Enhanced oil recovery process with hydrocarbon-soluble surfactant

Abstract

An enhanced oil recovery (EOR) process uses light hydrocarbon injection gas and a hydrocarbon-soluble nonionic surfactant to create foam. The nonionic surfactant comprises hydrophilic polyethylene glycol-polypropylene glycol copolymer terminated by a lipophilic chain. An anionic surfactant that comprises linear alkyl-diaryloxide disulfonate is added to increase the cloud point of the nonionic surfactant and / or the hydrocarbon solubility of the nonionic surfactant.

Description

[0001] ENHANCED OIL RECOVERY PROCESS WITH HYDROCARBON-SOLUBLE SURFACTANT

[0002] FIELD

[0003] This invention relates to the field of enhanced oil recovery.

[0004] INTRODUCTION

[0005] Recovery of crude oil from an underground oil field (also called a reservoir) often proceeds in three stages, called primary, secondary and tertiary recovery. The reservoir typically contains sand and / or porous rock with oil between the grains and / or in the pores. In primary oil recovery, a production well is drilled into the reservoir, and the natural pressure in the well and force of gravity propel crude oil through the pores to the production well, where it is pumped to the surface. This method frequently recovers only about 10 to 20 percent of the oil in the reservoir.

[0006] 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.

[0007] 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. (For clarity, the term “gas” is commonly applied to materials that are gases at IUPAC standard temperature and pressure (0°C and 1 bar), even if the material may be in a supercritical state rather than a gaseous state under the temperature and pressure used in the EOR process.) Injection gas adds pressure to drive oil to the production well. In addition, some injection gases (such as carbon dioxide and light hydrocarbon gases) dissolve in the oil and reduce its viscosity, so that the oil flows more effectively to the production well. Viscosity reduction is important for recovery of highly viscous crude oil such bitumen. 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.

[0008] Another gas EOR technique uses a single well as both the injection well and the production well. The rock of the reservoir may be too non-porous for oil to flow from an injection well to a production well. However, soluble gases can still reduce the viscosity of the oil and allow the oil to flow back to the well. The injection gas is injected into the well at high pressure (optionally with steam to add heat). Then the well is allowed to rest while the injection gas and heat infuse into the oil and reduce its viscosity. After time, less-viscous oil can be driven by gravity and gas pressure to the well, where it can be pumped to the surface.

[0009] Light hydrocarbon (LHC) gases, such as methane, ethane, propane, butane and mixtures such as natural gas, may be advantageous for use as injection gases for EOR. Light hydrocarbon gases are often convenient to obtain at the reservoir site; the oil reservoir itself produces light hydrocarbon gases that can be captured onsite and injected back into the reservoir. Further, light hydrocarbon gases can be miscible with oil in the reservoir.

[0010] The effectiveness of gas EOR processes can be reduced by poor sweep of the reservoir. Poor sweep can result from gas-channeling (also called gas-fingering) or from gas override. In gas channeling, the injection gas flows rapidly and easily through a few high-permeability layers in a reservoir and does not interact with less-permeable layers of the reservoir or with oil in those layers. In gas override, the reservoir forms a three-layer structure with water at the bottom, oil in the middle and injection gas on top. The gas flows easily above the oil- and water-containing layers of the reservoir toward the production well and does not interact with the oil or the water.

[0011] 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 in the reservoir to make a viscous foam. The water may be present in the reservoir or may be injected into the reservoir simultaneously with or alternating with the injection gas. The foam increases the viscosity of the injection gas and retards the flow of gas in high permeability gas channels and gas layers.

[0012] Foam may also be useful in single- well gas EOR. Rock that is too dense for crude oil to flow may still have cracks and pores that allow high pressure gas to flow out of the reservoir before the gas can infuse into the oil. Foam may slow the flow of injection gas and trap the gas near the well long enough to dissolve in oil near the well.

[0013] The surfactants used in the process are generally water-soluble surfactants that can be mixed with water injected into the injection well. Water in reservoirs is often briny, and so solubility in brine is desirable to avoid surfactant precipitating and either adsorbing to rock or plugging the pores of the reservoir.

[0014] SUMMARY

[0015] When surfactant is injected to create foam with LHC gas, it is desirable that the surfactant should be soluble in both water and the LHC injection gas, rather than a surfactant soluble in water only.

