Method for foam emplacement in carbon dioxide enhanced recovery

The permeability of higher permeability zones of a subterranean reservoir of heterogeneous permeability is reduced by injecting an aqueous solution of a water soluble surface active agent and then a gas mixture comprising carbon dioxide and a noncondensible, non-hydrocarbon gas insoluble in viscous crude. A stable foam forms in situ useful for blocking escape of solvent fluids into the higher permeability zones of the reservoir during enhanced recovery, typically by carbon dioxide flooding. Preferably, the solution of surface active agent and the gas mixture are injected in alternating slugs to enhance foam formation.

BACKGROUND OF THE INVENTION 
The present invention relates to a process of stimulating oil recovery from 
subterranean reservoirs or formations utilizing injection of gases. It is 
more specifically concerned with improving he efficiency of a secondary 
oil recovery process wherein carbon dioxide is used as a 
viscosity-reducing agent. 
Significant quantities of low gravity crude oil exist in underground 
formations. Because of this, techniques have been developed for 
stimulating production of oil from such reservoirs the high viscosity of 
the oil remaining in such formations makes recovery difficult and 
expensive. A number of methods designed to stimulate recovery of high 
viscosity petroleum have been used, including water flooding, steam 
injection, and gas injection, but none to date has been totally 
satisfactory. Typically, water flooding is inefficient for displacing 
viscous oil due to its high viscosity. Steam injection lowers viscosity, 
but is also unsatisfactory in certain types of formations and requires 
availability of inexpensive fuel and a large supply of clean water. A 
recent variation of the "huff and puff" steam injection method for 
reducing the viscosity of viscous oil is disclosed by West in U.S. Pat. 
No. 3,782,470. In "huff and puff" steam injection, the well is used for 
alternate injection of steam and production of reservoir fluids. In the 
recent variation, immediately following the injection phase of a "huff and 
puff" steam stimulation process, which lowers viscosity of the oil, a 
non-condensing, non-oxidizing gas is injected at ambient temperature. The 
gas displaces the low viscosity oil and thereby improves oil production 
rates, reduces the volume of steam required, and improves the water-oil 
ratio of the well. However, where a multi-component gas is employed, such 
as natural gas, the higher molecular weight hydrocarbons tend to condense 
as the formation cools following steam injections. The condensed 
hydrocarbons have high solubility and even miscibility with most crudes. 
As a result, crude oil may be miscibly displaced from the vicinity of the 
wellbore, resulting in reduced permeability to oil at the well bore. 
Many types of chemical additives have also been evaluated to enhance the 
flow of viscous oil, such as surfactants and soluble oils. A solvent may 
be used to effectively reduce the viscosity of the oil, but unless the 
solvent remains soluble, it will usually be produced preferentially to the 
oils as an immiscible, mobile phase. One of the most successful solvents 
used to stimulate recovery of viscous oils is carbon dioxide. The high 
solution factor of carbon dioxide in crude oil causes the viscosity of the 
carbon dioxide-crude oil solution to be markedly lower than that of the 
crude alone. For illustrative examples of stimulation processes utilizing 
carbon dioxide, reference is made to U.S. Pat. No. 3,442,332, which 
incorporates a list of U.S. patents and publications on the subject at 
column 2, lines 24 through 49. 
In oil recovery, two general types of processes utilizing carbon dioxide, 
typically in a gaseous form, are common. Where direct communication 
between adjacent wells exists or can be established, carbon dioxide may be 
introduced into the formation by one or more injection wells and the 
solution of crude oil and carbon dioxide withdrawn through one or more 
production wells. A second method uses the "huff and puff" technique 
employing the same well for alternate injection and production. This 
latter method is useful where communication between wells has not been 
established. Usually, carbon dioxide is introduced into the well, the 
formation is closed off to allow absorption of the carbon dioxide, and the 
resulting carbon dioxide-crude oil solution expands to fill the void 
spaces of the reservoir. The expanded solution will spontaneously flow or 
can be pumped to the surface once the well is reopened. 
In U.S. Pat. No. 4,390,068, an improvement upon these methods of using 
carbon dioxide to stimulate oil production results from introducing the 
solvent into the formulation as a liquid under a back pressure as low as 
about 300 p.s.i.g. Liquid carbon dioxide can be placed into the formation 
at about twice the mass rate of gas injection and is believed also to be 
more effective than gaseous carbon dioxide for displacing unwanted water 
saturation associated with the residual crude oil. As a result, oil 
recovery increases while water recovery decreases. In addition, 
maintaining the back pressure at no more than 300 p.s.i.g. displaces 
little oil from the wellbore. Resaturating the area of displaced oil 
surrounding the wellbore before production can begin is therefore not 
required. 
