US20160251568A1 - Compositions for enhanced oil recovery - Google Patents

Compositions for enhanced oil recovery Download PDF

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US20160251568A1
US20160251568A1 US15/052,439 US201615052439A US2016251568A1 US 20160251568 A1 US20160251568 A1 US 20160251568A1 US 201615052439 A US201615052439 A US 201615052439A US 2016251568 A1 US2016251568 A1 US 2016251568A1
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ppm
water
emulsion
surfactants
water source
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Linh Do
Brian Mueller
Duy T. Nguyen
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Ecolab USA Inc
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Ecolab USA Inc
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Priority to US15/052,439 priority Critical patent/US20160251568A1/en
Assigned to ECOLAB USA INC. reassignment ECOLAB USA INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: DO, LINH, MUELLER, BRIAN, NGUYEN, DUY T.
Publication of US20160251568A1 publication Critical patent/US20160251568A1/en
Priority to US16/004,889 priority patent/US10767104B2/en
Abandoned legal-status Critical Current

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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/584—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific surfactants
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/602—Compositions for stimulating production by acting on the underground formation containing surfactants
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/885—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures

Definitions

  • the present invention relates to compositions and methods for increased recovery of crude oil from a subterranean hydrocarbon-containing formation.
  • Hydraulic fracturing is a well-stimulation technique in which subterranean rock is fractured by a hydraulically pressurized fracturing fluid typically made by combining water, an hydraulic fracturing proppant (conventionally sand or aluminum oxide), and additive chemicals that modify subterranean flow, subterranean interfacial tension, and/or provide other effects.
  • a hydraulic fracture is formed by pumping the fracturing fluid into a wellbore at a rate sufficient to increase pressure at the target depth to exceed that of the fracture gradient (pressure gradient) of the rock.
  • the hydraulic fracturing proppants lodge within the cracks to hold the fractures open. Hydrocarbon compounds such as natural gas and petroleum are recovered via the cracks in the hydrocarbon-containing deep-rock formations. Hydraulic fracturing techniques can be used to form a new well and can also be used to extend the life of an existing conventional oil well.
  • Chemical additives including surfactants have been added to fracturing fluids in hydraulic fracturing processes to increase recovery of hydrocarbon compounds from subterranean hydrocarbon-containing formations.
  • the surfactants can act to lower the interfacial tension between the fracturing fluid and the oil trapped within the fractures in the reservoir and can change the wettability of the reservoir rock, thereby increasing the yield of hydrocarbon compounds released from the rock fractures.
  • many conventional surfactants and surfactant blends adsorb substantially onto the rock surfaces, depleting the surfactant quickly at the expense of deeper-lying fracture surfaces.
  • many injected surfactants facilitate underground emulsion formation between the hydrocarbon compounds and the fracturing fluid, which retards or prevents recovery of the hydrocarbon compounds.
  • conventional chemical surfactants and mixtures thereof are often unstable or insoluble in the high temperature and/or high total dissolved solids water sources encountered in some subterranean reservoirs. For example, in some reservoirs temperatures in excess of 60° C. are encountered; temperatures can be as high as 250° C. Additionally, underground water is often characterized as having high total dissolved solids, such as about 4 wt % total dissolved solids and as much as about 35 wt % total dissolved solids. In some cases, a substantial portion of the dissolved solids are ionic (one or more salts).
  • compositions that reduce the interfacial tension between a fracturing fluid and the oil trapped within the fractured subterranean rock formations without adsorbing strongly to the rock surfaces.
  • compositions that reduce the interfacial tension between a fracturing fluid and the oil trapped within the fractured subterranean rock formations in high temperature environments There is a need in the industry for compositions that reduce the interfacial tension between a fracturing fluid and the oil trapped within fractured rock formations in subterranean environments having water sources that include high total dissolved solids.
  • compositions that increase the yield of hydrocarbon compounds recovered from fractured subterranean rock formations.
  • FIG. 1 is a plot of interfacial tension as a function of temperature for fracturing fluids of the invention.
  • FIG. 2 is plot of interfacial tension as a function of temperature and concentration for fracturing fluids of the invention in 2 wt % KCl.
  • FIG. 3 is plot of interfacial tension as a function of temperature and concentration for fracturing fluids of the invention in 12 wt % KCl.
  • FIG. 4 is plot of interfacial tension as a function of KCl concentration for fracturing fluids of the invention.
  • FIG. 5 is plot of surface tension as a function of time for fracturing fluids of the invention in 2% KCl at 300° F. (149° C.) at 200 psi (1379 kPa).
  • compositions and methods for increased recovery of crude oil from a subterranean hydrocarbon-containing formation Disclosed herein are compositions and methods for increased recovery of crude oil from a subterranean hydrocarbon-containing formation. Disclosed herein are emulsions that are useful to form fracturing fluids for injection into one or more subterranean reservoirs.
  • the emulsions of the invention are diluted with a high total dissolved water source, such as produced water, to form the fracturing fluids of the invention.
  • the fracturing fluids of the invention are injected into oil-containing reservoirs.
  • the fracturing fluids are thermally stable when subjected to underground conditions including temperatures of about 60° C. to 120° C.
  • rock surfaces contacted by the fracturing fluids changes from oil-wettable to water-wettable.
  • the emulsion components of the fracturing fluids exhibit a low tendency to adsorb onto the rock.
  • the fracturing fluids further substantially lower the interfacial energy between the fluid and the hydrocarbons present in the reservoir.
  • the fracturing fluids also inhibit formation of emulsions in underground fracturing fluid flows.
  • the fracturing fluids exhibit improved sweeping efficiency and proppant clean-up performance under gravitational flow conditions when compared to conventional fracturing fluids.
  • the fracturing fluids of the invention substantially increase the yield of hydrocarbon products such as crude oil or shale oil from underground reservoirs when injected therein.
  • the fracturing fluids of the invention and are particularly useful for increasing the yield of hydrocarbon products in reservoirs where high temperatures are encountered underground.
  • compositions comprising about 98 wt % to 99.999 wt % of a water source comprising high total dissolved solids; one or more oil phase surfactants, the oil phase surfactants characterized as nonionic and having a combined HLB of less than about 9, one or more coupling agents, one or more water phase surfactants, wherein the water phase surfactants are nonionic, soluble or dispersible in water, and chemically different from the one or more oil phase surfactants, one or more ionic surfactants, a clay stabilizer, and water.
  • compositions comprising about 98 wt % to 99.999 wt % of a water source comprising high total dissolved solids; one or more coupling agents; one or more water soluble or dispersible nonionic surfactants; one or more zwitterionic surfactants; one or more anionic surfactants, and optionally one or more additional ionic surfactants.
  • the emulsion is shelf stable.
  • the composition is a fracturing fluid, the fracturing fluid comprising about 99 wt % to 99.999 wt % of a water source.
  • the water source is a high temperature water source, a high total dissolved solids water source, or a high temperature, high total dissolved solids water source.
  • the compositions comprise one or more additives, the additives comprising one or more viscosifying agents, solvents, alkali, flow back aids, non-emulsifiers, friction reducers, breakers, crosslinking agents, biocides, proppants, or mixtures thereof.
  • Also disclosed herein is a method of increasing recovery of crude oil from a subterranean hydrocarbon-containing formation, the method comprising: forming an emulsion, the emulsion comprising one or more oil phase surfactants, the oil phase surfactants characterized as nonionic and having a combined HLB of less than about 9; a coupling agent; one or more water phase surfactants, wherein the water phase surfactants are nonionic, soluble or dispersible in water, and chemically different from the one or more oil phase surfactants; one or more ionic surfactants; one or more clay stabilizers, and about 40 wt % to 80 wt % water; contacting the emulsion with a water source to form a fracturing fluid; injecting the fracturing fluid into a subterranean hydrocarbon-containing formation; and collecting a hydrocarbon from the subterranean hydrocarbon-containing formation.
  • the injecting is into a first wellbore connected to the subterranean hydrocarbon-containing formation
  • the collecting is from a second wellbore that is connected to the subterranean hydrocarbon-containing formation.
  • the injecting and the collecting are carried out in the same wellbore.
  • Also disclosed herein is a method of increasing recovery of crude oil from a subterranean hydrocarbon-containing formation, the method comprising: forming an emulsion, the emulsion comprising one or more coupling agents, one or more water soluble or dispersible nonionic surfactants, one or more zwitterionic surfactants, one or more anionic surfactants, and optionally one or more additional ionic surfactants; contacting the emulsion with a high total dissolved solids water source to form a fracturing fluid, the fracturing fluid comprising about 98 wt % to 99.99 wt % of the high total dissolved solids water source; injecting the fracturing fluid into a subterranean hydrocarbon-containing formation; and collecting a hydrocarbon from the subterranean hydrocarbon-containing formation.
