Method for improving sweep efficiency in CO.sub.2 oil recovery

Volumetric sweep efficiency and oil recovery by CO.sub.2 flooding processes may be increased by injecting a surfactant solution into the formation which will form a gel in-situ in the high permeability zones via interaction of the surfactant with formation brine, oil, and CO.sub.2 under formation conditions. Thereafter, improved oil recovery efficiency is realized in displacing oil from the lesser permeability zones. The surfactant solution is selected from phase behavior experiments which show gel precipitation at conditions of temperature, salinity, oil composition, and CO.sub.2 pressure which are expected to exist or may be practically established in the particular oil-containing formation. Preferably, the gel is precipitated at CO.sub.2 pressures above the minimum miscibility pressure for CO.sub.2 miscible flooding, and below the prevailing formation pressure during the CO.sub.2 flooding. The surfactant solution may be injected into the reservoir as an aqueous solution or as a microemulsion solution prepared in surface mixing facilities. The surfactant solution may also be injected prior to injection of CO.sub.2, or may be alternately injected in WAG cycles following CO.sub.2 breakthrough into production wells.

FIELD OF INVENTION 
This invention relates to a method for improving the vertical and/or 
horizontal volumetric sweep efficiency of a subterranean oil containing 
formation in a CO.sub.2 flooding process by selectively plugging the 
relatively high permeability zones in the formation by injecting a 
selective surfactant or surfactant mixture into the formation which 
preferentially enters the relatively high permeable zones and forms a gel 
in-situ under the temperature, salinity, oil composition and CO.sub.2 
pressure conditions within the formation. Formation of the gel plugs the 
highly permeable zones of the formation. 
BACKGROUND OF THE INVENTION 
A variety of supplemental recovery techniques have been employed in order 
to increase the recovery of viscous oil from subterranean viscous oil 
containing formations. These techniques include thermal recovery methods, 
waterflooding and miscible flooding, particularly CO.sub.2 flooding. 
In heterogeneous hydrocarbon containing subterranean formations, i.e., 
formations having relatively high permeability zones and relatively lesser 
permeability zones, tertiary oil recovery processes are relatively 
inefficient because fluids preferentially migrate into the highly 
permeable zones in the subterranean formations. Migration described above 
is undesirable when injecting treatment fluids into oil-containing 
formations for the recovery of oil since the treatment fluids channel 
through the highly permeable zones, bypassing the less permeable zones. 
The result is poor conformance and flow profiles of the treatment fluid in 
the formation. The hydrocarbons residing in the less permeable zones are 
not produced and the overall yield of hydrocarbons from the formation is 
reduced. 
To increase the efficiency of formation flooding processes, the highly 
permeable zones in a subterranean formations are plugged or partially 
plugged to prevent or reduce migration of treatment fluids into them and 
to divert treatment fluids into adjacent, less permeable zones. In 
injection profile control projects, polymeric materials have been used in 
liquid slurries or suspensions to effectively enter and plug or partially 
plug the highly permeable and/or fractured zones of the formation. Fluids 
injected after such a treatment therefore move into upswept areas or zones 
of the reservoir which results in increased oil recovery. 
In my U.S. Pat. No. 4,458,760 there is disclosed a process for improving 
oil recovery from stratified reservoirs by (1) injecting low salinity 
water to reduce the salinity in high permeability zones, (2) injecting a 
surfactant solution into the high permeability zones, (3) injecting high 
salinity water into the reservoir, thereby forming a surfactant/water/oil 
emulsion which reduces effective brine permeability in the high 
permeability zones, and (4) continuing to inject high salinity water into 
the reservoir, whereby water is diverted to low permeability zones and oil 
is recovered from the low permeability zones. Low salinity water may then 
be injected to break-up or release the emulsion in the high permeability 
zones and to recover oil from the high permeability zones. 
In the process of my present invention, a surfactant is injected into the 
formation that preferentially enters the highly permeable zones and 
produces a gel in-situ in the formation via interaction of the injected 
surfactant and subsequently injected CO.sub.2 under the temperature, 
salinity, oil composition and CO.sub.2 pressure conditions within the 
formation. Formation of the gel substantially plugs or partially plugs the 
highly porous zones to reduce channeling of injected CO.sub.2 through 
these zones, and to divert CO.sub.2 to lower permeability zones which 
would otherwise be by-passed by the CO.sub.2 thereby resulting in more 
complete displacement of oil from the formation. 
