WO2025090154A1

WO2025090154A1 - Enhanced oil recovery process with hydrocarbon-soluble surfactant

Info

Publication number: WO2025090154A1
Application number: PCT/US2024/040657
Authority: WO
Inventors: Amit KATIYAR; Troy E. KNIGHT; Wanglin Yu; Quoc Nguyen; Motaz TAHA; Daniel S. Miller
Original assignee: Dow Global Technologies LLC; Rohm and Haas Co; University of Texas System; University of Texas at Austin
Current assignee: Dow Global Technologies LLC; Rohm and Haas Co; University of Texas System; University of Texas at Austin
Priority date: 2023-10-25
Filing date: 2024-08-02
Publication date: 2025-05-01
Anticipated expiration: 2026-04-25

Abstract

The invention is a gas EOR process performed on an oil reservoir that has at least one production well and at least one injection well. Hydrocarbon gas or nitrogen gas is injected into the injection well. In the invention, the gas contains a surfactant that: 1. Comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment that contains on average more than 8 carbon atoms; and 2. Has a partition coefficient (Kp) between the gas and brine of at least 0.05, at 25°C,3000 psi pressure and 1 % initial concentration in the brine; 3. Generates viscous foam when contacted with both water and hydrocarbon gas; and 4. Is present in a concentration suitable to generate viscous foam when the surfactant encounters water.

Description

ENHANCED OIL RECOVERY PROCESS WITH HYDROCARBON-SOLUBLE SURFACTANT FIELD This invention relates to the field of enhanced oil recovery. INTRODUCTION Recovery of crude oil from an underground oil field (also called a reservoir) often proceeds in three stages, called primary, secondary and tertiary recovery. See, for example, US Patent 10,077,394 B2 and “Enhanced Oil Recovery” published the US Department of Energy at https://www.energy.gov/fecm/enhanced-oil-recovery. The reservoir typically contains porous rock with oil in the pores. In primary oil recovery, a production well is drilled into the reservoir, and the natural