[0016] Surfactant that is dissolved in the LHC gas gets carried by the gas to the gas channels (in the case of gas channeling) or to the gas layer (in the case of gas override), where the foam is most effective. On the other hand, surfactant dissolved in water may never reach the gas channels or gas layer and not reach gas needed for in-situ foam generation.

[0017] The relative solubility of the surfactant in the LHC gas and in brine can be measured using a variable called the partition coefficient (Kp). See Katiyar et al, “Low Adsorbing CO2 Soluble Surfactants for Commercially Viable Implementation ofCO2 Foam EOR Technology”, Society of Petroleum Engineers Publ. SPE-206361-MS (2021). The partition coefficient (Kp) is the ratio of the relative concentration at which surfactant partitions between a specific injection gas and a specific brine at a specific temperature and pressure. Many surfactants that are soluble in LHC gas have low solubility in water and brine, especially at moderate to high temperatures. As a result, the gas-soluble surfactants have a low cloud point temperature. Above the cloud point temperature, surfactant phase separates from the aqueous phase in the reservoir. Precipitated surfactant is ineffective for producing foam and can plug or damage the reservoir.

[0018] Therefore, it is desirable to identify surfactant compositions that have both (i) high partition coefficient between LHC gas and brine; and (ii) high cloud point temperature in brine.

[0019] One aspect of this invention is a gas EOR process performed at an oil reservoir, which process comprises the step of injecting into the reservoir (I) an injection gas that contains light hydrocarbon gas and (II) a surfactant mixture, together or separately, wherein (and characterized in that) the gas-soluble surfactant mixture comprises:

[0020] 1. A nonionic surfactant that comprises a hydrophilic segment and a lipophilic segment, wherein a. The lipophilic segment comprises a hydrocarbyl moiety that has on average more than 8 carbon atoms; and

[0021] b. The hydrophilic segment comprises a hydrophilic polyethylene glycol-polypropylene glycol copolymer; and

[0022] c. The nonionic surfactant has a partition coefficient (Kp) of at least 0.05 between ethane and a brine that contains 0.2 weight percent (wt%) NaCl, at 25°C, 3000 psi pressure and 1 wt% initial concentration in the brine; and

[0023] 2. An anionic surfactant that comprises

[0024] a. a di-aryl oxide moiety,

[0025] b. an unbranched aliphatic moiety containing at least 6 carbon atoms bonded to the di-aryl oxide moiety and

[0026] c. at least one pendant sulfonic acid or sulfonic acid salt moiety bonded to the di-aryl oxide moiety,

[0027] wherein the weight ratio of anionic surfactant to nonionic surfactant is from 2:10 to 30:10, and the surfactant mixture is present in a concentration suitable to generate viscous foam with the injection gas and water.

[0028] Surfactant mixtures of this invention can have higher cloud points in water than the nonionic surfactant alone and optionally also higher partition coefficient than the nonionic surfactant alone, which indicates higher solubility in both water and the LHC gas.

[0029] BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 illustrates an apparatus used for performing core flooding tests.

[0031] Figure 2 shows a graph of results from core flooding experiments. DETAILED DESCRIPTION

[0032] This invention is a gas enhanced oil recovery (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. In some embodiments, a production well reaches the oil reservoir, and an injection well reaches the oil reservoir at a distance from the production well. Injections of injection gas (and optionally stream or water) at the injection well push oil toward the production well, where the oil can be pumped to the surface. In some embodiments, a single well is both injection well and production well. Injections of injection gas (and optionally stream) through the well reduce the viscosity of oil in the reservoir so that it can later be pumped to the surface through the 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 gas EOR. See, for example, US Patents 5,363,915 and 9,874,079 B2; and “Enhanced Oil Recovery” at

[0033]

[0034] Injection gas that contains light hydrocarbon (LHC) gas is injected into the reservoir as part of the gas EOR process. The injection pressure 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) at 25°C.

[0035] In some embodiments, the gas EOR process is a 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.

