Fracturing process with hydrocarbon-soluble surfactant

Abstract

The invention is a fracturing process performed on a hydrocarbon reservoir that is reached by a well. A foaming composition containing hydrocarbon gas, water and a surfactant is injected at high pressure into the well. The hydrocarbon gas contains primarily hydrocarbons other than methane. In the invention, the surfactant: 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 hydrocarbon 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.

Description

[0001] FRACTURING PROCESS WITH HYDROCARBON-SOLUBLE SURFACTANT

[0002] FIELD

[0003] This invention relates to the field of reservoir fracturing.

[0004] INTRODUCTION

[0005] Hydraulic fracturing is used to increase the flow of crude oil and other hydrocarbons from low- permeability portions of a subterranean reservoir. In traditional hydraulic fracturing, fracturing fluid such as water is injected through a well bore into the reservoir at a rate and pressure that exceeds the formation fracture strength, such that fractures are created or expanded in the rock of the reservoir. Pressures in hydraulic fracturing are usually at least 3000 psi and more often from 8,000 to 20,000 psi. Fractures created or expanded by the high pressure fracturing fluid form cracks that propagate outward from the well bore. One or more particulate materials, known as proppants, are suspended in the fracturing fluid. The proppants are deposited in the newly created or expanded fractures and prevent the fractures from closing when the pressure is withdrawn. The fractures increase the permeability of the rock, allowing the hydrocarbons to flow to the well bore where it can be withdrawn.

[0006] Some types of hydraulic fracturing use water as the fracturing fluid; the water sometimes contains a gelling agent to increase its viscosity. In some techniques, the fracturing fluid is a viscous foam containing water, gas and a surfactant. Gases used in foam fracturing include carbon dioxide, nitrogen and hydrocarbons such as natural gas. Fracturing fluids that contain these gases are sometimes called “energized” fracturing fluids. See, for example, “Benefits of Energized Solutions in Fracturing”, published by The Linde Group (2018); Karadkar et al., “Energized Fluids for Upstream Production Enhancement: A Review”, Publication SPE-192255-MS, published by the Society of Petroleum Engineers (2018); and Pankaj et al., “Application of Natural Gas for Foamed Fracturing Fluid in Unconventional Reservoirs” , Publication SPE-191863-MS, published by the Society of Petroleum Engineers (2018). It is known that the “gas” used in foam fracturing is a gas at IUPAC standard temperature and pressure (0°C and 1 bar) but is often a supercritical fluid at the pressures and temperatures used for fracturing, combining properties of both a liquid and a gas.

[0007] In some cases, it has been desirable to increase the ratio of gas to water in the foam in order to reduce water consumption from the fracturing procedure. See, for example, Malpani et al., “Reducing the Volume of Water Needed for Hydraulic Fracturing by Employing Natural Gas Foamed Stimulation Fluid', Publication SPE-201450-MS, published by the Society of Petroleum Engineers (2020). In some cases, the reservoir may be in a location where fresh water is difficult or expensive to obtain. In some cases, the reservoir may contain formations that are sensitive to water.

[0008] SUMMARY

[0009] Improved techniques for low-water fracturing are needed. Foam viscosity may be difficult to maintain in low-water fracturing processes because the aqueous foam loses viscosity as the amount of water in the foam is reduced. The loss of viscosity limits the ability to reduce water use in foam fracturing operations. Further, in some cases, water settles out of the foam in the reservoir and carries the surfactant that is dissolved in the water to the bottom layers of the reservoir, so that foam dries out and becomes unstable, leading to viscosity loss. Combinations of gas and surfactant to overcome these problems are needed.

[0010] One aspect of this invention is a fracturing process, performed at a hydrocarbon reservoir that has a well for injecting fracturing fluid into the reservoir to increase the flow of hydrocarbon to the well, which process comprises the step of injecting into the well, at a pressure and injection rate suitable for fracturing, the following components which are collectively called a foaming composition:

[0011] 1. a hydrocarbon gas that contains on average more than 1.5 carbon atoms per molecule;

[0012] 2. water; and

[0013] 3. a nonionic surfactant that a. comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment, which contains on average more than 8 carbon atoms; and b. has a partition coefficient (Kp) between the hydrocarbon gas and 0.2 weight percent (wt.%) NaCl brine of at least 0.05, at 25°C, 3000 psi pressure and 1 % initial concentration in the brine; and c. is present in a concentration suitable to generate viscous foam containing the hydrocarbon gas and water, wherein the foaming composition contains more than 50 volume percent gas at the pressures used for the fracturing process, based on the combined volume of gas and water.

