CA1218227A - Sulfonate dimer surfactant additives for steam foam drives and a process of stimulating hydrocarbon recovery from a subterranean formation - Google Patents
Sulfonate dimer surfactant additives for steam foam drives and a process of stimulating hydrocarbon recovery from a subterranean formationInfo
- Publication number
- CA1218227A CA1218227A CA000450302A CA450302A CA1218227A CA 1218227 A CA1218227 A CA 1218227A CA 000450302 A CA000450302 A CA 000450302A CA 450302 A CA450302 A CA 450302A CA 1218227 A CA1218227 A CA 1218227A
- Authority
- CA
- Canada
- Prior art keywords
- alpha
- steam
- process according
- olefin sulfonate
- dimer
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
- C09K8/592—Compositions used in combination with generated heat, e.g. by steam injection
Abstract
ABSTRACT OF THE DISCLOSURE
An improved steam injection process for recovering hydrocarbons from a subterranean formation, The process includes the use of alpha-olefin sulfonate dimer surfactants in the steam to form a foam-steam drive medium which is injected into the formation through at least one injection well to enhance the recovery of hydrocarbons from at least one production well.
An improved steam injection process for recovering hydrocarbons from a subterranean formation, The process includes the use of alpha-olefin sulfonate dimer surfactants in the steam to form a foam-steam drive medium which is injected into the formation through at least one injection well to enhance the recovery of hydrocarbons from at least one production well.
Description
~Z~8~2Z~7 SULFONATE DIMER SURFACTANT ADDITIVES
FOR STEAM FOAM DRIVES AND A PROCESS OF
FROM A SUBTERRANEAN FORMATION
-BACKGROUND OF THE_I~VENTION
This invention relates to enhanced oil recovery.
More specifically, this invention relates to a process of enhancing oil recovery with steam injection~
Many hydrocarbons are too thick to be recovered from subterranean petroleum containing formations without assistance. These hydrocarbons are either the residual oil left in a depleted reservoir or virgin heavy hydrocarbons. These heavy hydrocarbons can be recovered through the use of steam drives which heat the formation, lower the viscosity of the hydrocarbons, and enhance the flow of the hydrocarbons toward a production well.
However, after initial steam injection breakthrough at the production well, the steam injection preferentially follows the path of the breakthrough. Thus, the total amount of the formation that is swept by the steam injection is limited. Commercial surfactants, such as Thermophoam BW-D~, a product of the Far Best Company, and Stepanlo 30~, a product of the Stepan Company, hava been injected along with steam to create a steam-foam flood.
The surfactants form a foam that inhibits the flow of the steam into that portion of the formation containing only residual oil saturation. Residual oil saturation is defined as the immobile oil remaining in that portion of the reservoir swept by steam. This forces the steam to drive the recoverable hydrocarbons from the less depleted portions oE the reservoir toward the production well(s).
To maximize the extraction of hydrocarbons from a formation, it would be highly desirable to have superior foaming surfactants which inhibit the flow of steam in a steam zone containing only residual oil saturation. Fur-thermore, it would be desirable to have the surfactants in 4 a steam foam recovery process which inhibit the flow of the s.eam in the zone which contains only the residual oil
FOR STEAM FOAM DRIVES AND A PROCESS OF
FROM A SUBTERRANEAN FORMATION
-BACKGROUND OF THE_I~VENTION
This invention relates to enhanced oil recovery.
More specifically, this invention relates to a process of enhancing oil recovery with steam injection~
Many hydrocarbons are too thick to be recovered from subterranean petroleum containing formations without assistance. These hydrocarbons are either the residual oil left in a depleted reservoir or virgin heavy hydrocarbons. These heavy hydrocarbons can be recovered through the use of steam drives which heat the formation, lower the viscosity of the hydrocarbons, and enhance the flow of the hydrocarbons toward a production well.
However, after initial steam injection breakthrough at the production well, the steam injection preferentially follows the path of the breakthrough. Thus, the total amount of the formation that is swept by the steam injection is limited. Commercial surfactants, such as Thermophoam BW-D~, a product of the Far Best Company, and Stepanlo 30~, a product of the Stepan Company, hava been injected along with steam to create a steam-foam flood.
The surfactants form a foam that inhibits the flow of the steam into that portion of the formation containing only residual oil saturation. Residual oil saturation is defined as the immobile oil remaining in that portion of the reservoir swept by steam. This forces the steam to drive the recoverable hydrocarbons from the less depleted portions oE the reservoir toward the production well(s).
To maximize the extraction of hydrocarbons from a formation, it would be highly desirable to have superior foaming surfactants which inhibit the flow of steam in a steam zone containing only residual oil saturation. Fur-thermore, it would be desirable to have the surfactants in 4 a steam foam recovery process which inhibit the flow of the s.eam in the zone which contains only the residual oil
- 2 ~ 1~ 7 and enhance the flow of s-team in the zone which contains the recoverable hydrocarbons. However, it is desirable not to have the flow of the recoverable hydrocarbons inhibited in the steam zone having an oil saturation greater than the residual oil saturation.
SUMMARY OF THE INVENTION
We have invented a foam surfactant steam process for recovering hydrocarbons from a subterranean formation. The process compri~es forming a steam and alpha-olefin sulfonate dimer foam; passing said steam and alpha-olefin sulfonate dimer foam into said formation and away from an injection well to assist the movement of hydrocarbons toward a production well;
and recovering hydrocarbons at said production well. The super-ior foaming characteristics of the alpha-olefin sulfonate dimers enhance the sweeping of the steam through the formation. This enhances the recovery of hydrocarbons at the production well.