  • the water source is contacted with the emulsion at a temperature of about 60° C. to 250° C. In some embodiments the contacting is carried out contemporaneously with the injecting; in other embodiments, the contacting is carried out prior to the injecting.
  • ionic surfactant means a water soluble or water dispersible molecule having cationic, anionic, or zwitterionic functionality.
  • nonionic surfactant means surfactant molecule characterized by the absence of cationic, anionic, or zwitterionic functionality.
  • an emulsion means a composition including at least water and a surfactant present in the water in an amount sufficient to surpass the critical micelle concentration (cmc).
  • an emulsion is a microemulsion.
  • Microemulsions are characterized as emulsions that are transparent and thermodynamically stable.
  • water source means a source of water comprising, consisting essentially of, or consisting of fresh water, tap water, well water, deionized water, distilled water, produced water, municipal water, waste water such as runoff water, “gray” water, or municipal waste water, treated or partially treated waste water, brackish water, or sea water, or a combination of two or more such water sources as determined by context.
  • a water source includes one or more salts, ions, buffers, acids, bases, surfactants, or other dissolved, dispersed, or emulsified compounds, materials, components, or combinations thereof.
  • a water source includes about 0 wt % to 35 wt % total dissolved solids.
  • the total dissolved solids are substantially non-polymeric solids.
  • the dissolved solids comprise, consist essentially of ionic compounds.
  • waterbased or “water solution” generally refers to a composition including a water source.
  • saline or “salinity” refers to a water source wherein a portion, in some embodiments a substantial portion, of the dissolved solids are salts.
  • water source includes high total dissolved solids water sources, high temperature water sources, and high total dissolved solids, high temperature water sources.
  • high temperature means about 60° C. to 120° C., as specified or determined by context.
  • high total dissolved solids refers to a water source comprising at least about 4 wt % non-polymeric solids dissolved therein, and in embodiments up to about 35 wt % non-polymeric solids dissolved therein.
  • the term “stable” as applied to an emulsion means a kinetically stable emulsion that absent any force applied, temperature change, or chemical added, is or is capable of being substantially free of coagulation, plating out, precipitation, gross coalescence of phases (conventionally referred to as “separation”) or any other evidence of instability conventionally associated with emulsions for at least about 24 hours at about 20° C. Where the emulsion is a microemulsion, the emulsion is also thermodynamically stable. As used herein, the term “storage stable” as applied to an emulsion means that the emulsion is stable after at least six months of storage at temperatures between about ⁇ 25° C. to 60° C.
  • the term “optional” or “optionally” means that the subsequently described component, event or circumstance may but need not be present or occur. The description therefore discloses and includes instances in which the event or circumstance occurs and instances in which it does not, or instances in which the described component is present and instances in which it is not.
  • the term “substantially” means “consisting essentially of”, as that term is construed in U.S. patent law, and includes “consisting of” as that term is construed in U.S. patent law.
  • a solution that is “substantially free” of a specified compound or material may be free of that compound or material, or may have a minor amount of that compound or material present, such as through unintended contamination or incomplete purification.
  • a “minor amount” may be a trace, an unmeasurable amount, an amount that does not interfere with a value or property, or some other amount as provided in context.
  • a composition that has “substantially only” a provided list of components may consist of only those components, or have a trace amount of some other component present, or have one or more additional components that do not materially affect the properties of the composition.
  • “substantially” modifying, for example, the type or quantity of an ingredient in a composition, a property, a measurable quantity, a method, a value, or a range, employed in describing the embodiments of the disclosure refers to a variation that does not affect the overall recited composition, property, quantity, method, value, or range thereof in a manner that negates an intended composition, property, quantity, method, value, or range.
  • compositions for use in the recovery of hydrocarbon compounds from hydrocarbon-containing subterranean fractured rock formations are emulsions.
  • the emulsions are microemulsions.
  • the emulsions comprise, consist essentially of, or consist of (1) one or more oil phase surfactants, the oil phase surfactants characterized as nonionic and having a combined HLB of less than about 9, (2) a coupling agent, (3) one or more water phase surfactants, wherein the water phase surfactants are nonionic, soluble or dispersible in water, and chemically different from the one or more oil phase surfactants, (4) one or more ionic surfactants, (5) one or more clay stabilizers, and (6) water.
  • Suitable oil phase surfactants usefully employed in the emulsions of the invention comprise, consist essentially of, or consist of one or more nonionic surfactants having an HLB of about 9 or less, or a combined HLB of about 9 or less.
  • HLB HLB
  • HLB is calculated using the Griffin formula:
  • a C10 ethoxylated alcohol bonded to 8 ethylene oxide repeat units has an HLB of 13.83:
  • suitable oil phase surfactants include alkoxylated alcohols, alkoxylated alkylphenols, glycerol esters, glycol esters, polyethylene glycol esters, polyglycerol esters, and sorbitol esters, and combinations of these.
  • the alkoxylated alcohols include ethoxylated, propoxylated, and ethoxylated propoxylated alcohols wherein the alcohols include 6-20 carbons in linear, branched, or cyclic conformation and the alkoxy functionality includes an average of 1-6 moles of ethylene oxide, propylene oxide, or a combination thereof.
  • Glycerol, glycol, polyethyleneglycol, polyglycerol, and sorbitol esters are formed from acids having 6-20 carbons in linear, branched, or cyclic conformation.
  • Suitable oil phase surfactants have an HLB of less than about 9, for example about 2 to 9, or about 3 to 9, or about 4 to 9, or about 5 to 9, or about 6 to 9, or about 7 to 9, or about 2 to 8, or about 2 to 7, or about 2 to 6, or about 2 to 5, or about 2 to 4, or about 3 to 8, or about 4 to 8, or about 5 to 8, or about 6 to 8, or about 3 to 7, or about 4 to 7, or about 5 to 7.
  • Mixtures of two or more such surfactants are also suitably employed in the emulsions of the invention.
  • the HLB of such combinations is an average of the contribution of each surfactant in the mixture, wherein that the combined HLB of the mixture of oil phase surfactants is about 9 or less as indicated above.
  • the amount of oil phase surfactants present in the emulsions of the invention is about 0.1 wt % to about 35 wt % based on the total weight of an emulsion, for example about 0.5 wt % to 35 wt %, or about 1.0 wt % to 35 wt %, or about 1.5 wt % to 35 wt %, or about 2.0 wt % to 35 wt %, or about 5.0 wt % to 35 wt %, or about 10 wt % to 35 wt %, or about 0.1 wt % to 30 wt %, or about 0.1 wt % to 25 wt %, or about 0.1 wt % to 20 wt %, or about 1.0 wt % to 30 wt %, or about 1.5 wt % to 30 wt %, or about 2.0 wt % to 30 wt %, or about 2.0 w
  • Suitable coupling agents employed in the emulsions of the invention comprise, consist essentially of, or consist of water miscible solvents and mixtures of two or more water miscible solvents.
  • the coupling agents do not destabilize the emulsions.
  • the coupling agents increase stability of the emulsions.
  • the coupling agent is fully miscible with water; that is, all possible coupling agent:water ratios are miscible.
  • the coupling agent is miscible with water at least up to about 20:1 water:coupling agent by volume, or about 10:1, about 9:1, about 8:1, about 7:1, about 6:1, about 5:1, about 4:1, about 3:1, about 2:1, about 1:1, about 1:2, about 1:3, about 1:4, about 1:5, about 1:6, about 1:7, about 1:8, about 1:9, about 1:10, about 1:20 water:coupling agent by volume, or ranges between any of these two ratios, such as between about 20:1 and 1:20, between 5:1 and 2:1, and the like.
  • Suitable coupling agents comprise, consist essentially of, or consist of linear, branched, or cyclic aliphatic alcohols having 1 to 6 carbon atoms, diols having 1 to 6 carbon atoms, alkyl ethers of alkylene glycols wherein the alkyl moiety has 1 to 6 carbon atoms (e.g., ethylene glycol mono-n-butyl ether) polyalkylene glycols, and mixtures thereof.
  • Also useful as coupling agents are glycol and glycerol based acetals and ketals, such as those formed from the condensation of e.g.
  • glycerol with formaldehyde, acetone, or oxocarboxylic acids, semialdehydes, and esters thereof such as levulinic acid or an alkyl levulinate.
  • useful coupling agents include methanol, ethanol, glycerol, and ethylene glycol.