It has long been known that recovery of petroleum using carbon dioxide 
could be greatly increased if the carbon dioxide were used in slug form 
and driven through the reservoir by an aqueous drive fluid, such as 
saline, plain, or carbonated water. A process using this technique is 
disclosed by Holm in U.S. Pat. No.3,065,790. However even 
alternate-injection, water-solvent processes using carbon dioxide as a 
solvent succeed in recovering only the petroleum in the reservoir 
contacted by the injected carbon dioxide. Large quantities of uncontacted 
petroleum are by-passed and left in the reservoir because an unfavorable 
mobility relationship between reservoir fluids and injected fluids causes 
the carbon dioxide to channel off into areas of high permeability. In the 
art of oil recovery, the areal sweep efficiency of oil displacement is 
greatest when the viscosity of the displacing fluid is equal to or greater 
than the viscosity of the displaced oil and/or the permeability of the 
displacing fluid is less than or equal to that of the oil. Since carbon 
dioxide is less viscous and more mobile than most crude oils, it is not of 
itself a very efficient oil displacement agent. 
The areal sweep efficiency of carbon-dioxide recovery is increased by 
generating a foam in situ to block the highly permeable features of the 
underground formation. U.S. Pat. No. 3,342,256 to Bernard et al. (which is 
hereby incorporated by reference in its entirety) discloses alternative 
methods for generating foam in situ to prevent channeling of carbon 
dioxide into high permeability channels away from the zone to be treated. 
In one embodiment, a small amount of a surfactant or foaming agent is 
dissolved in the carbon dioxide, which is maintained as a dense fluid or 
liquid at pressures in excess of about 700 p.s.i.g. to ensure solubility. 
A subsequently injected drive medium, such as water, forces the carbon 
dioxide-surfactant mixture through the formation to a production well 
where production continues until the produced fluids exhibit an 
undesirably high water/oil ratio. Production is then terminated, and the 
formation is depressurized to allow dissolved gases to come out of 
solution and form the foam. As the foam expands, it drives additional oil 
towards the producing well. 
In an alternative embodiment, alternate slugs of the foaming agent, usually 
dissolved in an aqueous or hydrocarbon vehicle, and the carbon dioxide are 
introduced into the reservoir. When a hydrocarbon vehicle is employed, the 
liquid light hydrocarbons will flash, producing a gas to generate foam in 
the areas of the reservoir of high pressure gradient, such as is found in 
high permeability channels. If a carbonated water vehicle is used to 
dissolve the foaming agent, upon encountering such areas of reduced 
pressure, the carbon dioxide will come out of solution and generate foam. 
The foam generated in situ by these released gases blocks the highly 
permeable strata and will prevent subsequently injected slugs of carbon 
dioxide from channeling into highly permeable zones. 
Relying upon gases released in low pressure zones to generate the foam, 
however, presents certain disadvantages. When the foaming agent is 
dissolved directly into carbon dioxide or into carbonated water, a large 
portion of the gaseous carbon dioxide released in the low pressure zone 
does not go to generating foam, but is preferentially absorbed into the 
crude. And if the released carbon dioxide migrates into a high pressure 
region, solubility of carbon dioxide is increased and may approach 
miscibility at pressures in excess of about 700 p.s.i.g. These 
difficulties are not encountered if the foaming agent is dissolved in a 
hydrocarbon vehicle, but the cost of liquid hydrocarbons is generally 
prohibitive. Moreover, a hydrocarbon-soluble surface-active agent 
generally foams the oil and restricts its movement through the reservoir. 
The upshot is that increasing the areal sweep efficiency of the recovery 
method by generating foam in situ is much more difficult and expensive in 
the reservoir than laboratory results might otherwise indicate. 
Accordingly, while each of the foregoing methods has met with some success, 
the need exists for further developments in enhanced oil recovery. For 
example, a need exists for an improved method of blocking the highly 
permeable zones of producing formations during carbon dioxide flooding so 
that the solvent is not lost into the highly permeable, relatively 
oil-free zones but contacts a larger cross-section of the oil-bearing 
strata. What is particularly needed is a method for injecting gaseous 
carbon dioxide in conjunction with an aqueous solution of surface active 
agent and a noncondensible, crude-oil insoluble gas. The insoluble, 
noncondensible gas will neither dissolve in the oil in place nor condense 
to a liquid, but remains free to generate foam of the aqueous solution in 
the highly permeable features of the formation. The foam generated in situ 
by this process will block the highly permeable zones and divert 
subsequently injected solvent into the less permeable, oil-containing 
zones, thereby substantially increasing the efficiency of oil recovery. 
SUMMARY OF THE INVENTION 
A method is provided for reducing the permeability zones of a subterranean 
reservoir having heterogeneous permeability and being penetrated by at 
least one well in which there is injected through a well into the 
reservoir (1) an aqueous liquid solution of a water soluble surface active 
agent, and (2) a gas mixture comprising carbon dioxide and a crude 
oil-insoluble, noncondensible, non-hydrocarbon gas, the injection being 
under conditions such that the gas mixture maintains a density between 
0.01 and 0.42 grams per centimeter in the reservoir. Then a stable foam is 
allowed to form in the higher permeability zones of the reservoir. As a 
result, subsequently injected carbon dioxide flooding gas is diverted into 
the less permeable zones of the formation and oil recovery is thereby 
enhanced. 
DETAILED DESCRIPTION OF THE INVENTION 
The present invention provides a method for increasing the areal sweep 
efficiency of carbon dioxide flooding for recovery of viscous oil, 
especially gaseous carbon dioxide flooding, from subterranean formations. 