Unexpectedly, the foam surfactant-steam combination recovers additional hydrocarbons from the previously residual oil sat-urated portions of the formation swept by only steam. The foamable mixture of steam, surfactant and ~optionally) non-condensible gas is injected into the formation at an injection well and displaced toward the production well with either addi-tional foamable mixture or steam alone to recover the hydro-carbons from the formation.
DETAILED DESCRIPTION OF THE INVENTION
Foaming surfactants for steam injection can be evalu-ated by comparing several properties of the foams. These pro-perties are resistance factors, (R), which are dekermined by the pressure drop across a foam generator or a sandpack with ~imultaneous flow of steam, and optionally non-condensible gas, ~ 2~
~ 2a -and brine as illustrated and at the following conclitions; (1) at residual oil saturation with and without surfactant, and (2) at mobile oil saturation with and without surfactant. The resis-tance factors are defined in Table I.
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SUMMARY OF THE INVENTION
We have invented a foam surfactant steam process for recovering hydrocarbons from a subterranean formation. The process compri~es forming a steam and alpha-olefin sulfonate dimer foam; passing said steam and alpha-olefin sulfonate dimer foam into said formation and away from an injection well to assist the movement of hydrocarbons toward a production well;
and recovering hydrocarbons at said production well. The super-ior foaming characteristics of the alpha-olefin sulfonate dimers enhance the sweeping of the steam through the formation. This enhances the recovery of hydrocarbons at the production well.
Unexpectedly, the foam surfactant-steam combination recovers additional hydrocarbons from the previously residual oil sat-urated portions of the formation swept by only steam. The foamable mixture of steam, surfactant and ~optionally) non-condensible gas is injected into the formation at an injection well and displaced toward the production well with either addi-tional foamable mixture or steam alone to recover the hydro-carbons from the formation.
DETAILED DESCRIPTION OF THE INVENTION
Foaming surfactants for steam injection can be evalu-ated by comparing several properties of the foams. These pro-perties are resistance factors, (R), which are dekermined by the pressure drop across a foam generator or a sandpack with ~imultaneous flow of steam, and optionally non-condensible gas, ~ 2~
~ 2a -and brine as illustrated and at the following conclitions; (1) at residual oil saturation with and without surfactant, and (2) at mobile oil saturation with and without surfactant. The resis-tance factors are defined in Table I.
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01 _4_ A high value of Rl indicates that the surfactant has the capability to create a foam that strongly inhibits the flow of steam in a steam zone containing residual oil. This parameter has been used before to evaluate surfactants and steam floods. Higher Rl values indicate more desirable the surfactants. In addition, resistance factors R2 and R3 are also important for evaluating the surfactant effectiveness~ A high value of R2 indicates the surfactant makes a much stronger flow inhibiting foam in a steam zone with residual oil than it makes in a steam zone with recoverable hydrocarbons. This has the effect of blocking off that portion of the formation which has been s~ept of recoverable hydrocarbons and forces the additional steam injection to drive the recoverable hydrocarbons toward the production well. R3 values should approach one and preferably be less than 1. An R3 value less than one indicates that the surfactant itself has the ability to actually improve the flow of recoverable hydrocarbons in the steam zone relative to the absence of surfactant. Thus, high values of Rl and R2 and a value of R3 less than 1.0 would indicate the most desirable surfactants to divert steam from the depleted zone of the reservoir and to accelerate the growth of the steam zone and thereby to accelerate and increasa the production of crude oil for a given amount of steam injection.
The surfactants of the present invention exhibit superior Rl-R3 valuec to standard surfactants, such as Siponate ~168~, Thermophoam BW-D~ and Stepanflo 30~.
These known surfactants are alpha-olefin sulfonates-having an olefin chain from C16-C18.
The surfactants of the invention are the dimers of alpha-olefin sulfonates wherein the monomers have a carbon chain length of from about C5 to about C24. In other words, the dimer has a chain length of C10-C48. The dimers derived from the monomers of Cll-C20 alpha-olefin sulfonate.c are preferred. The dimers of C15-C20 alpha-olefin sulfonates are most preferred. Mixtures of the 2~7 dimers can be employed to optimize the recovery oE hydrocarbonsfrom a particular formation. The dimers can be prepared by any known process. For example, the dimers of the monomers are complex mixtures of compounds which can be prepared by heating the monomers at a temperature above about 110C as disclosed in U.S. Patent 3,721,707. For convenience, the mixture is re-ferred to as alpha olefin sulfonate dimers. Of course, a speclfic dimer can be prepared by startin~ ~ith a specific monomer.
The injection and production wells can be arranged in any pattern. For example, a two-spot~ a three-spot, a regular four-spot, a skewed four-spot, a five-spot, a seven-spot, an inverted seven-spot, and the like. Suitable patterns are described in The Reservoir Engineering Aspects of Waterflooding by Forrest F. Craiq, Jr., Society of Petroleum Engineers of AIME, 1971, page 49. Preferably, the injection well is sur-rounded by production wells, i~e., regular four-spot and five-spot patterns.
Any standard method of creating a steam surfactant foam is suitable for use in the invention. Preferably, the method provides for the incorporation of a non-condensible gas, such as nitrogen, carbon dioxide, carbon monoxide, air and the like, into the steam foam surfactant combination. A preferred process of creating the foam and gravity override sweeping the formation is disclosed in U.S. Patent Serial No. 4,488,598.
