High Conformance Oil Recovery Process

This invention concerns a process for use in subterranean formations containing two or more zones which differ from one another in permeability such that steam flooding, water flooding or other enhanced oil recovery processes cannot effectively deplete both zones, resulting in poor vertical conformance. More specifically, the process involves injecting a fluid into the more permeable zone, after it has been depleted by steam or water flooding or some other supplemental oil recovery process, which fluid has relatively low viscosity at the time of injection but forms a high viscosity, coarse emulsion with the residual hydrocarbon in the depleted zone to reduce the permeability of that zone to subsequently injected fluids.

It is well recognized by persons skilled in the art of petroleum recovery that only a small fraction of the petroleum originally present in a formation can be recovered by primary production, e.g., by allowing the oil to flow to the surface of the earth as a consequence of naturally occuring energy forces, or by so called secondary recovery processes which comprise injecting water into the formation by one or more wells to displace petroleum through the formation toward one or more spaced-apart production wells and then to the surface of the earth. Although water flooding is an inexpensive supplemental oil recovery process, water does not displace oil effectively even in those portions of the formation through which it passes, because water and oil are immiscible and the interfacial tension between water and oil is quite high. This too has been recognized by persons skilled in the art of oil recovery, and many surface active agents or surfactants have been proposed for addition to the flood water, which materials reduce the interfacial tension between the injected aqueous fluid and the formation petroleum thereby increasing the microscopic displacement efficiency of the injected aqueous fluid. Surfactants which have been disclosed in the prior art for such purposes include alkyl sulfonates, alkylaryl sulfonates, petroleum sulfonates, alkyl or alkylarylpolyalkoxy sulfates, alkyl- or alkylarylpolyalkoxyalkyl sulfonates, and nonionic surfactants such as polyethoxylated aliphatic alcohols or alkanols, and polyethoxylated alkyl phenols.

Even if the surface tension between the injected aqueous fluid and the petroleum present in the subterranean reservoir can be reduced by incorporating surface active agents into the injected fluid, the total oil recovery efficiency of the process is frequently poor because many subterranean petroleum-containing reservoirs are comprised of a plurality of layers of widely differing permeabilities. When a fluid is injected into such a heterogeneous reservoir, the fluid passes primarily through the most permeable zones and little or none of the fluid passes through the lower permeability zones. If the ratio of permeabilities of the zones is as high as 2:1, essentially all of the injected fluid passes through the more permeable zone to the total exclusion of the less permeable zone. Furthermore, the situation described immediately above causing poor vertical conformance of the injected fluid in a heterogeneous reservoir is aggravated by application of the supplemental oil recovery process itself. If water is injected into a heterogeneous multi-layered petroleum reservoir, water passes principally through the most permeable zone and displaces petroleum therefrom, and as a consequence further increases the permeability of that zone. Accordingly, the difference between the permeability of the most permeable zone and the lesser permeable zone or zones is increased as a consequence of applying a fluid displacement oil recovery process thereto, including water flooding, surfactant flooding, etc.

The above described problem of poor vertical conformance in water flooding operations has also been recognized by persons skilled in the art, and numerous processes have been described in the prior art for treating the formation to correct the problems resulting from injecting an oil-displacing fluid into a formation having two or more zones of significantly different permeabilities. Many of the these processes involve the use of hydrophilic polymers including partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylic acid or water soluble acrylates, polysaccharides, etc. Unfortunately, the fluids employing these hydrophilic polymers are substantially more viscous than water at the time of injection, and so injection into the zones is difficult and there is little assurance that they will invade the same zones as would water or another aqueous fluid having about the same viscosity as water. Accordingly, the effectiveness of the above described processes has been restricted to reducing the permeability of only the most permeable flow channels in a zone, and is furthermore usually restricted only to the near wellbore zone of the formation, e.g. that portion of the most permeable zone in a formation immediately adjacent to the injection well, because of the difficulty of injecting viscous fluids through great portions of the formation.

In view of the foregoing discussion of the problems associated with poor vertical conformance in heterogeneous formations, it can be appreciated that there is a substantial need for a method of treating such formations to reduce the permeability of the very high permeability zones to force subsequently injected oil displacing fluids to pass into those zones which were originally of lower permeability, and so were not invaded by the first injected fluids.