[0036] The injection gas contains LHC gas. In some embodiments, the injection gas contains at least 10 mole percent LHC gas, or at least 20 mole percent LHC gas or at least 30 mole percent LHC gas or at least 40 mole percent LHC gas or at least 50 mole percent LHC gas or at least 60 mole percent LHC gas or at least 70 mole percent LHC gas or at least 80 mole percent LHC gas or at least 90 mole percent LHC gas or at least 95 mole percent LHC gas. In some embodiments the injection gas contains up to 100 mole percent LHC gas (excluding the surfactant mixture). In some embodiments, the injection gas further contains steam, nitrogen, carbon dioxide, hydrogen or hydrogen sulfide.

[0037] Light hydrocarbon (LHC) gas is a hydrocarbon composition that is gaseous at IUPAC standard temperature and pressure (0°C and 1 bar). Examples of LHC gases include methane, ethane, propane, butane, pentane and mixtures such as natural gas. In some embodiments, the LHC gas is a natural gas. In some embodiments, the organic components of the LHC 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 LHC gas can contain up to 100 mole percent methane. In some embodiments, the LHC 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 LHC components that may be part LHC gas include ethane, propane, butanes and pentanes.

[0038] 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.

[0039] A surfactant mixture is injected into the injection well. The surfactant mixture contains a nonionic surfactant and an anionic surfactant. In some embodiments, the surfactant mixture is mixed with injection gas that contains LHC to be injected into the injection well. In some embodiments, the surfactant mixture may be mixed with water to be injected into the injection well. Mixing with the injection gas may be more effective in carrying the surfactant to gas channels.

[0040] The nonionic surfactant contains a lipophilic segment bonded to a hydrophilic segment. The lipophilic segment of the nonionic surfactant is a hydrocarbyl moiety that contains on average more than 8 carbon atoms. In some embodiments, the lipophilic segment of the nonionic surfactant is branched. In some embodiments, the lipophilic segment of the nonionic surfactant is linear. In some embodiments, the lipophilic segment of the nonionic surfactant is an alkyl moiety. In some embodiments, the lipophilic segment of the nonionic surfactant is a linear alkyl moiety. In some embodiments, the lipophilic segment of the nonionic surfactant 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 of the nonionic surfactant 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 of the nonionic surfactant 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.

[0041] In some examples, a mixture of nonionic 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.

[0042] The hydrophilic segment of the nonionic surfactant comprises hydrophilic polyethylene glycolpolypropylene glycol (PEG-PPG) copolymer. The PEG-PPG copolymer contains repeating ethylene glycol units as illustrated in Formula 1.

[0043] (1) f-O-CH2-CH2-}

[0044] and repeating propylene glycol units as illustrated in Formula 2, wherein R a pendant methyl group. (2) I-O-CH2-CHR+

[0045] In some embodiments, the PEG-PPG copolymer segment further contains other repeating units, such as butylene glycol units which meet Formula in which R is an ethyl group, or other repeating units in which R contains 3 to 6 carbon atoms. In some embodiments, at least 70 mole percent of repeating units in the PEG-PPG copolymer segment are ethylene glycol units or propylene glycol units, or at least 75 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 or up to 100 mole percent.

[0046] 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 PEG-PPG copolymer segment contains one block of ethylene glycol units and one block of propylene glycol units. In some embodiments, the PEG-PPG copolymer 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.

[0047] In some embodiments, the hydrophilic segment of the nonionic surfactant contains on average at least 4 ethylene glycol units per molecule 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 of the nonionic surfactant contains on average at most 24 ethylene glycol units per molecule 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 of the nonionic surfactant may contain on average from 4 to 20 ethylene glycol units per molecule or from 5 to 18 ethylene glycol units per molecule.

[0048] In some embodiments, the hydrophilic segment of the nonionic surfactant contains on average at least 3 propylene glycol units per molecule 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 of the nonionic surfactant contains on average at most 24 propylene glycol units per molecule 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 of the nonionic surfactant may contain from 3 to 12 propylene glycol units per molecule.

[0049] In some embodiments, the average number ratio of ethylene glycol units to propylene glycol units in the nonionic surfactant 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 average number ratio of ethylene glycol units to propylene glycol units in the nonionic surfactant 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 average number ratio of ethylene glycol units to propylene glycol units in the nonionic surfactant may be from 0.5 to 2.5 or from 0.6 to 2. Surfactants are sometimes classified based on hydrophilic-lipophilic balance, as determined by the Griffin method, abbreviated HLBG. In some embodiments, the nonionic surfactant 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 nonionic surfactant 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 nonionic surfactant may have an HLBG from 6 to 10 or from 6.2 to 9.8.