  • the total amount of coupling agents included in the emulsions of the invention is about 0.1 wt % to 20 wt % based on the total weight of an emulsion, for example about 0.5 wt % to 20 wt %, or about 1.0 wt % to 20 wt %, or about 2.0 wt % to 20 wt %, or about 3.0 wt % to 20 wt %, or about 4.0 wt % to 20 wt %, or about 5.0 wt % to 20 wt %, or about 6.0 wt % to 20 wt %, or about 7.0 wt % to 20 wt %, or about 8.0 wt % to 20 wt %, or about 9.0 wt % to 20 wt %, or about 10 wt % to 20 wt %, or about 0.1 wt % to 19 wt %, or about 0.1
  • Suitable water phase surfactants employed in the emulsions of the invention comprise, consist essentially of, or consist of one or more nonionic surfactants that are soluble or dispersible in water and are chemically different from the one or more oil phase surfactants.
  • the water phase surfactant is one or more surfactants selected from the group comprising, consisting essentially of, or consisting of alkoxylated alcohols and alkoxylated alkyl phenols having an HLB greater than about 10, for example about 10 to 20, or about 10 to 18, or about 10 to 16, or about 10 to 14, or about 11 to 20, or about 11 to 18, or about 11 to 17, or about 11 to 16, or about 11 to 15, or about 11 to 14, or about 11 to 13, and mixtures of these compounds.
  • the amount of water phase surfactants employed in the emulsions of the invention totals about 0.1 wt % to to 10 wt % based on the total weight of an emulsion, or about 0.5 wt % to 10 wt %, or about 1.0 wt % to 10 wt %, or about 1.5 wt % to 10 wt %, or about 2.0 wt % to 10 wt %, or about 2.5 wt % to 10 wt %, or about 3.0 wt % to 10 wt %, or about 0.5 wt % to 9 wt %, or about 0.5 wt % to 8 wt %, or about 0.5 wt % to 7 wt %, or about 0.5 wt % to 6 wt %, or about 0.5 wt % to 5 wt %, or about 0.5 wt % to 4 wt %, or about
  • Suitable ionic surfactants employed in the emulsions of the invention comprise, consist essentially of, or consist of one or more amphoteric molecules having anionic, cationic or zwitterionic functionality and at least one linear, branched or cyclic hydrocarbon moiety having 6 to 20 carbons.
  • Suitable ionic surfactants include linear alkylbenzene sulfonic acid, alkyl benzene sulfonate, alkyl sulfonates, alkyl sulfates, alkyl ether sulfates, alkyl ammonium halides, alkyl aryl ammonium halides, imidazolium, cocoamidopropyl betaine, cocodimethyl betaine, and alkyl amine oxides.
  • the amount of ionic surfactants employed in the emulsions of the invention totals about 1 wt % to 20 wt % based on the total weight of an emulsion, for example about 1 wt % to 19 wt %, or about 1 wt % to 18 wt %, or about 1 wt % to 17 wt %, or about 1 wt % to 16 wt %, or about 1 wt % to 15 wt %, or about 1 wt % to 14 wt %, or about 1 wt % to 13 wt %, or about 1 wt % to 12 wt %, or about 1 wt % to 11 wt %, or about 1 wt % to 10 wt %, or about 2 wt % to 20 wt %, or about 3 wt % to 20 wt %, or about 4 wt % to 20 w
  • Suitable clay stabilizers employed in the emulsions of the invention comprise, consist essentially of, or consist of quaternary ammonium salt polymers having molecular weights of about 500 g/mol to 10,000 g/mol, choline chloride, inorganic salts, and mixtures thereof.
  • Inorganic salts usefully employed as clay stabilizers include KCl, CaCl 2 , and MgCl 2 . Additional clay stabilizers useful in the emulsions of the invention are listed at http://booksite.elsevier.com/samplechapters/9780123838445/9780123838445.pdf.
  • the amount of clay stabilizer employed in the emulsions of the invention totals about 1 wt % to 25 wt % based on the total weight of an emulsion, for example about 2 wt % to 25 wt %, or about 3 wt % to 25 wt %, or about 4 wt % to 25 wt %, or about 5 wt % to 25 wt %, or about 6 wt % to 25 wt %, or about 7 wt % to 25 wt %, or about 8 wt % to 25 wt %, or about 9 wt % to 25 wt %, or about 10 wt % to 25 wt %, or about 11 wt % to 25 wt %, or about 12 wt % to 25 wt %, or about 13 wt % to 25 wt %, or about 14 wt % to 25 wt %
  • the water employed to form the emulsions of the invention is a water source.
  • the water source comprises or consists essentially of water, wherein the water comprises 0 wt % to about 35 wt % total dissolved solids.
  • the water source is tap water.
  • the amount of water source employed in the emulsions is about 30 wt % to 95 wt % of the total weight of an emulsion, for example about 35 wt % to 95 wt %, or about 40 wt % to 95 wt %, or about 45 wt % to 95 wt %, or about 50 wt % to 95 wt %, or about 55 wt % to 95 wt %, or about 60 wt % to 95 wt %, or about 30 wt % to 90 wt %, or about 30 wt % to 85 wt %, or about 30 wt % to 80 wt %, or about 30 wt % to 75 wt %, or about 30 wt % to 70 wt %, or about 30 wt % to 65 wt %, or about 30 wt % to 60 wt %, or about 40 wt
  • nonionic oil soluble demulsifiers are added to improve efficiency of dilution of the emulsions during injection into the subterranean reservoir.
  • the nonionic oil soluble demulsifiers are selected from the group comprising, consisting essentially of, or consisting of polyethylenimine alkoxylates, alkoxylated alkylphenol formaldehyde resins, alkoxylated amine-modified alkylphenol formaldehyde resins, ethylene oxide/propylene oxide copolymers, crosslinked ethylene oxide/propylene copolymers, and mixtures thereof.
  • the nonionic oil soluble demulsifiers are present in the emulsions at about 0.01 wt % to 5 wt % based on the total weight of an emulsion, for example about 0.05 wt % to 5 wt %, or about 0.1 wt % to 5 wt %, or about 0.2 wt % to 5 wt %, or about 0.3 wt % to 5 wt %, or about 0.4 wt % to 5 wt %, or about 0.5 wt % to 5 wt %, or about 0.6 wt % to 5 wt %, or about 0.7 wt % to 5 wt %, or about 0.8 wt % to 5 wt %, or about 0.9 wt % to 5 wt %, or about 1.0 wt % to 5 wt %, or about 0.01 wt % to 4.5 w
  • the emulsions include one or more oil field additives conventionally used in hydraulic fracturing or post-primary fracturing of subterranean hydrocarbon-containing formations.
  • the additives are added to the emulsions and the resulting additive containing emulsions are stable, or even shelf stable.
  • the additives are not added directly to the emulsions, but rather are added to the subterranean reservoir contemporaneously with dilution of the emulsions to form fracturing fluids.
  • Suitable additives include viscosifying agents, solvents, alkali, flow back aids, non-emulsifiers, corrosion inhibitors, scale inhibitors, biocides, friction reducers, emulsion breakers, and proppants (e.g., sand or aluminum oxide particles).
  • Suitable corrosion inhibitors include imidazoline and quaternary ammonium compounds and functionalized compounds and polymers.
  • Suitable scale inhibitors include phosphonate compounds and acrylated polymers. In some embodiments, one or more such additives are added at an amount that is less than 1 percent by weight of the emulsion.
  • the additives added during dilution of an emulsion are employed at about 1 ppm to 500 ppm in the fracturing fluid formed during the dilution, for example about 2 ppm to 400 ppm, or about 3 ppm to 300 ppm, or about 4 ppm to 200 ppm, or about 5 ppm to 100 ppm of one or more additives.
  • the emulsions of the invention are stable.
  • the emulsions of the invention are shelf stable.
  • the emulsions are shelf stable for about 6 months to two years, or about 6 months to one year.
  • the total concentration of surfactants in the emulsion, or a diluted emulsion is referred to as the concentration of “actives” in a composition of the invention.
  • compositions for use in the recovery of hydrocarbon compounds from hydrocarbon-containing subterranean fractured rock formations are emulsions.
  • the emulsions are microemulsions.
  • the emulsions of the second embodiment comprise, consist essentially of, or consist of (1) a coupling agent, (2) one or more water soluble or dispersible nonionic surfactants, (3) at least one zwitterionic surfactant, (4) at least one anionic surfactant, (5) optionally one or more additional ionic surfactants, and (6) water.
  • the total concentration of surfactants in a composition of the invention is referred to as the concentration of “actives”.
