WO2018031655A1 - Particules polymères sensibles aux stimuli et leurs procédés d'utilisation - Google Patents

Particules polymères sensibles aux stimuli et leurs procédés d'utilisation Download PDF

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Publication number
WO2018031655A1
WO2018031655A1 PCT/US2017/046095 US2017046095W WO2018031655A1 WO 2018031655 A1 WO2018031655 A1 WO 2018031655A1 US 2017046095 W US2017046095 W US 2017046095W WO 2018031655 A1 WO2018031655 A1 WO 2018031655A1
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Prior art keywords
salinity
composition
monomers
polymer particles
responsive polymer
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PCT/US2017/046095
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English (en)
Inventor
Kishore K. Mohanty
Krishna PANTHI
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Board Of Regents, The University Of Texas System
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Publication of WO2018031655A1 publication Critical patent/WO2018031655A1/fr

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Classifications

    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20—Displacing by water
    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/514—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
    • 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
    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • 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
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Definitions

  • Water injection used in oil production is where water is injected into the reservoir to stimulate production. Generally, water is injected for two reasons: (1) for pressure support of the reservoir (also known as voidage replacement), and (2) to sweep or displace the oil from the reservoir, and push it towards an oil production well. Normally only 20% of the oil in a reservoir can be extracted, but water injection increases that percentage (known as
  • Oil recovery can be improved by blocking thief zones, thereby forcing fluids (e.g., water and/or carbon dioxide) through less permeable regions of the formation. By forcing these fluids through less permeable regions of the formation, the fluids will drive oil trapped within these less permeable regions towards an oil production well.
  • fluids e.g., water and/or carbon dioxide
  • compositions that include stimuli-responsive polymer particles that swell in response to a stimulus, such as a change in salinity, as well as oil recovery methods employing these compositions.
  • the stimuli-responsive polymer particles can be dispersed in an aqueous carrier having a first salinity at which the stimuli-responsive polymer particles swell slightly (or not at all), such that the stimuli-responsive polymer particles have an average particle size suitable for injection into high permeability regions of a subsurface reservoir.
  • this composition is injected into a subsurface reservoir, the salinity-responsive polymer particles are deposited within high permeability regions of the subsurface reservoir.
  • aqueous composition having a second salinity e.g., a salinity that is greater or less than the first salinity
  • a second salinity e.g., a salinity that is greater or less than the first salinity
  • compositions that comprise a population of salinity- responsive polymer particles dispersed in an aqueous carrier.
  • the salinity-responsive polymer particles can have an average particle size of from 1 micron to 1000 microns (e.g., from 5 microns to 500 microns, from 1 micron to 250 microns, from 5 microns to 250 microns, from 1 micron to 100 microns, from 5 microns to 100 microns, from 50 microns to 1000 microns, or from 50 microns to 500 microns).
  • the salinity-responsive polymer particles can occupy a first volume when dispersed in an aqueous carrier having a first salinity, and a second volume when dispersed in an aqueous carrier having a second salinity.
  • the second volume can be at least ten times greater (e.g., at least twenty times greater, or at least thirty times greater) than the first volume.
  • the salinity-responsive polymer particles can be stable to changes in pH.
  • the salinity-responsive polymer particles can exhibit relatively minimal changes in swelling across a wide range of pH values (e.g., across a range of pH values from 2 to 12.6, across a range of pH values from 4 to 10, across a range of pH values from 7 to 12.6, across a range of pH values from 9 to 12.6, or across a range of pH values from 2 to 7).
  • the pH stability of the salinity-responsive polymer particles can render these particles compatible with a wide variety of enhanced oil recovery methods, including methods that employ alkaline floods and methods that include carbon dioxide flooding.
  • the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 4; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume,
  • the salinity-responsive polymer particles can comprise a copolymer derived from one or more ethylenically unsaturated monomers.
  • the one or more ethylenically unsaturated monomers can comprise acrylamide.