[0050] Surfactants are sometimes classified based on hydrophilic-lipophilic balance, as determined by the Effective Chain Length method, abbreviated HLBECL- In some embodiments, the nonionic surfactant used in this invention has an HLBECL 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 nonionic 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.

[0051] The nonionic surfactant is chosen so that (at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine) its partition coefficient (Kp) between ethane and the brine is at least 0.05. In some embodiments (at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine), the Kp of the nonionic surfactant between ethane and 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 (at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine), the Kp of the nonionic surfactant between ethane and the brine is at most 50 or at most 30 or at most 10 or at most 1.

[0052] In some embodiments (at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine), the partition coefficient (Kp) of the nonionic surfactant between the injection gas and the brine is at least 0.05. In some embodiments (at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine), the Kp of the nonionic surfactant between the injection gas and 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 (at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine), the Kp of the nonionic surfactant between the injection gas and the brine is at most 50 or at most 30 or at most 10 or at most 1.

[0053] In addition to being soluble in the injection gas, the nonionic 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 nonionic surfactant has a cloud temperature limit in deionized water (1 wt% concentration of surfactant) of at least 20°C or at least 25 °C or at least 30°C or at least 40°C or at least 50°C. In some embodiments, the nonionic surfactant has a cloud temperature limit in 4% NaCl brine water (1 wt% concentration of surfactant) of at least 20°C or at least 25 °C or at least 30°C or at least 40°C or at least 50°C. In some embodiments, the nonionic surfactant has a cloud temperature limit in deionized water (1 wt% concentration of surfactant) of at most 70°C or at most 60°C or at most 50°C or at most 40°C or at most 30°C or at most 25°C or at most 20°C. In some embodiments, the nonionic surfactant has a cloud temperature limit in 4% NaCl brine water (1 wt% concentration of surfactant) of at most 70°C or at most 60°C or at most 50°C or at most 40°C or at most 30°C or at most 25°C or at most 20°C.

[0054] 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.

[0055] The anionic surfactant comprises (A) a di-aryl oxide moiety, (B) an unbranched aliphatic moiety containing at least 6 carbon atoms bonded to the di-aryl oxide moiety and (C) at least one pendant sulfonic acid or sulfonic acid salt moiety bonded to the di-aryl oxide moiety. The di-aryl oxide moiety meets the following Formula 1 :

[0056] (1) Ar-O-Ar

[0057] wherein each Ar is independently an aryl group, such as a phenyl, tolyl or cumenyl group. At least one of the aryl groups is bonded to a lipophilic moiety. At least one of the aryl groups has a pendant sulfonic acid or sulfonic acid salt moiety. In some embodiments, each aryl group has a pendant sulfonic acid or sulfonic acid salt moiety. We hypothesize (without intending to be bound) that the aryl groups and the unbranched aliphatic moieties form a lipophilic portion of the anionic surfactant, and the sulfonic acid (salt) moieties form a hydrophilic portion of the anionic surfactant.

[0058] In some embodiments, the anionic surfactants meet the following Formula 2:

[0059]

[0060] wherein at least one A is a sulfonic acid or sulfonic acid salt moiety and at least one of R1and R2is a lipophilic moiety. In some embodiments, only one A is a sulfonic acid or sulfonic acid salt moiety; in some embodiments, each A is independently a sulfonic acid or sulfonic acid salt moiety. In some embodiments, only one of R1and R2is a lipophilic moiety; in some embodiments, each of R1and R2is independently a lipophilic moiety. In some embodiments, the phenyl rings have one or more pendant lower alkyl groups, and in some embodiments the phenyl rings are unsubstituted.

[0061] In some embodiments, the aliphatic moieties (R1and R2) are unsaturated. In some embodiments, aliphatic moieties (R1and R2) are saturated. In some embodiments, lipophilic moieties (R1and R2) are alkyl groups.

[0062] In some embodiments, the aliphatic moieties (R1and / or R2) independently contain on average at least 6 carbon atoms or at least 10 carbon atoms or at least 12 carbon atoms. In some embodiments, the aliphatic moieties of the anionic surfactants independently contain 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.