Numerous references suggest formulating viscous emulsions on the surface, and injecting the emulsion into a subterranean formation for the purpose of decreasing the permeability of a zone which is substantially more permeable than other zones. These include U.S. Pat. No. 3,149,669; Reissue No. 27,198 (original patent U.S. No. 3,443,636); U.S. Pat. No. 3,502,146 (1970); and U.S. Pat. No. 3,866,680 (1975).

Numerous patents describe the use of high HLB, water soluble nonionic surfactants in combination with organic sulfonates for use as low interfacial tension oil-displacing fluids in high salinity formations, including U.S. Pat. Nos. 3,792,731; 3,811,504; and 3,811,505.

We have discovered a process applicable to subterranean, petroleum-containing formations containing two or more zones, at least one of which has a permeability at least 50 percent greater than the other zone, which will permit more effective water flooding, steam injection or surfactant flooding in both zones. The process involves first injecting water or other aqueous displacing fluid into the formation to pass through the more permeable zone, displacing petroleum therefrom, until the ratio of injected fluid to formation petroleum of fluids being recovered from the formation reaches a predetermined or economically unsuitable level. This further increases the ratio of the permeability of the most permeable zone to the permeability of the lesser permeable zone or zones. Thereafter an aqueous fluid is injected into the formation, which fluid will pass substantially exclusively into and through the most permeable, previously flooded zone, which fluid has a viscosity not substantially greater than the viscosity of water, said fluid containing a surfactant mixture which readily emulsifies the residual oil present in the previously flooded zone. The surfactants present in the injected treating fluid must form an emulsion with the formation petroleum at a salinity about equal to the salinity of the aqueous fluid present in the previously flooded, high permeability zone, and should also be relatively stable with changes in salinity since there will normally be variations in water salinity from one point in the subterranean formation to another. The emulsion formed should also be stable with time and changes in salinity at the temperature of the formation, in order to maintain the desired reduction of permeability within the treated zone. The surfactant employed in the process of our invention comprises at least two components, one of which is an organic sulfonate such as an alkyl sulfonate, alkylaryl sulfonate, or petroleum sulfonate which is at least partially soluble in the water present in the formation, and a low HLB, essentially water-insoluble nonionic surfactant, specifically an ethoxylated aliphatic or ethoxylated alkylaryl compound such as an ethoxylated aliphatic alcohol, an ethoxylated alkanol, or an ethoxylated alkylphenol. The nonionic surfactant has a relatively low HLB number, e.g. relatively fewer ethoxy groups per molecule, than that described in the literature for use in solubilizing organic sulfonates in high salinity environments. The nature of the nonionic surfactant used in combination with the organic sulfonate, as well as the ratio of nonionic to organic sulfonate, is chosen so as to optimize the emulsion-formation tendency of the surfactant combination with respect to the petroleum and brine present in the portion of the formation to be treated. The optimum surfactant mixture for our process is not an optimum surfactant combination for effective low surface oil displacement surfactant water flooding. This process and fluid are suitable for use in formations containing water whose salinity is from 0 to 20,000 parts per million total dissolved solids.

FIG. 1a illustrates a subterranean oil formation containing three zones of different permeabilities, illustrating the interface between an injected fluid and the petroleum in each zone at a time near the economic end of a water flood process. FIG. 1b illustrates the same subterranean formation, after it has been subject to the treatment of the process of this invention, and then subjected to additional water flood.

Briefly, the process of our invention comprises a method of treating a subterranean formation containing at least two zones or strata whose permeabilities are sufficiently different from one another that a fluid injected into a well in communication with both zones will pass primarily through the more permeable zone. Ordinarily, for example, if the permeability of one zone to the flow of the injected fluid is at least 50 percent greater than and certainly if it is 100 percent greater than the permeability of the other zone, fluid injected into wells in fluid communication with both zones will pass almost exclusively into the more permeable zone. For example, in a water flood applied to such a formation, water will pass into the more permeable zone exclusively and will displace petroleum towards the production well, with substantially no oil displacement occuring in the less permeable zone. After oil has been displaced through the more permeable zone and oil recovery has proceeded to the point at which water breakthrough has occurred at the production well, continued injection of water into the well in communication with both zones will accomplish substantially no additional oil recovery even though the oil saturation in the less permeable zone may be substantially the same as it was before commencing water flood or other supplemental oil recovery operations. Moreover, injecting a surfactant fluid which achieves low interfacial tension, but which produces no emulsion, into the formation at this time will achieve essentially the same results as injecting additional water, e.g. the surfactant fluid invades the previously swept high permeability, low oil saturation zone, bypassing the high oil saturation, low permeability zone or zones.