oil through the pores to the production well, where it is pumped to the surface. This method frequently recovers only about 10 – 20 percent of the oil in the reservoir. In secondary recovery, also called water-flooding, water is injected into the reservoir though a second well, called an injection well, that enters the reservoir at a distance from the production well. Pressure from the water drives oil to the production well. Secondary recovery can recover 10 to 30 percent of the oil from the reservoir but leaves more than half of the oil unrecovered. Tertiary recovery, also called “enhanced oil recovery” or “EOR”, can increase recovery to 30 to 60 percent. Enhanced oil recovery requires the injection of a material other than water into the reservoir to increase oil production. Examples of common materials that may be injected during enhanced oil recovery (EOR) include gases, steam and other chemicals. One common method of enhanced oil recovery, called gas EOR, is injection of gas (“injection gas”) into the injection well. A common gas EOR technique is called “Water Alternating Gas” (“WAG”) injection. In WAG injection, alternating “slugs” of injection gas and water are injected into the reservoir. See, for example, Katiyar et al., “Successful Field Implementation of CO2-Foam Injection for Conformance Enhancement in the EVGSAU Field in the Permian Basin”, publication SPE-200327-MS by the Society of Petroleum Engineers (2020). Some injection gases chosen for gas EOR are non-condensable gases, although at pressure used in gas EOR even the non-condensable gases may enter a supercritical state in which they exhibit characteristics of both gas and liquid, such as density similar to a liquid but viscosity similar to a gas. (For clarity, the terms “gas EOR” and “injection gas” are commonly used when material that is injected into the reservoir is a gas at atmospheric pressure and ambient temperature, even if the material may be in a supercritical state rather than a strictly gaseous state under the conditions in gas EOR.) Examples of injection gases that have been explored for gas EOR include carbon dioxide, nitrogen, light hydrocarbon gases such as methane, ethane, propane, butane and mixtures such as natural gas, hydrogen sulfide, carbonyl sulfide, air and flue gas. In some cases, the injection gas is immiscible with oil, but more often the injection gas is miscible with oil at the reservoir conditions. In addition to increasing pressure in the reservoir, oil- miscible gases mix with the oil and reduce the viscosity of the oil, so that the oil can flow more easily through pores in the rock to the production well. Carbon dioxide, nitrogen and light hydrocarbon gases can all be oil-miscible under the conditions of gas EOR. The effectiveness of gas EOR processes can be reduced by poor sweep of the reservoir. See US Patent 10,077,394 B2 and Katiyar et al., above. Poor sweep can result from different layers of rock in the reservoir that have different permeability. Injection gas has low viscosity as compared to oil and pushes easily through the high-permeability layers to the production well without having significant interaction with the less-permeable layers or the oil in those layers (called “gas-fingering” or “gas-channeling”). In addition, the injection gas has low density as compared to oil and water. The reservoir can form a three- layer structure with water at the bottom, oil in the middle and injection gas on top (“gas override”). The gas flows easily above the oil- and water-containing layers of the reservoir toward the production well without having significant interaction with the oil or the water. Gas channeling and gas over-ride can be reduced by injecting a foaming surfactant into the injection well. The surfactant mixes with the injection gas and water to make a viscous foam. The foam increases the viscosity of the injection gas and retards its flow through the reservoir. In some cases, water-soluble surfactants are injected into the injection well dissolved in water slugs. See, for example, US Patent 5,363,915 and Bello et al., Foam EOR as an Optimization Technique for Gas EOR, 16 Energies 972 (2023), which is available at https://doi.org/10.3390/en16020972. It is also known to inject carbon dioxide soluble surfactant into the injection well when carbon dioxide is injected. See, for example, US Patents 8,857,527 B2, 9,874,079 B2 and 10,077,394 B2, and Katiyar et al., above. SUMMARY In some cases, the injection gas is hydrocarbon gas or nitrogen, rather than carbon dioxide. Many oil reservoirs are located in remote areas where it is not convenient to ship carbon dioxide. On the other hand, the oil reservoir itself can produce large quantities of hydrocarbon gases, which can be captured onsite and injected back into the reservoir. Alternately, nitrogen can be condensed from the atmosphere onsite. It is desirable to create foam using a surfactant that is soluble in both the injection gas and brine, rather than a surfactant soluble in water only. The injection gas effectively carries the surfactant to places where the injection gas flows: the gas channels in the case of gas channeling or the gas layer in the case of gas override. This may be especially important in the case of gas override because surfactant dissolved in water may be carried into a water layer below the oil layer and never reach the gas layer at all. The relative solubility of the surfactant in the injection gas and in brine can be measured using a variable called as partition coefficient (Kp). See Katiyar et al, “Low Adsorbing CO2 Soluble Surfactants for Commercially Viable Implementation of CO2 Foam EOR Technology”, Society of Petroleum Engineers Publ. SPE-206361-MS (2021). The partition coefficient (Kp) measures the relative concentration at which surfactant partitions between a specific injection gas and a specific brine at a specific temperature and pressure. One aspect of this invention is a gas EOR process, performed at an oil reservoir that has a production well for recovering oil and an injection well for injecting substances to increase the flow of oil to the production well, which process comprises the step of injecting into the injection well an injection gas that contains primarily hydrocarbon gas or nitrogen, wherein the injection gas contains a dissolved nonionic surfactant that: 1. Comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment that contains on average more than 8 carbon atoms; and 2. Has a partition coefficient (Kp) between the injection gas and 0.2 weight percent (wt.%) NaCl brine of at least 0.05, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine; and 3. Generates viscous foam when contacted with both water and hydrocarbon gas; and 4. Is present in a concentration suitable to generate viscous foam when the hydrocarbon gas encounters water. A second aspect of this invention is a gas EOR process, performed at an oil reservoir that has a production well for recovering oil and an injection well for injecting substances to increase the flow of oil to the production well, wherein an injection gas that contains primarily hydrocarbon gas or nitrogen is injected into the injection well, characterized in that the injection gas contains a dissolved nonionic surfactant that: 1. Comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment that contains on average more than 8 carbon atoms; and 2. Has a partition coefficient (Kp) between the injection gas and 0.2 wt.% NaCl brine of at least 0.05, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine; 3. Generates viscous foam when contacted with both water and hydrocarbon gas; and 4. Is present in a concentration suitable to generate viscous foam when the surfactant encounters water. BRIEF DESCRIPTION OF THE DRAWINGS Drawing 1 illustrates an apparatus used for performing core flooding tests. Drawing 2 shows a graph of results from core folding experiments. DETAILED DESCRIPTION This invention is used in the context of a gas EOR process performed on an underground oil reservoir. The oil reservoir contains crude oil. In some embodiments, the oil reservoir further contains water or brine. A production well reaches the oil reservoir, and oil can be pumped from the reservoir to the surface through the production well. An injection well reaches the oil reservoir at a distance from the production well. It is well-known in the oil-drilling art how to identify oil reservoirs and how to sink production wells and injections wells to perform water- and gas EOR. See, for example, US Patents 5,363,915 and 9,874,079 B2; and “Enhanced Oil Recovery” at https://www.energy.gov/fecm/enhanced- oil-recovery. or