During the course of carbon dioxide flooding, breakthrough of carbon 
dioxide at a producing well signals the need for plugging highly permeable 
zones of the formation. The foam emplacement process of this invention, 
therefore, is typically instituted midway in a carbon dioxide flooding 
regime, especially a flood utilizing carbon dioxide in a gaseous state. To 
maintain carbon dioxide as a gas, injection pressures are adjusted so that 
the density of the carbon dioxide remains below the critical density of 
0.42 grams per centimeter, typically between 0.01 and 0.42 grams per 
centimeter. 
In accordance with the present invention, an aqueous, liquid solution of a 
surfactant or foaming agent is injected into a well penetrating an 
oil-bearing formation, especially a formation containing viscous oil, such 
as a crude having an API gravity of below about 22.degree. and viscosity 
greater than about 200 centipoise at 60.degree. F. Following injection of 
the liquid solution, a noncondensible, crude oil-insoluble non-hydrocarbon 
gas is added to gaseous carbon dioxide, and the resulting gaseous mixture 
is injected into the formation. These recovery fluids are driven through 
the reservoir by a subsequently injected aqueous flooding medium which 
displaces them towards at least one production or output well completed in 
the same reservoir. 
As the fluids pass through the reservoir, the noncondensible, crude-oil 
insoluble, non-hydrocarbon gas and the solution of surfactant or foaming 
agent interact within the reservoir to form a stable foam in those areas 
of the formation where the least resistance is presented to the passage of 
fluids. These locations of high permeability will contain little crude oil 
to depress foam formation, either because little oil is present due to 
previous treatment or because the carbon dioxide introduced in accordance 
with this invention dissolves readily in the oil in place and the 
decreased viscosity oil passes from the zones of high permeability. By 
contrast, in the less permeable zones of the formation, the oil in place 
depresses foam formation. As a result, foam preferentially forms in and 
blocks passage of fluids through the highly permeable, relatively oil-free 
features of the reservoir, including strata, cracks and fissures. 
Consequently, the foam diverts carbon dioxide, which is highly soluble in 
crude oil, into the less permeable, oil-containing zones of the reservoir 
where it is absorbed by the crude oil. As the carbon dioxide is absorbed, 
the viscosity of the carbon dioxide-crude oil solution decreases markedly. 
As a result, a subsequently injected drive fluid, typically aqueous, can 
readily move the solution towards a producing well where petroleum and 
other fluids are recovered by conventional means. 
The injection and production wells can be arranged in any convenient 
pattern designed to achieve maximum contact of the oil-bearing zones by 
the advancing flood front--such as the conventional "five-spot" pattern of 
a central producing well surrounded by four somewhat symetrically located 
injection wells. Another conventional flooding pattern that can be 
employed in the practice of this invention is the "line-drive" pattern in 
which the injection wells are arranged in a line so that the injected 
flooding medium advances through the formation to displace oil toward one 
or more spaced production wells arranged in a line substantially parallel 
to the line of injection wells. 
The non-condensible, crude oil-insoluble non-hydrocarbon gas used in the 
process of this invention usually comprises a non-hydrocarbon gas that is 
substantially both noncondensible and insoluble in crude oil at typical 
reservoir conditions of between about 90.degree. and 180.degree. F. and 
between about 700 and 2500 p.s.i.g. of pressure. Typically, the 
noncondensible, crude oil-insoluble, non-hydrocarbon gas is selected from 
the group consisting of air, nitrogen, and argon, or mixtures thereof, and 
preferably is nitrogen. The proportion of non-condensible, crude, 
oil-insoluble, non-hydrocarbon gas in the gas mixture is typically between 
about 5 and 20 volume percent, and preferably between about 10 and 15 
volume percent. 
Surface active agents suitable for use in the practice of this invention 
are water soluble, and should have sufficient foaming ability and 
stability to form a stable foam in the highly permeable zones of a 
reservoir, thereby preventing carbon dioxide from channeling through 
highly permeable fissures, cracks or strata. More particularly, the term 
"surface active agent" as used in this specification and the appended 
claims denotes a surfactant or foaming agent having a tendency tc generate 
foam, or to promote the generation of foam, in an underground reservoir or 
formation in the presence of a liquid and a gas. Such agents are known to 
alter the interface between liquid and gas phases or between two 
immiscible phases. 
Non-limiting examples of surface active agents useful in this invention are 
those which, when incorporated in an aqueous liquid such as water or 
seawater in an amount not in excess of 5 percent by weight, meet the 
following described test. The surface active agent is dissolved in an 
aqueous test medium and 500 milliliters of the solution is placed in a 
graduated cylinder to form a column having a height of 50 centimeters. 
Natural gas is passed into the bottom of the column through a fritted 
glass disc at substantially atmospheric pressure so that the gas bubbles 
through the column of liquid and passes out of the top of the cylinder. 
The gas rate is maintained at about 500 milliliters of gas per minute per 
square inch of column cross-sectional area, and the flow of gas is 
continued for a period of 15 minutes. A column of foam will then be found 
to exist at the top of the column of liquid hydrocarbon or water. The 
surface active agent, generally a foaming agent or surfactant, should 
desirably, but not necessarily, be capable of producing a column of foam 
not less than 180 centimeters in height under the conditions 
aforedescribed. 