Attempts to treat a formation such as that described above by techniques taught in the prior art have been only partially successful at best for a variety of reasons. Injecting a viscous fluid, which may be either an emulsion formed on the surface for the purpose of plugging the more permeable zone, or a viscous aqueous solution of a hydrophilic polymer such as polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylates, polysaccharides, etc., are generally not entirely satisfactory because the more viscous fluid only invades the largest flow channels of the formation, and so does not invade all of the flow channels which would be invaded by a fluid whose viscosity was more nearly equal to the viscosity of water. Furthermore, emulsions formed by, for example, adding caustic and water to crude oil are not particularly stable with respect of time and are also not stable with respect to changes in the salinity of fluid which they may contact. Thus an emulsion formed with caustic, water and oil which effectively plugs the larger flow channels of a high permeability zone, including one which has previously been water flooded, may be broken later either as a consequence of the passage of time, or as the emulsion contacts pockets of water having greater or lesser salinity, which are frequently found in most subterranean reservoirs. Moreover, there are problems associated with adsorption of hydrophilic polymers, and furthermore many of the hydrophilic polymers are not sufficiently temperature stable to allow them to be used in even moderately high temperature formations.

The fluid injected into the formation according to the process of our invention is an aqueous fluid or solution containing at least two surfactants, or surface-active agents, which are carefully chosen individually and their ratio selected on the basis of displaying optimum emulsification characteristics. Surfactants which are effective for this purpose, e.g. for forming gross macroemulsions suitable for plugging the flow channels of the formation, are not suitable for low surface tension flooding operations, and will not produce optimum oil displacement in a formation if utilized in a surfactant water flooding process. The reason the surfactants suitable for use in the process of this invention are ineffective for water flooding operations is believed to be associated with the fact that when an emulsion is formed, essentially all of the surface active agents which participate in the emulsification reaction, are concentrated at the interface between the discontinuous phase and continuous phase, and so little surfactants remain in the aqueous solution, and so cannot reduce the interfacial tension between formation petroleum and the aqueous fluid present in the flow channels as is necessary to achieve efficient low surface tension displacement of petroleum.

It is necessary that the surfactants utilized in the process of this invention be stable and effective for emulsification in an aqueous fluid having a salinity about equal to the average salinity of the aqueous fluid present in the flow channel of the high permeability zone, e.g. the zone into which the treating fluid is to be injected, and at the time the treatment is applied. In application after a steam flood, the water present in the high permeability zone through which steam and steam condensate have passed is usually quite fresh, much lower in salinity than before steam injection. Preferably, the surfactants should be identified by tests utilizing actual fluids from the formation, including water or brine and formation petroleum, since particular characteristics of any of these fluids will affect the efficiency of the surfactant for emulsification of formation petroleum and injected aqueous fluid.

The aqueous emulsifying treating fluid injected into the high permeability zone in practicing the process of our invention contains the following two surfactants. (1) An organic sulfonate, such as an alkyl sulfonate, linear or branched, containing from 8 to 20 and preferably from 9 to 18 carbon atoms, or an alkylaryl sulfonate such as the following

wherein R is a benzene, toluene or xylene having attached thereto at least one alkyl group, either linear or branched, containing from 8 to 20 and preferably from 9 to 18 carbon atoms, and M is ammonium, sodium, potassium or lithium. A particularly preferred organic sulfonate is an ammonium, sodium, potassium, or lithium salt of a petroleum sulfonate which is at least partially soluble in the formation water or brine. The median equivalent weight of preferred petroleum sulfonates is generally from about 350 to 450 and it is preferred that there be a fairly broad, even spectrum of molecular species of equivalent weights from about 300 to at least 500. It is often necessary to blend two or more commercial petroleum sulfonate samples to achieve the desired average equivalent weight and broad, even equivalent weight distribution desired for optimum emulsification effectiveness. The formulation of the optimum blend is preferably done experimentally using formation water or brine samples, and selecting and using the blend which produces the maximum amount of emulsion and which achieves the most time stable emulsion at formation conditions, e.g. temperature, salinity, etc. (2) A low HLB, relatively water-insoluble nonionic surfactant is used in combination with the organic sulfonate surfactant, having the following formula:

wherein R' is an aliphatic, such as branched or linear alkyl, containing from 7 to 25 carbon atoms and preferably from 9 to 18 carbon atoms, or an alkylaryl group such as benzene, toluene or xylene having attached thereto at least one alkyl group, linear or branched, containing from 7 to 15 and preferably from 9 to 13 carbon atoms in the alkyl chain; R" is ethylene or a mixture of ethylene and higher alkylene such as propylene with relatively more ethylene than higher alkylene; and n is a number, either whole or fractional, from 1 to 10 and preferably from 2 to 6.