and injection rate of the injection gas may be any pressure and rate useful for the gas EOR process. Typical pressures are from 1000 psi (7 MPa) to 12000 psi (83 MPa), but in some cases other pressures may be useful. In some embodiments, the pressure is high enough so that the injection gas is supercritical at the temperature in the reservoir, such as at least 2300 psi (16 MPa) or at least 2600 psi (18 MPa) for natural gas at 25℃. In some embodiments, the gas EOR is deployed through water-alternating-gas (WAG) process, in which alternating injections (slugs) of injection gas and water are injected into the injection well. The injection pressure and injection rate of water may be any pressure and rate useful for the WAG process. Typical pressures are from 1000 psi to 12000 psi, but in some cases other pressures may be useful. A wide ratio of water to gas may be used in a WAG process. In some embodiments, the volume ratio of water to injection gas in the WAG process is at least 1:9 or at least 2:8 or at least 3:7 or at least 4:6 or at least 5:5 or at least 6:4. In some embodiments, the volume ratio of water to injection gas in the WAG process is at most 9:1 or at most 8:2 or at most 7:3. In some embodiments, the injection gas contains primarily nitrogen, or at least 70 mole percent nitrogen or at least 80 mole percent nitrogen or at least 90 mole percent nitrogen or at least 95 mole percent nitrogen; in some embodiments the injection gas contains up to 100 mole percent nitrogen. In some embodiments, the injection gas contains primarily hydrocarbon, or at least 70 mole percent hydrocarbon or at least 80 mole percent hydrocarbon or at least 90 mole percent hydrocarbon or at least 95 mole percent hydrocarbon; in some embodiments the injection gas contains up to 100 mole percent hydrocarbon. In addition to hydrocarbon and/or nitrogen components, the injection gas may contain minor amounts (less than 50 mole percent) of other gases, such as water vapor, carbon dioxide, hydrogen and hydrogen sulfide. Examples of hydrocarbon gases include methane, ethane, propane, butane, pentane and mixtures such as natural gas. In some embodiments, the hydrocarbon gas is a natural gas. In some embodiments, the organic components of the hydrocarbon gas contain at least 50 mole percent methane, or at least 60 mole percent or at least 70 mole percent or at least 80 mole percent or at least 85 mole percent or at least 90 mole percent or at least 95 mole percent. In some embodiments, the hydrocarbon gas can contain up to 100 mole percent methane. In some embodiments, the hydrocarbon gas contains at least 1 mole percent hydrocarbons other than methane, or at least 2 mole percent or at least 5 mole percent. Examples of other hydrocarbon components that may be part hydrocarbon gas include ethane, propane, butanes and pentanes. In some embodiments, the injection gas is immiscible with oil under reservoir conditions. In some embodiments, the injection gas is miscible with oil under reservoir conditions. It is recognized that some injection gases have a minimum-miscibility pressure (MMP) based on the temperature; they are immiscible with oil below the MMP and miscible with oil above the MMP. See US Patent 8,857,527 B2 at col 12-13. The pressure of core flooding may be adapted to achieve or avoid miscibility as desired. The injection gas contains a nonionic surfactant that is soluble in the injection gas. The nonionic surfactant contains a lipophilic segment bonded to a hydrophilic segment. The lipophilic segment is a hydrocarbyl moiety that contains on average more than 8 carbon atoms. In some embodiments, the lipophilic segment is branched. In some embodiments, the lipophilic segment is linear. In some embodiments, the lipophilic segment is an alkyl moiety. In some embodiments, the lipophilic segment is a linear alkyl moiety. In some embodiments, the lipophilic segment contains on average at least 8.5 carbon atoms or at least 9 carbon atoms or at least 10 carbon atom or at least 11 carbon atoms or at least 12 carbon atoms. In some embodiments, the lipophilic segment contains on average at most 20 carbon atoms or at most 18 carbon atoms or at most 16 carbon atoms or at most 14 carbon atoms. For example, the lipophilic segment can be a linear alkyl moiety that contains on average 9 to 18 carbon atoms or 10 to 16 carbon atoms or 12 to 14 carbon atoms. In some examples, a mixture of surfactants is used in which the lipophilic segments contain different numbers of carbon atoms. For example, a first surfactant