  • the coupling agent employed in the compositions of the second embodiment comprises, consists essentially of, or consists of water miscible solvents and mixtures of two or more water miscible solvents.
  • the coupling agents do not destabilize the emulsions.
  • the coupling agents increase stability of the emulsions.
  • the coupling agent is fully miscible with water; that is, all possible coupling agent:water ratios are miscible.
  • the coupling agent is miscible with water at least up to about 20:1 water:coupling agent by volume, or about 10:1, about 9:1, about 8:1, about 7:1, about 6:1, about 5:1, about 4:1, about 3:1, about 2:1, about 1:1, about 1:2, about 1:3, about 1:4, about 1:5, about 1:6, about 1:7, about 1:8, about 1:9, about 1:10, about 1:20 water:coupling agent by volume, or ranges between any of these two ratios, such as between about 20:1 and 1:20, between 5:1 and 2:1, and the like.
  • Suitable coupling agents comprise, consist essentially of, or consist of linear, branched, or cyclic aliphatic alcohols having 1 to 6 carbon atoms, diols having 1 to 6 carbon atoms, alkyl ethers of alkylene glycols wherein the alkyl moiety has 1 to 6 carbon atoms (e.g., ethylene glycol mono-n-butyl ether) polyalkylene glycols, and mixtures thereof.
  • Also useful as coupling agents are glycol and glycerol based acetals and ketals, such as those formed from the condensation of e.g.
  • glycerol with formaldehyde, acetone, or oxocarboxylic acids, semialdehydes, and esters thereof such as levulinic acid or an alkyl levulinate.
  • useful coupling agents include methanol, ethanol, glycerol, and ethylene glycol.
  • the total amount of coupling agents included in the emulsions of the second embodiment is about 0.1 wt % to 20 wt % based on the total weight of an emulsion, for example about 0.5 wt % to 20 wt %, or about 1.0 wt % to 20 wt %, or about 2.0 wt % to 20 wt %, or about 3.0 wt % to 20 wt %, or about 4.0 wt % to 20 wt %, or about 5.0 wt % to 20 wt %, or about 6.0 wt % to 20 wt %, or about 7.0 wt % to 20 wt %, or about 8.0 wt % to 20 wt %, or about 9.0 wt % to 20 wt %, or about 10 wt % to 20 wt %, or about 0.1 wt % to 19 wt %, or about
  • the nonionic surfactant employed in the compositions of the second embodiment comprises, consists essentially of, or consists of one alkoxylated alcohols, alkoxylated alkylphenols, glycerol esters, glycol esters, polyethylene glycol esters, polyglycerol esters, and sorbitol esters, and combinations of these.
  • the nonionic surfactant is one or more surfactants selected from the group comprising, consisting essentially of, or consisting of alkoxylated alcohols and alkoxylated alkyl phenols having an HLB greater than about 10, for example about 10 to 20, or about 10 to 18, or about 10 to 16, or about 10 to 14, or about 11 to 20, or about 11 to 18, or about 11 to 17, or about 11 to 16, or about 11 to 15, or about 11 to 14, or about 11 to 13, and mixtures of these compounds.
  • the alkoxylated alcohols include ethoxylated, propoxylated, and ethoxylated propoxylated alcohols wherein the alcohols include 4 to 10 carbons in linear, branched, or cyclic conformation and the alkoxy functionality includes an average of 4 to 12 moles of ethylene oxide, propylene oxide, or a combination thereof.
  • the nonionic surfactant is an alkoxylated C6 alcohol.
  • the amount of the nonionic surfactant employed in the emulsions of the second embodiment totals about 5 wt % to to 15 wt % based on the total weight of an emulsion, or about 6 wt % to 15 wt %, or about 7 wt % to 15 wt %, or about 8 wt % to 15 wt %, or about 9 wt % to 15 wt %, or about 5 wt % to 14 wt %, or about 5 wt % to 13 wt %, or about 5 wt % to 12 wt %, or about 5 wt % to 11 wt %, or about 5 wt % to 10 wt %, or about 6 wt % to 12 wt %, or about 7 wt % to 11 wt %, or about 8 wt % to 10 wt % based on the total weight of the emul
  • the zwitterionic surfactant employed in the compositions of the second embodiment comprises, consists essentially of, or consists of one or more amphoteric molecules including at least one linear, branched or cyclic hydrocarbon moiety having 6 to 20 carbons, or about 8 to 18 carbons, or about 10 to 16 carbons.
  • Suitable zwitterionic surfactants include betaines, sultaines, and alkyl amine oxides.
  • Suitable zwitterionic surfactants include cocoamidopropyl betaine, cocodimethyl betaine, N,N-dimethyl hexadecaneamine N-oxide, cocodimethyl amine oxide, cocoamidopropyl hydroxysultaine, and dodecyl amino-hydroxypropyl sultaines such as lauryl hydroxysultaine (n-dodecyl(2-hydroxy-3-sulfonatopropyl)dimethylammonium).
  • the amount of zwitterionic surfactants employed in the emulsions of the second embodiment totals about 10 wt % to 20 wt % based on the total weight of an emulsion, for example about 10 wt % to 19 wt %, or about 10 wt % to 18 wt %, or about 10 wt % to 17 wt %, or about 10 wt % to 16 wt %, or about 11 wt % to 20 wt %, or about 12 wt % to 20 wt %, or about 13 wt % to 20 wt %, or about 14 wt % to 20 wt %, or about 15 wt % to 20 wt %, or about 16 wt % to 20 wt %, or about 12 wt % to 18 wt % based on the total weight of the emulsion.
  • the anionic surfactant employed in the emulsions of the second embodiment includes at least one anionic moiety and has an HLB of about 9 to 15, for example about 9 to 14, or about 9 to 13, or about 9 to 12, or about 9 to 11, or about 10 to 15, or about 11 to 15.
  • Suitable anionic surfactants include sulfonated esters of alkyl, aralkyl, or aryl-functional carboxylic acids wherein the ester groups are derivatives of linear or branched alcohols having about 4 to 15 carbons.
  • anionic surfactants include di-n-octyl sodium sulfosuccinate (“DOSS” or “Aerosol OT”), sodium bis(2-ethylhexyl) sulfosuccinate, dicyclohexyl sodium sulfosuccinate, terminal (a-) and internal olefin functional alkyl sulfonated surfactants,and alkylbenzene sulfonates.
  • DOSS di-n-octyl sodium sulfosuccinate
  • Aerosol OT sodium bis(2-ethylhexyl) sulfosuccinate
  • dicyclohexyl sodium sulfosuccinate dicyclohexyl sodium sulfosuccinate
  • terminal (a-) and internal olefin functional alkyl sulfonated surfactants and alkylbenzene sulfonates.
  • the amount of the anionic surfactant employed in the emulsions of the second embodiment totals about 1 wt % to 10 wt % based on the total weight of an emulsion, for example about 1 wt % to 9 wt %, or about 1 wt % to 8 wt %, or about 1 wt % to 7 wt %, or about 1 wt % to 6 wt %, or about 1 wt % to 5 wt %, or about 2 wt % to 10 wt %, or about 3 wt % to 10 wt %, or about 2 wt % to 9 wt %, or about 2 wt % to 8 wt %, or about 2 wt % to 7 wt %, or about 2 wt % to 6 wt %, or about 2 wt % to 5 wt %, or about 2 wt % to 4
  • the additional ionic surfactant optionally employed in the emulsions of the second embodiment comprises, consists essentially of, or consists of one or more molecules having anionic, cationic or zwitterionic functionality and at least one linear, branched or cyclic hydrocarbon moiety having 6 to 20 carbons, wherein the additional ionic surfactant is chemically different from the zwitterionic surfactant and the anionic surfactant included in the composition of the second embodiment.
  • Suitable ionic surfactants include linear alkylbenzene sulfonic acid, alkyl benzene sulfonate, alkyl sulfonates, alkyl sulfates, alkyl ether sulfates, alkyl ammonium halides, alkyl aryl ammonium halides, imidazolium, cocoamidopropyl betaine, cocodimethyl betaine, and alkyl amine oxides.
  • the amount of additional ionic surfactant employed in the emulsions of the second embodiment totals about 1 wt % to 20 wt % based on the total weight of an emulsion, for example about 1 wt % to 19 wt %, or about 1 wt % to 18 wt %, or about 1 wt % to 17 wt %, or about 1 wt % to 16 wt %, or about 1 wt % to 15 wt %, or about 1 wt % to 14 wt %, or about 1 wt % to 13 wt %, or about 1 wt % to 12 wt %, or about 1 wt % to 11 wt %, or about 1 wt % to 10 wt %, or about 2 wt % to 10 wt %, or about 3 wt % to 10 wt %, or about 4 wt % to 10
  • the emulsions of the second embodiment include one or more oil field additives conventionally used in hydraulic fracturing or post-primary fracturing of subterranean hydrocarbon-containing formations.