  • the salinity-responsive polymer particles can comprise a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the copolymer can be derived from 10% to 80% by weight (e.g., from 20% to 60% by weight, or from 25% to 45% by weight) acrylamide monomers, based on the total weight of the monomers that form the copolymer. In one embodiment, the copolymer can be derived from 30% to 40% by weight (e.g., about 35% by weight) acrylamide monomers, based on the total weight of the monomers that form the copolymer. The copolymer can be derived from 20% to 90% by weight (e.g., from 35% to 80% by weight, from 45% to 70% by weight) acid-containing monomers, based on the total weight of the monomers that form the copolymer. In one embodiment, the copolymer can be derived from 50% to 65% by weight (e.g., about 58% by weight) acid-containing monomers, based on the total weight of the monomers that form the copolymer.
  • the salinity-responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0-15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the one or more acid-containing monomers comprise sulfonic acid groups.
  • the one or more acid-containing monomers are chosen from vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2- methacrylamido-2-methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3-acrylamido- 3-methylbutanesulfonic acid, and 2-acrylamido-2,4,4-trimethylpentanesulfonic acid.
  • the one or more acid-containing monomers comprise 2-acrylamido-2- methylpropanesulfonic acid.
  • the one or more additional ethylenically-unsaturated monomers can comprise any suitable monomers.
  • the one or more ethylenically-unsaturated monomers can comprise one or more poly ethylenically-unsaturated monomers (e.g., one or more diethylenically-unsaturated monomers, one or more triethylenically-unsaturated monomers, one or more tetraethylenically-unsaturated monomers, one or more pentaethylenically-unsaturated monomers).
  • the salinity-responsive polymer particles can comprise a polysaccharide (co)polymer (e.g., a polysaccharide polymer or copolymer).
  • the salinity-responsive polymer particles can comprise an alginate
  • the polysaccharide (co)polymer can comprise a blend of an alginate (co)polymer and a second (co)polymer.
  • the alginate (co)polymer and the second (co)polymer can be blended at varying weight ratios.
  • the alginate (co)polymer and the second (co)polymer can be present in the particles in a weight ratio of from 2:1 to 10:1 (e.g., from 4:1 to 8:1).
  • the second (co)polymer can comprise, for example, chitosan.
  • compositions comprising the salinity-responsive polymer particles described herein can be used in oil and gas operations, including oil recovery operations.
  • Methods for hydrocarbon recovery can comprise (a) providing a subsurface reservoir containing hydrocarbons there within; (b) providing a wellbore in fluid communication with the subsurface reservoir; (c) preparing an aqueous particle composition comprising a population of salinity-responsive polymer particles having a first volume dispersed in an aqueous carrier having a first salinity; (d) injecting the aqueous particle composition through the wellbore into the subsurface reservoir, thereby depositing the salinity-responsive polymer particles within high permeability regions of the subsurface reservoir; and (e) injecting an aqueous composition having a second salinity into the subsurface reservoir, thereby causing the population of salinity-responsive polymer particles within the high permeability regions of the subsurface reservoir to swell to a second volume.
  • the second volume can be at least ten times (e.g., at least twenty times, or at least thirty times) greater than the first volume.
  • the aqueous particle composition can be any of the compositions described above.
  • the aqueous particle composition can comprise a population of salinity-responsive polymer particles formed from a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the salinity-responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0- 15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the first salinity can be higher than the second salinity.
  • the aqueous particle composition can comprise a population of salinity- responsive polymer particles formed from an alginate (co)polymer (e.g., an alginate polymer or copolymer) or a blend of an alginate (co)polymer and a second (co)polymer (e.g., chitosan).
  • the second salinity can be higher than the first salinity.
  • the wellbore in step (b) can be an injection wellbore associated with an injection well.
  • the methods of hydrocarbon recovery can further comprise providing a production well spaced apart from the injection well a predetermined distance and having a production wellbore in fluid communication with the subsurface reservoir. Injection of the aqueous composition having a second salinity in step (e) can increase the flow of hydrocarbons to the production wellbore.
  • Methods can further comprise producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.
  • the aqueous composition having a second salinity can comprise a polymer (P) flooding solution, an alkaline-polymer (AP) flooding solution, a surfactant-polymer (SP) flooding solution, an alkaline- surfactant-polymer (ASP) flooding solution, or any combination thereof.