[0063] In some embodiments, the aliphatic moieties of the anionic surfactants (R1and / or R2) collectively contain on average at least 12 carbon atoms per molecule or at least 14 carbon atoms or at least 16 carbon atoms or at least 18 carbon atoms or at least 20 carbon atoms. In some embodiments, the aliphatic moieties of the anionic surfactants collectively contain on average at most 32 carbon atoms per molecule or at most 30 carbon atoms or at most 28 carbon atoms or at most 26 carbon atoms.

[0064] The di-aryl oxide moiety of the anionic surfactant contains is bonded to on average at least one pendant sulfonic acid group or sulfonic acid salt (A) . In some embodiments, the di-aryl oxide moiety of the anionic surfactant is bonded to on average two pendant sulfonic acid groups or sulfonic acid salts (A). In some embodiments, each aryl group in the di-aryl oxide moiety is bonded to a pendant sulfonic acid group or sulfonic acid salt (A). Examples of suitable sulfonic acid salts include alkaline or alkaline earth metal salts and ammonium salts.

[0065] Examples of the anionic surfactants are sold commercially by The Dow Chemical Company under the DOWFAX™ trademarks. Commercial anionic surfactants that contain di-aryl oxide moieties are frequently sold as solutions containing 30 to 80 wt% water. Others can be made by known processes such as by a two-step process comprising:

[0066] (a) a Friedel Crafts reaction of an olefin with diaryl oxide, using aluminum trichloride as a catalyst, to add the aliphatic lipophilic moieties to the diaryl oxide; and

[0067] (b) reaction of the product of step (a) with sulfur trioxide or another sulfonating agent in a solvent such as sulfur dioxide, methylene chloride or air.

[0068] Suitable reactions are described in US Patent 6,743,764 Bl .

[0069] The weight ratio of anionic surfactant to nonionic surfactant is at least 2:10. In some embodiments, the weight ratio of anionic surfactant to nonionic surfactant is at least 3:10 or at least 4:10 or at least 5:10 or at least 6:10 or at least 7: 10 or at least 8:10 or at least 9:10 or at least 10:10. The weight ratio of anionic surfactant to nonionic surfactant is at most 30: 10. In some embodiments, the weight ratio of anionic surfactant to nonionic surfactant is at most 25:10 or at most 20:10 or at most 18:10 or at most 15:10 or at most 12:10 or at most 10: 10.

[0070] The surfactant mixture forms 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 mixture 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 mixture 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.

[0071] In some embodiments, the nonionic surfactant and the anionic surfactant are mixed together to form the surfactant mixture, before they are added to the injection gas or water. In some embodiments, the nonionic surfactant and the anionic surfactant are added separately to the injection gas or water and form the surfactant mixture in the injection gas or water. The individual surfactants and / or the surfactant mixture 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 surfactants in the liquid formulation may be any concentration which produces a stable formulation and effectively delivers the surfactants into the reservoir in suitable quantities. The best concentrations may vary depending on the selection of surfactants and solvent. In some embodiments, the liquid formulation contains at least 5 wt% surfactant(s) 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(s) may be used neat (100 wt%).

[0072] The surfactant mixture desirably has a cloud point that is higher than the cloud point of the nonionic surfactant alone, when measured at 1 wt% concentration in distilled water according to the Test Methods. In some embodiments, cloud point of the surfactant mixture is at least 1°C higher than cloud point of the nonionic surfactant alone, or at least 5°C higher or at least 10°C higher or at least 15°C higher or at least 20°C higher or at least 25°C higher or at least 30°C higher or at least 35°C higher. In some embodiments, cloud point of the surfactant mixture is at most 70°C higher than cloud point of the nonionic surfactant alone, or at most 60°C higher or at most 50°C higher or at most 45°C higher or at most 40°C higher.

[0073] In some embodiments, when the partition coefficient (Kp) of the surfactant mixture is tested at 25°C, 3000 psi pressure and 1 wt% initial concentration in 0.2 wt% NaCl brine:

[0074] • Kp of the surfactant mixture between the injection gas and 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;

[0075] • Kp of the surfactant mixture between the injection gas and the brine is at most 50 or at most 30 or at most 10 or at most 1;

[0076] • Kp of the surfactant mixture between ethane and 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; and

[0077] • Kp of the surfactant mixture between ethane and the brine is at most 50 or at most 30 or at most 10 or at most 1.

