavy bracing of the model faces and high-pressure inlet and production systems, substitute f l u i d s were used. In place of carbon dioxide, a non-aromatic kerosene-range hydrocarbon was used, with a viscosity of 1.3 cp (or kPa-s). This i s about 20 times the v i s c o s i t y of carbon dioxide under normal


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conditions of use so i n order to preserve the same r a t i o of f l u i d m o b i l i t i e s as i n an oil reservoir, the water was thickened using glycerine to 14.3 cp (kPa-s) and a mixture of white o i l s of 25.9 cp was used to represent crude oil. Ihe light oil representing carbon dioxide was miscible with the heavier oil representing crude oil. Thus phase behavior effects which might confound the observable results were avoided. The experiments were conducted at a tlow rate such that most of the dimensionless ratios of forces or of rates were made the same as in a typical layer of a west Texas dolomite reservoir (about 10 millidarcys permeability, 105 °F, 40 acre five-spot, 2000-3000 psig). In particular, the gravity-viscous force r a t i o and the r a t i o of transverse dispersion to longitudinal convection rate were made as close as possible to the prototype oil reservoir. These ratios control respectively the extent of gravity segregation and the extent of viscous fingering (for any given unfavorable mobility ratio).


f

Table I. Laboratory Model C02 Flooding Results Percent JESQE Recovery Basis original o u m Place (QQIP) Wetting State: Water-Wet Qil-Wet Process: Secondary Tertiary Secondary Tertiary Slug Size* 0.1 0.2 0.4 0.1 0.2 0.4 0.1 0.2 0.4 0.1 0.2 0.4 1:1 WfiG 1:1 Foam

2.5 4 5 10

5 12

2 4

3 8

3 10

1 10

2 16

3 19

6 10

10 15

13 18

*Equal size water slug injected i n 0.05 HCPV increments i n WAG or continuously in foam operation. In the foam displacements, IGEPAL 710 was used, a t a concentration of 0.05 % basis aqueous phase. This gave a foam or emulsion containing equal proportions of each phase (we were advised by an industrial supporter that t h i s i s the r a t i o observed with carbon dioxide - brine foam systems). The emulsion was stable for a week or more so long as no heavy oil (representing crude oil) was present, but was unstable when as much as 10% of the heavy oil was added, or when the heavy oil alone was used. These are desired emulsion stability conditions. This particular surfactant was well adapted for our substitute fluid system, but would not be appropriate for reservoir systems where the temperature i s higher and where the water s a l i n i t y i s generally much higher than i n our laboratory system. The concentration of surfactant used i s i n s u f f i c i e n t to cause oil recovery by reduction of i n t e r f a c i a l tension. This was checked by performing waterfloods with and without surfactant i n the water; identical oil recovery curves were obtained. Thus, any sweep efficiency improvement over that obtained using WAG had to be due to the emulsifying or foaming effect of the surfactant. The surfactant adsorbs on water-wet glass beads. Experiments reported i n Ref. 27 show that about 0.5 HCPV of surfactant solution i s required to s a t i s f y the adsorption capacity of the bead pack. Hence, when a slug size of 0.2 HCPV of carbon dioxide and an equal slug of surfactant solution are injected together, the surfactant i s a l l adsorbed when about 40% of the volume of the bead pack has been contacted. This i s apparently sufficient to obtain the benefits of