may contain lipophilic segments that have on average at most 12 carbon atoms or at most 11 carbon atoms or at most 10 carbon atoms, and a second surfactant may contain lipophilic segments that have on average at least one more carbon atom that the first surfactant or at least 2 more carbon atoms or at least 3 more carbon atoms. For example, lipophilic segments in the first surfactant may contain on average 8 to 10 carbon atoms, and lipophilic segments in the second surfactant may contain on average 12 to 14 carbon atoms. In some embodiments, the hydrophilic segment comprises polyethylene glycol (PEG) polymer or copolymer. The PEG polymer or copolymer contains repeating ethylene glycol units as illustrated in Formula 1, optionally with other repeating units. (1) [-O-CH₂-CH₂-] In some embodiments, the hydrophilic segment comprises a polyethylene glycol-polypropylene glycol (PEG-PPG) copolymer. In addition to ethylene glycol units, the PEG-PPG copolymer contains repeating propylene glycol units as illustrated in Formula 2, wherein R a pendant methyl group. (²⁾ _{[-O-CH2-CHR-]} In some embodiments, the PEG-PPG copolymer is a block copolymer containing one other more blocks of ethylene glycol units and one or more blocks of propylene glycol units. In some embodiments, the hydrophilic segment contains one block of ethylene glycol units and one block of propylene glycol units. In some embodiments, the hydrophilic segment contains two blocks of ethylene glycol units and one block of propylene glycol units. For example, a block of ethylene glycol units may be linked to the lipophilic segment, and a block of propylene glycol units may be linked to the ethylene glycol block. Optionally, a second block of ethylene glycol units may be linked to the propylene glycol block. In some embodiments, the hydrophilic segment contains on average at least 4 ethylene glycol units or at least 5 ethylene glycol units or at least 6 ethylene glycol units or at least 7 ethylene glycol units or at least 8 ethylene glycol units. In some embodiments, the hydrophilic segment contains on average at most 24 ethylene glycol units or at most 20 ethylene glycol units or at most 18 ethylene glycol units or at most 16 ethylene glycol units or at most 12 ethylene glycol units. For example, the hydrophilic segment may contain 4 to 20 ethylene glycol units or 5 to 18 ethylene glycol units. In some embodiments, the hydrophilic segment contains on average at least 3 propylene glycol units or at least 4 propylene glycol units or at least 5 propylene glycol units or at least 6 propylene glycol units or at least 7 propylene glycol units or at least 8 propylene glycol units. In some embodiments, the hydrophilic segment contains on average at most 24 propylene glycol units or at most 20 propylene glycol units or at most 18 propylene glycol units or at most 16 propylene glycol units or at most 12 propylene glycol units. For example, the hydrophilic segment may contain 3 to 12 propylene glycol units. In some embodiments, the number ratio of ethylene glycol units to propylene glycol units in the hydrophilic segment is at least 0.5 or at least 0.6 or at least 0.7 or at least 0.8 or at least 0.9 or at least 1. In some embodiments, the number ratio of ethylene glycol units to propylene glycol units in the hydrophilic segment is at most 2.5 or at most 2 or at most 1.8 or at most 1.6 or at most 1.4 or at most 1.2. For example, the number ratio of ethylene glycol units to propylene glycol units in the hydrophilic segment 0.5 to 2.5 or 0.6 to 2. Surfactants are sometimes classified based on hydrophilic-lipophilic balance, as determined by the Griffin method, abbreviated HLB_G. See, for example, Griffin, Calculation of HLB Values of Non- Ionic Surfactants, 1954 J. Soc. Cosmetic Chemists 249 (1954). In some embodiments, the surfactant used in this invention has an HLBG of at least 5.0 or at least 6.0 or at least 6.2 or at least 6.5 or at least 7.0 or at least 7.5. In some embodiments, the surfactant used in this invention has an HLBG of at most 12 or at most 10 or at most 9.8 or at most 9.0 or at most 8.5 or at most 8.0. For example, the surfactant may have an HLBG from 6 to 10 or 6.2 to 9.8. Surfactants are sometimes classified based on hydrophilic-lipophilic balance, as determined by the Effective Chain Length method, abbreviated HLB_ECL. In some embodiments, the surfactant used in this invention has an HLB_ECL of at least 6.0 or at least 7.0 or at least 8.0 or at least 8.2 or at least 8.5 or at least 9.0. In some embodiments, the