High conformance oil recovery process

The conformance of an aqueous flooding oil recovery process, including steam, hot water or surfactant or other chemicalized water flood process, in a formation containing at least two zones of different permeability, the permeability of one zone being at least 50 percent greater than the permeability of the other zone, is improved by flooding until the higher permeability zone has been depleted, after which a fluid is injected into the depleted, high permeability zone, said fluid having relatively low viscosity at the time of injection and containing a mixture of at least two surface active agents which promotes the formation of a coarse emulsion in the flow channels of the formation which reduces the permeability of the high permeability zone. Since the viscosity of the fluid injected into the previously water flooded, high permeability zone is no greater than water, it is injected easily into the zone and moves through substantially the same flow channels as water would move in the formation. After the permeability of the first zone has been reduced substantially, flooding may then be accomplished in the second zone which was originally not invaded by the injected oil displacing fluid since its permeability was substantially less than the permeability of the first zone. The surface active agents are tailored to exhibit optimum emulsion formation properties with the particular aqueous fluid present in the flow channels of the formation to be treated.

FIELD OF THE INVENTION 
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. 
BACKGROUND OF THE INVENTION 
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. 
DESCRIPTION OF THE PRIOR ART 
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. 
SUMMARY OF THE INVENTION 
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.

DESCRIPTION OF THE PREFERRED EMBODIMENTS 
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 
EQU R--SO.sub.3 M 
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: 
EQU R'(OR").sub.n OH 
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. 
TABLE I 
__________________________________________________________________________ 
EMULSIFICATION TESTS 
PPM Total 
Concentration of Emulsification 
Run 
Salinity 
Surfactant % of Total Volume 
__________________________________________________________________________ 
1 .about.0 
1.9% petroleum sulfonate.sup.1 
24 
same oil visible 
2 .about.0 
1.9% petroleum sulfonate.sup.1 + 
35% creamy appearing 
1.0% 3.15 mole EO.sup.2 adduct of nonyl phenol 
no oil visible in aqueous layers 
3 .about.0 
1.9% petroleum sulfonate.sup.1 + 
7% emulsion 
1.0% 12 mole EO.sup.2 adduct of nonyl phenol 
17% unemulsified oil 
aqueous layer appeared oil-free 
4 12,000 
1.9% petroleum sulfonate.sup.1 
oil layer 22% - same emulsion 
in oil layer 
No emulsion in aqueous layer 
5 12,000 
1.9% petroleum sulfonate.sup.1 + 
--* 
1.0% 3.15 mole EO.sup.2 adduct of nonyl phenol 
6 12,000 
1.9% petroleum sulfonate.sup.1 + 
--** 
1.0% 12.0 mole EO.sup.2 adduct of nonyl phenol 
__________________________________________________________________________ 
.sup.1 Witco 1080.RTM. petroleum sulfonate 
.sup.2 EO = ethylene oxide 
*test incomplete due to stability problem 
**phase separation occurred at room temperature 
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. 
TABLE II 
__________________________________________________________________________ 
Receptivity 
Ratios 
Core or 
Initial Permeability 
Volume of 
Material 
Prior To 
After .DELTA.P After Treatment 
Run 
Pack to Water Treating Fluid 
Used Treatment 
Treatment 
.DELTA.P Before 
__________________________________________________________________________ 
Treatment 
7 A 704 .14 (2) 5.8 4.0.sup.(1) 
-- 
B 139 .03 
8 C 75 0.13 (2) -- -- 4.0 
D 65 0.17 -- -- 1.4 
9 E 96 (3) 4.6 1.0 -- 
F 20 
__________________________________________________________________________ 
.sup.(1) Reduced to 2.4 on injecting petroleum sulfonate oil displacing 
fluid 
.sup.(2) Dinonylphenol (3.8) polyethoxyethyl sulfonate 
.sup.(30) Dodecylphenol (3.0) polyethoxyethyl sulfonate + dodecylphenol 
(3.0) polyethoxylate 
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.