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the surfactant. No adsorption occurs on the oil-wet glass beads. Apparently the Quilon i s so strongly adsorbed and the coverage i s great enough that no Igepal 710 could be adsorbed. Note that the oil-wet results are considerably better than the water-wet EQR recoveries, except for the secondary WAG process in the oil-wet model. The foam results were better for the oil-wet pack for both the secondary and tertiary cases than they were in the water-wet pack. We attribute the poorer performance of the water-wet pack to a higher proportion of oil which i s blocked from contact with the 002 at the water saturations which occur i n WAG and foam flooding. This apparently cuts the EOR recovery to about h a l f of that observed i n the oil-wet pack for equivalent water saturations. Computer Simulation The computer simulation program which was available for miscible flood simulation i s the Todd, Dietrich & Chase Multiflood Simulator (28). This simulator provides for seven components, of which the t h i r d i s expected to be carbon dioxide and the seventh water. The t h i r d component i s allowed to dissolve i n the water i n accordance with the partial pressure of the third component in the non-aqueous phase or phases. I t i s t y p i c a l l y expected that the f i r s t two components w i l l be gas components, while the fourth, f i f t h , and sixth w i l l be oil components. There i s provision for limited solubility of the sixth component i n the non-aqueous l i q u i d phase, so that under specified conditions of mol f r a c t i o n of other components (such as carbon dioxide) the solubility of the sixth component i s reduced and some of that component may be precipitated or adsorbed i n the pore space. It i s possible to make the solubility of the sixth component a function of the amount of precipitated or adsorbed component six within each grid block of the mathematical model of the reservoir. This implies, conversely, a dependence of the amount adsorbed or precipitated on the concentration (mol fraction) of the sixth component i n the l i q u i d non-aqueous phase, hence i t i s possible to use an adsorption isotherm to determine the degree of adsorption. In this simulator, for incorporation of the effects of viscous fingering of carbon dioxide or of a hydrocarbon miscible solvent through theoilphase, the carbon dioxide or hydrocarbon solvent i s given a fictitiously high equilibrium Κ value, so that i t appears to be almost entirely i n a f i c t i t i o u s or pseudo gas phase. This i s solely for the purpose of invoking the mixing parameter method (29) for calculating a viscosity for the solvent which i s i n between the v i s c o s i t y of pure solvent and of the mixture of solvent and oil i n the proportions present i n any given g r i d block, and s i m i l a r l y a v i s c o s i t y for the oil which i s intermediate between the pure oil viscosity and the mixture viscosity. The total relative permeability for the non-aqueous l i q u i d phase i s shared between the solvent and the oil i n proportion to their volume fractions i n the non-aqueous liquid phase (which i s correct i f there does not in fact exist a gas phase but only a l i q u i d phase containing the miscible solvent and oil). The mixing parameter method thus causes the miscible solvent to move through the system at a rate r e l a t i v e to the oil which i s characteristic of the behavior of viscous fingers of solvent, even when the number of blocks in the grid i s too few to allow fingers to be seen in saturation maps. The sweep efficiency i s affected in the same way as i t i s by viscous fingering.



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For the purpose of simulating C02 foam flooding, i t i s necessary to use the capability of adsorbing component 6 to represent the adsorption of surfactant from the water phase. This requires that the normally expected phases and phase components be reversed. That i s , component 7 must now be oil (and the oil phase must contain both oil and carbon dioxide). Component 3 (carbon dioxide) can dissolve i n component 7, now the oil phase, to an extent which can be specified as a function of system pressure. The aqueous phase can be made up of components 1,2,3,4,5, and 6. This i s more than i s needed for the present purpose. It was decided to use component 5 as the water component. Component 3 (carbon dioxide) can be kept as a separate phase from the water phase by introducing a large K-value for the third component, and a zero K-value for the other five of the six components mentioned, including components 5 and 6. Components 1,2, and 4 are not used. Hence, the system consists of components 3, 5, 6, and 7, representing carbon dioxide, water, surfactant, and crude oil, respectively, or their counterparts i n the laboratory model f l u i d system: l i g h t oil, g l y c e r i n e - t h i c k e n e d water, surfactant, and heavy oil, respectively. With this reversal of phases, i t i s no longer possible to make effective use of the mixing parameter method present i n the simulator. The value of the mixing parameter was therefore set to a very low value (0.01), but not to zero, because i t was desired to use the table of C02 s o l u b i l i t y i n the oil (seventh component) which would not be accepted i f the mixing parameter were set to zero. It was found that the s o l u b i l i t y of C02 i n component 7 (oil) could be used i n much the same way as the mixing parameter to vary the r e l a t i v e rate of movement of C02 andoil,and thus control the extent of enhanced oil recovery in order to match the simulated oil recovery to the laboratory model results. Desirably, the solubility should f a l l in a narrow range in such matching, so that the value of solubility so obtained could be used for predictive purposes, just as a narrow range of mixing parameter i s found to hold i n matching laboratory and f i e l d miscible floods. The pressure varies only over about a ten psi range between the injector and producer, even with the higher viscosity foam present as compared to the viscosity of the other fluids. The higher viscosity of the foam was obtained by assigning a fictitiously high viscosity to the surfactant, such that the blend of v/ater and surfactant which was injected had a viscosity of 62 cp (kPa-s), which i s the viscosity measured for foam i n the laboratory experiments (with a Brookfield cone & plate viscometer). Secondary as well as t e r t i a r y recovery (without or with prior water flooding) processes were simulated i n both lab model and computer simulation experiments. In every case, i n j e c t i o n of the carbon dioxide slug was followed by a f i n a l waterflood u n t i l an assumed economically limiting oil cut of 2 % was reached. The extra oil for secondary C02 floods was determined by subtracting from the over-all oil yield the recovery which could have been obtained by a prior water flood. The secondary and tertiary extra oil yields are therefore comparable. A comparison of the extra oil recovery by computer simulation with that obtained i n the laboratory model i s shown in Table II, on the next page. The water floods for both water-wet and oil-wet lab models were