  • methods can further include injecting a polymer flooding solution, an AP flooding solution, a SP flooding solution, an ASP flooding solution, carbon dioxide, or any combination thereof into the subsurface reservoir following step (e), and producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.
  • Figure 1A includes photographs illustrating dry SSPP particles (left) and SSPP particles in DI water (right) at the same magnification.
  • Figure IB includes photographs illustrating similar sized dry particles after immersing in two different brines.
  • Figure 1C illustrates the swelling of 0.1 cc of SSPP particles in DI water (sample b) and NaCl solution (sample a).
  • Figures 2A- Figures 2C illustrate the swelling of SSPP particles as a function of NaCl concentration at 25°C.
  • Figure 2A shows 0.1 cc of dry SSPP particles in different vials before the addition of brines
  • Figure 2B shows the swollen SSPP particles after an hour in NaCl solutions of varying concentration.
  • Figure 2C is a plot showing the swelling factor of SSPP particles as a function of salinity.
  • Figure 3A is a plot showing the swelling factor of SSPP particles as a function of time (in days) upon incubation in deionized water (diamond trace), 0.1% NaCl (square trace), and 20% NaCl (triangle trace) at room temperature.
  • Figure 3B is a plot showing the swelling factor of SSPP particles as a function of time (in days) upon incubation in deionized water (diamond trace), 0.1% NaCl (square trace), and 20% NaCl (triangle trace) at 60°C.
  • Figure 3C is a plot showing the swelling factor of SSPP particles as a function of time (in days) upon incubation in deionized water (diamond trace), 0.1% NaCl (square trace), and 20% NaCl (triangle trace) at 80°C.
  • Figure 4 is a plot detailing the oil recovery and pressure drop of core flood #1.
  • Figure 5 is a plot detailing the oil recovery and pressure drop of core flood #2.
  • Figure 6 is a plot detailing the oil recovery and pressure drop of core flood #3.
  • Figure 7 includes photographs illustrating the core and SSPP particles before and after flooding during core flood #3.
  • Figure 8 is a plot detailing the oil recovery and pressure drop of core flood #4.
  • Oil recovery can be improved by blocking thief zones, thereby forcing fluids (e.g., water and/or carbon dioxide) through less permeable regions of the formation. By forcing these fluids through less permeable regions of the formation, the fluids will drive oil trapped within these less permeable regions towards an oil production well.
  • fluids e.g., water and/or carbon dioxide
  • compositions that include stimuli-responsive polymer particles that swell in response to a stimulus, such as a change in salinity, as well as oil recovery methods employing these compositions.
  • the stimuli-responsive polymer particles can be dispersed in an aqueous carrier having a first salinity at which the stimuli-responsive polymer particles swell slightly (or not at all), such that the stimuli-responsive polymer particles have an average particle size suitable for injection into high permeability regions of a subsurface reservoir.
  • this composition is injected into a subsurface reservoir, the salinity-responsive polymer particles are deposited within high permeability regions of the subsurface reservoir.
  • aqueous composition having a second salinity e.g., a salinity that is greater or less than the first salinity
  • a second salinity e.g., a salinity that is greater or less than the first salinity
  • compositions that comprise a population of salinity- responsive polymer particles dispersed in an aqueous carrier.
  • the salinity-responsive polymer particles can have an average particle size of from 1 micron to 1000 microns (e.g., from 5 microns to 500 microns, from 1 micron to 250 microns, from 5 microns to 250 microns, from 1 micron to 100 microns, from 5 microns to 100 microns, from 50 microns to 1000 microns, or from 50 microns to 500 microns).
  • the salinity-responsive polymer particles can occupy a first volume when dispersed in an aqueous carrier having a first salinity, and a second volume when dispersed in an aqueous carrier having a second salinity.
  • the second volume can be at least ten times greater (e.g., at least twenty times greater, or at least thirty times greater) than the first volume.
  • the salinity-responsive polymer particles can be stable to changes in pH.