With some surface-active agents, the aforedescribed test requirements will 
be met by incorporating quantities of surfactant or foaming agent far less 
than 2 percent by weight in the aqueous test medium. Thus, where it is 
found that 1 percent by weight of a given surface active agent is capable 
of meeting the requirements of the aforedefined test, it is preferred for 
reasons of economy that this amount be used. But typically the 
concentration of surface-active agent in the aqueous solution is between 
about 0.1 and 2.0 weight percent active surface-active agent. The use of 
excessive quantities of surfactant or foaming agents should be avoided not 
only for reasons of economy but also to prevent the production of an 
excessively thick and viscous foam bank, which might require the use of 
costly, high injection pressures. 
The use of various commercial high-foaming surfactants or foaming agents is 
contemplated. An example of a water-soluble surfactant or foaming agent 
preferred for promoting the formation of foam in oil-bearing reservoirs is 
alkyl polyethylene oxide sulfate, known commercially under the trade name 
"Alipal CD 128" and marketed by General Aniline and Film Corporation. In 
the preferred embodiment, the water-soluble surface active agent is 
selected from the group consisting of dioctyl sodium sulfosuccinate, 
modified ether alcohol sulfate sodium salts, sodium lauryl sulfate, 
dioctyl sodium sulfosuccinate, and alkyl polyethylene oxide sulfates. 
Other examples of suitable foam-producing agents include dimethyl 
didodecenyl ammonium chloride, methyl trioctenyl ammonium iodide, 
trimethyl decenyl ammonium chloride, dibutyl dihexadecenyl ammonium 
chloride, and water-soluble salts of esters of C.sub.3 -C.sub.6 sulfur 
dicarboxylic acids having the general formula 
##STR1## 
where M is a substituent forming a water-soluble salt, such as alkali 
metals, ammonium, and substituted ammonium, R is a C.sub.3 -C.sub.16 alkyl 
substituent, and n is an integer from 1-4, e.g., monosodium dioctyl 
sulfosuccinate, ammonium dilaurylsulfosuccinate, monosodium dibutyl 
sebacate, monosodium diamyl sulfoadipate, and others. Still other suitable 
foam-producing agents include water-soluble perfluoroalkanoic acids and 
salts having 3-24 carbon atoms per molecule, e.g., perfluorooctanoic acid, 
perfluoropropanoic acid, and perfluorononanoic acid. Other surfactive 
agents which may be used in the practice of this invention are modified 
fatty alkylolamides, polyoxyethylene alkyl aryl ethers, sodium lauryl 
sulfate, and octylphenoxyethanols as well as the following commercial 
products: 
______________________________________ 
Trade Name 
Chemical Name 
______________________________________ 
Aerosol C-61 
Ethanolated alkyl guanidine-amine complex 
Aerosol OS 
Isopropylpaphthalene sodium sulfonate 
Aerosol OT 
Dioctyl sodium sulfosuccinate 
Duponol EP 
Alkyl alkylolamine sulfate 
Duponol RA 
Modified ether alcohol sulfate sodium salt 
Duponol WAQ 
Sodium lauryl sulfate 
Ethomid HT-15 
Condensation of hydrogenated tallow amide and 
ethylene oxide 
Miranol HM 
Ethylene cyclomido 1-lauryl, 2-hydroxy 
Concentrate 
ethylene Na alcoholate, methylene Na 
carboxylate 
Miranol MM 
Same as Miranol HM except myristyl group is 
substituted for lauryl group 
Nacconal 4OF 
Alkyl arylsulfonate 
Petrowet R 
Sodium hydrocarbon sulfonate 
Pluronic L44 
Condensation product propylene oxide with 
ethylene oxide 
Sorbit AC Sodium alkyl napthalene sulfonate 
Sulfanole FAF 
Sodium salt of fatty alcohols, sulfated. 
Triton X-100 
Octylphenoxy polyethoxy ethanol. 
Span 20 Sorbitan Monolaurate 
Span 40 Sorbitan Monopalmitate. 
Span 85 Sorbitan Trioleate 
Tween 65 Polyoxyethylene Sorbitan Tristearate 
Tween 81 Polyoxyethylene Sorbitan Monooleate 
Triton GR-7 
Dioctyl Sodium Sulfosuccinate 
Triton B-1956 
Modified Phthalic Glycerol Alkyl Resin 
Triton X-45 
Octylphenoxy polyethoxy ethanol 
Triton X-100 
Acetylphenoxy polyethoxy ethanol 
______________________________________ 
Generally, during the course of a carbon dioxide flooding regime, treatment 
of the reservoir by foam emplacement does not begin until the breakthrough 
of carbon dioxide gas from the gas flooding mixture at the producing well 
signals escape of the solvent gas into high permeability zones. Therefore, 
foam emplacement typically commences after a gas flooding mixture 
comprising carbon dioxide has been injected into the reservoir until the 
breakthrough of carbon dioxide is detected at the producing well. Then the 
foam emplacement regime is instituted, typically beginning with injection 
of the surface active solution and ending with injection of the gas 
mixture comprising carbon dioxide and a crude oil-insoluble, 
noncondensible, non-hydrocarbon gas. During foam emplacement, alternate 
injection of slugs of the surface active solution and of the gas mixture 
can be repeated for as many cycles as is desired to block the highly 
permeable zones. After foam emplacement, injection of the gas flooding 
mixture is typically resumed. 