[0078] In some embodiments, when Kp of the surfactant mixture is tested at 25°C, 3000 psi pressure and 3 g / L initial concentration in 0.2 wt% NaCl brine:

[0079] • Kp of the surfactant mixture between the injection gas and the brine is at least 80% of the Kp of the nonionic surfactant between the injection gas and the brine, or at least 90% or at least 100% or at least 110% or at least 125% or at least 150% or at least 160% or at least 170%; and

[0080] • Kp of the surfactant mixture between ethane and the brine is at least 80% of the Kp of the nonionic surfactant between ethane and the brine, or at least 90% or at least 100% or at least 110% or at least 125% or at least 150% or at least 160% or at least 170%.

[0081] In some embodiments, when the Kp of the surfactant mixture is tested at 25°C, 3000 psi pressure and 12 g / L initial concentration in 0.2 wt% NaCl brine: • Kp of the surfactant mixture between the injection gas and the brine is at least 100% of the Kp of the nonionic surfactant between the injection gas and the brine, or at least 125% or at least 150% or at least 175% or at least 200% or at least 225% or at least 250%; and

[0082] • Kp of the surfactant mixture between ethane and the brine is at least 100% of the Kp of the nonionic surfactant between ethane and the brine, or at least 125% or at least 150% or at least 175% or at least 200% or at least 225% or at least 250%.

[0083] The surfactant mixture is mixed with the injection gas or water before or during the gas EOR process. The concentration of surfactant mixture in the injection gas or water should be suitable to generate viscous foam in the reservoir. The optimum concentration of surfactant mixture 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 mixture 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 mixture in the injection gas is at most 10 wt% or at most 5 wt% 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.

[0084] The surfactant mixture does not need to be added to all slugs of injection gas or water or to all injection gas or water in a given slug. In some embodiments, at least 5 percent of injection gas contains surfactant mixture 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 mixture, or up to 80 percent or up to 60 percent or up to 40 percent.

[0085] 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%.

[0086] Except for the addition of surfactant mixture to the injection gas or water, the gas EOR process may be carried out by ordinary procedures as previously described. We hypothesize, without intending to be bound, that injection gas can carry the surfactant mixture to high permeability areas of the reservoir. Even when the surfactant mixture is dissolved in water, it can partition into injection gas that contacts the water and be carried by the gas. The injection gas, the surfactant mixture and water 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.

[0087] 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). 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 the surfactant mixture 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 the surfactant mixture 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.

[0088] TEST METHODS

[0089] 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.

[0090] Hydrophilic Lipophilic Balance (Griffin Method) (HLBG): See Griffin, Calculation of HLB Values of Non-lonic Surfactants, 1954 J. Soc. Cosmetic Chemists 249 (1954)

[0091] 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. https: / / doi.org / 10.1016 / jjcis.2005.12.009

[0092] Partitioning Coefficient (Kp)

[0093] The following steps are carried out at room temperature.

[0094] 1. Surfactant is dissolved at the desired concentration (3 g / L or 12 g / L) in a brine solution containing 3 wt% NaCl. The surfactant solution is added to a high pressure cell to fill half the cell volume.

[0095] 2. The cell is pressurized with LHC gas to 3000 psi. The volume ratio of LHC gas and surfactant solution in the cell is 1 : 1 (equal volumes).

[0096] 3. The cell is mixed regularly for 3 days at 50°C, except solutions that contain just ITS3 are mixed at 40°C to avoid clouding.

[0097] 4. The cell is depressurized by slowly venting the LHC gas from the top of the cell.

[0098] 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 determined using an Agilent 6130 mass spectroscopy device.

[0099] 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

[0100] Wherein

[0101] • C Gas-Partitioned is the concentration of surfactant dissolved in the gas at 3000 psi, in g / L

[0102] • C Brine initial is the concentration of surfactant dissolved in the surfactant solution before partitioning, in g / L; and

[0103] • C Brine-Partitioned is the concentration of surfactant dissolved in the surfactant solution after partitioning, in g / L.