Alternatively, the procedures outlined in U.S. Patent 4,086,964 can be employed. In additionr the procedures outlined in U.S. Patents 4,085,800 and 3,412,793, can be used with pro-ducing formations that ~LZ~Z2~7 contain zones of high permeability and/or are susceptible to channeling. In those formations, the high permeability 05 zones are plugged to enhance the recovery of -hydrocarbons from the zones of lower permeability.
The foam is created by heating water to its boiling point at formation pressure [212F (100C) or higher] to form a steam. For California heavy oil reservoirs the steam temperature is typically in the range 250-~00F. Typically, 80 percent or less of the injected water is converted to steam; the remainder is injected as hot water. Thereafter, the surfactant is injected into the steam in an amount of from about 0.01~ to about 10~ of the liquid phase of the steam. Preferably, the surfactant is injected in as small an amount as possible to enhance the oil recovery. This is on the order of about 0.1~ tO
about 1~ surfactant present in the liquid phase.
Optionally, sufficient non-condensible gas is injected into the steam such that the gas phase composition is from about 1 to about 50% non-condensible gas and from about 99 to about 50~ steam by volu~e The steam with its associated surfactant and non-condensible gas is injected into an injection well at a rate determined by reservoir characteristics and well pattern area. Typically, steam is injected into each injection well at about 500 barrels per day, (BPD), of cold water equivalent. Optionally, the water for forming the steam can contain other additives which enhance its properties such as scale inhibitors, cosurfactants, and the like. The water can also contain salts.
The process is carried out in the following procedure to minimize the cost of the operation.
Initially, a first slug of steam is injected into the formation for a sufficient time to form a steam zone and a hot water zone in the subterranean formation containing the hydrocarbons. The steam injection is continued until there is steam breakthrough at the production well. This recovers the mobile oil in the steam-swept portion of the formation. Thereafter, a second slug of steam, surfactant 2~7 and (optionally) non-condensible gas is in~ected. This slug diverts the steam from the area of breakthrough and forces it to sweep through undepleted portions of the formation to recov-er additional hydrocarbons. Slugs of steam, surfactant and gas can be alternated with slugs of pure steam. Optionally, the slugs can be tapered compositionally from one slug into the next to form a smooth transition or steam-surfactant-gas in~ec-tion can be continuous. Finally, pure steam is injected to sweep the last portion of the formation.
Having described the invention, the following examples are illustrative of the superior surfactants and process of recovery. However, it should be understood that the examples are not intended to limit the scope of the invention.
Modifications which should be obvious to the ordinary skilled artisan are contemplated to be within the scope of the inven-tion.
EXAMPLES
The dimers were compared with other surfactants by the stainless-steel wool pack procedure to evaluate their per-formance. Steam-foam flow tests were run in a ~ inch diameter by 2~ inch long stainless-steel-wool pack containing brine (1 NaCl + 500 ppm CaC12) and Kern River crude oil at 400F. The gas phase of the generated foam consisted of equal volumes of steam and nitrogen (40 cc per minute total at conditions). The liquid phase flow rate was 3.25 ml/min. containing approxi-mately 0.5~ by weight active sulfonate. The results are given in Table II.
- 7a -TABLE II
Commercial Sulfonates Surfactant Resistance Factor R~ R~ R~
Suntech* IV (ATS) 19.4 2.21 1.30 Stepanflo* 30 (Cl~-1g LAOS) 21.9 1.29 2.51 Siponate A* 168 (Cl~-1g BAOS) 19.2 1.14 2.48 ~2~22~7 Table II (Cont'd) 05 Alkylaryl Sulfonates - Surfactant Resistance Factor - Rl R2 C12 16 ABS 15.6 1.15 2.01 10 C12-16 ATS 14.5 1.57 1.36 C15-18 ATS 17.2 1.41 1.81 C21 ATS 19.21.59 1.79 C12-16 AXS 13.3 2.15 0.92 Alpha-Olefin Sulfonates Surfactant Resistance Factor Rl R2 R3 C7_20 AOS 25.7 2.94 1.29 C15-18 AOS 22.~ 2.59 1.23 C15-20 AOS 21.2 1.27 2.47 Alpha-Olefin Sulfonate Dimers -:
SurfactantResistance Factor Rl R2 R~
.
Dimer of C~ AOS 26.5 4.67 0.85 Dimer of C13_14 AOS 21.2 4.15 0.76 Dimer of C15~18 AOS 22.4 4.97 0.67 Dimer of C15_20 AOS 26.1 5.75 0.67 ATS = alkyl toulene sulfonate LAOS = linear alpha olefin sulfonate BAOS = branched alpha olefin sulfonate AOS = alpha olefin sulfonate ABS = alkyl benzene sulfonate AXS = alkyl zylene sulfonate Rl, R2 and R3 values were obtained for both commercial and experimental surfactants. Three classes of sulfonates were tested: alkylaryl sulfonates, alpha olefin sulfo-nates, and alpha olefin sulfonate dimers (Table II). The alpha olefin sulfonates and sulfonate dimers gave better
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01 _4_ A high value of Rl indicates that the surfactant has the capability to create a foam that strongly inhibits the flow of steam in a steam zone containing residual oil. This parameter has been used before to evaluate surfactants and steam floods. Higher Rl values indicate more desirable the surfactants. In addition, resistance factors R2 and R3 are also important for evaluating the surfactant effectiveness~ A high value of R2 indicates the surfactant makes a much stronger flow inhibiting foam in a steam zone with residual oil than it makes in a steam zone with recoverable hydrocarbons. This has the effect of blocking off that portion of the formation which has been s~ept of recoverable hydrocarbons and forces the additional steam injection to drive the recoverable hydrocarbons toward the production well. R3 values should approach one and preferably be less than 1. An R3 value less than one indicates that the surfactant itself has the ability to actually improve the flow of recoverable hydrocarbons in the steam zone relative to the absence of surfactant. Thus, high values of Rl and R2 and a value of R3 less than 1.0 would indicate the most desirable surfactants to divert steam from the depleted zone of the reservoir and to accelerate the growth of the steam zone and thereby to accelerate and increasa the production of crude oil for a given amount of steam injection.