To determine effectiveness of the foam emplacement procedure or the point 
at which the highly permeable zones have been effectively plugged, 
comparative tests such as tests to determine injectivity to gas and the 
permeability of the formation, or of any selected zones of the formation, 
can be conducted. Preferably test results obtained before foam emplacement 
is undertaken are compared with results obtained at convenient intervals 
during foam emplacement to determine the progress and result of the foam 
emplacement regime. 
During foam emplacement, dilution of the solvent gas with an insoluble gas 
will result in decreased rather than increased oil recovery if the 
proportion of insoluble gas becomes too large. What proportion of 
insoluble gas will be effective in the particular reservoir to be treated 
will depend in part upon pressure and temperature in the reservoir and 
what proportion of the total pore volume of the reservoir is occupied by 
highly permeable zones and features. It has been found in the practice of 
this invention that when a solution of surfactant or foaming agent is 
injected in conjunction with the mixture of carbon dioxide and insoluble 
gases, generally dilution of the solvent carbon dioxide gas with up to 20 
volume percent of crude oil-insoluble, noncondensible, non-hydrocarbon gas 
is effective for increasing oil recovery over that achieved by injection 
of the solvent gas alone. 
The amount of the gas mixture injected into the subterranean formation will 
also vary for different formations, and will depend upon total reservoir 
pore volume, crude oil pore volume, formation pressure and temperature and 
other unique formation characteristics. Throughout this description and 
the appended claims the term "effective pore volume" means that portion of 
the reservoir expected to be contacted by the carbon dioxide-containing 
gas mixture injected. 
To achieve the best success in carrying out the process of this invention, 
typically a total of between about 0.01 and 0.2, and preferably between 
about 0.01 and 0.05, effective pore volume of the foam emplacement gas 
mixture containing carbon dioxide and a noncondensible, crude 
oil-insoluble, non-hydrocarbon gas is injected through an input or 
injection well into the formation. The carbon dioxide in the gas mixture 
is injected as a gas or dense fluid under conditions such that in the 
reservoir the carbon dioxide is gaseous, the gas mixture having a density 
at or below the critical density for carbon dioxide of 0.42 grams per 
cubic centimeter. 
The amount of surfactant or foaming agent used will be determined according 
to the requirements of the reservoir being treated, but generally it has 
been found that for successful foam emplacement the solution of surface 
active agent should represent between about 0.1 and 10 volume percent of 
the total injected fluids, exclusive of the drive fluid. Or, expressed in 
terms of the effective pore volume of the reservoir to be treated, between 
about 0.01 and 0.2 effective pore volume of a 0.1 to 2.0 weight percent 
active solution of surfactant or foaming agent will be effective. More 
preferably, between about 0.01 and 0.05 effective pore volume of a 0.5 to 
1.0 weight percent active solution of surfactant or foaming agent is 
injected followed by injection of between about 0.01 and 0.05 effective 
pore volume of the foam emplacement gas mixture. Then, injection of the 
remaining amount of between about 0.1 to 1.0 effective pore volume of the 
carbon dioxide-containing gas flooding mixture is resumed. Alternatively 
injection of a gas flooding mixture comprising carbon dioxide is resumed 
until one effective pore volume of carbon dioxide has been introduced into 
the reservoir. 
In an alternative and preferred embodiment, during foam emplacement the gas 
mixture and solution of surface active agent are injected alternately in 
small slugs to facilitate contact between the insoluble gas, the foaming 
agent, and reservoir fluids. More particularly, at the point during a 
typical carbon dioxide flood that breakthrough of carbon dioxide gas 
occurs at a producing well, foam emplacement typically is started. 
Alternately, slugs of the surface active solution and of the 
aforedescribed foam emplacement gas mixture are injected. The slugs are 
typically as small in size as is economically feasible while achieving the 
goal of maximum contact between the insoluble gas and the foaming agent 
and the size of the slugs of gas mixture are up to 10 times the size of 
the surfactant slugs. Preferably the slugs of the solution of surface 
active agent are between about 0.001 and 0.01 effective pore volume in 
size, while the foam emplacement slugs of the gas mixture are preferably 
between about 0.002 and 0.1 effective pore volume in size. 
This regime of alternately injected slugs of foam emplacement gas mixture 
and surfactant solution usually continues until sufficient foam has been 
generated in the reservoir to block the highly permeable zones and 
features. Typically between about 4 and 10 cycles of alternation are 
required. Tests to determine gas injectivity and permeability are usually 
conducted to determine when the highly permeable zones have been 
satisfactorily plugged. In the preferred embodiment, a total of between 
about 5 and 7 cycles of gas flooding mixture and surfactant solution is 
injected, followed by continuous injection of the gas mixture until a 
cumulative total of about one effective pore volume of carbon dioxide has 
been injected. 