  • the additives are added to the emulsions and the resulting additive containing emulsions are stable, or even shelf stable.
  • the additives are not added directly to the emulsions, but rather are added to the subterranean reservoir contemporaneously with dilution of the emulsions.
  • Suitable additives include viscosifying agents, solvents, alkali, flow back aids, non-emulsifiers, corrosion inhibitors, scale inhibitors, biocides, friction reducers, emulsion breakers, and proppants (e.g. sand or aluminum oxide particles) as listed above. In some embodiments, one or more such additives are added at an amount that is less than 1 percent by weight of the emulsion of the second embodiment.
  • the additives added during dilution of an emulsion of the second embodiment are employed at about 1 ppm to 500 ppm in the fracturing fluid formed during the dilution, for example about 2 ppm to 400 ppm, or about 3 ppm to 300 ppm, or about 4 ppm to 200 ppm, or about 5 ppm to 100 ppm of one or more additives.
  • the emulsions of the second embodiment are stable. In some embodiments, the emulsions of the second embodiment are shelf stable. In some such embodiments, the emulsions are shelf stable for about 6 months to two years, or about 6 months to one year.
  • the emulsions of the invention are diluted with a high total dissolved solids water source to form a fracturing fluid.
  • the fracturing fluid is injected into a subterranean hydrocarbon containing fractured rock formation, or reservoir, where it results in increased recovery of hydrocarbon compounds from the subterranean hydrocarbon-containing formation.
  • the water source, the subterranean environment, or both are at a high temperature, that is about 60° C. or higher.
  • the emulsions of the first embodiment or the second embodiment are combined with a high total dissolved solids water source and any desired additives to produce a fracturing fluid of the invention contemporaneously with one or more injection processes.
  • the reservoirs are characterized by one or more of low permeability, low porosity, and high temperature.
  • the water source used to dilute the emulsions of the invention to form fracturing fluids are characterized by high total dissolved solids, and in particular by a high concentration of divalent cations such as calcium and magnesium.
  • the water source is produced water.
  • the water source is a combination of produced water and a second water source such as sea water, brackish water, fresh water, tap water, and the like. For example, in some embodiments, the water source is about 50% to 100% produced water.
  • the fracturing fluids of the invention comprise, consist essentially of, or consist of about 10 wt % or less of an emulsion of the first embodiment or the second embodiment, and about 90 wt % or more of a high total dissolved solids water source; optionally, the fracturing fluid further includes one or more of the additives as described above.
  • the fracturing fluids are formed by combining the water source and the emulsion using conventional mixing procedures familiar to those of skill in the art of forming hydraulic fracturing fluids. No special methods or apparatuses are required to form the fracturing fluids of the invention from the emulsions of the first or second embodiments.
  • a fracturing fluid of the invention comprises, consists essentially of, or consists of a combination of an emulsion of the first embodiment or of the second embodiment, a high total dissolved solids water source, and optionally one or more additives.
  • the water source is produced water.
  • the produced water is high temperature.
  • At the target (injectable) volume of produced water in the fracturing fluid is about 90% to 99.999% of the fracturing fluid volume, or about 91% to 99.999%, or about 92% to 99.999%, or about 93% to 99.999%, or about 94% to 99.999%, or about 95% to 99.999%, or about 96% to 99.999%, or about 97% to 99.999%, or about 98% to 99.999%, or about 99% to 99.999%, or about 90% to 99.99%, or about 90% to 99.9%, or about 90% to 99%, or about 90% to 98%, or about 92% to 99.9%, or about 94% to 99.9%, or about 95% to 99.9%, or about 98% to 99.9%, or about 99% to 99.9% of the fracturing fluid volume.
  • the water source employed to form the fracturing fluids of the invention is a high total dissolved solids water source, wherein the water source comprises about 4 wt % to 35 wt % substantially non-polymeric total dissolved solids.
  • the water source is a high temperature, high total dissolved solids water source.
  • a substantial portion of the total dissolved solids are ionic compounds.
  • High total dissolved solids water sources include about 5 wt % to 35 wt %, or about 5 wt % to 32 wt %, or about 5 wt % to 30 wt %, or about 5 wt % to 28 wt %, or about 5 wt % to 26 wt %, or about 5 wt % to 24 wt %, or about 5 wt % to 22 wt %, or about 5 wt % to 20 wt %, or about 6 wt % to 35 wt %, or about 7 wt % to 35 wt %, or about 8 wt % to 35 wt %, or about 9 wt % to 35 wt %, or about 10 wt % to 35 wt %, or about 12 wt % to 35 wt %, or about 14 wt % to 35 wt %, or about 16 wt
  • “Produced water” is an industrial term of art meaning water that flows from a subterranean formation after release of pressure used to fracture the subterranean rock.
  • the produced water is contacted with an emulsion of the invention to dilute the emulsion, and eliminate the emulsion itself (forming a single phase composition) prior to or during subterranean injection.
  • produced water contains high levels of divalent ions and other ions that cause instabilities when conventional emulsions are blended therewith.
  • Substantial amounts of ions such as Cl, Na, Ca, Mg, Sr, Ba, or Fe are known to cause instabilities in conventional fracturing fluids, that is, fracturing fluids formed from produced water and conventional emulsions.
  • the water source contacting the emulsion such as sea water, brackish water, produced water, or combinations thereof with one or more additional water sources includes 300 ppm or more of one or more ions.
  • the water source contacting the emulsion contains one more of the following: about 300 ppm or more of Ca, for example 500 ppm or more or even 3000 ppm or more of Ca; about 1100 ppm or more of Mg; about 300 ppm or more of Ba, for example about 500 ppm or more of Ba; or about 85000 ppm Cl or more.
  • stable fracturing fluids are formed from the emulsions of the invention by blending the emulsions with water sources containing 300 ppm or more of any one or more ions, such as Cl, Na, Ca, Mg, Sr, Ba, or Fe.
  • the fracturing fluids of the invention are stable in the presence of any one or more of the following: about 300 ppm to 20,000 ppm Ca, or about 500 ppm to 20,000 ppm Ca, or about 1000 ppm to 20,000 ppm Ca, or about 2000 ppm to 20,000 ppm Ca, or about 3000 ppm to 20,000 ppm Ca, or about 4000 ppm to 20,000 ppm Ca, or about 5000 ppm to 20,000 ppm Ca, or about 6000 ppm to 20,000 ppm Ca, or about 7000 ppm to 20,000 ppm Ca, or about 8000 ppm to 20,000 ppm Ca, or about 9000 ppm to 20,000 ppm Ca, or about 10,000 ppm to 20,000 ppm Ca; about 300 ppm to 4000 ppm Mg, or about 400 ppm to 4000 ppm Mg, or about 500 ppm to 4000 ppm Mg, or about 600 ppm to 4000 ppm
  • the water source contacting the emulsions of the invention is a high total dissolved solids water source wherein the total amount of ions is at least about 4 wt % (40,000 ppm) and as much as about 35 wt % (350,000 ppm); in such embodiments, the fracturing fluids of the invention are stable in the presence of high total dissolved solids water sources.
  • the fracturing fluids of the invention are stable not only in the presence of ions in individual amounts greater than 300 ppm, and in the presence of about 4 wt % to 35 wt % total dissolved solids, but further wherein the fracturing fluid is formed, injected, or otherwise employed at about 10° C.
  • to 60° C. or about 20° C. to 60° C., or about 30° C. to 60° C., or about 40° C. to 60° C., or about 50° C. to 60° C., or at high temperature, that is about 60° C. to 120° C., or about 70° C. to 120° C., or about 80° C., to 120° C., or about 90° C. to 120° C.
  • a produced water can have one or more of the following: more than about 24,000 ppm Na content, more than about 2500 Ca content, more than about 70,000 Cl content, more than about 100 ppm Ba content, more than about 50 ppm Fe content, more than about 500 ppm Mg content, and more than about 1500 ppm carbonate (carbonic acid equivalent) content.
  • a fracturing fluid can be made using produced water to dilute an emulsion prior to injection only if the emulsion produces a stable diluted fluid in the presence of a range of dissolved ionic species as well as concentrations of those species.