SUMMARY OF THE INVENTION 
This invention is a method for improving the vertical and/or horizontal 
sweep efficiency of a subterranean oil and brine containing formation 
having at least one relatively high permeability zone and at least one 
relatively low permeability zone, the formation being penetrated by at 
least one injection well and a spaced apart production well in fluid 
communication with the formation, the method comprising: (a) determining 
the formation temperature and properties of the oil and brine contained 
within the formation; (b) injecting a predetermined amount of a surfactant 
solution into the formation via the injection well that perferentially 
enters the relatively high permeability zone or zones and forms a 
surfactant/brine/oil microemulsion when said surfactant mixes with the oil 
and brine in the formation at the temperature, pressure and salinity 
within the formation; (c) injecting CO.sub.2 at a predetermined pressure 
into the formation via the injection well that preferentially enters the 
relatively high permeability zone or zones and upon contact with the 
microemulsion causes the surfactant to precipitate into a gel under the 
temperature, salinity, oil composition and CO.sub.2 pressure conditions 
within the formation which substantially plugs or partially plugs the 
relatively high permeability zone or zones of the formation; (d) injecting 
a predetermined amount of CO.sub.2 into the formation capable of forming a 
miscible bank with the oil in the relatively low permeability zones which 
miscible displaces CO.sub.2 and oil through the relatively low 
permeability zone or zones of the formation and recovering oil via the 
production well; and (e) injecting a displacing fluid into the formation 
to displace CO.sub.2 and oil through the relatively low permeability zones 
of the formation toward the production well from which oil is recovered. 
The amount of CO.sub.2 injected during step (d) to form a miscible bank of 
CO.sub.2 and oil which will miscibly displace CO.sub.2 and oil from the 
relatively low permeability zone toward the production well from which oil 
is recovered is within the range of 0.1 to 0.5 pore volume. Suitable 
displacing fluids injected during step (e) includes CO.sub.2, water, a 
brine solution, nitrogen, flue gas, a mixture of CO.sub.2 and flue gas and 
a mixture of CO.sub.2 and recycled produced gases. 
In another embodiment of the invention, the surfactant solution may be 
injected into the formation as a microemulsion comprising surfactant, 
brine and oil that preferentially enters the high permeability zones and 
forms a surfactant gel in-situ under the conditions of temperature, 
salinity, oil composition, and CO.sub.2 pressure within the formation. 
Formation of the gel substantially plugs the high permeability zones. 
In either embodiment, the surfactant gel is preferably precipitated at 
CO.sub.2 pressures above the minimum miscibility pressure (MMP) or 
CO.sub.2 miscible flooding, and below the prevailing reservoir pressure 
during the CO.sub.2 flood. The surfactant may be injected prior to 
CO.sub.2, or may be alternatively injected in WAG cycles following 
CO.sub.2 breakthrough into the production wells.

DESCRIPTION OF THE PREFERRED EMBODIMENT 
The process of my invention concerns an improvement in oil recovery by 
CO.sub.2 flooding processes by utilizing surfactant gels to increase 
volumetric sweep efficiency of injected CO.sub.2 that tends to channel 
through relatively high permeability zones in the formation. More 
particularly, the method is applied to a subterranean, permeable, oil and 
brine-containing formation penetrated by at least one injection well and 
at least one spaced-apart production well. The injection well and 
production well are perforated to establish fluid communication with a 
substantial portion of the formation. 
While recovery of the type contemplated by the present invention may be 
carried out by employing only two wells, it is to be understood that the 
invention is not limited to any particular number of wells. The invention 
may be practiced using a variety of well patterns as is well known in the 
art of oil recovery, such as an inverted five spot pattern in which an 
injection well is surrounded with four production wells, or in line drive 
arrangement in which a series of aligned injection wells and a series of 
aligned production wells are utilized. Any number of wells which may be 
arranged according to any pattern may be applied in using the present 
method as illustrated in U.S. Pat. No. 3,927,716 to Burdyn et al, the 
disclosure of which is hereby incorporated by reference. By the term "pore 
volume" as used herein, is meant that pore volume of the portion of the 
formation underlying the well pattern employed, which is described in 
greater detail in the Burdyn et al patent. 