The surfactants of the present invention exhibit superior Rl-R3 valuec to standard surfactants, such as Siponate ~168~, Thermophoam BW-D~ and Stepanflo 30~.
These known surfactants are alpha-olefin sulfonates-having an olefin chain from C16-C18.
The surfactants of the invention are the dimers of alpha-olefin sulfonates wherein the monomers have a carbon chain length of from about C5 to about C24. In other words, the dimer has a chain length of C10-C48. The dimers derived from the monomers of Cll-C20 alpha-olefin sulfonate.c are preferred. The dimers of C15-C20 alpha-olefin sulfonates are most preferred. Mixtures of the 2~7 dimers can be employed to optimize the recovery oE hydrocarbonsfrom a particular formation. The dimers can be prepared by any known process. For example, the dimers of the monomers are complex mixtures of compounds which can be prepared by heating the monomers at a temperature above about 110C as disclosed in U.S. Patent 3,721,707. For convenience, the mixture is re-ferred to as alpha olefin sulfonate dimers. Of course, a speclfic dimer can be prepared by startin~ ~ith a specific monomer.
The injection and production wells can be arranged in any pattern. For example, a two-spot~ a three-spot, a regular four-spot, a skewed four-spot, a five-spot, a seven-spot, an inverted seven-spot, and the like. Suitable patterns are described in The Reservoir Engineering Aspects of Waterflooding by Forrest F. Craiq, Jr., Society of Petroleum Engineers of AIME, 1971, page 49. Preferably, the injection well is sur-rounded by production wells, i~e., regular four-spot and five-spot patterns.
Any standard method of creating a steam surfactant foam is suitable for use in the invention. Preferably, the method provides for the incorporation of a non-condensible gas, such as nitrogen, carbon dioxide, carbon monoxide, air and the like, into the steam foam surfactant combination. A preferred process of creating the foam and gravity override sweeping the formation is disclosed in U.S. Patent Serial No. 4,488,598.
Alternatively, the procedures outlined in U.S. Patent 4,086,964 can be employed. In additionr the procedures outlined in U.S. Patents 4,085,800 and 3,412,793, can be used with pro-ducing formations that ~LZ~Z2~7 contain zones of high permeability and/or are susceptible to channeling. In those formations, the high permeability 05 zones are plugged to enhance the recovery of -hydrocarbons from the zones of lower permeability.
The foam is created by heating water to its boiling point at formation pressure [212F (100C) or higher] to form a steam. For California heavy oil reservoirs the steam temperature is typically in the range 250-~00F. Typically, 80 percent or less of the injected water is converted to steam; the remainder is injected as hot water. Thereafter, the surfactant is injected into the steam in an amount of from about 0.01~ to about 10~ of the liquid phase of the steam. Preferably, the surfactant is injected in as small an amount as possible to enhance the oil recovery. This is on the order of about 0.1~ tO
about 1~ surfactant present in the liquid phase.
Optionally, sufficient non-condensible gas is injected into the steam such that the gas phase composition is from about 1 to about 50% non-condensible gas and from about 99 to about 50~ steam by volu~e The steam with its associated surfactant and non-condensible gas is injected into an injection well at a rate determined by reservoir characteristics and well pattern area. Typically, steam is injected into each injection well at about 500 barrels per day, (BPD), of cold water equivalent. Optionally, the water for forming the steam can contain other additives which enhance its properties such as scale inhibitors, cosurfactants, and the like. The water can also contain salts.
The process is carried out in the following procedure to minimize the cost of the operation.
Initially, a first slug of steam is injected into the formation for a sufficient time to form a steam zone and a hot water zone in the subterranean formation containing the hydrocarbons. The steam injection is continued until there is steam breakthrough at the production well. This recovers the mobile oil in the steam-swept portion of the formation. Thereafter, a second slug of steam, surfactant 2~7 and (optionally) non-condensible gas is in~ected. This slug diverts the steam from the area of breakthrough and forces it to sweep through undepleted portions of the formation to recov-er additional hydrocarbons. Slugs of steam, surfactant and gas can be alternated with slugs of pure steam. Optionally, the slugs can be tapered compositionally from one slug into the next to form a smooth transition or steam-surfactant-gas in~ec-tion can be continuous. Finally, pure steam is injected to sweep the last portion of the formation.
Having described the invention, the following examples are illustrative of the superior surfactants and process of recovery. However, it should be understood that the examples are not intended to limit the scope of the invention.
Modifications which should be obvious to the ordinary skilled artisan are contemplated to be within the scope of the inven-tion.