[0014] As previously described, the term “hydrocarbon gas” means that the material is a gas at IUPAC standard temperature and pressure (0°C and 1 bar); the hydrocarbon gas may be a supercritical fluid under the conditions of the fracturing process. In this application, the hydrocarbon gas, water and surfactant are collectively referred to as a “foaming composition.” The components of the foaming composition may be injected into the well separately or together as further described in this application.

[0015] A second aspect of this invention is an aqueous foam that contains:

[0016] 1. a continuous phase of water;

[0017] 2. a discontinuous phase of supercritical hydrocarbon gas that is dispersed in the water and that contains on average more than 1 .5 carbon atoms per molecule; and

[0018] 3. a nonionic surfactant that a. comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment, which contains on average more than 8 carbon atoms; and b. has a partition coefficient (Kp) between the hydrocarbon gas and 0.2 weight percent (wt.%) NaCl brine of at least 0.05, at 25°C, 3000 psi pressure and 1 % initial concentration in the brine; and c. is present in a concentration suitable to generate viscous foam containing the hydrocarbon gas and water, wherein the foam contains more than 50 volume percent gas, based on the combined volume of gas and water.

[0019] In some embodiments, the fracturing foams used in this invention can maintain high viscosity, even at very low water content such as no more than 30 or 20 or 10 volume percent. Further, surfactant dissolves in the hydrocarbon gas; in some embodiments, the hydrocarbon gas in the higher areas of the reservoir carries enough surfactant to sustain a viscous foam with ambient water in the reservoir, if the water in the foam settles lower in the reservoir.

[0020] BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Drawing 1 illustrates an apparatus used for performing core flooding tests.

[0022] Drawings 2 and 3 show graphs of results from core flooding experiments using foams that contain various surfactants and various hydrocarbon gases, with different levels of hydrocarbon gas in the foam. The level of hydrocarbon gas is described in terms of “foam quality,” which is described below.

[0023] DETAILED DESCRIPTION

[0024] One aspect of this invention is a fracturing process performed on an underground hydrocarbon reservoir. The hydrocarbon reservoir contains crude oil and / or hydrocarbon gas (hydrocarbons). In some embodiments, the hydrocarbon reservoir further contains water or brine. A well reaches the hydrocarbon reservoir. Pressurized fracturing fluid can be pumped down though the well to the reservoir, and hydrocarbons can be produced from the reservoir to the surface through the well. It is well-known in the oil-drilling art how to identify hydrocarbon reservoirs and how to select wells to perform fracturing. See, for example, King et al., “Hydraulic Fracturing 101”, published by the Society of Petroleum Engineers as SPE 152596 (2012).

[0025] In this invention, the fracturing process is accomplished by pumping into the well a foaming composition that contains hydrocarbon gas, water and surfactant. In some embodiments, the foaming composition is a foam when it is injected into the well. In some embodiments, the foaming composition forms a foam after it is injected into the well. For example, the components may be injected separately into the well and may mix to make the foam in the well or in the reservoir. The injection pressure and injection rate of the foaming composition may be any pressure and rate useful for the fracturing process. In some embodiments, the pressure is at least 3000 psi (20 MPa) or at least 5,000 psi (35 MPa) or at least 8,000 psi (55 MPa) or at least 10,000 psi (69 MPa) or at least 12,000 psi (83 MPa) or at least 14,000 (96 MPa) psi or at least 15,000 psi (100 MPa). In some embodiments, the pressure is at most 25,000 psi (170 MPa) or at most 23,000 psi (160 MPa) or at most 21,000 psi (140 MPa) or at most 20,000 psi (138 MPa). The hydrocarbon gas contains one or more hydrocarbons that are gaseous at standard temperature and pressure. Hydrocarbons in the hydrocarbon gas contain on average more than 1.5 carbon atoms per molecule. In some embodiments, hydrocarbons in the hydrocarbon gas contain on average at least 1.8 carbon atoms per molecule or at least 1.9 carbon atoms per molecule or at least 2 carbon atoms per molecule. In some embodiments, hydrocarbons in the hydrocarbon gas contain on average at most 5 carbon atoms per molecule or at most 4 carbon atoms per molecule or at most 3 carbon atoms per molecule or at most 2 carbon atoms per molecule.