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fitted by adjusting the relative permeability curves, starting with the relative permeability curves obtained with a 1-inch diameter, 12inch long bead pack in either the water-wet or oil-wet state. Then the C02 floods were simulated. For simple WAG operation, the computer simulator components were used with the normal assignments of f l u i d s , while for foam floods the assignments of oil and water components were reversed as mentioned above. In the latter case, the water floods were again matched.


Table II. Comparison of Computer Simulated and Lab Model Enhanced O i l Recoveries (Percent EOR Recovery Basis Original Oil In Place) Oil-Wet Wettinq State: Water-Wet Tertiary Secondary Process: Secondary Tertiary 0,4 0.1 0.2 0.4 Slug Size 0*1 SLZ 0*4. ÎL1 0*2 SLA 0.1 0.2 Lab. 1:1 WAG 2.5 Sim.l:l WAG 1.8 Lab. 1:1 Foam 5 Sim.l:l Foam 7.1

4 5 2.3 2.8 10 12 9.2 10.9

2 3.1 4 7.2

3 3 3.8 4.7 8 10 8.4 9.2

1 2 3 6 10 1.3 2.6 3.1 8.6 10.2 10 16 19 10 15 8.7 12.7 15.9 9.9 14.2

13 11 18 18

Figures 1 and 4 show the water flood matches to the water-wet and oil-wet lab model curves, respectively. The carbon dioxide flooding runs i n the lab model were then matched by computer simulation. In the simulations, as i n the lab model, the carbon dioxide slug was followed by waterflooding to an assumed economically l i m i t i n g water cut of 98%, and the enhanced oil recovery was calculated as the difference between the ultimate total recovery at t h i s point and that of a water flood starting from i n i t i a l oil saturation and continued u n t i l a 98% water cut was reached. Secondary carbon dioxide floods started from the same i n i t i a l oil saturation, while t e r t i a r y carbon dioxide floods started with the condition at the 98% water cut point in the simple water flood. Since the foam or emulsion tests involved a 1:1 ratio of water and carbon dioxide, comparisons are shown only for the case of 1:1 WAG operation vs foam. Fitting of the WAG data was not entirely satiafactory, as can be seen from Table II and from Figures 2,3,5, and 6. The trapped oil saturation vs water saturation i s important in the water-wet case, so we did not use the inverted phases for the water-wet WAG case, but instead varied the mixing parameter within the range of 0.6 to 0.8 and the value of â in the equation: Sot = Sorw/[l + â(kro/krw)] - a version of the Raimondi-Torcaso equation (30) due to Todd (31), over the range from 5 to 0.5. The best compromise was found with a = 0.5 and with the mixing parameter = 0.8 for secondary and 0.6 for tertiary. In general, the computed EOR was too low for secondary and too high for tertiary, as compared to lab model results. In the oilwet case, the inverted phase formulation was used and the solubility of carbon dioxide i n the oil phase was varied. The f i t shown for secondary WAG was obtained for 0.35 mol f r a c t i o n carbon dioxide solubility, while for tertiary WAG a solubility of 0.75 mol fraction gave the f i t shown. This large a variation i n s o l u b i l i t y i s not


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80 Γ O I L R E C O V E R Y % O F OOIP


LAB MODEL COMPUTER SIMULATION

50 100 150 WATER THROUGHPUT, % OF OOIP Figure 1.