EXAMPLES
The dimers were compared with other surfactants by the stainless-steel wool pack procedure to evaluate their per-formance. Steam-foam flow tests were run in a ~ inch diameter by 2~ inch long stainless-steel-wool pack containing brine (1 NaCl + 500 ppm CaC12) and Kern River crude oil at 400F. The gas phase of the generated foam consisted of equal volumes of steam and nitrogen (40 cc per minute total at conditions). The liquid phase flow rate was 3.25 ml/min. containing approxi-mately 0.5~ by weight active sulfonate. The results are given in Table II.
- 7a -TABLE II
Commercial Sulfonates Surfactant Resistance Factor R~ R~ R~
Suntech* IV (ATS) 19.4 2.21 1.30 Stepanflo* 30 (Cl~-1g LAOS) 21.9 1.29 2.51 Siponate A* 168 (Cl~-1g BAOS) 19.2 1.14 2.48 ~2~22~7 Table II (Cont'd) 05 Alkylaryl Sulfonates - Surfactant Resistance Factor - Rl R2 C12 16 ABS 15.6 1.15 2.01 10 C12-16 ATS 14.5 1.57 1.36 C15-18 ATS 17.2 1.41 1.81 C21 ATS 19.21.59 1.79 C12-16 AXS 13.3 2.15 0.92 Alpha-Olefin Sulfonates Surfactant Resistance Factor Rl R2 R3 C7_20 AOS 25.7 2.94 1.29 C15-18 AOS 22.~ 2.59 1.23 C15-20 AOS 21.2 1.27 2.47 Alpha-Olefin Sulfonate Dimers -:
SurfactantResistance Factor Rl R2 R~
.
Dimer of C~ AOS 26.5 4.67 0.85 Dimer of C13_14 AOS 21.2 4.15 0.76 Dimer of C15~18 AOS 22.4 4.97 0.67 Dimer of C15_20 AOS 26.1 5.75 0.67 ATS = alkyl toulene sulfonate LAOS = linear alpha olefin sulfonate BAOS = branched alpha olefin sulfonate AOS = alpha olefin sulfonate ABS = alkyl benzene sulfonate AXS = alkyl zylene sulfonate Rl, R2 and R3 values were obtained for both commercial and experimental surfactants. Three classes of sulfonates were tested: alkylaryl sulfonates, alpha olefin sulfo-nates, and alpha olefin sulfonate dimers (Table II). The alpha olefin sulfonates and sulfonate dimers gave better
4~ Rl values than the alkylaryl sulfonate, but the dimers 2~:7 . 01 _9_ gave significantly better R2 and R3 values than either the alkylaryl sulfonates or the alpha olefin sulfonates.
S Further comparisons were made with the sandpack procedure. Steam flow tests were run at 400F in a 3/4"
diameter by 6" long pipe packed with 140 mesh Ottawa sand. These sandpacks were saturated with heavy Kern River reservoir crude oil and water. The pressure drops were measured across the sandpacks at residual oil saturation, and in the presence of mobile oil satura-tion. Measurements were made with and without 0.5%
surfactant present in the liquid phase. The gas flow rate was 40 cc. per minute and gas composïtion was 20~ nitrogen and 80% steam by volume. The liquid phase flow rate was about 3.25 milliliters per minute. The resistance factors were calculated for the surfactants listed below in Table III.
TABLE III
- Surfactant Resistance Factor - Rl R2 R3 Thermophoam BW-D 1.00.31 n.c.
Stephanflo 30 16 3.2 n.c.
Dimer of Cll C14 AOS 39 4.6 n.c.
Dimer of Cl5-C18 AOS 45 7.3 n.c.
n.c. = not calculated The results in Table III clearly indicate that the dimers of alpha-olefin sulfonates are superior to standard commercial alpha-olefin sulfonates.
~0
S Further comparisons were made with the sandpack procedure. Steam flow tests were run at 400F in a 3/4"
diameter by 6" long pipe packed with 140 mesh Ottawa sand. These sandpacks were saturated with heavy Kern River reservoir crude oil and water. The pressure drops were measured across the sandpacks at residual oil saturation, and in the presence of mobile oil satura-tion. Measurements were made with and without 0.5%
surfactant present in the liquid phase. The gas flow rate was 40 cc. per minute and gas composïtion was 20~ nitrogen and 80% steam by volume. The liquid phase flow rate was about 3.25 milliliters per minute. The resistance factors were calculated for the surfactants listed below in Table III.
TABLE III
- Surfactant Resistance Factor - Rl R2 R3 Thermophoam BW-D 1.00.31 n.c.
Stephanflo 30 16 3.2 n.c.
Dimer of Cll C14 AOS 39 4.6 n.c.
Dimer of Cl5-C18 AOS 45 7.3 n.c.
n.c. = not calculated The results in Table III clearly indicate that the dimers of alpha-olefin sulfonates are superior to standard commercial alpha-olefin sulfonates.
~0
Claims (29)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A process for recovering hydrocarbons from a sub-terranean hydrocarbon bearing formation penetrated by at least one injection well and at least one production well, said pro-cess comprising:
forming a steam and alpha-olefin sulfonate dimer foam;
passing said steam and alpha-olefin sulfonate dimer foam into said formation and away from an injection well to assist the movement of hydrocarbons toward a production well; and recovering hydrocarbons at said production well.
forming a steam and alpha-olefin sulfonate dimer foam;
passing said steam and alpha-olefin sulfonate dimer foam into said formation and away from an injection well to assist the movement of hydrocarbons toward a production well; and recovering hydrocarbons at said production well.
2. The process according to claim 1 wherein the dimer comprises from about 0.01% to about 10% of the water phase of the steam.