The individual stratum associated with various sedimentary deposits within 
facies can have a wide degree of variability with respect to permeability 
by CO.sub.2 flooding. Consequently, CO.sub.2 may tend to channel through 
high permeability strata or stringers. When a thin section of low 
permeability strata is sandwiched between relatively thick sections of 
high permeability strata, oil may be displaced during CO.sub.2 flooding 
from the thin section of low permeability strata by crossflow between the 
high permeability strata. However, such cross flow may not occur to an 
appreciable extent if the section of low permeability strata is 
sufficiently thick. Furthermore, when relatively thick sections of low 
permeability strata, e.g., the entire thickness of a particular facies, 
sandwich a central section, e.g., also corresponding to an entire facies, 
of high permeability strata, injected water will tend to channel through 
the central high permeability strata, substantially avoiding the outer low 
permeability strata. 
Accordingly, it will be understood that the term "zone" as used herein 
shall refer to an individual stratum or adjacent strata composites. Thus, 
a zone may be as thin as an individual stratum or stringer or may be, 
e.g., as thick as an entire facies. 
The process of the present invention utilizes surfactant solutions selected 
from phase behavior experiments which show surfactant gel precipitation at 
conditions of temperature, salinity, oil compositions and CO.sub.2 
pressure within the formation, to increase flow resistance in high 
permeability strata, thereby diverting subsequently injected CO.sub.2 to 
low permeability zones to improve reservoir conformance or volumetric 
sweep efficiency. 
In accordance with the invention, the formation temperature and properties 
of the oil and brine contained within the formation are determined. A 
solution containing a surfactant or surfactant mixture for injection into 
the formation is selected from phase behavior experiments which show gel 
precipitation at appropriate formation conditions of salinity, 
temperature, CO.sub.2 pressure, and crude oil composition. Since the 
process of the present invention is used principally to improve oil 
recovery by CO.sub.2 miscible flooding, the surfactant gels are preferably 
produced at CO.sub.2 pressures between the minimum miscibility pressure 
(MMP) for CO.sub.2 flooding and the prevailing formation pressures during 
the miscible flood, and a temperature, salinities, and oil composition 
near those existing in a particular formation being flooded with CO.sub.2. 
Depending upon the formation temperature, there is a minimum pressure at 
which conditional miscibility exists between the carbon dioxide and 
formation oil which is known as the CO.sub.2 minimum miscibility pressure 
(MMP). Conditional miscibility is to be distinguished from instant 
miscibility by the fact that miscibility in a conditional miscibility 
sense is achieved by a series of transition multiphase conditions wherein 
the carbon dioxide vaporizes intermediate components from the oil, thus 
creating the miscible transition zone in the formation. This minimum 
miscibility pressure can be determined by means of slim tube displacement 
tests which means conditions are established simulating those of an 
enriched gas drive, see paper by Yellig et al entitled, "Determination and 
Prediction of CO.sub.2 Minimum Miscibility Pressure," J. of Pet. Tech., 
Jan. 1980, pp. 160-168, the disclosure of which is incorporated by 
reference. Briefly, CO.sub.2 MMP is determined by the slim tube test 
wherein percent oil recovery of the in-place fluid is determined at 
solvent breakthrough at given pressure conditions. By varying the pressure 
at constant composition and temperature, a break-point is determined in a 
curve of percent recovery versus pressure. This break-point is indicative 
of the inception of conditional miscible-type behavior. 
As illustrated in FIGS. 1A-1F, it has now been discovered that CO.sub.2 
pressure has significant effects on surfactant/brine/hydrocarbon phase 
behavior. The data summarized in this figure were obtained by 
equilibrating surfactant/brine/hydrocarbon mixtures at different CO.sub.2 
pressures. In these experiments, 4 ml of aqueous surfactant solutions, 
each 1.5 wt. percent C1720 IOS (C.sub.17 to C.sub.20 internal olefin 
sulfonate made by Shell Chemical Co., USA) plus 0.5 wt. percent Leonox K 
(alkylether sulfonate made by Lion Chemical Corp., Japan) plus 2.0 wt. 
percent isopropyl alcohol, were layered with 3 ml of a synthetic stock 
tank oil, a blend of pure hydrocarbons of composition shown in Table 1. 