The concentration of the organic sulfonate surfactant is ordinarily in the range of from about 0.01 to about 10 and preferably from about 0.5 to about 4.0 percent by weight. The concentration of the nonionic surfactant, is ordinarily be from about 0.1 to about 5.0 and preferably from about 0.4 to about 2.0 percent by weight. The ratio of nonionic surfactant to the organic sulfonate will ordinarily be from about 0.5 to about 4.0, depending on the salinity of the fluid in which it is formulated, which in turn is usually about equal to the salinity of the fluid present in the subterranean formation.

The volume of treating fluid to be injected into the formation when applying the process of our invention is ordinarily from about 1.0 to about 100 and preferably from 10 to 50 pore volume percent, based on the pore volume of the high permeability zone or zones to be contacted by the treating fluid. It is important to note that the pore volume on which these numbers are based relates to the pore volume of the high permeability zone to be treated, not the pore volume of the whole formation.

The procedural steps involved in applying the process of our invention to a subterranean formation are best understood by referring to the attached drawing, to which the following description applies.

A subterranean, petroleum-containing formation is located at depth of about 6200 feet, and it is determined that the total thickness of the formation is 35 feet. The salinity of the formation water is 3000 parts per million total dissolved solids. The formation is not homogeneous in terms of permeability, however; rather, the formation is made up of three separate zones or layers. The initial oil saturation in all three layers is approximately 30 percent. Oil saturation is designated in the drawing as S.sub.O. Zone 1, the top layer in the formation, has a permeability of about 6 md (millidarcies) and is approximately 10 feet thick. Zone 2, the middle zone of the formation, has a permeability of about 46 md and is about 15 feet thick. Zone 3, which occupies the lower portion of the formation, is approximately 10 feet thick and has an average permeability of about 15 md.

Eighty percent quality steam is injected into injection well 5 which is in fluid communication with the full vertical thickness of the formation, i.e., all three zones of the formation. Since the permeability of zone 2 is substantially greater than either zone 1 or zone 3, steam flows much more readily into zone 2, and all of the oil production obtained as a consequence of water injection is in fact derived from zone 2. It should be noted that this is not necessarily apparent to operators on the surface of the earth, however. Steam injection continues and an interface forms in each zone between steam or steam condensate and the oil bank that is formed as a consequence of the steam flood, designated as 6 in zone 1, 7 in zone 2 and 8 in zone 3. At a time just before steam and steam condensate breakthrough at the production well 4, the position of interfacial zones 6, 7 and 8 is shown in FIG. 1a. It can be seen that steam and steam condensate breakthrough is about to occur at production well 4 from zone 2. Once steam breakthrough occurs, further injection of steam into well 5 will not recover any significant amount of additional oil from any of the three zones. All of the steam injected after breakthrough of steam and steam condensate at production well 4 will pass into and through zone 2, and essentially none of the steam will pass into zones 1 and 3. Thus interfacial zone 6 and 8 will remain approximately where they are shown in FIG. 1a after breakthrough of steam into the production well at zone 2, no matter how much additional steam is thereafter injected into the injection well and flowed through the reservoir. At this time oil production drops off rapidly and the amount of steam and steam condensate being produced increases rapidly until further water injection and oil production are no longer economically feasible.

The salinity of the water in the steam-swept, depleted zone 2 is much less than the original formation brine, due to the dilution effect of steam condensate. The salinity averages about 800 parts per million total dissolved solids, and it is this salinity level for which the emulsifying surfactants for our process are tailored. The temperature in the swept zone is 300.degree. F. (149.degree. C.). It is desired to formulate a treating fluid suitable for use in this low salinity environments, and at that temperature, and the surfactants are chosen by a series of laboratory experiments employing actual samples of water and petroleum from the swept zone of the formation into which the treating fluid is to be injected and at the formation zone tempeature. After a series of laboratory tests, essentially similar to those to be described more fully later hereinafter below, it is determined that a preferred emulsifying fluid for use in reducing the permeability of zone 2 contains 1.9 percent of a sodium salt of petroleum sulfonate having a median equivalent weight of 405; and (2) 1.0 percent of polyethoxylated dodecylphenol nonionic surfactant having 3.1 moles of ethylene oxide per mole of surfactant.