To propel the bank of chemical additives through the reservoir, a drive 
medium having a favorable mobility ratio with respect to the mixture of 
fluids to be moved through the reservoir is employed. The drive medium 
typically comprises fresh, saline or carbonated water, or any mixture of 
these, and preferably contains a thickening agent to improve the mobility 
ratio between the drive fluid and the reservoir fluids. Sufficient drive 
medium is employed to push the carbon dioxide through the reservoir from 
the injection well to a production well. Injection of the drive fluid is 
usually continued until the liquids produced from the production well have 
a high water/oil ratio, at which time injection of drive fluid is commonly 
terminated. Subsequent to terminating injection of the drive fluid, the 
formation can be depressurized to allow formation of additional foam by 
any gases coming out of solution or to drive additional oil towards the 
production well.

Specific embodiments of the practice of this invention are illustrated by 
the following examples. 
EXAMPLES 1 to 4 
Comparative tests are run to determine the effect of adding a crude 
oil-insoluble, noncondensible, non-hydrocarbon gas to the gaseous carbon 
dioxide used in a carbon dioxide foam flood of a Berea sandstone core. 
Four flooding sequences are conducted at a temperature of 127.degree. F. 
The first test uses continuous injection of carbon dioxide alone, and the 
second test employs alternately injected slugs of carbon dioxide and 
water. In the second pair of tests, a method employing continuous 
injection of a gas mixture of carbon dioxide and nitrogen followed by 
injection of water is compared with a method of alternate injection of 
slugs of the carbon dioxide-nitrogen gas mixture and an aqueous surfactant 
solution. 
To prepare for the flooding tests, a 11/2 inch by 11/2 inch by 4 feet Berea 
sandstone core is evacuated of air by pulling a vacuum on the outlet and 
closing the inlet. After 8 hours, the inlet is opened and the core is 
flooded by seawater. The original pore volume is measured and the 
permeability of the core to seawater are then measured using an ISCO 
positive displacement pump. To saturate the core with crude oil, 
Wilmington heavy crude oil having a viscosity of 14.degree. API or 450 
centipoise is injected into the core while sufficient seawater is 
displaced therefrom to saturate the core to 0.77 of the original pore 
volume. Then, to displace from the core the oil that would be recovered 
during primary water flooding, one pore volume of seawater is injected 
while sufficient crude oil is displaced to leave between 0.4 and 0.6 pore 
volume of residual oil saturation. 
In Test 1, carbon dioxide at ambient temperature and a pressure of 950 
p.s.i.g. is continuously injected into a Berea core at 127.degree. F. 
prepared by the foregoing procedure using a pressurized cylinder of carbon 
dioxide. Following injection of 120 liters of carbon dioxide, a seawater 
drive of one pore volume is injected to displace the bank of carbon 
dioxide through the core. The displaced fluids are collected and measured 
and the percent recovery of the residual oil is calculated. 
In test 2, slugs of carbon dioxide are alternately injected with slugs of 
seawater into a Berea core prepared as in Test 1. Slugs of carbon dioxide 
of 0.02 pore volume in size are injected at a pressure of 950 p.s.i.g. 
alternately with 0.05 pore volume slugs of seawater until a total of 5 
slugs of each has been injected. Then carbon dioxide alone is continuously 
injected until a total of 120 liters of carbon dioxide has been injected. 
To displace fluids from the core, one pore volume of seawater drive is 
injected while the displaced fluids are collected and measured. The 
percent recovery of residual oil is calculated. 
In Test 3, a gas mixture containing 11 volume percent of nitrogen and 89 
volume percent of carbon dioxide is injected into a Berea core prepared as 
described in Test 1. The gas mixture is continuously injected at ambient 
temperature and a pressure of 950 p.s.i.g. using a pressurized cylinder of 
carbon dioxide until 120 liters have been injected. Then a seawater drive 
of one pore volume size is injected to push the bank of gas mixture 
through the core. Displaced fluids are collected and measured, and the 
percent recovery of the residual oil is calculated. 
To determine the effect upon oil recovery of an alternately injected foam 
emplacement carbon-dioxide flood, in Test 4, slugs of a foam-generating 
surfactant solution are alternately injected with slugs of the carbon 
dioxide-nitrogen gas mixture used in Test 3. More particularly, a 0.6 
volume percent active solution of Alipal CD 128 surfactant marketed by the 
GAF Corporation is prepared using seawater as the diluent. The gas mixture 
used in Test 2 is injected using the methods of Test 2 above until the 
breakthrough of gas at the producing end of the core. Following gas 
breakthrough, a 0.05 pore volume slug of the surfactant solution is 
followed by a 0.02 pore volume slug of the gas mixture. Then continuous 
injection of the carbon dioxide-insoluble gas mixture is resumed until a 
total of 120 liters in all of the gas mixture has been injected. Finally, 
to displace fluids from the core, one pore volume of seawater drive is 
injected. Displaced fluids are collected and measured, and the percent 
recovery of the residual oil is calculated. 