[0026] In some embodiments, at least 80 weight percent of the hydrocarbons are alkyl, or at least 85 weight percent or at least 90 weight percent or at least 95 weight percent or at least 99 weight percent. In some embodiments, up to 100 weight percent or the hydrocarbons are alkyl.

[0027] Examples of hydrocarbon gases include ethane, propane, butane, pentane and mixtures thereof. Any isomers of butane and pentane may be used. The hydrocarbon gas may also contain less than 50 mole percent methane. In some embodiments, the hydrocarbon gas contains less than 30 mole percent methane or less than 20 mole percent or less than 10 mole percent; in some embodiments, the hydrocarbon gas contains 0 mole percent methane. In some embodiments, the hydrocarbon gas contains at least 50 mole percent ethane, or at least 60 mole percent or at least 70 mole percent or at least 80 mole percent or at least 90 mole percent. In some embodiments, the hydrocarbon gas contains up to 100 mole percent ethane.

[0028] In some embodiments, the hydrocarbon gas is miscible with oil under reservoir conditions. It is recognized that some gases have a minimum-miscibility pressure (MMP) based on the temperature and the composition of oil and hydrocarbon gas; 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.

[0029] In many embodiments, the hydrocarbon gas is a supercritical fluid at the pressure and temperature used in the fracturing process. Supercritical fluids combine properties of both liquids and gases. In particular, supercritical fluids may have density that is similar to a liquid, but may have diffusion and viscosity that is similar to a gas. In some embodiments, the supercritical hydrocarbon gas has a density of at least 0.2 g / mL or 0.25 g / mL. In some embodiments, the supercritical hydrocarbon gas has a density of at most 0.6 g / mL or 0.5 g / mL.

[0030] In some embodiments, the gas in the foaming composition may contain a minor amount (less than 50 mole percent) of a non-hydrocarbon gas. Examples of non-hydrocarbon gases include water vapor, carbon dioxide, hydrogen and hydrogen sulfide. In some embodiments, the gas in the foaming composition contains no more than 40 mole percent non-hydrocarbon gas, or no more than 30 mole percent or no more than 20 mole percent or no more than 10 mole percent or no more than 5 mole percent. In some embodiments, the hydrocarbon gas contains no detectable amount (as low as 0 mole percent) of non-hydrocarbon gas. The foaming composition also contains water. The ratio of gas to water in foam is reported in terms of “foam quality,” which is the volume percent of gas in the foam, based on the combined volume of gas and water. Foam quality is often estimated as the volume ratio of gas injected into the well to total fluid injected into the well; this estimate assumes that the injected gas and water mix completely to form foams under the conditions they are mixed. Foaming compositions used in this invention contain more than 50 volume percent gas at the pressures used for the fracturing process, based on the combined volume of gas and water. In some embodiments, the foam quality is at least 60 percent or at least 70 percent or at least 75 percent or at least 80 percent or at least 82 percent or at least 84 percent or at least 86 percent or at least 88 percent or at least 90 percent. In some embodiments, the foam quality is at most 95 percent or at most 92 percent or at most 90 percent.

[0031] The salinity (total dissolved solids) of the water can affect the ability of a surfactant to make foam. In some embodiments, the water has a salinity of no more than 3.5% or no more than 1% or no more than 0.3%. In some embodiments, that salinity of the water is as low as 100 ppm (For further discussion, see Godsey, “ Fresh, Brackish or Saline Water for Hydraulic Fracs: What are the Options?” published by the US E,P.A at https: / / www.epa.gov / sites / default / files / documents / 02_Godsey_- _Source_Options_508.pdf). The reservoir may contain soluble salts or brine, so the salinity of the water may change after the water is injected into the reservoir.

[0032] In some embodiments, the water may contain acid or base. In some embodiments, the pH of the water is at least 4 or at least 5 or at least 6 or at least 7. In some embodiments, the pH of the water is at most 10 or at most 9 or at most 8 or at most 7.