  • the salinity-responsive polymer particles can exhibit relatively minimal changes in swelling across a wide range of pH values (e.g., across a range of pH values from 2 to 12.6, across a range of pH values from 4 to 10, across a range of pH values from 7 to 12.6, across a range of pH values from 9 to 12.6, or across a range of pH values from 2 to 7).
  • the pH stability of the salinity-responsive polymer particles can render these particles compatible with a wide variety of enhanced oil recovery methods, including methods that employ alkaline floods and methods that include carbon dioxide flooding.
  • the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 2; the salinity -responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 12.6; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume.
  • the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 4; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume.
  • the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 7; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 12.6; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume.
  • the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 12.6; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume.
  • the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 2; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 7; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume.
  • Salinity-responsive polymer particles can be formed from one or more (co)polymers, such as one or more acrylamide-containing (co)polymers or one or more alginate (co)polymers.
  • polymer As used herein, the terms “polymer,” “polymers,” “polymeric,” and similar terms are used in their ordinary sense as understood by one skilled in the art, and thus may be used herein to refer to or describe a large molecule (or group of such molecules) that contains recurring units.
  • Polymers may be formed in various ways, including by polymerizing monomers and/or by chemically modifying one or more recurring units of a precursor polymer.
  • a polymer may be a "homopolymer" comprising substantially identical recurring units formed by, e.g.,
  • a polymer may also be a "copolymer” comprising two or more different recurring units formed by, e.g., copolymerizing two or more different monomers, and/or by chemically modifying one or more recurring units of a precursor polymer.
  • the term "terpolymer” may be used herein to refer to polymers containing three or more different recurring units.
  • polymer as used herein is intended to include both the acid form of the polymer as well as its various salts.
  • the one or more (co)polymers forming the salinity -responsive polymer particles can be a (co)polymer useful for enhanced oil recovery applications.
  • the salinity-responsive polymer particles can comprise a
  • the one or more ethylenically unsaturated monomers can comprise acrylamide.
  • the salinity-responsive polymer particles can comprise a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the copolymer can be derived from 10% to 80% by weight (e.g., from 20% to 60% by weight, or from 25% to 45% by weight) acrylamide monomers, based on the total weight of the monomers that form the copolymer. In one embodiment, the copolymer can be derived from 30% to 40% by weight (e.g., about 35% by weight) acrylamide monomers, based on the total weight of the monomers that form the copolymer. The copolymer can be derived from 20% to 90% by weight (e.g., from 35% to 80% by weight, from 45% to 70% by weight) acid-containing monomers, based on the total weight of the monomers that form the copolymer. In one embodiment, the copolymer can be derived from 50% to 65% by weight (e.g., about 58% by weight) acid-containing monomers, based on the total weight of the monomers that form the copolymer.
  • the salinity-responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0-15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • acid-containing monomers include, for example, monomers comprising - COOH groups, such as acrylic acid or methacrylic acid, crotonic acid, itaconic acid, maleic acid or fumaric acid, monomers comprising sulfonic acid groups, such as vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2-methacrylamido-2- methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3-acrylamido-3- methylbutanesulfonic acid or 2-acrylamido-2,4,4-trimethylpentanesulfonic acid, or monomers comprising phosphonic acid groups, such as vinylphosphonic acid, allylphosphonic acid, N- (meth)acrylamidoalkylphosphonic acids or (meth)acryloyloxyalkyl-phosphonic acids.
  • monomers comprising phosphonic acid groups such as vinylphosphonic acid, allylphosphonic acid, N-
  • the one or more acid-containing monomers comprise sulfonic acid groups.
  • the one or more acid-containing monomers are chosen from vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2-methacrylamido-2-methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3- acrylamido-3-methylbutanesulfonic acid, and 2-acrylamido-2,4,4-trimethylpentanesulfonic acid.
  • the one or more acid-containing monomers comprise 2- acrylamido-2-methylpropanesulfonic acid.
  • the one or more additional ethylenically-unsaturated monomers can comprise any suitable monomers.