surfactant used in this invention has an HLBECL of at most 15 or at most 13 or at most 12.3 or at most 12 or at most 11 or at most 10.5 or at most 10. For example, the surfactant may have an HLBECL from 8 to 13 or from 8.2 to 12.3. The surfactant is chosen so that its partition coefficient (Kp) between the injection gas and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, is at least 0.05, when measured according to the Test Methods. In some embodiments, the partition coefficient (Kp) of the surfactant between the injection gas and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, is at least 0.08 or at least 0.1 or at least 0.2 or at least 0.3 or at least 0.4. In some embodiments, the partition coefficient (Kp) of the surfactant between the injection gas and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, is at most 1 or at most 0.9 or at most 0.85 or at most 0.8. In some embodiments, the partition coefficient (Kp) of the surfactant between ethane and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, is at least 0.05 or at least 0.08 or at least 0.1 or at least 0.2 or at least 0.3 or at least 0.4. In some embodiments, the partition coefficient (Kp) of the surfactant between ethane and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, is at most 1 or at most 0.9 or at most 0.85 or at most 0.8. In addition to being soluble in the injection gas, the surfactant is usually soluble in water under conditions expected in the reservoir. It is known that concentration, temperature and salinity can all impact solubility of the surfactant in water. Solubility can be estimated by cloud temperature limit, the temperature at which surfactants visibly begin to phase separate from water. In some embodiments, the surfactant has a cloud temperature limit in deionized water (1% concentration of surfactant) of at least 20℃ or at least 25℃ or at least 30℃ or at least 40℃ or at least 50℃ or at least 60℃. In some embodiments, the surfactant has a cloud temperature limit in 4% NaCl brine water (1% concentration of surfactant) of at least 20℃ or at least 25℃ or at least 30℃ or at least 40℃ or at least 50℃ or at least 55℃. There is no maximum desired cloud temperature limit, but in some cases a cloud temperature limit up to 95℃ in distilled water or brine may be adequate. In some embodiments, the surfactant can tolerate NaCl salinity at room temperature without clouding up to at least 10 wt.% or at least 20 wt.% or at least 25 wt.% or at least 30 wt.%. There is no maximum desired tolerance for salinity, but tolerance over 50 wt.% or 40 wt.% may be unnecessary. The surfactant is capable of forming viscous foam in the presence of water and the injection gas. Foam is considered viscous when its viscosity is higher than the viscosity of the gas and water without surfactant. Foam viscosity can be measured by core flooding tests as described in the Test Methods. In some embodiments, the surfactant provides a steady-state viscosity of at least 1 cP when tested according to the Test Methods with ethane, or at least 5 cP or at least 10 cP or at least 20 cP or at least 30 cP. In some embodiments, the surfactant provides a steady-state viscosity of at least 1 cP when tested according to the Test Methods with methane, or at least 2 cP or at least 3 cP or at least 4 cP or at least 5 cP. The viscosity of water and injection gas at reservoir conditions, without surfactant, is typically on the order of 0.1 cP and 0.01 cP respectively. Appropriate nonionic surfactants are commercially available, such as under the ELEVATE™ trademark. Others can be made by known processes, such as polymerizing ethylene oxide (and optionally propylene oxide together or sequentially) in the presence of a fatty alcohol that corresponds to the lipophilic segment of the surfactant and in the presence of a catalyst such as a base or a metal cyanide. See, for example, US Patents 6,355,845 B1 and 9,874,079 B2. Surfactants used in the process may optionally be dissolved or suspended in an aqueous or organic solvent to form a liquid formulation. In some embodiments, the solvent comprises water. In some embodiments, the solvent comprises an organic solvent that is appropriate for gas EOR, such as a liquid hydrocarbon, alcohol, ketone, ether or chlorinated hydrocarbon. The concentration of surfactant in the liquid formulation may be any concentration which produces a stable formulation and effectively delivers the surfactant into the reservoir in suitable quantities. The best concentrations may vary depending on the selection of surfactant and solvent. In some embodiments, the liquid formulation contains at least 5 wt.