  • Additional challenges of employing produced water include substantial compositional variability (see Table 1), variation in regulations governing the storage, treatment, and disposal of produced water, and availability of produced water at the source—that is, fresh water or other low total dissolved solids water sources are often not readily available in the field, or are in short supply and cannot be used to dilute the produced water. Shipping water to the field is not a practical solution due to cost. Thus, it is beneficial to hydraulic fracturing operations to enable the use of the substantially variable high total dissolved water sources available in the field.
  • the emulsions of the first embodiment and the second embodiment are usefully employed to dilute with high total dissolved solids water, such as produced water, to form stable fracturing fluids.
  • the fracturing fluids of the invention do not exhibit cloudiness, precipitation, phase separation, gelation, or any other behavior attributable to instability.
  • the fracturing fluids are thermally stable when subjected to underground conditions including temperatures of about 60° C. to 120° C.
  • the fracturing fluids made using produced water are suitable for injection into a subterranean reservoir, where the fluids remain stable and do not cause precipitation, phase separation, or another behavior attributable to instability, while flowing underground. This in turn results in optimal recovery of hydrocarbons from the reservoir.
  • the fracturing fluids of the invention are particularly useful for increasing the yield of hydrocarbon products from reservoirs where high temperatures are encountered underground since no instabilities are encountered due to high temperature.
  • a method of the invention comprises, consists essentially of, or consists of diluting the emulsions of the first embodiment or the second embodiment with a high total dissolved solids water source to form a fracturing fluid, injecting the fracturing fluid into a well which is in contact with a subterranean hydrocarbon-containing formation, and collecting one or more hydrocarbon compounds from the well.
  • the fracturing fluid contains an amount of the emulsion of the invention that is effective for lowering the interfacial tension between fracturing fluid and the hydrocarbon compounds trapped within the formation.
  • the fracturing fluid contains an amount of the emulsion of the invention that is effective for changing the wettability of the subterranean hydrocarbon-containing formation to recover hydrocarbon compounds from the subterranean hydrocarbon-containing formation.
  • the injecting includes injecting into an underground reservoir wherein high temperatures are encountered.
  • the fracturing fluid becomes a high temperature fracturing fluid.
  • the water source present in the fracturing fluid becomes a high temperature water source in addition to being a high total dissolved solids water source.
  • the underground temperatures encountered by the injected fracturing fluids of the invention is about 60° C. to 120° C., for example about 60° C. to 115° C., or about 60° C.
  • the fracturing fluids of the invention are stable at these high temperatures.
  • the fracturing fluids of the invention When subjected to high temperature conditions, the fracturing fluids of the invention maintain superior properties for producing low interfacial tension with hydrocarbon compounds, low adsorption onto rock surfaces, production of water-wettable rock surfaces, and improved sweeping efficiency and proppant clean-up performance under gravitational flow conditions when compared to conventional fracturing fluids.
  • the methods of the invention optionally include adding one or more additives to the emulsion or to the fracturing fluid prior to or contemporaneously with formation of and/or injection of the fracturing fluid into a subterranean reservoir.
  • Suitable additives include viscosifying agents, solvents, alkali, flow back aids, non-emulsifiers, corrosion inhibitors, scale inhibitors, biocides, friction reducers, emulsion breakers, and proppants (e.g., sand or aluminum oxide particles).
  • Suitable corrosion inhibitors include imidazoline and quaternary ammonium compounds and functionalized compounds and polymers.
  • Suitable scale inhibitors include phosphonate compounds and acrylated polymers.
  • the additives added during dilution of an emulsion to form a fracturing fluid.
  • the additives are employed at about 1 ppm to 500 ppm in the fracturing fluid, for example about 2 ppm to 400 ppm, or about 3 ppm to 300 ppm, or about 4 ppm to 200 ppm, or about 5 ppm to 100 ppm of one or more additives.
  • rock surfaces contacted by the fracturing fluids changes from oil-wettable to water-wettable. Yet the emulsion components of the fracturing fluids exhibit a low tendency to adsorb onto the rock.
  • the methods of the invention further include collecting one or more hydrocarbon compounds from the underground reservoir after injection of the fracturing fluid of the invention into the reservoir.
  • the fracturing fluids of the invention are effective to change the wettability of subterranean rock, coated or even saturated with hydrocarbon compounds, from oil-wet to water-wet, or from mixed-wet to water-wet. Wettability of the subterranean rock is critical for obtaining maximum yield of hydrocarbon, which can otherwise stay adhered to the surface of rock in the form of a film.
  • the large amount of subterranean rock surface area makes the surface energy, that is, the wettability of the rock with oil vs. aqueous compositions, critical.
  • Wettability is determined by measuring contact angle of a fracturing fluid on oil-saturated rock.
  • the fracturing fluids of the invention result in a contact angle of less than 90° when contacted with rock previously soaked in hydrocarbon compounds such as crude oil products.
  • contact angle of a fracturing fluid of the invention is observed to be 70° or less, such as about 5° to 70°, or about 10° to 70°, or about 20° to 70°, or about 30° to 70°, or about 40° to 70°, or about 5° to 65°, or about 5° to 60°, or about 5° to 55°, or about 5° to 50°, or about 5° to 45°, or about 10° to 60°, or about 10° to 50°, or about 20° to 50°, or about 30° to 50°.
  • contact angle of a fracturing fluid of the invention is observed to be 50° or less, such as about 5° to 50°, or about 10° to 50°, or about 20° to 50°, or about 30° to 50°, or about 5° to 45°, or about 5° to 40°, or about 5° to 35°, or about 10° to 35°, or about 10° to 30°, or about 20° to 40°, or about 25° to 40°.
  • contact angle of a fracturing fluid of the invention is observed to be 40° or less, such as about 5° to 40°, or about 7° to 40°, or about 10° to 40°, or about 15° to 40°, or about 20° to 40°, or about 5° to 35°, or about 5° to 30°, or about 5° to 25°, or about 5° to 20°, or about 7° to 30°, or about 7° to 25°, or about 10° to 25°.
  • the emulsions of the invention exhibit low critical micelle concentration (cmc) when diluted with a water source.
  • the emulsions of the invention that is the combined emulsion components along with any additives employed - exhibit cmc of about 1 ppm to 50 ppm, or about 1 ppm to 40 ppm, or about 1 ppm to 30 ppm, or about 1 ppm to 20 ppm, or about 1 ppm to 10 ppm, or about 2 ppm to 10 ppm in high temperature, high total dissolved solids water sources, wherein measured cmc values vary as a function of type and amount of solids dissolved in the water source and temperature of the water.
  • fracturing fluids of the invention lead to reduced interfacial tension between the fracturing fluid and the hydrocarbon compounds present in the hydrocarbon containing subterranean rock formation.
  • a fracturing fluid of the invention reduces interfacial tension between a hydrocarbon compound mixture and a high temperature high total dissolved solids water source an order of magnitude or more compared to the interfacial tension of a mixture of the hydrocarbon compound mixture and the high temperature, high total dissolved solids water source without the fracturing fluid of the invention.
  • the interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention is about 0.2 mN/m to 0.005 mN/m, or about 0.15 mN/m to 0.005 mN/m, or about 0.12 mN/m to 0.005 mN/m, or about 0.1 mN/m to 0.005 mN/m, or about 0.09 mN/m to 0.005 mN/m, or about 0.08 mN/m to 0.005 mN/m, or about 0.07 mN/m to 0.005 mN/m, or about 0.06 mN/m to 0.005 mN/m, or about 0.05 mN/m to 0.005 mN/m, or about 0.04 mN/m to 0.005 mN/m, or about 0.03 mN/m to 0.005 mN/m, or about 0.02 mN/m to 0.005 mN
  • the interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention stays within the stated ranges. It is an unexpected advantage of the fracturing fluids of the invention that very low interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention is maintained even at elevated temperatures. At such temperatures, the fracturing fluid also contains high total dissolved solids. Yet the fracturing fluids are stable under such conditions and provide enhanced performance as a result of these properties.
  • the interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention remains substantially constant in high total dissolved solids water sources over a range of water source composition. This is so even when the water source includes a substantial amount of divalent cations such as calcium, magnesium, barium, and the like. This effect is beneficial for providing predictable performance of the fracturing fluids over a range of conditions encountered in the field.
  • the interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention varies about ⁇ 0.08 mN/m or less over a range of water sources having between 0 and 35 wt % total dissolved non-polymeric solids, for example about ⁇ 0.08 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.07 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.06 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.05 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.04 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.03 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.02 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.08 mN/m to ⁇ 0.02 mN/m, or about ⁇ 0.08 mN
  • the interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention remains substantially constant in high total dissolved solids water sources over a range of temperatures. This is so even when the water source includes a substantial amount of divalent cations such as calcium, magnesium, barium, and the like. This effect is beneficial for providing predictable performance of the fracturing fluids over a range of conditions encountered in the field.