[0033] In some embodiments, the water may be mixed with a minor quantity (less than 50 weight percent) of a water-miscible co-solvent, such as ethanol, acetone or ethylene glycol. In some embodiments, the combined water and cosolvents contain at least 60 weight percent water, based solely on the weight or water and cosolvents, or at least 70 weight percent or at least 80 weight percent or at least 90 weight percent or at least 95 weight percent or at least 98 weight percent. In some embodiments, water is the only solvent (up to 100 weight percent).

[0034] The foaming composition contains one or more nonionic surfactants that are soluble in the hydrocarbon gas. The nonionic surfactants contain a lipophilic segment bonded to a hydrophilic segment.

[0035] 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.

[0036] 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.

[0037] In some embodiments, the hydrophilic segment comprises polyethylene glycol (PEG) polymer or copolymer. The PEG polymer or copolymer contains repeating ethylene oxide units as illustrated in Formula 1, optionally with other repeating units.

[0038] (1) f-O-CH2-CH2-}

[0039] In some embodiments, the hydrophilic segment comprises a polyethylene glycol-polypropylene glycol (PEG-PPG) copolymer. In addition to ethylene oxide units, the PEG-PPG copolymer contains repeating propylene oxide units as illustrated in Formula 2, wherein R is a pendant methyl group.

[0040] (2) f-O-CH2-CHR-}

[0041] In some embodiments, the PEG-PPG copolymer is a block copolymer containing one or more blocks of ethylene oxide units and one or more blocks of propylene oxide units. In some embodiments, the hydrophilic segment contains one block of ethylene oxide units and one block of propylene oxide units, called a diblock polymer. In some embodiments, the lipophilic segment in the surfactant is bonded to the propylene glycol block of the diblock polymer. In some embodiments, the lipophilic segment in the surfactant is bonded to the ethylene glycol block of the diblock polymer.

[0042] In some embodiments, the hydrophilic segment contains two blocks of ethylene oxide units and one block of propylene oxide units, called a triblock polymer. In some embodiments, the lipophilic segment in the surfactant is bonded to one of the ethylene glycol blocks of the triblock polymer.

[0043] In some embodiments, each hydrophilic segment contains on average at least 4 ethylene oxide units or at least 5 ethylene oxide units or at least 6 ethylene oxide units or at least 7 ethylene oxide units or at least 8 ethylene oxide units. In some embodiments, each hydrophilic segment contains on average at most 24 ethylene oxide units or at most 20 ethylene oxide units or at most 18 ethylene oxide units or at most 16 ethylene oxide units or at most 12 ethylene oxide units. For example, each hydrophilic segment may contain 4 to 20 ethylene oxide units or 5 to 18 ethylene oxide units.

[0044] In some embodiments, each hydrophilic segment contains on average at least 3 propylene oxide units or at least 4 propylene oxide units or at least 5 propylene oxide units or at least 6 propylene oxide units or at least 7 propylene oxide units or at least 8 propylene oxide units. In some embodiments, each hydrophilic segment contains on average at most 24 propylene oxide units or at most 20 propylene oxide units or at most 18 propylene oxide units or at most 16 propylene oxide units or at most 12 propylene oxide units. For example, each hydrophilic segment may contain 3 to 12 propylene oxide units.

[0045] In some embodiments, the number ratio of ethylene oxide units to propylene oxide 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 oxide units to propylene oxide 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 oxide units to propylene oxide units in the hydrophilic segment 0.5 to 2.5 or 0.6 to 2.

[0046] Surfactants are sometimes classified based on hydrophilic-lipophilic balance, as determined by the Griffin method, abbreviated HLBG. See, for example, Griffin, Calculation of HLB Values of NonIonic 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.

[0047] Surfactants are sometimes classified based on hydrophilic-lipophilic balance, as determined by the Effective Chain Length method, abbreviated HLBECL. In some embodiments, the 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 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.

[0048] The surfactant is chosen so that its partition coefficient (Kp) between the hydrocarbon gas and 0.2 wt.% NaCl brine, at 25°C, 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 hydrocarbon gas and 0.2 wt.% NaCl brine, at 25°C, 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 hydrocarbon gas and 0.2 wt.% NaCl brine, at 25°C, 3000 psi pressure and 1 % initial concentration in the brine, is at most 50 or at most 30 or at most 10 or at most 1.