% surfactant or at least 10 wt.% or at least 20 wt.% or at least 30 wt.% or at least 40 wt.%. In some embodiments, the surfactant may be used neat (100 wt.%). The surfactant is mixed with the injection gas before or during the gas EOR process. The concentration of surfactant in the injection gas should be suitable to generate viscous foam in the reservoir. The optimum concentration of surfactant in the injection gas may vary, depending on several factors such as the selection of surfactant and injection gas, and the ratio of injection gas to water in a WAG process. In some embodiments, the concentration of surfactant in the injection gas is at least 50 parts per million by weight (ppmw) or at least 100 ppmw or at least 200 ppmw or at least 500 ppmw. In some embodiments, the concentration of surfactant in the injection gas is at most 10 weight percent or at most 5 weight percent or at most 10,000 ppmw or at most 6000 ppmw or at most 5000 ppmw or at most 3000 ppmw or at most 2000 ppmw. Surfactant does not need to be added to all slugs of injection gas or to all injection gas in a given slug. In some embodiments, at least 5 percent of injection gas contains surfactant or at least 10 percent or at least 15 percent or at least 20 percent or at least 25 percent. In some embodiments, up to 100 percent of injection gas may contain surfactant, or up to 80 percent or up to 60 percent or up to 40 percent. Optionally, the injection gas or water may further contain other additives, such as corrosion inhibitors, scale inhibitors or other surfactants. In some embodiments, the concentration of the other additives is no more than 5 wt.% of the slug or no more than 3 wt.% or no more than 1 wt.%. In some embodiments, the concentration of the other additives is 0 wt.%. Except for the addition of surfactant to the injection gas, the gas EOR process may be carried out by ordinary procedures as previously described. We hypothesize, without intending to be bound, that injection gas and surfactant encounter water as they flow though high permeability areas of the reservoir and make foam which increases the viscosity of the injection gas. With increased viscosity, gas channeling and gas override are reduced, and the injection gas interacts more with the bypassed oil to achieve more effective gas EOR. Effective foam generation in the reservoir can sometimes be demonstrated by a decrease in the gas injectivity at the injection well (the quantity of gas that flows into the injection well at a given pressure and during a given period of time). See, for example, Katiyar et al., “Successful Field Implementation of CO2-Foam Injection for Conformance Enhancement in the EVGSAU Field in the Permian Basin”, publication SPE-200327-MS by the Society of Petroleum Engineers at pages 9-10 (2020). Declines in gas injectivity are not uniform, and the effect may increase, reach a maximum and then decrease several times over a period of 60 days before eventually waning. In some embodiments, during the first 60 days after surfactant is injected into the reservoir according to this process, the gas injectivity declines at least once by at least 5 percent or at least 10 percent or at least 15 percent or at least 20 percent or at least 25 percent. In some embodiments, during the first 60 days after surfactant is injected into the reservoir according to this process, the gas injectivity declines at most 80 percent or at most 60 percent or at most 50 percent or at most 40 percent. Other indications that foam is forming and having an impact on the gas EOR process include changes in production characteristics of the reservoir such as changes in the ratio of oil, injection gas and water recovered and the production well, redistribution of production of gas, water, and oil from production wells connected to reservoir, and oil production uplift. TEST METHODS Properties described in this application are measured using the following test methods, unless it is clear from the context that a different method is intended. Hydrophilic Lipophilic Balance (Griffin Method) (HLBG): See Griffin, Calculation of HLB Values of Non-Ionic Surfactants, 1954 J. Soc. Cosmetic Chemists 249 (1954) Hydrophilic Lipophilic Balance (Effective Chain Length Method) (HLBELC): See Guo et al., Calculation of Hydrophile-Lipophile Balance for Polyethoxylated Surfactants by Group Contribution Method. J Colloid Interface Sci 2006, 298 (1), 441–450.