  • suitable additional monomers include, for example, acrylamide derivatives such as, for example, N-methyl(meth)acrylamide, ⁇ , ⁇ '- dimethyl(meth)acrylamide, and N-methylolacrylamide, N-vinyl derivatives such as N- vinylformamide, N-vinylacetamide, N-vinylpyrrolidone or N-vinylcaprolactam, and vinyl esters, such as vinyl formate or vinyl acetate, vinyl aromatic monomers (e.g., styrene), and (meth)acrylate monomers.
  • acrylamide derivatives such as, for example, N-methyl(meth)acrylamide, ⁇ , ⁇ '- dimethyl(meth)acrylamide, and N-methylolacrylamide
  • N-vinyl derivatives such as N- vinylformamide, N-vinylacetamide, N-vinylpyrrolidone or N-vin
  • (Meth)acrylate monomers can include esters of ⁇ , ⁇ - monoethylenically unsaturated monocarboxylic and dicarboxylic acids having 3 to 6 carbon atoms with alkanols having 1 to 12 carbon atoms (e.g., esters of acrylic acid, methacrylic acid, maleic acid, fumaric acid, or itaconic acid, with C1-C20, C1-C12, C1-C8, or C1-C4 alkanols).
  • esters of acrylic acid, methacrylic acid, maleic acid, fumaric acid, or itaconic acid with C1-C20, C1-C12, C1-C8, or C1-C4 alkanols.
  • Exemplary acrylate and methacrylate monomers include, but are not limited to, methyl acrylate, methyl methacrylate, ethyl acrylate, ethyl methacrylate, butyl acrylate, butyl methacrylate, isobutyl (meth)acrylate, n-hexyl (meth)acrylate, ethylhexyl (meth)acrylate, n- heptyl (meth)acrylate, ethyl (meth)acrylate, 2-methylheptyl (meth)acrylate, octyl
  • (meth)acrylate isooctyl (meth)acrylate, n-nonyl (meth)acrylate, isononyl (meth)acrylate, n- decyl (meth)acrylate, isodecyl (meth)acrylate, dodecyl (meth)acrylate, lauryl (meth)acrylate, tridecyl (meth)acrylate, stearyl (meth)acrylate, glycidyl (meth)acrylate, alkyl crotonates, vinyl acetate, di-n-butyl maleate, di-octylmaleate, acetoacetoxy ethyl (meth)acrylate,
  • acetoacetoxypropyl (meth)acrylate hydroxyethyl (meth)acrylate, allyl (meth)acrylate, tetrahydrofurfuryl (meth)acrylate, cyclohexyl (meth)acrylate, 2-ethoxyethyl (meth)acrylate, 2- methoxy (meth)acrylate, 2-(2-ethoxyethoxy)ethyl (meth)acrylate, 2-ethylhexyl (meth)acrylate, 2-propylheptyl (meth)acrylate, 2-phenoxyethyl (meth)acrylate, isobornyl (meth)acrylate, caprolactone (meth)acrylate, polypropyleneglycol mono(meth)acrylate, polyethyleneglycol (meth)acrylate, benzyl (meth)acrylate, 2,3-di(acetoacetoxy)propyl (meth)acrylate,
  • hydroxypropyl (meth)acrylate methylpoly glycol (meth)acrylate, 3,4-epoxycyclohexylmethyl (meth)acrylate, 1,6 hexanediol di(meth)acrylate, 1,4 butanediol di(meth) acrylate and combinations thereof.
  • the one or more ethylenically-unsaturated monomers can comprise one or more polyethylenically-unsaturated monomers (e.g., one or more
  • diethylenically-unsaturated monomers one or more triethylenically-unsaturated monomers, one or more tetraethylenically-unsaturated monomers, one or more pentaethylenically-unsaturated monomers).
  • the salinity-responsive polymer particles can comprise a polysaccharide (co)polymer (e.g., a polysaccharide polymer or copolymer).
  • the salinity-responsive polymer particles can comprise an alginate
  • the polysaccharide (co)polymer can comprise a blend of an alginate (co)polymer and a second (co)polymer.
  • the alginate (co)polymer and the second (co)polymer can be blended at varying weight ratios.