[0104] 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) •

[0105] (2) Kp = C Gas-Partitioned / C Brine -Partitioned Cloud Point Temperature

[0106] Cloud point temperature (or “cloud point”) is tested in deionized water or in NaCl brine. Surfactant solutions are prepared to 1 wt% concentration in the deionized water or brine and added to 10 ml glass vials. The vials are placed in a temperature controlled oven. The temperature is increased and allowed to equilibrate in steps; and a rough cloud point temperature is determined visually as the temperature the surfactant solution starts to cloud. Then several tests are performed in which samples are started at a temperature about 5 °C below the rough cloud point temperature. The oven temperature is increased in 1°C increments and the vials are given 30 minutes to equilibrate at each temperature. The cloud point for each sample is determined visually as the temperature the sample begins to cloud. The results are averaged to determine the cloud point temperature for the solution.

[0107] Foam Viscosity

[0108] Foam viscosity is measured by core flooding tests. Figure 1 shows the apparatus used for coreflood tests. The apparatus contains a 1 foot long 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 the temperature of the test

[0109] 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 (BPR-2 and BPR3) 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.)

[0110] The pressure drop across the porous core is recorded. The apparent viscosity of foam is calculated using Darcy’s law:

[0111] (2) (ia= [k (AP)] / [L (vdarcy)]

[0112] Where |tais the apparent viscosity of the foam in cP, AP / 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 v darcy is the superficial velocity in cm / s. After each test, the core is flooded with brine until the initial permeability is restored.

[0113] EXAMPLES

[0114] The following Examples illustrate cloud point, partitioning and foam formation of surfactant mixtures used in some embodiments of the invention.

[0115] The surfactants shown in Table 1 are obtained. Table 1

[0116]

[0117] Cloud Point Measurement

[0118] Solutions shown in Table 2 are made by dissolving surfactants shown in Table 2 in distilled water in the weight ratio shown, to achieve 1 wt% concentration of surfactant. The cloud point of each solution is measured as set out in the Test Methods. Results are shown in Table 2. The results show that the blends of ITS3 and ANSI in distilled water have higher cloud points than ITS3 alone.

[0119] Partition Index Measurement

[0120] Solutions shown in Table 2 are made by dissolving surfactants shown in Table 2 in 3% brine. The concentration of ITS3 is either 3 g / L: or 12 g / L as shown in Table 2. The partition coefficient between ethane and brine for each solution is measured as described in the Test Methods. Results are shown in Table 2. The results show that the blends of ITS3 and ANSI have higher solubility in ethane than ITS3 alone, whereas the blends of ITS3 and ANS2 have lower to unchanged solubility in ethane than ITS3 alone.

[0121] Table 2

[0122]

[0123] Foam Viscosity

[0124] Three solutions are made that contain surfactant in brine. The first solution, which is an example of the invention, contains 0.5 weight percent ITS3 and 0.16 weight percent ANSI. The second solution, which is not an example of the invention, contains only 0.5 weight percent ITS3. The third solution, which is not an example of the invention, contains 0.5 weight percent APG.

[0125] Each solution is tested for foam viscosity as described in the Test Methods. The foam is made by co-injecting the solution with ethane. The foam quality is 50 percent. The total flow rate is 10 ft / day. The testing temperatures are shown in Figure 2. The results are shown in Figure 2.

Claims

CLAIMS:

1. A gas EOR process performed at an oil reservoir, which process comprises the step of injecting into the reservoir (I) an injection gas that contains light hydrocarbon gas and (II) a surfactant mixture, together or separately, wherein the gas-soluble surfactant mixture comprises:a) a nonionic surfactant that comprises a hydrophilic segment and a lipophilic segment, wherein:i) the lipophilic segment comprises a hydrocarbyl moiety that has on average more than 8 carbon atoms; andii) the hydrophilic segment comprises a hydrophilic polyethylene glycol-polypropylene glycol copolymer; andiii) the nonionic surfactant has a partition coefficient (Kp) of at least 0.05 between ethane and a brine that contains 0.2 weight percent NaCl, at 25 °C , 3000 psi pressure and 1 wt% initial concentration in the brine; andb) an anionic surfactant that comprises:i) a di-aryl oxide moiety,ii) an unbranched aliphatic moiety containing at least 6 carbon atoms bonded to the di-aryl oxide moiety andiii) at least one pendant sulfonic acid or sulfonic acid salt moiety bonded to the di-aryl oxide moiety,wherein the weight ratio of anionic surfactant to nonionic surfactant is from 2:10 to 30:10, and the surfactant mixture is present in a concentration suitable to generate viscous foam with the injection gas and water.