200

250

Water flood of water-wet system.

EOR, % OF OOIP

0.2 0.1 C 0 SLUG SIZE, % OF OOIP

0.3

0.4

2

Figure 2.

Secondary 1:1 WAG C 0 flood of water-wet system. 2

C 0 SLUG SIZE, % OF OOIP 2

Figure 3.

Tertiary

1:1 WAG C 0 flood of water-wet system. 2




368

Figure 6.

Tertiary

1:1 WAG CO

flood of oil-wet system.


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reasonable. If the normal phase assignment i s used, either a large variation i n a or i n the mixing parameter, or both, i s required. Possibly the lab model results are i n error. Further study of t h i s question i s planned. In the case of the water-wet foam floods, the carbon dioxide solubility which gave the best match to the secondary floods was 0.8 mol fraction, while a value of 0.7 gave the best match for the


t e r t i a r y foam floods, as shown i n Figures 7 and 8. The best values f o r the oil-wet case were 0.9 niol f r a c t i o n f o r both the secondary and t e r t i a r y cases, as shown i n Figures 9 and 10.

Thus, i n most cases a f i t could be obtained with the inverted phases with carDon dioxide s o l u b i l i t y i n a narrower range than the range required of the mixing parameter i f the normal phases were used and the mixing parameter was varied. On the other hand, the use of the inverted phases with carbon dioxide s o l u b i l i t y as the only parameter available does not make use of the other features of the Multiflood simulator such as the trapped oil curve and the simulation of the effects of fingering i n the way shown successfully before. It must be concluded that i t would be preferable to construct a new simulator, or a suitable adaptation of the Multiflood simulator or otner miscible flooding simulator, to take into account the new physico-chemical aspects of foam or emulsion flow while retaining the other valuable capabilities of these simulators, rather than to use the inverted-phase form of the Multiflood simulator. This has been suggested to Todd, Dietrich & Chase. In the meantime, the s i g n i f i c a n t advantage indicated by our laboratory work for injection of carbon dioxide as a foam or emulsion rather than alternately with water (WAG) w i l l , we hope, serve as a stimulus to the oil companies carrying out carbon dioxide floods to give consideration to t h i s version of the process. Many of these companies have the Todd, Dietrich and Chase Multiflood simulator, or one which i s similar. The option to precipitate or adsorb a component i s necessary. Then the surfactant component can be adsorbed and can also provide a higher v i s c o s i t y when i t i s not adsorbed (simulating foam). In the meantime, using the guidance provided here, simulator predictions of f i e l d behavior under carbon dioxide foam flooding can be made. If these are s u f f i c i e n t l y interesting to the oil company involved in any given case, then pilot testing would be encouraged. It should be pointed out that foam could be employed in the case of hydrocarbon miscible flooding as well as i n the case of carbon dioxide flooding. Based on the indications seen i n our lab work, liquid hydrocarbons w i l l probably make emulsions which are about 50% quality, or about 1:1 water and hydrocarbon. Hence t h i s mixture could be injected as the slug material. However, i t i s not known whether the residue gas (90%+ methane), which i s of low density and gas-like at the appropriate reservoiroditions for miscible flooding, w i l l form a foam of t h i s low a quality. If the quality i s i n the range of 95% or higher as i s the case for atmospheric pressure gases and water plus surfactant, the v i s c o s i t y i s l i k e l y to be much too high for use i n medium to low permeability reservoirs. However, water alone could be used to drive the slug through the reservoir. This would tend to leave a trapped saturation of NGL mixture, and t h i s must be taken into account i n the economic evaluation. It i s s t i l l possible that the sweep efficiency improvement may make this


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16 I


R

EOR, % OF OOIP

0 C0 Figure 7.

2

0.1 0.2 SLUG SIZE, % OF OOIP

Secondary 1:1 foam C 0

2

0.3

0.4

flood of water-wet system.

16^ EOR, Γ % OF OOIP

12k

C0 Figure 8.

2

SLUG SIZE, % OF OOIP

Tertiary

1:1 foam CO

flood of water-wet system.



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Figure 9.

2

Secondary 1:1 foam CO


C 0 SLUG SIZE, % OF OOIP 2

Figure 10.