Since the wells are 150 feet apart, and the formation to be treated is principally zone 2, which is 15 feet thick, and has a porosity of 30%, and since it is determined that the swept area in a simple two-well pattern such as this is 11,200 square feet, the volume of formation to be treated is (11,200)(15)(0.30)=50,400 cu. ft.

A 20 percent pore volume slug or 10,080 cubic feet is chosen for use in treating the above identified zone. Accordingly, the volume of the solution necessary to treat zone 2 in this example is approximately 2133 cubic meters or 75,398 gallons.

The above described emulsifying fluid is injected into injection well 5. Because the permeability of zone 2 is substantially greater than the permeability of zones 1 and 3 at that time, the difference being substantially greater than existed at the time steam flooding was initiated, it is not necessary to isolate zone 2 from the other zones for the purpose of selectively injecting the fluid into zone 2. Substantially all of the fluid injected into well 5, which is in fluid communication with all three zones of the formation, will pass into zone 2. Injection of the treating fluid into zone 2, which causes an emulsion to form in zone 2, reducing the permeability of the zone and additionally recovering some additional oil therefrom, reduces the oil saturation in zone 2 to only 4 percent. Steam injection into the formation is then resumed. Since the permeability of zone 2 has been increased substantially, steam injected into well 5 will now flow principally into zones 1 and 3, and so will continue pushing the interface between the injected steam or the condensate thereof and the formation petroleum toward the production well. If steam in zone 3 breaks through at producing well 4 before it does in zone 1, it may be necessary to treat zone 3 in about the same fashion as was used to treat zone 2 in the same manner as is described above. If this is accomplished, steam injection may again be resumed, with essentially all of the steam passing into zone 1. Steam injection is then continued until steam and/or steam condensate again breaks through at well 4, signifying that substantially all of the formation has been swept by steam flooding.

The above process may be repeated through several cycles of steam or hot water injection with intermittent injection of slugs of the optimum emulsifying surfactant fluid for optimum oil recovery.

For the purpose of illustrating the types of fluids suitable for use in the process of our invention, and illustrating the results obtainable from application thereof, a series of laboratory experiments were performed.

A series of bottle tests was performed to determine the effectiveness of several surfactant combinations of this invention for forming emulsions suitable for use in adjusting permeability variations of subterranean formations as described above. A total of six samples were prepared using various combinations of surfactants and at several salinity values. The surfactants and salinities, as well as emulsions observed after 24 hours of agitation in an oven at 43.degree. C., are given in Table I below. It can be seen that petroleum sulfonate alone is ineffective for forming the desired amount and type of emulsion, whereas combinations of petroleum sulfonate and low HLB nonionic surfactants (runs 2 and 5) were effective produced a substantial amount of a creamy-appearing emulsion, which we have found is especially effective for our process. Petroleum sulfonate and high HLB nonionic surfactants (runs 3 and 6) produced very little useful emulsion or were insoluble in the solution. The stability of the emulsion of run 3, which corresponds to the embodiment of our invention as would be applied in steam flooding, was verified at 80.degree. C. and found to be quite stable.

Laboratory equipment was especially constructed for core flood tests, and comprised essentially two separate formation earth core samples encased in holders and arranged for flooding, with the two cores being placed in parallel to simulate the situation similar to that described above, in which an injection well contacts two earth strata of substantially different permeabilities. Fluids injected into the apparatus will pass predominantly through the highest permeability core to the exclusion of the other core. In all of the experiments described below, the cores were separately water flooded to an irreducible oil saturation prior to being connected in parallel for the purpose of studying the effect of the adverse permeability distribution-correcting treatment of my invention.