TABLE I 
______________________________________ 
Results of Carbon Dioxide Flooding Tests 
Oil CO.sub.2 utilization 
Test Recovery (MCF of CO.sub.2 /bbl 
No. Flooding regime (% OIP)* of oil recovery) 
______________________________________ 
1 CO.sub.2 slug followed 
35 6 
by water 
2 CO.sub.2 slugs alternately 
35 3 
injected with water slugs 
3 CO.sub.2 slug containing nitro- 
25 5 
gen followed by water 
4 CO.sub.2 slug containing nitro- 
45 1 
gen alternately injected 
65 6 
with slugs of foaming 
solution 
______________________________________ 
*OIP means residual oil in place after primary recovery by water flooding 
 
The results of Tests 1 to 4 are summarized in Table I. As can be seen by 
comparison of the results, the alternate injection foam emplacement method 
of Test 4 in accordance with this invention results in a significantly 
higher percent recovery of oil in place than any of the other methods 
used. Moreover, with this method the greatest recovery per barrel of 
carbon dioxide injected occurs early in the flooding regime. Comparison of 
results from Tests 1 and 4 shows that, when 45 percent of the residual oil 
has been recovered using alternate injection foam emplacement, the carbon 
dioxide requirement is six times less per barrel recovered than for 
continuous carbon dioxide flooding after 35 percent recovery of residual 
oil. By continuing the alternate injection foam emplacement regime in test 
4, as much as 65 percent of the oil can be recovered at no greater expense 
of carbon dioxide per barrel than is needed for percent recovery in Test 1 
using continuous carbon dioxide flooding. 
The results of Test 4 above indicate that the most economical and efficient 
recovery using the method of this invention occurs very early in the 
flooding regime when between 10 and 20 percent of the total amount of the 
carbon dioxide used in the test has been injected. Continuing the flooding 
regime results in higher recovery than in any other method used, but the 
rate of recovery increasingly diminishes. One skilled in the art will 
recognize that this pattern of high initial cutput and continuously 
decreasing rate of recovery is common to other flooding techniques that 
employ alternate injection of carbon dioxide and fluids. For instance, 
alternate injection of small slugs of carbon dioxide and water in Test 2 
achieves the same percent recovery when only half the carbon dioxide has 
been injected as is recovered by the full regime of continuous carbon 
dioxide flooding in Test 1. Despite overall similarity of the recovery 
patterns exhibited in Tests 2 and 4, however, the alternate injection foam 
emplacement process exhibits significantly improved overall recovery as 
compared with alternate injection of carbon dioxide and water at markedly 
less consumption of carbon dioxide per barrel of oil recovered. This 
marked increase in overall recovery is attributed to increased efficiency 
of the areal sweep, which ensures that the carbon dioxide contacts a high 
percentage of the residual oil in place. 
Merely diluting a continuously injected carbon dioxide flood with 11 volume 
percent of insoluble gas, as in Test 3, results in 10 percent less oil 
recovery than if undiluted carbon dioxide is employed, as can be seen by 
comparing the results of Tests 1 and 3. However, alternate injection of 
the same diluted carbon dioxide gas mixture with a solution containing 
surfactant in accordance with the practice of this invention unexpectedly 
almost doubles the yield, and the data clearly indicate that an increase 
in yields by a factor of 0.75 over those obtained with continuous 
injection of carbon dioxide gas are achievable. Due to the foam generated 
in situ blocking escape of the solvent gas into the highly permeable 
channels of the core, the solvent gas more efficiently contacts and 
reduces the viscosity of the residual oil in place so that the overall 
recovery is increased by a factor of 0.86 over that achieved by continuous 
injection of carbon dioxide above. 
TEST 5 
A Field Test is conducted to determine the effect upon permeability of foam 
emplacement into highly permeable zones. Location of the site used for 
Field Test 5 is Block V in the Wilmington Field, Calif. The depth of the 
reservoir, FZ 214 Rd, is about 2300 feet and its temperature and pressure 
are about 130.degree. F. and 900 to 1100 p.s.i.g., respectively. The 
permeability to air of the producing formations is between about 100 and 
1000 millidarcies, and the oil in place is found to have a gravity of 
about 13.degree. to 14.degree. API. 
The reservoir area covers approximately 320 surface acres and is faulted on 
three sides, the fourth side being embanked by water injection wells to 
prevent escape of the carbon dioxide and other enhanced recovery fluids. 
The area includes 8 injection wells and 47 producing wells. Prior to foam 
emplacement, of the eight injection wells four inject carbon dioxide at 
pressures well below those required for miscible displacement, up to about 
1440 p.s.i.g., and four inject water at pressures of 1600 or 1800 p.s.i.g. 
Once a predetermined size of slug has been administered, the wells switch 
injection fluids; those wells that had been injecting carbon dioxide 
switch to water injection, and those that had been injecting water switch 
to carbon dioxide. 
This method, known as an immiscible water-alternating gas, or WAG, method 
is selected to help control injectivity problems in an unconsolidated sand 
formation. Injection history for the well to be treated, FZ 214 Rd of 
Block V, Wilmington field, shows that almost all the injected fluids have 
entered upper wet sand Zone S, while Zone T, a lower zone of comparatively 
lower permeability, has taken no fluid during the WAG injection regime. 
To prepare for foam emplacement, the zone of lowest permeability, which 
requires no further reduction in permeability, is protected by gravel 
packing. Once the foam emplacement regime has been completed, the gravel 
is recirculated out of the well so that subsequently injected carbon 
dioxide will be free to enter this oil-bearing layer. 