The salinities of the surfactant solutions were varied from 0 to 8 wt. 
percent (PCT.) total dissolved solids (TDS) by appropriate dilution or 
concentration of the synthetic reservoir brine compositions shown in Table 
2. 
TABLE 
______________________________________ 
SYNTHETIC CRUDE OIL COMPOSITION 
Component Weight Percent 
______________________________________ 
n-hexadecane 70 
cyclohexane 8 
decalin 12 
propylbenzene 10 
______________________________________ 
TABLE 2 
______________________________________ 
SYNTHETIC BRINE COMPOSITION 
Compound Grams/liter 
______________________________________ 
NaCl 47.83 
CaCl.sub.2.1H.sub.2 O 
17.40 
MgCl.sub.2.6H.sub.2 O 
7.97 
______________________________________ 
Following layering of surfactant brine solutions with the synthetic oil, 
the solutions were mixed by rocking gently under different applied 
pressures of CO.sub.2 in a constant temperature oven. When the mixtures 
had solubilized as much CO.sub.2 as possible during mixing, the tubular 
cells containing the mixture were returned to a vertical position to 
equilibrate under the fixed CO.sub.2 pressure. The volumes of equilibrium 
phases formed were recorded to produce the phase maps shown in FIGS. 
1A-1F. 
With reference to FIGS. 1A-1F, at low CO.sub.2 pressures, the 
surfactant/brine/hydrocarbon system exhibits a characteristic phase 
behavior of progressing from lower phase microemulsion (Windsor Type I) to 
middle phase microemulsion (Windsor Type III) to upper phase microemulsion 
(Windsor Type II), with increasing salinity. As CO.sub.2 pressure 
increases, surfactant is driven progressively from lower phase 
microemulsion into middle and upper phase microemulsions, shifting the 
"optimal salinity" for surfactant flooding downward. As CO.sub.2 pressure 
continues to increase, and as more CO.sub.2 is solubilized in the oil, 
surfactant tends to precipitate from the upper phase microemulsions, to 
form first a white, flocky emulsion in the brine phase. At CO.sub.2 
pressures of 1500 psig in this example, the surfactant begins to 
precipitate from the upper oil external microemulsions and the white, 
flocky emulsions as a particulate gel which settles and absorbs additional 
water from the brine to completely fill the volume of the tubes below the 
microemulsion or excess oil phase. On mixing, the gel disperses but 
settles again as a particulate gel when the tubes are returned to a 
vertical position. 
As CO.sub.2 pressure continues to increase, e.g., to 1750 and 1900 psig in 
FIGS. 1E and 1F, the gels at lower salinities, 3 to 6 percent, tend to 
revert to condensed middle phase microemulsions, whereas the gels at 
higher salinities, 7 and 8 percent in this example, become more rigid and 
tend to adhere to the sapphire walls of the phase behavior cells. 
These types of gels may be produced in-situ in CO.sub.2 flooding processes 
to improve sweep efficiency of CO.sub.2. In the first step of the 
invention a predetermined amount of an aqueous surfactant solution is 
injected into the formation via the injection well. The injected aqueous 
surfactant will flow preferentially into the high permeability zones and 
fractures and form microemulsion phases on mixing with the formation crude 
oil and brine. The quantity of aqueous surfactant injected into the 
formation is within the range of 0.1 to 1.0 pore volumes, based upon the 
pore volume of the relatively high permeability zone or zones between the 
injection well and the production wells. This amount will vary depending 
upon the porosity, thickness and oil and water saturation of the formation 
treated. The preferred volume of the aqueous surfactant injected into the 
formation will depend upon formation characteristics and the degree of 
plugging desired. 