3. The process according to claim 2 wherein a non-condensible gas in an amount of from about 1% to about 50% of the gaseous phase of said steam is injected into said steam prior to the injection of said steam at the injection well.
4. The process according to claim 3 wherein the non-condensible gas is selected from the group consisting of nitro-gen, carbon dioxide, air, flue gas, CH4, and carbon monoxide.
5. The process according to claim 4 wherein the alpha-olefin sulfonate dimer includes alpha-olefin sulfonate dimer in the range of C10-C48.
6. The process according to claim 5 further comprising injecting substantially pure steam into the formation prior to the injection of said steam and alpha-olefin sulfonate dimer foam.
7. The process according to claim 6 wherein substan-tially pure steam is injected into the formation after the injection of said steam and alpha-olefin sulfonate dimer.
8. The process according to claim 7 wherein the steam injection is tapered into a steam and alpha-olefin sulfonate dimer injection which is tapered into a steam injection.
9. The process according to claim 8 wherein the alpha-olefin sulfonate dimer is injected in its salt form or the acid form.
10. The process according to claim 9 wherein said alpha-olefin sulfonate dimer includes alpha-olefin sulfonate dimer in the range of C22-C40.
11. The process according to claim 10 wherein the alpha-olefin sulfonate dimer is synthesized according to the oligo-merization process which comprises heating in the liquid phase the sulfonation product of the reaction of sulfur trioxide with a straight chain alkene hydrocarbon having a carbon atom con-tent in the range of from about 5 to 24, wherein the heating is at a temperature above about 110°C. and below the carbonization temperature of the sulfonate, is effected in the substantial absence of water, and is continued for a period at least sufficient for a significant conversion of the sulfonate feed to the corresponding oligomeric disulfonic acid and wherein the resulting oligomeric sulfonic acid is neutralized with ammonia, an alkali metal base, a calcium base, a magnesium base or a mixture thereof.
12. The process according to claim 11 wherein said straight chain alkene hydrocarbon is a mixture in the range of C5-C24.
13. The process according to claim 12 wherein said straight chain alkene hydrocarbon mixture is in the range of C11-C20.
14. The process according to claim 1 wherein the alpha-olefin sulfonate dimer includes alpha-olefin sulfonate dimer in the range of C10 - C48.
15. The process according to claim 14 wherein the alpha-olefin sulfonate dimer includes a mixture of alpha-olefin sulfonate dimer in the range of C10 - C48.
16. The process according to claim 15 wherein the alpha-olefin sulfonate timer is synthesized according to the alpha-olefin sulfonate dimer is synthesized according to the oligo-merization process which comprises heating in the liquid phase the sulfonation product of the reaction of sulfur trioxide with a straight chain alkene hydrocarbon having a carbon atom content in the range of from about 5 to 24, wherein the heating is at a temperature above about 110°C. and below the carboniza-tion temperature of the sulfonate, is effected in the substan-tial absence of water, and is continued for a period at least sufficient for a significant conversion of the sulfonate feed to the corresponding oligomeric disulfonic acid.
17. The process according to the claim 16 wherein said straight chain alkene hydrocarbon is a mixture in the range of C5 - C24.
18. The process according to claim 17 wherein said straight chain alkene hydrocarbon mixture is in the range of C11 - C20.
19. The process according to claim 18 wherein a non-con-densible gas in an amount of from about 1% to about 50% of the gaseous phase of said steam is injected with said steam at the injection well.
20. The process according to claim 14 wherein said alpha-olefin sulfonate dimer includes alpha-olefin sulfonate dimer in the range of C22 - C40.
21. The process according to claim 20 wherein the alpha-olefin sulfonate dimer includes a mixture of alpha-olefin sulfonate dimer in the range of C22 - C40.
22. A process for recovering hydrocarbons from a sub-terranean hydrocarbon bearing formation penetrated by at least one injection well and at least one production well, said process comprising:
forming a steam and alpha-olefin sulfonate dimer foam;
injecting said steam and alpha-olefin sulfonate dimer foam at an injection well and into said formation;
continuing to inject said steam and alpha-olefin sulfonate dimer foam through said injection well and into said formation to assist the movement of hydrocarbons towards a production well; and recovering hydrocarbons from a production well.
forming a steam and alpha-olefin sulfonate dimer foam;
injecting said steam and alpha-olefin sulfonate dimer foam at an injection well and into said formation;
continuing to inject said steam and alpha-olefin sulfonate dimer foam through said injection well and into said formation to assist the movement of hydrocarbons towards a production well; and recovering hydrocarbons from a production well.
23. The process according to claim 22 wherein the dimer comprises from about 0.01% to about 10% of the liquid phase of the steam.
24. The process according to claim 23 wherein said foam further contains a non-condensible gas selected from the group consisting of nitrogen, carbon dioxide, air, flue gas, CH4, and carbon monoxide.
25. The process according to claim 24 wherein said alpha-olefin sulfonate dimer includes alpha-olefin sulfonate dimer in the range of C22 - C40.
26. The process according to claim 24 wherein the alpha-olefin sulfonate dimer is synthesized according to the oligo-merization process which comprises heating in the liquid phase the sulfonation product of the reaction of sulfur trioxide with a straight chain alkene hydrocarbon having a carbon atom content in the range of from about 5 to 24, wherein the heating is at a temperature above about 110°C. and below the carboniza-tion temperature of the sulfonate, is effected in the substan-tial absence of water, and is continued for a period at least sufficient for a significant conversion of the sulfonate feed to the corresponding oligomeric disulfonic acid and wherein the resulting oligomeric sulfonic acid is neutralized with ammonia, an alkali metal base, a calcium base, a magnesium base or a mixture thereof.