  • the interfacial energy of a mixture of a hydrocarbon and a fracturing fluid of the invention varies about ⁇ 0.08 mN/m or less when measured in water sources having between 0 and 35 wt % total dissolved non-polymeric solids and further wherein the temperature of the fracturing fluid ranges from about 20° C.
  • ⁇ 0.08 mN/m to ⁇ 0.01 mN/m for example about ⁇ 0.08 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.07 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.06 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.05 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.04 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.03 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.02 mN/m to ⁇ 0.01 mN/m, or about ⁇ 0.08 mN/m to ⁇ 0.02 mN/m, or about ⁇ 0.08 mN/m to ⁇ 0.03 mN/m, or about ⁇ 0.08 mN/m to ⁇ 0.04 mN/m, or about ⁇ 0.06 mN/m to ⁇ 0.0
  • the fracturing fluids of the invention do not induce formation of emulsions with hydrocarbon compounds when injected into subterranean reservoirs.
  • a fracturing fluid of the invention is thoroughly mixed with a hydrocarbon compound or mixture thereof using a high shear mixing apparatus designed to form emulsions, the mixture separates rapidly once shear is stopped. In some embodiments, such mixtures separate completely within about 1 minute to 5 minutes, or about 1 minute to 4 minutes, or about 1 minute to 3 minutes, or about 2 minutes to 5 minutes, or about 2 minutes to 4 minutes.
  • the fracturing fluids exhibit improved sweeping efficiency and proppant clean-up performance under gravitational flow conditions when compared to conventional fracturing fluids.
  • the fracturing fluids of the invention substantially increase the yield of hydrocarbon compounds and mixture thereof, such as crude oil or shale oil, from underground reservoirs when injected therein when compared to conventional compositions. Water saturation of sand type proppants, for example, is reduced by employing the fracturing fluids.
  • saturation of proppant silica sand after treatment with the fracturing fluids of the invention followed by gravity assisted draining is less than about 70 wt % fracturing fluid based on the weight of the sand, for example about 70 wt % to 20 wt %, or about 70 wt % to 25 wt %, or about 70 wt % to 30 wt %, or about 70 wt % to 35 wt %, or about 70 wt % to 40 wt %, or about 70 wt % to 45 wt %, or about 70 wt % to 50 wt %, or about 65 wt % to 20 wt %, or about 60 wt % to 20 wt %, or about 55 wt % to 20 wt %, or about 50 wt % to 20 wt %, or about 45 wt % to 20 wt %, or about
  • the average flow rate of hydrocarbons recovered from the reservoir after treating with a fracturing fluid of the invention is increased at least ten-fold, or 10 ⁇ , compared to the average flow rate obtained by conventional surfactants; in embodiments the average flow rate is increased 10 ⁇ to 50 ⁇ , or 20 ⁇ to 50 ⁇ , or 30 ⁇ to 50 ⁇ , or even 40 ⁇ to 50 ⁇ compared to flow rate obtained by conventional surfactants.
  • oil flow rates as high as about 0.1 mL/min to 1 mL/min are obtained using the fracturing fluids of the invention, or about 0.2 mL/min to 1 mL/min, or about 0.3 mL/min to 1 mL/min, or about 0.4 mL/min to 1 mL/min, or about 0.5 mL/min to 1 mL/min, or about 0.1 mL/min to 0.9 mL/min, or about 0.1 mL/min to 0.8 mL/min, or about 0.1 mL/min to 0.7 mL/min, or about 0.1 mL/min to 0.6 mL/min, or about 0.1 mL/min to 0.5 mL/min are obtained using the fracturing fluids of the invention.
  • the subterranean hydrocarbon-containing formation addressed by the emulsions and fracturing fluids of the invention is a sandstone reservoir or a carbonate reservoir.
  • the injection is carried out after hydraulic fracturing of the well. In other embodiments, the injection is carried out during hydraulic fracturing of the well.
  • the methods of the invention are particularly useful when the reservoir has low permeability, low porosity, oil-wet wettability, high temperature, and/or high salinity, and/or when there is a high concentration of divalent cations in the fracturing fluid and/or produced water.
  • SAGD steam assisted gravity drainage
  • SAGD is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of parallel horizontal wells are drilled into a subterranean reservoir, one a few meters above the other. High pressure steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore, where it is pumped out.
  • the emulsions or fracturing fluids of the invention are usefully injected along with the steam to affect wettability, surface tension, and the like.
  • Emulsion 1 The following components were blended to form Emulsion 1:
  • Nonylphenol ethoxylates (HLB of about 13) 2.4 wt % Castor oil ethoxylate (HLB of about 11.5) 0.8 wt % Methanol 10.8 wt % Cocoamidopropyl betaine 9.6 wt % Water 58.8 wt % Choline chloride 15.0 wt % C12-14 alcohol ethoxylate (HLB of about 8) 0.2 wt % Ethylene oxide/propylene oxide copolymer 0.8 wt % Polyethylene imine ethoxylate 1.0 wt %
  • Emulsion 1 was observed to be stable. Emulsion 1 was further observed to be a microemulsion. Emulsion 1 was observed to be stable at 115° C.
  • the solubility of surfactant-containing compositions in brines was determined to reduce the possibility of damage to a reservoir in subsequent field testing. This screening test ensures that no solid precipitates when the composition comes into contact with a formation fluid or fracturing fluid.
  • compositions were prepared by adding the compositions to Bakken produced water (27% total dissolved solids) to form aqueous mixtures having 0.2% concentration of actives. The mixtures were monitored for stability at 115° C. and were observed for precipitation and suspension formation. A mixture that remains visibly clear is considered to have sufficient aqueous stability. The results are reported in Table 2.
  • a composition was formed according to Example 1. Then 120 ppm of a quaternized imidazoline surfactant (corrosion inhibitor), 150 ppm of a a phosphonate (scale inhibitor), and 120 ppm glutaraldehyde (biocide) was added to the composition to yield a shelf stable microemulsion, referred to as Emulsion 2.
  • a quaternized imidazoline surfactant corrosion inhibitor
  • 150 ppm of a a phosphonate scale inhibitor
  • 120 ppm glutaraldehyde biocide
  • Bakken reservoir rock core plugs were weighed, saturated with Bakken oil (a hydrocarbon compound mixture) and stored for at least 4 days at ambient pressure to achieve oil wet status. Then excess oil was wiped from the plugs, and the plugs were reweighed; the density of the oil was determined in order to calculate the volume of oil taken up by the rock cores. The cores were then placed with all faces opened in glass imbibition cells having precision graduations in 0.1 mL. For each of the following tests, two rock core plugs were tested.
  • Emulsion 1 An aliquot of Emulsion 1 was diluted to 0.1 wt % solids (that is, a total of 0.1 wt % of all surfactants combined) with a 4 wt % brine solution to form Fracturing Fluid 1.
  • the imbibition cells were filled with a volume of the diluted Emulsion 1, then placed in a heated bath set at a temperature of 115° C. Displaced oil from the plugs formed a layer on top of the diluted Emulsion 1 in the cells, quantifiable as displaced volume.
  • the cells were allowed to remain in the heated bath for up to 500 hours or until displacement of oil, measured by the volume graduations of the imbibition cells, was observed to stop.
  • ODIP % Original Oil in Place
  • Emulsion 2 was repeated with Emulsion 2, diluted to 0.1% solids in 4% brine to form Fracturing Fluid 2.
  • a comparative experiment was run using 4% brine alone. Then the experiment was repeated using 0.1 wt % of various surfactants dissolved in 4% brine.
  • the sulfobetaine is lauryl sulfobetaine, which is described in International Publication WO
  • the alcohol ether sulfonate is oleyl alcohol ether sulfonate, as described in U.S. Pat. No. 7,629,299. Results are shown in Table 3.
  • Example 3 The procedure of Example 3 was repeated with Emulsion 2, except that Emulsion 2 was diluted to 0.01 wt % solids with 4% brine to form Fracturing Fluid 3. Results of oil displacement are shown in Table 4.
  • Bakken cores were saturated with the Bakken oil at 900 psi (6205 kPa), 115° C. for 7 days or longer, then the surface oil was wiped off. A drop of a test material was placed on the core and the contact angle was measured as a function of time after drop placement using a goniometer. A comparative experiment was run with 4% brine alone. Additionally, the sulfobetaine and alcohol ether sulfonate employed in Example 2 were added at 0.1 wt % in 4% brine and contact angle measurements carried out with these surfactants solutions. All measurements were made at 25° C. Results are shown in Table 5.