Suitable surfactants may be selected from the group consisting of 
alkylsulfonates, alkylarylsulfonates, alpha olefin sulfonates, internal 
olefin sulfonates, petroleum sulfonates, ethoxylated alcohols, ethoxylated 
alkylphenols, ethoxylated alkylsulfonates, and ethoxylated 
alkyarylsulfonates. A preferred surfactant is a C.sub.17 to C.sub.20 
internal olefin sulfonate sold under the tradename "C1720 IOS" by Shell 
Chemical Company. The preferred surfactant solution may also contain an 
oxyalkylated sulfonate cosurfactant, such as that sold under the tradename 
"Leonox K" by Lion Chemical Corp., Japan, to increase the solubility of 
the surfactant in the preferred injection brine. The total surfactant 
concentration may vary from 0.05 to 5 wt. percent, preferably from 0.1 to 
0.5%. The salinities of aqueous surfactant solutions will vary from 0 to 
20 wt. percent depending upon the salinity of the formation in the high 
permeability zones. 
The aqueous surfactant solution injected into the formation preferentially 
enters the high permeability zones and upon mixing with the brine and oil 
contained in these zones forms a surfactant/brine/oil microemulsion at the 
temperature, pressure and salinity within the formation. The surfactant or 
surfactant mixture is selected such that the microemulsion formed at 
formation temperature, pressure, and salinity will subsequently 
precipitate as a gel when contacted and pressurized with CO.sub.2. 
After the desired amount of aqueous surfactant has been injected into the 
formation, carbon dioxide is injected into the formation via the injection 
well that preferentially enters the higher permeability zones and fingers 
through the more viscous surfactant/brine/oil microemulsion and, as 
CO.sub.2 pressure in the formation is increased, a gel will precipitate 
which substantially plugs or partially plugs the high permeability zones. 
Gelation preferably occurs at the formation temperature and salinity and 
at CO.sub.2 pressure greater than the CO.sub.2 MMP for the reservoir crude 
oil. Thereafter, a predetermined amount of CO.sub.2 is injected into the 
formation capable of forming a miscible bank with the oil in the 
relatively low permeability zones which miscibly displaces CO.sub.2 and 
oil through the relatively low permeability zones of the formation toward 
the production well from which oil is produced. The amount of CO.sub.2 
injected to form a miscible bank with the oil in the relatively low 
permeability zones is within the range of 0.1 to 0.5 pore volume depending 
upon the formation characteristics. Once the amount of CO.sub.2 has been 
injected, a displacing fluid is injected into the formation to displace 
CO.sub.2 and oil through the relatively low permeability zones of the 
formation toward the production well from which oil is recovered. The 
displacing fluid may be CO.sub.2, water, a brine solution, nitrogen, flue 
gas, a mixture of CO.sub.2 and flue gas, or a mixture of CO.sub.2 and 
recycled produced gases. The preferred displacing fluid is a brine 
solution. 
The carbon dioxide preferably is introduced into the injection well in the 
liquified state because less energy is required than pumping it in the 
gaseous state. As the liquid carbon dioxide descends in the wellbore, it 
is heated by a naturally increasing temperature, causing it to become 
gaseous within the wellbore or in the formation in the immediate vicinity 
of the wellbore. The injected carbon dioxide will preferentially enter the 
higher permeability zones and finger through the more viscous 
surfactant/brine/oil microemulsion and, as CO.sub.2 pressure in the 
formation is increased, a gel will precipitate which substantially plugs 
or partially plugs the high permeability zones. Gelation preferably occurs 
at the formation temperature and salinity and at CO.sub.2 pressure greater 
than the MMP for the reservoir crude oil. 
In another embodiment, surfactant injection is deferred until CO.sub.2 
channeling problems become obvious by appearance of high CO.sub.2 cuts in 
the production well, in which case only those areas of the field where 
CO.sub.2 channeling is a severe problem may be treated. Therefore, in this 
embodiment, CO.sub.2 is injected into the formation prior to injection of 
the surfactant and oil is recovered from the formation via the production 
well until CO.sub.2 breakthrough occurs at the production well. In this 
embodiment, depending upon the amount of residual oil remaining in the 
high permeability CO.sub.2 swept zones, it may be desirable to coinject a 
selected hydrocarbon with the aqueous surfactant to form the microemulsion 
phase from which the gel is precipitated in-situ by subsequent injection 
of CO.sub.2. Suitable hydrocarbons may be selected from the group 
consisting of refined hydrocarbons, kerosine, diesel fuel, gas oil, and 
stock tank crude oil. 