[0049] In some embodiments, the partition coefficient (Kp) of the surfactant between ethane and 0.2 wt.% NaCl brine, at 25°C, 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°C, 3000 psi pressure and 1 % initial concentration in the brine, is at most 50 or at most 30 or at most 10 or at most 1. In addition to being soluble in the hydrocarbon gas, the surfactant is usually soluble in water under conditions used in the fracturing process. 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°C or at least 25°C or at least 30°C or at least 40°C or at least 50°C or at least 60°C. In some embodiments, the surfactant has a cloud temperature limit in 4% NaCl brine water (1% 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 or at least 55°C. There is no maximum desired cloud temperature limit, but in some cases a cloud temperature limit up to 95°C in distilled water or brine may be adequate.

[0050] In some embodiments, the surfactant can tolerate NaCl salinity at room temperature (25 °C) 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.

[0051] The surfactant is capable of forming viscous foam in the presence of water and the hydrocarbon 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 the hydrocarbon gas, 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 hydrocarbon gas at reservoir conditions, without surfactant, is typically on the order of 0.1 cP and 0.01 cP respectively.

[0052] 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 Bl and 9,874,079 B2.

[0053] Surfactants used in the process may optionally be dissolved or suspended in an aqueous or organic solvent as a liquid formulation. In some embodiments, the solvent comprises water. In some embodiments, the solvent comprises an organic solvent that is appropriate for hydraulic fracturing, 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 foaming composition 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 concentration of surfactant in the foaming composition should be suitable to generate viscous foam. The optimum concentration of surfactant may vary, depending on several factors such as the selection of surfactant and hydrocarbon gas, and the ratio of hydrocarbon gas to water. In some embodiments, the weight ratio of surfactant to hydrocarbon gas in the foaming composition is at least 50 parts per million by weight (ppmw) or at least 100 ppmw or at least 200 ppmw or at least 300 ppmw or at least 500 ppmw. In some embodiments, the weight ratio of surfactant to hydrocarbon gas in the foaming composition is at most 50,000 ppm 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. In some embodiments, the weight ratio of surfactant to foaming composition (counting only gas and water and excluding other elements of the foaming composition) is at least 50 ppmw or at least 100 ppmw or at least 200 ppmw or at least 300 ppmw or at least 500 ppmw. In some embodiments, the weight ratio of surfactant to hydrocarbon gas in the foaming composition is at most 20,000 ppm or at most 12,000 ppmw or at most 10,000 ppmw or at most 6000 ppmw or at most 3000 ppmw or at most 2000 ppmw or at most 1000 ppmw.

[0054] The foam is made by mixing the hydrocarbon gas and water in the presence of the surfactant under pressure and other conditions such that a discontinuous phase of hydrocarbon gas is formed in a continuous phase of water. In some embodiments, the surfactant is dissolved in the water. In some embodiments, the surfactant is dissolved in the hydrocarbon gas. Dissolving the surfactant in the hydrocarbon gas ensures that the gas phase of the foam contains substantial dissolved surfactant, and this may provide advantages in the fracturing process. For example, if hydrocarbon gas separates from water in the foam, hydrocarbon gas that contains dissolved surfactant can mix with ambient water in the reservoir to make more foam.

[0055] In some embodiments, the peak steady-state viscosity of the foam is at least 40 cP, when measured according to the Test Methods, or at least 50 cP or at least 60 cP or at least 65 cP or at least 70 cP or at least 75 cP or at least 80 cP or at least 85 cP or at least 90 cP. In some embodiments, the peak steady-state foam viscosity is at most 200 cP or at most 150 cP or at most 100 cP. In some embodiments, the foregoing foam viscosity is achieved in a foam that has a foam quality of at least 60 percent or at least 65 percent or at least 70 percent or at least 75 percent or at least 80 percent or at least 85 percent or at least 90 percent.