Tertiary

1:1 foam CO



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feasible. T h i s i s an i m p o r t a n t avenue f o r f u r t h e r r e s e a r c h , p a r t i c u l a r l y i n connection with Canadian l i g h t oil reservoirs where carbon d i o x i d e i s not a v a i l a b l e i n adequate q u a n t i t i e s but NGL hydrocarbons are.


Conclusions I t i s concluded t h a t carbon d i o x i d e foam or e m u l s i o n f l o o d i n g has g r e a t promise. The oil r e c o v e r y i s s i g n i f i c a n t l y h i g h e r than w i t h the use of WAG a t the same water - carbon dioxide r a t i o . We have been a b l e t o match l a b o r a t o r y model r e s u l t s w i t h a computer s i m u l a t i o n program (Todd, D i e t r i c h & Chase's M u l t i f l o o d ) with values of the matching parameters which do not vary widely i n most cases. For carbon dioxide foam simulation, i t was necessary t o i n v e r t the normal assignment of oil and water components. I t seems l i k e l y that predictions could be made f o r f i e l d cases u s i n g the guidance g i v e n here, which c o u l d s e r v e f o r p r e l i m i n a r y e v a l u a t i o n purposes t o determine whether a p i l o t t e s t would be justified. The adaptation of the M u l t i f l o o d simulator used i n t h i s work i s not e n t i r e l y s a t i s f a c t o r y . A new s i m u l a t o r , or a d a p t a t i o n of an e x i s t i n g simulator t o include the surfactant and foam behavior, i s desirable. Acknowledgments This work was funded by the i n d u s t r i a l consortium of companies which s u p p o r t t h e EOR L a b o r a t o r y , a d i v i s i o n o f the Energy L a b o r a t o r y o f the University of Houston. The consortium has included: Amoco, Arco, Chevron, CNOOC, Conoco, Esso Canada, Exxon, G e t t y , G u l f Canada, Mobil, Schlumberger, S h e l l , Sun, Texaco, Todd D i e t r i c h & Chase, and Unocal. A d d i t i o n a l f u n d i n g was p r o v i d e d by t h e Energy Laboratory. Further, personal contributions by E.L. Claridge, a pensioner of the S h e l l Companies, were matched two for one by the S h e l l Foundation. Nomenclature â = a parameter i n the modified Raimondi-Tôrcaso equation, kro = r e l a t i v e permeability of porous medium t o oil phase, krw " " " " " " water phase, OOIP = o r i g i n a l oil i n place i n a given system, volume units. Sot = trapped oil saturation, dimensionless, Sorw = r e s i d u a l oil s a t u r a t i o n a f t e r e x h a u s t i v e water f l o o d , dimensionless References 1. Leonard, Jim: "Increased Rate of EOR Brightens Outlook," Oil & Gas J., April 14, 1986, pp. 71-102. 2. Soc. Pet. Eng. Reprint Series Book No. 18: Miscible Processes. 3. Stalkup, F.I.: Soc. Pet. Eng. Monograph No. 8, Miscible Displacement. 4. Claridge, E.L.:"Current Status, Economics, and Future of CO2 Enhanced Oil Recovery," Paper presented at the 2nd World Oil & Gas Show & Conference, Dallas, Texas, June 4-7, 1984.