It is determined that success of foam emplacement will be measured by (1) 
the decrease of gas and liquid entering upper Zone S and the corresponding 
increase into adjacent lower sand Zone T; (2) the decrease in injectivity 
of gas into the well; (3) the reduced amount of gas produced from 
surrounding wells; and (4) the length of time the beneficial changes in 
flow are maintained. During the alternate injection foam emplacement 
regime, the water wells inject a solution of Alipal CD 128 foaming agent 
having a density of 370 pounds per barrel and a concentration of 1000 
barrels of water and 1 barrel of Alipal CD 128 foaming agent. The gas 
mixture injected during foam emplacement contains gaseous carbon dioxide, 
between about 15 and 8 volume percent of nitrogen, and a small amount of 
methane. This mixture is obtained by recovering gas produced during WAG 
injection, which begins as substantially pure carbon dioxide, but becomes 
sufficiently diluted with noncondensible, crude oil-insoluble, 
non-hydrocarbon gas during passage through the reservoir to be recycled as 
the gas mixture during foam emplacement. In Table II, the alternate 
injection sequence for the foam emplacement regime is summarized. 
TABLE II 
______________________________________ 
Injection Sequence for Foam Emplacement Regime 
Day Injection Fluid 
______________________________________ 
1 2 bbls. of X-cide XC 137 in 
5000 bbls. of water 
2 50 bbls. of Alipal CD 128 
in 5000 bbls. of water 
3 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
4 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
5 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
6 25 bbls. of Alipal CD 128 in 
2500 bbls. of water 
7 12 MM SCF of CO.sub.2 --N.sub.2 mixture 
8 33 bbls. of Alipal CD 128 
in 3300 bbls. of water 
9 4 MM SCF CO.sub.2 --N.sub.2 mixture 
10 4 MM SCF CO.sub.2 --N.sub.2 mixture 
11 Inject maximum amount of 
CO.sub.2 --N.sub.2 mixture at 1330 
p.s.i.g. and run injection 
profile survey. 
Run bottomhole pressure falloff 
tests with injection water 
20 25 bbls. of Alipal 128 in 2500 
bbls. of water 
21 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
22 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
23 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
24 25 bbls. of Alipal 128 in 2500 bbls. 
of water 
25 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
26 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
27 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
28 25 bbls. of Alipal CD 128 in 
2500 bbls. of water 
29 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
30 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
31 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
32 25 bbls. of Alipal 128 in 
2500 bbls. of water 
33 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
34 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
35 4 MM SCF of CO.sub.2 --N.sub.2 mixture 
Run CO.sub.2 injection profile survey. 
Run bottomhole pressure falloff tests with 
injection water. 
______________________________________ 
During foam emplacement, the solution of Alipal CD 128 and the 
nitrogen-carbon dioxide gas mixture are injected alternately according to 
the sequence summarized in Table II. Gas pressure is maintained below 
about 1440 p.s.i.g. so that the density of the gas mixture in the 
reservoir remains at or below 0.42 grams per cubic centimeter throughout. 
It will be noted that a gas injection profile survey and a bottomhole 
pressure falloff test using injection water are conducted by techniques 
well known in the art after the 11th and 35th days to measure the effect 
of the foam emplacement process during its progress. Results of the 
pressure fall off tests and the gas injection profile tests are summarized 
in Tables III and IV. 
TABLE III 
______________________________________ 
Pressure Falloff Test Results 
Intermediate 
After Foam 
Pre Foam 
After 11th day 
After 35th day 
______________________________________ 
Permeability(md) 
100.7 32.4 14.2 
Skin factor 
10.1 1.5 -0.9 
Radius of 1406 587 396 
investigation (ft) 
______________________________________ 
TABLE IV 
______________________________________ 
Carbon Dioxide-Nitrogen Injection Survey Tests 
After Foam 
Pre Intermediate 
After After 
Foam After 11th day 
35th day 46th day 
______________________________________ 
Injection Rate 
13,125 7,725 4,610 3,190 
(MCD/day) 
Injection Pressure 
1,340 1,300 1,320 1,330 
(p.s.i.g.) 
Percent Injected 
by Sand Zone 
S 98.7 82 56.7 70.6 
T 1.3 18 43.3 29.2 
______________________________________ 
These tests indicate that as the result of foam emplacement, permeability 
is reduced by more than 85 millidarcies while the rate of gas injection 
decreases by greater than 75 percent. The beneficial effects of the foam 
emplacement are still appparent after 46 days, so it can be predicted that 
the treatment will produce long-term improvements in injectivity and 
injection rates. In addition, after 46 days the excessive flow of recovery 
fluids into Zone S, the wet sand zone of high permeability, is reduced by 
28 percent while flow into adjacent sand Zone T is increased to about 30 
percent. 
Although the invention has been described in conjunction with embodiments 
thereof, including a preferred embodiment, it is apparent that the 
invention is capable of many modifications, alternatives and variations. 
Accordingly, it is intended to embrace within the invention all such 
modifications, alternatives and variations as may fall within the spirit 
and scope of the appended claims.