Gas-Brine Partitioning Coefficient The following steps are carried out at room temperature. 1. Surfactant is dissolved at the desired concentration (0.5, 1, 1.5 and 2.0 wt.%). in a brine solution containing 0.2 wt.% NaCl. The surfactant solution is added to a high pressure cell to fill half the cell volume. 2. The cell is pressurized with gas to 3000 psi. The volume ratio of gas and surfactant solution in the cell is 1:1 (equal volumes). 3. The cell is mixed regularly for 3 days. 4. The cell is depressurized by slowly venting the gas from the top of the cell. 5. A sample of brine that contains surfactant is collected, and diluted by a factor of 100. The concentration of the surfactant in the brine sample is carried out using an Agilent 6130 mass spectroscopy device. 6. The mass concentration (C) of surfactant partitioned into the gas is estimated using equation (1): (1) C _{Gas-Partitioned} = C _{Brine Initial} – C _{Brine-Partitioned} Wherein • C Gas-Partitioned is the concentration of surfactant dissolved in the gas at 3000 psi, in g/L • C _{Brine Initial} is the concentration of surfactant dissolved in the surfactant solution before partitioning, in g/L; and • C Brine-Partitioned is the concentration of surfactant dissolved in the surfactant solution after partitioning, in g/L. The partitioning coefficient (Kp) is the mass concentration/fraction of surfactant dissolved in the gas after partitioning (C _{Gas-Partitioned}) divided by the mass concentration/fraction of surfactant dissolved in the brine after partitioning (C _{Brine-Partitioned}): (2) Kp = C Gas-Partitioned / C Brine-Partitioned Cloud Temperature Cloud temperature is tested in deionized water or in NaCl brine. Surfactant solutions are prepared to 1 wt.% concentration in the water or brine and added to 10 ml glass vials. The vials are placed in a temperature controlled oven. The temperature is increased in 1°C increments and given 30 minutes to equilibrate at each temperature. The cloud temperature is estimated visually as the temperature the surfactant solution starts to cloud. Foam Viscosity Foam viscosity is measured by core flooding tests. Drawing 1 shows the apparatus used for core- flood tests. The apparatus contains a carbonate core of 54 mD permeability and 24.5% porosity in a core holder which is in an oven, plus accumulators and pumps outside the oven to hold and inject brine and gas into the core. The brine accumulators are loaded with brine containing surfactant at a known concentration. The gas accumulators are loaded with gas under pressure. The core holder and accumulators are heated in the oven to 40℃. The core holder confining pressure is set to 3500-4000 psi. The system pressure is set to 3000 psi using a backpressure regulator (BPR-1), two additional BPRs set to 2000 and 1000 psi are used to ensure a smooth depressurization of effluent. Brine and surfactant solutions are injected into the core using a Quizix pump through three 1-liter accumulators. Gas is injected into the core at a pressure of 3000 psi using a Quizix pump. Foam flooding is carried out at a flow rate of 10 ft/d and 50% foam quality (FQ) to steady state when a stable pressure drop is observed. (Foam quality is the % of gas in the foam.) The pressure drop across the porous core is recorded. The apparent viscosity of foam is calculated using Darcy’s law: (2) μa = [k (ΔP)]/[L (ν darcy)] Where μ_a is the apparent viscosity of the foam in cP, ΔP/L is the pressure drop across the core in atm/cm, k is the absolute permeability in Darcy, L is the length of the core in cm, and ν darcy is the superficial velocity in cm/s. After each test, the core is flooded with brine until the initial permeability is restored. EXAMPLES The following Examples illustrate partitioning and foam formation of surfactants used in some embodiments of the invention. The surfactants shown in Table 1 are obtained. All the surfactants contain a fatty alkyl group as the lipophilic segment and a PEG-PPG block copolymer as the hydrophilic segment. The hydrophilic segments in surfactants IDS1-IDS9 contain diblock copolymers, with a PEG block linked to the lipophilic segment and a PPG block linked to the PEG block. The hydrophilic segments in surfactants ITS1-ITS5 contain triblock copolymers, with (i) a first PEG block that contains on average about 4 repeating ethylene glycol units linked to the lipophilic segment and (ii) a PPG block linked to the first PEG block and (iii) a second PEG block that contains the remaining ethylene glycol units linked to the PPG block. The HLBG and HLBELC for each surfactant are calculated and shown in Table 2. The cloud temperature for each surfactant is measured in deionized water and shown in Table 2. The cloud temperature for some surfactants is measured in a 4% NaCl solution and shown in Table 2. Five comparative surfactants (CS1 – CS5) are obtained and listed in Table 1: Surf ID Surfactant Cloud Point (℃)