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5. Claridge, E.L.: "Prospects for Enhanced Oil Recovery in Texas," IOCC Bulletin 23, No. 2 (Dec. 1981). 6. Claridge, E.L.: "Prospects for Enhanced Oil Recovery in the United States," Proceedings IECEC'82, The 17th Intersociety Energy Conversion Engineering Conference, Los Angeles CA August 1982. 7. Goodrich, John: "Target Reservoirs for CO2 Miscible Flooding," Dept. of Energy Report DOE/MC/08341-12, Vols. I-IV. 8. National Petroleum Council Report: "Enhanced Oil Recovery," National Petroleum Council, 1625 Κ Street N.W., Washington D.C. 20006, June 21, 1984. 9. National Petroleum Council, "Factors Affecting U.S. Oil & Gas Outlook," February 1987. 10. Reference 2, pp. 65-89. 11. Shelton, J.L., and Yarborough, 1.: "Multiple Phase Behavior in Porous Media During CO2 or Rich Gas Flooding," J. Pet. Tech. (Sept. 1977), 1171-1178.; 12. Stalkup, F.I.: "Carbon Dioxide Miscible Flooding: Past, Present, and Outlook for the Future," J. Pet. Tech. (Aug. 1978), 1102-1112. 13. Gardner, J.W., Orr, F.M., and Patel, P.D.: "The Effect of Phase Behavior on CO2-Flood Displacement Efficiency," J. Pet. Tech. (Nov. 1981), 2067-2081. 14. Schneider, F.N. and Owens, W.W.: "Relative Permeability Studies of Gas-Water Flow Following Solvent Injection in Carbonate Rocks," Soc. Pet. Eng. J. (Feb. 1976), 23-30. 15. Pontious, S.B. and Tham, M.J.: "North Cross (Devonian) Unit CO2 Flood - Review of Flood Performance and Numerical Simulation Model," J. Pet. Tech. (Dec. 1978), 1706-1716. 16. Reference 2, pp. 648-655. 17. Chuoke, R.L., van Meurs, P., and van der Poel, C.: "The Instability of Slow, Immiscible, Liquid-Liquid Displacements in Permeable Media," Petr. Trans. AIME 216 (1959), 188. 18. Perrine, R.L.: "A Unified Theory for Stable and Unstable Miscible Displacement," Pet. Trans. AIME 228 (1963), 205. 19. Jackson, D.D., Andrews, G.L., and Claridge, E.L.: "Optimum WAG Ratio vs Rock Wettability in CO2 Flooding," SPE Paper No. 14303, presented at the 60th Annual Technical Conference of the Society of Petroleum Engineers, Las Vegas, Sept. 1985 (being revised for publication). 20. Claridge, E.L.: "Prediction of Recovery in Unstable Miscible Flooding," Soc. Pet. Eng. J. (April 1972), 143. 21. Bernard, G.G., Holm, L.W., and Harvey, C.P.: "Use of Surfactant to Reduce CO2 Mobility in Oil Displacement," Soc. Pet. Eng. J. (Aug. 1980), 281-292. 22. Casteel, J.F. and Djabbargh, N.F.: "Sweep Improvement in Carbon Dioxide Flooding Using Foaming Agents," SPE Paper No. 14392, presented at the 60th Annual Technical Conference of the Society of Petroleum Engineers, Las Vegas, Sept. 1985. 23. Heller, J.P., Lien, C.L., and Kuntamukkula, M.S.: Foamlike Dispersions for Mobility Control in CO2 Floods," Soc. Pet. Eng. J. (Aug. 1985),603-13. 24. Borchardt, J.K., Bright, D.B., Dickson, M.K., and Wellington, S.L.: "Surfactants for CO2 Foam Flooding," SPE Paper 14394, presented at the 61st Annual Technical Conference of the Society of Petroleum Engineers, Las Vegas, September 1985.




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25. Lescure, B.M. and Claridge, E.L.: "CO2 Foam Flooding Performance vs. Rock W e t t a b i l i t y , " SPE Paper No. 15445, presented at the 61st Annual Technical Conference of the Society of Petroleum Engineers, New Orleans, Oct. 1986. 26. Tiffin, D.L., and Yellig, W.F.: "Effects of Mobile Water on Multiple-Contact Miscible Gas Displacements," Soc.Pet.Eng.J. (June 1983), 447-455. 27. Lescure, B.M.: "CO2 Foam Flooding," M.S. Thesis, Ch.E. Dept., Univ. of Houston, May 1987. 28. Chase, C.A. and Todd, M.R.: "Numerical Simulation of CO2 Flood Performance," Soc. Pet. Eng. J. (Dec. 1984), 597-605. 29. Todd, M.R. and Longstaff, W.J.: "The Development, Testing, and Application of a Numerical Simulator for Predicting Miscible Flood Performance," J. Pet. Tech. (July 1972), 874. 30. Raimondi, P. and Torcaso, M.A.: "Distribution of the Oil Phase Obtained Upon Imbibition of Water," Soc. Pet. Eng. J. (March 1964), 49-55 31. Todd, M.R. et al: "CO Flood Performance Evaluation for the Cornell Unit, Wasson San Andres Field," J.Pet.Tech. (Oct. 1982), 2271-2282. 2

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