[0056] In some embodiments, the foam has a foam quality of at least 60 percent and a foam viscosity of at least 45 cP. In some embodiments, the foam has a foam quality of at least 70 percent and a foam viscosity of at least 50 cP or 55 cP. In some embodiments, the foam has a foam quality of at least 75 percent and a foam viscosity of at least 55 cP or 60 cP. In some embodiments, the foam has a foam quality of at least 80 percent (such as 80 percent to 95 percent) and a foam viscosity of at least 60 cP or 70 cP. In some embodiments, the foam has a foam quality of at least 85 percent and a foam viscosity of at least 70 cP or 75 cP. In some embodiments, the viscosity of a foam with 60 percent foam quality is at least as high as or higher than the viscosity of a foam with 50 percent foam quality that is made with similar components and surfactant concentration, when tested according to the Test Methods. In some embodiments, the viscosity of a foam with 70 percent foam quality is at least as high as or higher than the viscosity of a foam with a 60 percent or 50 percent foam quality that is made with similar components and surfactant concentration, when tested according to the Test Methods. In some embodiments, the viscosity of a foam with 80 percent foam quality is at least as high as or higher than the viscosity of a foam with 70 percent or 60 percent or 50 percent foam quality that is made with similar components and surfactant concentration, when tested according to the Test Methods. In some embodiments, the viscosity of a foam with 90 percent foam quality is at least as high as or higher than the viscosity of a foam with 80 percent or 70 percent or 60 percent or 50 percent foam quality that is made with similar components and surfactant concentration, when tested according to the Test Methods.

[0057] The foaming composition optionally contains a proppant. Examples of proppant materials include sand, resin coated sand, plastic, thermoplastic or thermosetting composites, nutshell pieces, seed shell pieces, fruit pit pieces, sintered bauxite, glass beads, ceramic materials, synthetic organic particles such as nylon pellets, naturally occurring materials, or a combination comprising at least one of the foregoing proppant materials. In some embodiments, the proppant particles have a size in the range of from about 2 to about 400 mesh, U.S. Sieve Series. In some embodiments, the size distribution ranges for proppant particles are one or more of 6 / 12 mesh, 8 / 16, 12 / 20, 16 / 30, 20 / 40, 30 / 50, 40 / 60, 40 / 70, or 50 / 70 mesh. The proppant particles may have any useful shapes including substantially spherical, fibrous, polygonal (such as cubic), and derivatives or mixtures thereof. In some embodiments, the foaming composition contains at least 1 weight percent proppant or at least 2 weight percent proppant. In some embodiments, the foaming composition contains at most 60 weight percent proppant or at most 40 weight percent proppant or at most 30 weight percent proppant.

[0058] Optionally, the foaming composition may further contain other additives, such as gel breakers, gel stabilizers, fluid loss control additives, clay stabilizers, corrosion inhibitors, scale inhibitors, bactericides or other surfactants. In some embodiments, the concentration of the other additives is no more than 5 weight percent of the foaming composition or no more than 3 weight percent or no more than 1 weight percent. In some embodiments, the concentration of the other additives is 0 wt.%.

[0059] In some embodiments of the fracturing process, the water and hydrocarbon gas are injected sequentially into the well, with the surfactant dissolved in water or hydrocarbon gas or both, so that the foam is generated in the reservoir. In some embodiments of the fracturing process, the water and hydrocarbon gas are co-injected into the wellhead, with the surfactant dissolved in water or hydrocarbon gas or both, so that the foam is made in the well or well-head. In some embodiments of the fracturing process, the foam is made on the surface by mixing the components of the foaming composition in a vessel or mixer at the surface, and the resulting foam is injected into the well. For example, foam can be generated by co-injecting the components of the foaming composition into a sand pack at the wellhead as a foam generator. Equipment and processes for mixing and foaming the components of the foaming composition are well known and described in publications such as US patent Publication US 2016 / 0312108 Al; Beck et ah, “Laboratory Evaluation of a Natural Gas-Based Foamed Fracturing Fluid”, SPE-187199-MS, published by the Society of Petroleum Engineers (2017); “Evaluating Natural Gas Foam as a Hydraulic Fracturing Fluid” made available by the Southwest Research Institute at https: / / www.swri.org / technology-today / evaluating-natural-gas-foam-hydraulic-fracturing-fluid: and “SwRI Researchers Test Natural Gas Foam’s Ability to Reduce Water Use in Fracking”, made available by the Southwest Research Institute at https: / / www.swri.org / press-release / testing-natural-gas-foain-to- reduce-water-use.

[0060] In some embodiments, the effective production of foam in a wellhead, well or reservoir can be inferred either from an increase of pressure at a constant injection rate or from a decrease of injection rate at a constant pressure. For example, effective foam production can be inferred from a pressure increase of at least 10 psi or at least 20 psi or at least 50 psi or at least 80 psi or at least 100 psi.

[0061] TEST METHODS

[0062] 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.