In still another embodiment, it may be desirable to inject surfactant in 
the form of a microemulsion prepared in surface facilities from 
surfactant, brine, and a selected hydrocarbon as discussed above. 
Surfactant concentration in the microemulsion may range from 1 to 20 wt. 
%, preferably 2 to 5 %. The injected microemulsion may be either a 
water-external or oil-external microemulsion formed from mixing aqueous 
surfactant, brine and a selected hydrocarbon as described above. 
Thereafter, CO.sub.2 is injected into the formation to produce the gel 
in-situ by the same fingering mechanism as previously described. 
In still another embodiment, it may be desirable to inject alternate slugs 
of surfactant and CO.sub.2 in WAG cycles or alternate slugs of surfactant, 
water and CO.sub.2 to reduce channeling of CO.sub.2 in the formation. The 
salinity of the slug of water is less than that required to precipitate a 
gel from the surfactant being injected into the formation. Again, 
depending upon residual oil saturations expected in the high permeability 
zones with each successive WAG cycle, it may be desirable to coinject oil 
or a selected hydrocarbon with the surfactant or inject the surfactant in 
the form of a surface prepared microemulsion to assure presence of enough 
oil to form the surfactant gel. 
Regardless of the timing or form of surfactant injection, precautions must 
be taken to prevent precipitation of the surfactant gel in the immediate 
vicinity (10 to 15 ft. radius) of the injection wells, and thus avoid 
serious reduction of well injectivities. To prevent precipitation of gel 
in the immediate vicinity of injection wells, the surfactant may be 
injected at a salinity below which upper phase microemulsion phases are 
produced and gels are precipitated (below about 2 wt. percent brine in 
this example). The upper phase microemulsion and gel phases are produced 
as the injected low salinity surfactant mixes with higher salinity 
formation brine and crude oil farther out in the formation. 
Another means of preventing gel precipitation within immediate vicinities 
of injection wells is to use brine spacers between injected surfactant (or 
surfacant microemulsion) and CO.sub.2 slugs. Thus, as in a WAG cycle, 
CO.sub.2 should be displaced from the vicinity of the injection well by 
brine before injecting surfactant, and the surfactant should in turn be 
displaced by a small amount of brine before resumption of CO.sub.2 
injection. 
The effect of salinity on gel precipitation and flow resistance imparted by 
precipitated gel is illustrated in FIGS. 2A-2D. Those figures show 
pressure drops (PSI) across a 158 md porcelain core during three-phase 
flow experiments. In these experiments, CO.sub.2, aqueous surfactant, and 
the synthetic oil of Table 1 were coinjected at fixed proportions of 
73.9%, 13.0%, and 13.1%, respectively, at a total flow rate of 29.8 cc/hr. 
(11.03 ft./day), against a back pressure of 1900 psig. At 1% salinity, 
where the upper phase microemulsion and gel phases do not form, pressure 
drops across the core were very low, not significantly different from 
reference three-phase flow pressure drops obtained with CO.sub.2, oil and 
surfactant-free brine coinjected at the same rates. Pressure gradients at 
fixed flow rates increase progressively at 4%, 6.74%, and 8% aqueous 
surfactant salinities, as the resultant gel phases become more copious and 
rigid. According to the 1900 psi phase diagram of FIG. 1F, the gel is 
expected to precipitate t 6.74% and 8% salinities, but not at 1% or 4%. 
The experiments of FIGS. 2A-2D were performed using the same core in the 
sequence of aqueous surfactant salinites of 6.74%, 1%, 4%, and 8% 
successively. The high pressure drops built by 6.74% surfactant 
coinjection were dissipated by 1% aqueous surfactant coinjection, and 
increased as salinity of the coinjected surfactant solution increased. The 
gels formed by three-phase coinjection were apparently formed mostly in 
the upstream section of the core, showing the need for avoiding direct 
mixing of oil, aqueous surfactant, and CO.sub.2 components in the vicinity 
of injection wells under conditions of salinity, temperature, and CO.sub.2 
pressure where the gel is precipitated. 
The cyclical character of the pressure drops at 8% salinity, observed to a 
lesser extent at 6.74% salinity, suggests the gel may have thixotropic 
properties. The cyclical response was obtained on resumption of 
three-phase flow following an overnight shut-down of the injection pumps, 
which may have allowed the precipitated gel to set-up in the core. 