27. The process according to claim 26 wherein said straight chain alkene hydrocarbon is a mixture of C5 - C24 hydrocarbons.
28. The process according to claim 27 wherein said mix-ture is a C11 - C20 mixture.
29. The process according to claim 27 wherein said mix-ture is a C15 - C20 mixture.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US06/489,649 US4556107A (en) | 1983-04-28 | 1983-04-28 | Steam injection including alpha-olephin sulfonate dimer surfactant additives and a process of stimulating hydrocarbon recovery from a subterranean formation |
| US489,649 | 1990-03-07 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1218227A true CA1218227A (en) | 1987-02-24 |
Family
ID=23944699
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000450302A Expired CA1218227A (en) | 1983-04-28 | 1984-03-23 | Sulfonate dimer surfactant additives for steam foam drives and a process of stimulating hydrocarbon recovery from a subterranean formation |
Country Status (9)
| Country | Link |
|---|---|
| US (1) | US4556107A (en) |
| AR (1) | AR248175A1 (en) |
| AU (1) | AU563811B2 (en) |
| BR (1) | BR8401909A (en) |
| CA (1) | CA1218227A (en) |
| DE (1) | DE3415569C2 (en) |
| ES (1) | ES8608620A1 (en) |
| GB (1) | GB2138869B (en) |
| NL (1) | NL8401097A (en) |
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| US4743385A (en) * | 1984-11-21 | 1988-05-10 | Sun Refining And Marketing Company | Oil recovery agent |
| US4769161A (en) * | 1984-12-14 | 1988-09-06 | Sun Refining And Marketing Company | Silicate-containing oil recovery compositions |
| US4597442A (en) * | 1985-02-26 | 1986-07-01 | Shell Oil Company | Reservoir preflushing process for increasing the rate of surfactant transport in displacing oil with injected steam and steam-foaming surfactant |
| US4678039A (en) * | 1986-01-30 | 1987-07-07 | Worldtech Atlantis Inc. | Method and apparatus for secondary and tertiary recovery of hydrocarbons |
| US4702317A (en) * | 1986-09-02 | 1987-10-27 | Texaco Inc. | Steam foam floods with a caustic agent |
| US5005644A (en) * | 1987-05-28 | 1991-04-09 | Chevron Research Company | Steam enhanced oil recovery method using branched alkyl aromatic sulfonates |
| US4957646A (en) * | 1987-08-26 | 1990-09-18 | Shell Oil Company | Steam foam surfactants enriched in alpha olefin disulfonates for enhanced oil recovery |
| US4860828A (en) * | 1988-06-01 | 1989-08-29 | The Dow Chemical Company | Gas flooding processing for the recovery of oil from subterranean formations |
| US4852653A (en) * | 1988-07-06 | 1989-08-01 | Shell Oil Company | Method to obtain rapid build-up of pressure in a steam foam process |
| US5069802A (en) * | 1988-12-19 | 1991-12-03 | Shell Oil Company | Gas flood surfactants enriched in olefin disulfonate |
| US4911238A (en) * | 1988-12-19 | 1990-03-27 | Shell Oil Company | Gas flooding with surfactants enriched in olefin disulfonate |
| US4967837A (en) * | 1989-03-31 | 1990-11-06 | Chevron Research Company | Steam enhanced oil recovery method using dialkyl aromatic sulfonates |
| US5110487A (en) * | 1989-04-03 | 1992-05-05 | Chevron Corporation | Enhanced oil recovery method using surfactant compositions for improved oil mobility |
| US4923009A (en) * | 1989-05-05 | 1990-05-08 | Union Oil Company Of California | Steam enhanced oil recovery processes and compositions for use therein |
| US5056597A (en) * | 1989-07-27 | 1991-10-15 | Chevron Research And Technology Company | Method for improving the steam splits in a multiple steam injection process using multiple steam headers |
| US5000263A (en) * | 1989-07-27 | 1991-03-19 | Chevron Research And Technology Company | Method for improving the steam splits in a multiple steam injection process using multiple steam headers |
| US4953635A (en) * | 1989-07-27 | 1990-09-04 | Chevron Research Company | Method for improving the steam splits in a multiple steam injection process |
| US5273682A (en) * | 1989-09-22 | 1993-12-28 | Chevron Research And Technology Company | Viscosity control additives for foaming mixtures |
| US5000262A (en) * | 1989-09-22 | 1991-03-19 | Mitchell Danzik | Viscosity control additives for foaming mixtures |
| US5052487A (en) * | 1989-12-29 | 1991-10-01 | Chevron Research & Technology Company | Sequential injection foam process for enhanced oil recovery |
| US5193618A (en) * | 1991-09-12 | 1993-03-16 | Chevron Research And Technology Company | Multivalent ion tolerant steam-foaming surfactant composition for use in enhanced oil recovery operations |
| US5190105A (en) * | 1991-09-26 | 1993-03-02 | Chevron Research And Technology Company | Method for improving the steam splits in a multiple steam injection process |
| GB2365464B (en) | 2000-08-07 | 2002-09-18 | Sofitech Nv | Scale dissolver fluid |