[0063] Hydrophilic Lipophilic Balance (Griffin Method) (HLBG): See Griffin, Calculation of HLB Values ofNon-Ionic Surfactants, 1954 J. Soc. Cosmetic Chemists 249 (1954)

[0064] Hydrophilic Lipophilic Balance (Effective Chain Length Method) (HLBET C): 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

[0065] Gas Partitioning Coefficient

[0066] The following steps are carried out at room temperature.

[0067] 1. Surfactant is dissolved at the desired concentration (0.5, 1 , 1.5 and 2.0 wt.%) in water or a brine solution containing 0.2 wt.% NaCl. The surfactant solution is added to a high pressure cell to fill half the cell volume.

[0068] 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).

[0069] 3. The cell is mixed regularly for 3 days.

[0070] 4. The cell is depressurized by slowly venting the gas from the top of the cell.

[0071] 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.

[0072] 6. The mass concentration (C) of surfactant partitioned into the gas is estimated using equation (1): wherein • C Gas-Paititioned is the concentration of surfactant dissolved in the gas at 3000 psi, in g / L

[0073] • C Bnne initial is the concentration of surfactant dissolved in the surfactant solution before partitioning, in g / L; and

[0074] • C Brine-Partitioned is the concentration of surfactant dissolved in the surfactant solution after partitioning, in g / L.

[0075] 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):

[0076] (2) Kp = C Gas-Partitioned / C Brine-Partitioned

[0077] Cloud Temperature

[0078] 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.

[0079] Foam Viscosity

[0080] Foam viscosity is measured by core flooding tests. Drawing 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 40°C.

[0081] 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 quality is 50% unless otherwise noted. The shear rate in the core is estimated to be from 50-60 s-1, using the calculations set out in Hirasake et al., “Analysis of Factors Influencing Mobility and Adsorption in the Flow of Polymer Solution through Porous Media”, published by the Society of Petroleum Engineers (1974) and available at http: / / onepetro.org / spejournal / article- pdf / 14 / 04 / 337 / 2157055 / spe-4026-pa.pdf / l. Foam flooding is carried out at a flow rate of 10 ft / d to steady state when a stable pressure drop is observed.

[0082] The pressure drop across the porous core is recorded. The apparent viscosity of foam is calculated using Darcy’s law:

[0083] (3) pa= [k (AP)] / [L (V darcy)] Where (ij is 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 Vdarcy is the superficial velocity in cm / s. After each test, the core is flooded with brine until the initial permeability is restored.

[0084] EXAMPLES The following Examples illustrate partitioning and foam formation of surfactants used in some embodiments of the invention.

[0085] The surfactants shown in Table 2 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 PPG block linked to the lipophilic segment and a PEG block linked to the PPG 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 oxide 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 oxide units linked to the PPG block.

[0086] 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.

[0087] Five comparative surfactants (CS1 - CS5) are obtained and listed in Table 1:

[0088] Table 1

[0089] CS5 has an HLBG of 12.5 and an HLBECL of 13.6 Table 2

[0090] EO# = number of ethylene oxide units. PO# = number of propylene oxide units

[0091] 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.

[0092] Table 3

[0093] Low-Water Foaming using Methane, Ethane and 75% Methane 25% Ethane Gas Mixture:

[0094] Foam viscosity is measured by core flooding (as set out in the Test Methods) for surfactant ITS3 with three different gases - methane, ethane and Gas Mix 1(75% methane / 25% ethane) - at two different gas pressures - 1500 psi and 3000 psi. Surfactant is dissolved in the water at a concentration of 0.5 weight percent. The shear rate in the core is estimated to be from 50-60 s-1, using the calculations set out in Hirasake et al., “Analysis of Factors Influencing Mobility and Adsorption in the Flow of Polymer Solution through Porous Media”, published by the Society of Petroleum Engineers (1974) and available at http: / / onepetro.Org / speiournal / article-pdf / 14 / 04 / 337 / 2157055 / spe-4026-pa.pdf / l. Viscosities at foam qualities (“FQ”) of 30, 50, 70 and 90 percent are tested. Drawing 2 illustrates the measured foam viscosity. Drawing 2 shows that for methane and Gas Mix, viscosity drops as the foam quality increases, but for ethane, viscosity increases as the foam quality increases.