2. The enhanced oil recovery process of Claim 1 wherein the surfactant mixture is mixed with injection gas and injected into the reservoir together with injection gas.

3. The enhanced oil recovery process of Claim 2 wherein the lipophilic segment of the nonionic surfactant contains a linear alkyl moiety having on average from 9 to 18 carbon atoms; and the hydrophilic segment of the nonionic surfactant contains one or more block of polyethylene glycol polymer and one or more block of polypropylene glycol polymer.

4. The enhanced oil recovery process of Claim 3 wherein the hydrophilic segment of the nonionic surfactant contains on average from 5 to 20 ethylene glycol units.

5. The enhanced oil recovery process of Claim 4 wherein the ratio of ethylene glycol units to propylene glycol units in the hydrophilic segment of the nonionic surfactant is 0.5 to 2.5.

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

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

8. The enhanced oil recovery process of Claim 2 wherein:a) the nonionic surfactant comprises a lipophilic segment that contains a linear alkyl moiety having on average from 9 to 18 carbon atoms;b) the hydrophilic segment of the nonionic surfactant contains on average from 5 to 20 ethylene glycol units and wherein the ratio of ethylene glycol units to propylene glycol units in the hydrophilic segment of the nonionic surfactant is 0.5 to 2.5; andc) wherein the hydrophilic-lipophilic balance of the nonionic surfactant, as determined by the Griffin method, is from 5.0 to 12.

9. The enhanced oil recovery process of Claim 2 wherein the anionic surfactant meets Formula 2wherein at each A is a sulfonic acid or sulfonic acid salt moiety, and at least one of R1and R2is an unbranched aliphatic lipophilic moiety containing at least 8 carbon atoms, and R1and R2collectively contain on average from 12 to 32 carbon atoms per molecule.

10. The enhanced oil recovery process of Claim 2 wherein the weight ratio of anionic surfactant to nonionic surfactant in the surfactant mixture is from 2:10 to 12:10.

11. The enhanced oil recovery process of Claim 2 whereina) the nonionic surfactant comprises a lipophilic segment that contains a linear alkyl moiety having on average from 9 to 18 carbon atoms;b) the hydrophilic segment of the nonionic surfactant contains on average from 5 to 20 ethylene glycol units and wherein the ratio of ethylene glycol units to propylene glycol units in the hydrophilic segment of the nonionic surfactant is 0.5 to 2.5; andc) wherein the hydrophilic-lipophilic balance of the nonionic surfactant, as determined by the Griffin method, is from 5.0 to 12; andd) the anionic surfactant meets Formula 2wherein the phenyl rings illustrated in Formula 2 are unsubstituted except for A, R1and R2; each A is independently a sulfonic acid or sulfonic acid salt moiety; R1and R2are selected from hydrogen atoms and alkyl moieties; and R1and R2collectively contain on average from 12 to 32 carbon atoms per molecule; ande) the weight ratio of anionic surfactant to nonionic surfactant in the surfactant mixture is from 2: 10 to 12:10.

12. The enhanced oil recovery process of Claim 11 wherein injection gas is injected into the reservoir through an injection well, and oil is recovered from the reservoir through a separate production well.

13. The enhanced oil recovery process of Claim 11 wherein a single well functions both as an injection well through which injection gas is injected into the reservoir and as a production well through which oil is recovered from the reservoir.

14. The enhanced oil recovery process of any one of Claims 1 to 13 wherein the cloud point of the surfactant mixture is at least 10°C higher than cloud point of the nonionic surfactant alone.

15. The enhanced oil recovery process of Claim 14 wherein, at 25°C, 3000 psi pressure and 3 g / L initial concentration in 0.2 wt% NaCl brine, the partition coefficient of the surfactant mixture between ethane and brine is at least 110% of the partition index of the nonionic surfactant alone between ethane and brine.

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