Table 2 Lipophilic Segment H^{ydrophilic Seg} Cloud Points C_ontent ^{ment Content HLB} (℃) Surf Avg Avg Avg EO/PO DI 4% Cl

The partition coefficient (Kp) of each surfactant is measured between ethane and brine (containing 0.2% NaCl) when the surfactant concentration in the brine is 0.5 wt.%, 1 wt.%, 1.5 wt.% and 2 wt.%, as described in the Test Methods. The results are set out in Table 3. Surfactant Partition Coefficient (Kp)

The partition coefficient (Kp) of surfactant between surfactant and brine (containing 0.2% NaCl) is measured using surfactants ITS3 and CS3 using 5 different hydrocarbon gases (methane, ethane, butane, Gas Mix 1 and Gas Mix 2) and using brines that contain 0.5 wt.%, 1 wt.%, 1.5 wt.% and 2 wt.% surfactant. Temperature is 25℃ and pressure is 3000 psi. Information about the gases is shown in Table 4. Results are shown in Table 5. Table 4 Gas Alkane mole % in test gas Gas properties at 25 °C and 3000 psi C1 C2 C4 ρ (g/cc) μ (cp)

Partitioning coefficient % Surf in Brine 0.5 1 1.5 2

oa scos y s easu e o su ac a ee e e gases Methane, Gas Mix 1 and Ethane) as set out in the Test Methods. A 0.5 wt.% solution of surfactant ITS3 in water is co-injected into the porous core, with the gas to be foamed. The temperature is 40℃, the flow rate is 10 ft/d, and the foam quality is 50%. The pressure drop across the porous core is measured, and viscosity is calculated as described in the Test Methods. (The steady state viscosity of water and gas, without surfactant, is typically about 0.1 cP to 0.01 cP.) Drawing 2 illustrates the measured foam viscosity based on the recorded pressure drop across the core. The steady state foam viscosity for ITS3 is above 5 when the hydrocarbon gas is methane, is above 25 when the hydrocarbon gas is gas mix and above 40 when the hydrocarbon gas is ethane.

Claims

CLAIMS: 1. A gas EOR process, performed at an oil reservoir that has a production well for recovering oil and an injection well for injecting substances to increase the flow of oil to the production well, which process comprises the step of injecting into the injection well an injection gas that contains primarily hydrocarbon gas or nitrogen, wherein the injection gas contains a dissolved surfactant that: a) Comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment that contains on average more than 8 carbon atoms; and b) Has a partition coefficient between the injection gas and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, of at least 0.05; c) Generates viscous foam when contacted with both water and hydrocarbon gas; and d) Is present in a concentration suitable to generate viscous foam when the hydrocarbon gas encounters water.

2. The enhanced oil recovery process of Claim 1 wherein the injection gas contains from 80 to 100 mole percent hydrocarbon gas.

3. The enhanced oil recovery process of Claim 2 wherein the surfactant comprises a lipophilic segment that contains a linear alkyl moiety having on average from 10 to 18 carbon atoms.

4. The enhanced oil recovery process of Claim 2 wherein the hydrophilic segment of the surfactant contains one or more block of polyethylene glycol polymer and one or more block of polypropylene glycol polymer.

5. The enhanced oil recovery process of Claim 4 wherein the polyethylene glycol blocks in each surfactant molecule contain on average at least 5 repeating ethylene glycol units.

6. The enhanced oil recovery process of Claim 5 wherein the polyethylene glycol blocks in each surfactant molecule contain on average at most 20 repeating ethylene glycol units.

7. The enhanced oil recovery process of Claim 5 wherein the polypropylene glycol blocks in each surfactant molecule contain on average from 2 to 20 repeating propylene glycol units.

8. The enhanced oil recovery process of Claim 4 wherein the ratio of ethylene glycol units to propylene glycol units is 0.5 to 2.5.

9. The enhanced oil recovery process of Claim 2 wherein the hydrophilic-lipophilic balance of the surfactant, as determined by the Griffin method, is from 5.0 to 12.

10. The enhanced oil recovery process of Claim 2 wherein the hydrophilic-lipophilic balance of the surfactant, as determined by the Effective Chain Length method, is from 6.0 to 15.

11. The enhanced oil recovery process of Claim 2 wherein the surfactant has a partition coefficient between ethane and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, of at least 0.08.

12. The enhanced oil recovery process of Claim 2 wherein the surfactant has a partition coefficient between ethane and 0.2 wt.% NaCl brine, at 25℃, 3000 psi pressure and 1 % initial concentration in the brine, of at least 0.2.

13. The enhanced oil recovery process of Claim 2 wherein: a) The surfactant comprises a lipophilic segment that contains an alkyl moiety having on average from 9 to 20 carbon atoms; b) the surfactant comprises a hydrophilic segment that contains one or more block of polyethylene glycol polymer and one or more block of polypropylene glycol polymer wherein the ratio of ethylene glycol units to propylene glycol units is 0.5 to 2.5; and c) hydrophilic-lipophilic balance of the surfactant, as determined by the Griffin method, is from 5.0 to 12; and d) the surfactant has a partition coefficient between ethane and 0.2% NaCl brine at 25℃ of at least 0.2.

14. The enhanced oil recovery process of Claim 13 wherein: a) the lipophilic segment is a linear alkyl group and contains on average from 10 to 14 carbon atoms; b) the hydrophilic segment contains on average from 3 to 12 propylene glycol units, and the ratio of ethylene glycol units to propylene glycol units is 0.6 to 2; and c) hydrophilic-lipophilic balance of the surfactant, as determined by the Griffin method, is from 6.2 to 9.8; and d) the cloud temperature of the surfactant as a 1 percent solution in deionized water is from 28℃ to 95℃.