In run 7, the first experiment of this series, core A was a fresh Berea limestone core having a permeability of 704 millidarcies. The core was 5.08 cm in diameter and 15.8 cm in length and had a total pore volume of 73 cubic centimeters. The porosity was 23 percent. The residual oil saturation after water flooding was 25 percent. Core B utilized in Run 7 was a similar size core having pore volume of 65 cubic centimeters and a porosity of 20 percent, but a much lower permeability, only 139 millidarcies. The residual oil saturation of Core B after water flooding was 35 percent. After the cores were flooded to an irreducible water saturation and mounted in parallel, water injection into the cores at a flow rate of 0.9 cc per minute resulted in a receptivity ratio (the ratio of the volume of fluid injected into core A divided by the volume of fluid injected into core B during the same period, when the cores are connected in parallel) of approximately 5.8. During the treatment procedure the receptivity ratio declined to 4.7 and levelled off at 4.0 during the subsequently applied water flood operation. A quantity of petroleum sulfonate solution was then injected, and during the surfactant flood portion of the test, the receptivity declined still further to 2.4. A polymer mobility control buffer was then injected into the system, and the receptivity ratio increased to 4.2 after 0.2 pore volumes of the polymer solution had been injected, and then rose to 5.6 after 1 pore volume of polymer had been injected. It is believed that the increase in receptivity ratio resulting from the fact that the polymer was dissolved in fresh water, which broke the emulsion formed in the course of the treatment procedure described above. Nevertheless, Run 7 clearly illustrates how treatment of two cores in a parallel arrangement, which cores have widely different permeabilities, can reduce the permeability deviation between the two cores and improve the receptivity ratio from 5.8 to 2.4, which is substantially less than half of the original receptivity ratio.

Experiment 8 was performed to verify that in situ emulsification was the mechanism responsible for the improvement in receptivity noted in experiment 7 above. In Run 8, two packs of crushed formation core material were formulated and cleaned. Pack C was saturated with crude oil and pack D was not. Pack C was water flooded to an irreducable oil saturation prior to the treatment. Both packs were treated with 13 pore volume percent of a 30 kilogram/meter.sup.3 solution of dinonylphenolpolyethoxyethyl sulfonate (3.8 moles ethylene oxide per mole surfactant) and finally flooded with field brine. In this experiment, the packs were not flooded in parallel as was the case in Run 7 above but rather were independently flooded after treatment with the emulsifying fluid. The pressure differential across the packs was determined during the course of the treatment and subsequent water flood as an indication of increasing resistance to fluid flow through the packs. The pack which was originally saturated with oil, water flooded and then treated, experienced a four-fold increase in the pressure required to flood with water in a constant rate flood whereas the pack which contained essentially no oil prior to the treatment experienced less than a 50 percent increase in differential pressure during the course of approximately 3 pore volumes of water flood. This clearly illustrates that oil must be present in the treated formation for the injectivity-reducing emulsification phenomena to be achieved, which is necessary for the treatment described herein to accomplish the desired objective of reducing the permeability of the high permeability zone.

Experiment 9 was comparable to experiment 7, except the treating solution contained 13.6 kg/m.sup.3 dodecylbenzene (3.0) polyethoxyethylene sulfonate with 7.6 kg/m.sup.3 3.0 mole ethylene oxide adduct of dodecylphenol and packs were formulated from crushed formation core material. Pack E had 96 millidarcy permeability and Pack F had 20 millidarcy permeability. After the packs were each flooded to irreducable water saturation and mounted in parallel, water injection into the cores at a flow rate of 1.0 cm.sup.3 per minute in a receptivity ratio (Pack E/Pack F) of 4.6. During the treatment procedure, the receptivity ratio decline to 2.8 and levelled off at 1.0 during the subsequently applied water flood operation. A receptivity ratio of 1 was maintained during injection of petroleum sulfonate solution and the ratio fluctuated between 1.6 and 0.6 during a polymer solution injection. Experiment 9 clearly illustrates that the sulfonate-nonionic mixture can be used to reduce the permeability deviation between two packs of significantly different permeabilities.

The data from runs 7, 8 and 9 are given in Table II below.

While the foregoing description involved mixing the surfactants in a single fluid, the process may also comprise injecting two separate fluids, one containing the organic sulfonate and the other containing the nonionic surfactant, in either order, so the mixing occurs in the formation.

Thus we have disclosed and demonstrated how it is possible to treat a formation containing two or more strata of substantially different permeabilities so as to reduce the permeability of the more permeable strata, by injecting an emulsifying fluid thereinto which forms a gross macro-emulsion with residual oil remaining in the flow channels of the flooded portion of a formation after water flooding, thereby reducing the permeability difference between the strata, after which water or other oil displacing fluids may be injected into the formation with substantially improved vertical conformance over that which would be obtained without the permeability adjusting treatment of our invention.

While our invention has been described in terms of a number of illustrative embodiments, it is clearly not so limited since many variations thereof will be apparent to persons skilled in the art of oil recovery without departing from the true spirit and scope of my invention. It is our desire and intention that our invention be limited only by those limitations and restrictions appearing in the claims appended immediately hereinafter below.