[0095] Foam viscosity is measured by core flooding (as set out in the Test Methods) for surfactant ITS3 with methane and ethane and for Comparative Surfactant CS4 with ethane. Surfactant is dissolved in the water at a concentration of 0.5 weight percent. Viscosities at foam qualities (“FQ”) of 30, 50, 70 and 90 percent are tested. The measurements for surfactant ITS3 are carried out at 10 ft / d and in 58 mD rock. The measurements for CE4 are carried out in 63 mD rock at 5 ft / d injection speed; literature reports show that viscosity for CE4 would be even lower at 10 ft / d due to shear thinning. Drawing 3 illustrates the measured foam viscosity. Drawing 3 shows that for methane-ITS3 and ethane-CS4, viscosity drops as the foam quality increases, but for ethane-ITS3, viscosity increases as the foam quality increases.

Claims

CLAIMS:1 . A fracturing process, performed at a hydrocarbon reservoir that has a well for injecting fracturing fluid into the reservoir to increase the flow of hydrocarbon to the well, which process comprises the step of injecting into the well, at a pressure and injection rate suitable for fracturing, the following components which are collectively called a foaming composition: a) a hydrocarbon gas that contains on average more than 1.5 carbon atoms per molecule; b) water; and c) a nonionic surfactant that i) comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment that contains on average more than 8 carbon atoms; and ii) has a partition coefficient (Kp) between the hydrocarbon gas and 0.2 weight percent (wt.%) NaCl brine of at least 0.05, at 25°C, 3000 psi pressure and 1 % initial concentration in the brine; and iii) is present in a concentration suitable to generate viscous foam when the hydrocarbon gas encounters water, wherein the foaming composition contains more than 50 volume percent gas at the pressures used for the fracturing process, based on the combined volume of gas and water.

2. The fracturing process of Claim 1 wherein the hydrocarbon gas contains one or more of ethane, methane, propane, butane or pentane and contains no more than 25 mole percent methane.

3. The fracturing 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 fracturing 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 fracturing process of Claim 4 wherein the polyethylene glycol blocks in each surfactant molecule contain on average from 5 to 20 repeating ethylene oxide units.

6. The fracturing process of Claim 4 wherein the ratio of ethylene oxide units to propylene oxide units is 0.5 to 2.5.

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

8. The fracturing 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.

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

10. The fracturing process of Claim 2 wherein the foaming composition contains from 80 to 95 volume percent gas at the pressures used for the fracturing process, based on the combined volume of gas and water.

11. The fracturing process of Claim 2 wherein: a) the hydrocarbon gas contains one or more of ethane, methane, propane, butane or pentane and contains no more than 25 mole percent methane. b) The surfactant comprises a lipophilic segment that contains an alkyl moiety having on average from 9 to 20 carbon atoms; c) 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 oxide units to propylene oxide units is 0.5 to 2.5; and d) hydrophilic-lipophilic balance of the surfactant, as determined by the Griffin method, is from 5.0 to 12; and e) the surfactant has a partition coefficient between ethane and 0.2% NaCl brine at 25°C of at least 0.2.

12. The fracturing process of any one of Claims 1 to 13 wherein the foaming composition makes a foam that has a viscosity of at least 40 cP.

13. The fracturing process of Claim 13 wherein the foaming composition makes a foam that has a viscosity of at least 50 cP, and the foaming composition contains at least 70 volume percent gas at the pressures used for the fracturing process, based on the combined volume of gas and water.

14. The fracturing process of Claim 13 wherein the foaming composition makes a foam that has a viscosity of at least 60 cP, and the foaming composition contains from 80 to 95 volume percent gas at the pressures used for the fracturing process, based on the combined volume of gas and water.

15. An aqueous foam that contains: a) a continuous phase of water; b) a discontinuous phase of supercritical hydrocarbon gas that is dispersed in the water and that contains on average more than 1.5 carbon atoms per molecule; and c) a nonionic surfactant that: i) comprises a hydrophilic segment bonded directly or indirectly to a lipophilic segment, which contains on average more than 8 carbon atoms; andii) has a partition coefficient (Kp) between the hydrocarbon gas and 0.2 weight percent (wt.%) NaCl brine of at least 0.05, at 25°C, 3000 psi pressure and 1 % initial concentration in the brine; and iii) is present in a concentration suitable to generate viscous foam containing the hydrocarbon gas and water, wherein the foam contains more than 50 volume percent gas, based on the combined volume of gas and water.

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