  • Critical micelle concentration at 80° C. was determined for Emulsion 1 by measuring the surface tension as a function of surfactant concentration at 80° C. using a Kriiss Tensiomer K-100 (obtained from Kriiss GmbH of Hamburg, Germany). As a comparative example, the sulfobetaine employed in Example 2 was also measured. Table 6 shows the results of critical micelle concentration (cmc) measurements.
  • Emulsion 3 was tested according to the above procedure and the results are reported in Table 7.
  • Emulsion 1 was diluted to various concentrations in 4% brine and 22% brine against Bakken oil at 80 C.
  • Interfacial tension (IFT) was measured for the diluted Emulsion 1 using a spinning drop tensiometer.
  • Table 8 shows the interfacial tension (IFT) of Emulsion 1 as a function of the concentration of Emulsion 1 actives.
  • Emulsion 1 actives against Bakken oil at 80° C.
  • Emulsions 4-10 were blended to form Emulsions 4-10, C1 (control), and C2 (control).
  • the blended components formed microemulsions at ambient temperature.
  • fracturing fluids formed from emulsions C1, C2, 4, 5, and 7 were measured by diluting the emulsions with brine and observing the fracturing fluids at selected temperatures.
  • fracturing fluids were formed by diluting the emulsions to a total of 0.2 wt % of emulsion “actives” (components other than water) with either a 2 wt % total dissolved solids (TDS) water source (synthetic Eagle Ford brine) or a 30 wt % TDS water source (synthetic Bakken brine).
  • TDS total dissolved solids
  • the fracturing fluids were held at 20° C., 55° C., 65° C., 75° C., or 90° C. for two weeks and the appearance of the fluid was assessed. Results are shown in Table 10. “Unstable” for purposes of this experiment means any visible sign of phase separation or precipitation.
  • Interfacial tension experiments were carried out on fracturing fluids formed from Emulsions 5 and C1 using an M6500 spinning drop tensiometer (obtained from Grace Instrument Company of Houston, Tex.). Fracturing fluid samples were prepared by diluting the emulsion with a brine solution at 1:1000 vol/vol emulsion:brine. The brine included 110,000 ppm total dissolved solids (11 wt % TDS). Tensiometer readings were recorded every 5 minutes over a 30 minute test period to evaluate the interaction of the tested fracturing fluid with crude oil, condensate or model alkane oil at projected reservoir temperatures.
  • the interfacial tension of the fracturing fluid derived from Emulsion C2 with Eagle Ford condensate was found to be 1.007 mN/m at ambient temperature; the interfacial tension of the fracturing fluid derived from Emulsion 5 with Eagle Ford condensate was 0.012 mN/m at ambient temperature.
  • Emulsions 4 and 8 were repeated for Emulsions 4 and 8, wherein temperature was varied from 30° C. to 90° C. during the test.
  • a plot of interfacial tension after 30 min equilibration at each target temperature is shown in FIG. 1 .
  • Emulsions 5 and 8 were repeated for Emulsions 5 and 8, wherein measurements were compared at 1:1000 vol:vol of the emulsion:2 wt % KCl and 1:500 emulsion:2 wt % KCl.
  • a semi-log scale plot of interfacial tension (after 30 min equilibration at the target temperature) as a function of temperature is shown in FIG. 2 .
  • Emulsions 5 and 8 were repeated for Emulsions 5 and 8, wherein measurements were compared at 1:1000 vol:vol of the emulsion:12 wt % KCl and 1:500 emulsion:12 wt % KCl.
  • a semi-log scale plot of interfacial tension (after 30 min equilibration at the target temperature) as a function of temperature is shown in FIG. 3 .
  • Emulsions 5 and 8 wherein the dilutions were 1:1000 emulsion:brine and for Emulsions 5, 8, and 10 wherein the dilutions were 1:500 emulsion:brine, wherein for all emulsions and dilutions the brine composition was varied between 2 wt % and 12 wt % KCl, and the entire test was conducted at 90° C.
  • a semi-log scale plot of interfacial tension (after 30 min equilibration at 90° C.) as a function of KCl concentration is shown in FIG. 4 .
  • Gravitational drainage column testing was carried out on on fracturing fluids formed from Emulsions 5, 10, and C1. This test was designed to evaluate the sweeping efficiency and proppant clean-up performance of different fracturing fluids under gravitational flow conditions.
  • the test employs crude oil or a condensate, brine (synthetic or formation), 100-mesh sand, and a fracturing fluid.
  • Fracturing fluid samples were prepared by diluting an emulsion with a brine solution at a ratio of 1:1000 vol/vol or 1:500 vol/vol emulsion:brine. The column was pre-heated to the indicated temperature.
  • the column pack was prepared by filling the column with about 16.5 mL of the fracturing fluid to be tested and slowly adding 60 grams of sand into the column. Then the column was compacted using vibration to minimize the presence of air pockets and compact the sand in the column. After compacting, the level of the fracturing fluid in the column was adjusted to extend to just above the sand pack. Then the column was allowed to stand undisturbed for 30 minutes or until the column reached the target temperature. Then two pore volumes of oil ( ⁇ 33 mL) were added into the column, a valve at the bottom of the column was open and a timer was started. Effluent flowing from the column was observed. The time when oil first appeared in the effluent was recorded as the time to breakthrough. The flow rate of oil after breakthrough was measured by recording the cumulative oil flowing out of the column after breakthrough and over about 30-60 min. Results are shown in Table 11.
  • Emulsions 5 and 10 provide substantially lower water saturation and substantially higher rate of oil flow compared to Emulsion C1. In the field, these results translate to more complete water cleanup (improved final water quality) and lower fracturing fluid saturation of the subterranean reservoir.
  • Emulsions 8 and 10 Thermal stability of Emulsions 8 and 10 was tested by measuring the surface tension of each emulsion in 2% aqueous KCl at 300° F. (149° C.) at 200 psi (1379 kPa) as a function of time. Each emulsion was prepared at 0.2% by weight of surfactant solids in the 2% aqueous KCl solution. The initial surface tension value of each prepared emulsion was measured by the Wilhemy plate method using a Kriiss Force Tensiometer K100. Each prepared emulsion was then transferred into a a Teflon liner and each Teflon liner was placed inside an aging cell constructed of grade 316 stainless steel.
  • Each aging cell was pressurized to 200 psi (1379 kPa) and then both cells were placed in an oven at 300° F. (149° C.).
  • Samples of each prepared emulsion were taken out periodically (every 3-4 days) and the surface tension value of each prepared emulsion was measured by the Wilhemy plate method using a Kriiss Force Tensiometer K100. The surface tension values were monitored until a significant increase in surface tension was observed (i.e. when surface tension changed from 27 mN/m to 60 mN/m).
  • Plots of the surface tensions of the two prepared emulsions as a function of time are shown in FIG. 5 and the results are shown in Table 12.
  • Emulsion 10 shows improved thermal stability as judged by surface tension stability over time at 300° F. (149° C.) and 200 psi (1379 kPa) in 2% KCl.
  • the surface tension of prepared Emulsion 8 rose from an initial value of 26.39 mN/m to 31.73 mN/m at 7 days, and at 14 days had risen to 47.35 mN/m, rising to over 50 mN/m after 21 days.
  • the surface tension of prepared Emulsion 10 did not rise over the first 14 days: from an initial value of 25.23 mN/m, the surface tension of prepared Emulsion 10 at 14 days was measured to be 24.89 mN/m, and had only rise to 25.98 mN/m at 21 days, 31.56 mN/m at 28 days, 34.58 mN/m at 35 days, and 33.66 mN/m after 42 days.
  • the invention illustratively disclosed herein can be suitably practiced in the absence of any element which is not specifically disclosed herein. While the invention is susceptible to various modifications and alternative forms, specifics thereof have been shown by way of examples, and are described in detail. It should be understood, however, that the invention is not limited to the particular embodiments described. On the contrary, the intention is to cover modifications, equivalents, and alternatives falling within the spirit and scope of the invention as described herein. In various embodiments, the invention suitably comprises, consists essentially of, or consists of the elements described herein and claimed according to the claims.

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EP3262276A1 (fr) 2018-01-03
RU2715771C2 (ru) 2020-03-03
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RU2017129837A (ru) 2019-02-25
CA2976263A1 (fr) 2016-09-01
EP3262276B1 (fr) 2020-10-07
BR112017017404A2 (pt) 2018-04-03
US20180312745A1 (en) 2018-11-01
US10767104B2 (en) 2020-09-08

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