Thereafter, the gel appeared to exhibit a yield stress which allowed 
intemittent flow and pressure dissipation, followed by resetting of the 
gel to obstruct flow until the yield stess again was exceeded. 
FIGS. 3A-3C shows that the high flow resistances imparted by the gel are 
retained during subsequent flow of CO.sub.2, oil, and high salinity brine. 
However, high flow resistance is not maintained for injection or 
coinjection of a brine of lower salinity than that required for the gel to 
precipitate, as seen in the case of 1% brine coinjection. This sensitivity 
of flow resistance to brine salinity may make the surfactant gel superior 
in one respect to surfactant foams or polymer gels for mobility control 
and profile modification in CO.sub.2 miscible processes. Both of the 
latter agents may impart more permanent losses of fluid injectivities in 
injection wells. 
The sensitivity of surfactant gel precipitation to salinity and CO.sub.2 
pressure also provides a mechanism by which a surfactant gel may be 
propagated in the reservoir. Once a surfactant gel has been precipitated 
in the reservoir by one of the procedures described earlier, injection of 
low salinity water and/or reduction of CO.sub.2 pressure below conditions 
for which the gel forms should result in reversion of the surfactant gel 
to a microemulsion. Continued fluid injection will move the microemulsion 
farther out into the reservoir where mixing of the microemulsion with 
higher salinity brine and/or reestablishing higher CO.sub.2 pressure will 
precipitate the gel. 
The potential for propagating the gel by this mechanism is illustrated in 
FIGS. 4A-4D which show the pressure drops in three-phase flow experiments 
similar to the one described earlier (same core, same three-phase fluid 
injection rates). FIG. 4A shows a cyclical character similar to that 
exhibited by three-phase coinjection of CO.sub.2, oil, and surfactant at 
8% salinity, described previously. Successively larger increments of low 
salinity water (1% NaCl and distilled water) were injected intermittently 
during this three-phase flow experiment to move the gel from the upstream 
section of the core to the downstream section. During each cycle of low 
salinity water injection, pressure drops across the core decreased 
markedly, but were re-established by resumption of three-phase flow with 
8% brine. By the time 1.55 pore volume of low salinity water had thus been 
injected, the cyclical character of flow had been supplanted by near 
steady-state flow, and flow resistance was still higher in the upstream 
section of the core (FIG. 4B). Following further increments of low 
salinity water injection, accompanied by production of surfactant 
microemulsion from the core, three-phase flow continued to be 
steady-state, pressure drops declined and flow resistance continued to be 
greater in the upstream section (FIG. 4C). Following 8.08 pore volumes of 
intermittent low salinity water injection (PVI), steady-state pressure 
drops had declined substantially, and most of the residual flow resistance 
had been moved to the downstream section of the core (FIG. 4D). 
These data illustrate how a surfactant gel can be precipitated in high 
permeability zones within an oil reservoir to markedly increase flow 
resistance, and thus divert subsequently injected CO.sub.2 to other zones 
within the reservoir. Although the data are representative of one 
surfactant/brine/hydrocarbon/CO.sub.2 system, the behavior is believed to 
be general for these types of systems. Surfactant and surfactant mixtures 
different from the example system described here are expected to be useful 
for different oil reservoirs, and surfactants and surfactant mixtures 
appropriate for each reservoir application may be selected from phase 
behavior and flow experiments similar to those described, using fluid 
samples, temperature, and pressures appropriate for the target reservoir. 
In general, surfactants useful in surfactant flooding processes, i.e., 
those which produce the characteristic transition from lower phase to 
middle phase to upper phase microemulsion systems with increasing 
salinity, are expected to be useful for precipitating surfactant gels when 
pressurized with CO.sub.2. Thus, a useful screening procedure for 
selecting a surfactant to produce a surfactant gel for CO.sub.2 diversion 
is to screen surfactants or surfactant mixtures expected to have an 
optimal salinity for surfactant flooding near the salinity of the target 
CO.sub.2 flood reservoir. 
The invention as described herein is capable of a variety of modifications 
and variations which will be apparent to a person skilled in the art and 
which are included in the spirit of the claims appended hereto.