| MXPA03001195A (en) * | 2000-08-07 | 2004-05-17 | Sofitech Nv | Viscoelastic wellbore treatment fluid. |
| US6776234B2 (en) | 2001-12-21 | 2004-08-17 | Edward L. Boudreau | Recovery composition and method |
| US7809538B2 (en) | 2006-01-13 | 2010-10-05 | Halliburton Energy Services, Inc. | Real time monitoring and control of thermal recovery operations for heavy oil reservoirs |
| US7770643B2 (en) | 2006-10-10 | 2010-08-10 | Halliburton Energy Services, Inc. | Hydrocarbon recovery using fluids |
| US7832482B2 (en) | 2006-10-10 | 2010-11-16 | Halliburton Energy Services, Inc. | Producing resources using steam injection |
| US20080261835A1 (en) * | 2007-04-23 | 2008-10-23 | Paul Daniel Berger | Surfactant based compositions and process for heavy oil recovery |
| US9845669B2 (en) | 2014-04-04 | 2017-12-19 | Cenovus Energy Inc. | Hydrocarbon recovery with multi-function agent |
| WO2017023664A1 (en) | 2015-08-04 | 2017-02-09 | Stepan Company | Alpha-olefin sulfonic dimer acid process |
| CA2994147C (en) | 2015-08-04 | 2023-07-11 | Carolina E. ROJAS | Mixed dimers from alpha-olefin sulfonic acids |
| CA2972203C (en) | 2017-06-29 | 2018-07-17 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| CA2974712C (en) | 2017-07-27 | 2018-09-25 | Imperial Oil Resources Limited | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| CA2978157C (en) | 2017-08-31 | 2018-10-16 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| CA2983541C (en) | 2017-10-24 | 2019-01-22 | Exxonmobil Upstream Research Company | Systems and methods for dynamic liquid level monitoring and control |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US529836A (en) * | 1894-11-27 | Conduit electric railway | ||
| US569519A (en) * | 1896-10-13 | Billiard table cushion | ||
| US3357487A (en) * | 1965-08-26 | 1967-12-12 | Phillips Petroleum Co | Method of oil recovery with a hot driving fluid |
| US3412793A (en) * | 1966-01-11 | 1968-11-26 | Phillips Petroleum Co | Plugging high permeability earth strata |
| US3463231A (en) * | 1968-02-12 | 1969-08-26 | Chevron Res | Generation and use of foamed well circulation fluids |
| US3953338A (en) * | 1969-09-15 | 1976-04-27 | Chevron Research Company | Foam well cleanout using oligomeric sulfonic acids |
| US3721707A (en) * | 1969-09-15 | 1973-03-20 | Chevron Res | Organic sulfonic acid oligomers and production process |
| US3951823A (en) * | 1972-07-28 | 1976-04-20 | Chevron Research Company | Foam well cleanout using oligomeric sulfonates |
| US3994345A (en) | 1974-12-05 | 1976-11-30 | Phillips Petroleum Company | Method of recovering oil using steam |
| US3993133A (en) | 1975-04-18 | 1976-11-23 | Phillips Petroleum Company | Selective plugging of formations with foam |
| US4072191A (en) * | 1975-06-12 | 1978-02-07 | Phillips Petroleum Company | Fire floor process |
| US4085800A (en) * | 1976-12-07 | 1978-04-25 | Phillips Petroleum Company | Plugging earth strata |
| US4086964A (en) * | 1977-05-27 | 1978-05-02 | Shell Oil Company | Steam-channel-expanding steam foam drive |
| US4148217A (en) * | 1977-10-31 | 1979-04-10 | Phillips Petroleum Company | Evaluating surfactants |
| US4161217A (en) * | 1978-05-08 | 1979-07-17 | Shell Oil Company | Hot water foam oil production process |
| US4393937A (en) * | 1981-03-25 | 1983-07-19 | Shell Oil Company | Olefin sulfonate-improved steam foam drive |
| US4417088A (en) * | 1981-09-25 | 1983-11-22 | Chevron Research Company | Oligomerization of liquid olefins |
-
1983
- 1983-04-28 US US06/489,649 patent/US4556107A/en not_active Expired - Lifetime
-
1984
- 1984-03-23 CA CA000450302A patent/CA1218227A/en not_active Expired
- 1984-04-02 AU AU26312/84A patent/AU563811B2/en not_active Ceased
- 1984-04-05 NL NL8401097A patent/NL8401097A/en not_active Application Discontinuation
- 1984-04-25 BR BR8401909A patent/BR8401909A/en not_active IP Right Cessation
- 1984-04-26 AR AR84296457A patent/AR248175A1/en active
- 1984-04-26 DE DE3415569A patent/DE3415569C2/en not_active Expired - Fee Related
- 1984-04-26 GB GB08410728A patent/GB2138869B/en not_active Expired
- 1984-04-27 ES ES532010A patent/ES8608620A1/en not_active Expired
Also Published As
| Publication number | Publication date |
|---|---|
| GB2138869A (en) | 1984-10-31 |
| US4556107A (en) | 1985-12-03 |
| BR8401909A (en) | 1984-12-04 |
| GB8410728D0 (en) | 1984-05-31 |
| NL8401097A (en) | 1984-11-16 |
| DE3415569A1 (en) | 1984-10-31 |
| ES532010A0 (en) | 1986-06-16 |
| AR248175A1 (en) | 1995-06-30 |
| ES8608620A1 (en) | 1986-06-16 |
| AU563811B2 (en) | 1987-07-23 |
| DE3415569C2 (en) | 1994-08-11 |
| GB2138869B (en) | 1986-07-02 |
| AU2631284A (en) | 1984-11-01 |
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