  • the alginate (co)polymer and the second (co)polymer can be present in the particles in a weight ratio of from 2: 1 to 10: 1 (e.g., from 4:1 to 8: 1).
  • the second (co)polymer can comprise, for example, chitosan, polylactic acid, poly glutamic acid, and PLGA (poly (lactic acid-co-glutamic acid)).
  • compositions comprising the salinity-responsive polymer particles described herein can be used in oil and gas operations, including oil recovery operations.
  • enhanced oil recovery refers to techniques for increasing the amount of unrefined petroleum (e.g., crude oil) that may be extracted from an oil reservoir (e.g., an oil field). Using EOR, 40-60% of the reservoir's original oil can typically be extracted compared with only 20- 40% using primary and secondary recovery (e.g., by water injection or natural gas injection). Enhanced oil recovery may also be referred to as improved oil recovery or tertiary oil recovery (as opposed to primary and secondary oil recovery).
  • EOR operations include, for example, miscible gas injection (which includes, for example, carbon dioxide flooding), chemical injection (sometimes referred to as chemical enhanced oil recovery (CEOR), and which includes, for example, polymer flooding, alkaline flooding, surfactant flooding, as well as combinations thereof such as alkaline-polymer flooding or alkaline-surfactant-polymer flooding), microbial injection, and thermal recovery (which includes, for example, cyclic steam, steam flooding, and fire flooding).
  • miscible gas injection which includes, for example, carbon dioxide flooding
  • chemical injection sometimes referred to as chemical enhanced oil recovery (CEOR)
  • CEOR chemical enhanced oil recovery
  • thermal recovery which includes, for example, cyclic steam, steam flooding, and fire flooding.
  • the EOR operation can include a polymer (P) flooding operation, an alkaline- polymer (AP) flooding operation, a surfactant-polymer (SP) flooding operation, an alkaline- surfactant-polymer (ASP) flooding operation, a conformance control operation, or any combination thereof.
  • P polymer
  • AP alkaline- polymer
  • SP surfactant-polymer
  • ASP alkaline- surfactant-polymer
  • conformance control operation or any combination thereof.
  • Methods for hydrocarbon recovery can comprise (a) providing a subsurface reservoir containing hydrocarbons there within; (b) providing a wellbore in fluid
  • aqueous particle composition comprising a population of salinity -responsive polymer particles having a first volume dispersed in an aqueous carrier having a first salinity; (d) injecting the aqueous particle composition through the wellbore into the subsurface reservoir, thereby depositing the salinity- responsive polymer particles within high permability regions of the subsurface reservoir; and (e) injecting an aqueous composition having a second salinity into the subsurface reservoir, thereby causing the population of salinity-responsive polymer particles within the high permability regions of the subsurface reservoir to swell to a second volume.
  • the second volume can be at least ten times (e.g., at least twenty times, or at least thirty times) greater than the first volume.
  • the aqueous particle composition can be any of the compositions described above.
  • the aqueous particle composition can comprise a population of salinity -responsive polymer particles formed from a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the salinity -responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0-15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).
  • the first salinity can be higher than the second salinity.
  • the aqueous particle composition can comprise a population of salinity-responsive polymer particles formed from an alginate (co)polymer (e.g., an alginate polymer or copolymer) or a blend of an alginate (co)polymer and a second (co)polymer (e.g., chitosan).
  • the second salinity can be higher than the first salinity.
  • the wellbore in step (b) can be an injection wellbore associated with an injection well.
  • the methods of hydrocarbon recovery can further comprise providing a production well spaced apart from the injection well a predetermined distance and having a production wellbore in fluid communication with the subsurface reservoir.
  • Injection of the aqueous composition having a second salinity in step (e) can increase the flow of hydrocarbons to the production wellbore.
  • Methods can further comprise producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.
  • the aqueous composition having a second salinity can comprise a polymer (P) flooding solution, an alkaline-polymer (AP) flooding solution, a surfactant-polymer (SP) flooding solution, an alkaline- surfactant-polymer (ASP) flooding solution, or any combination thereof.
  • methods can further include performing any of the EOR operations described above following step (e), and producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.
  • methods can further comprise injecting a polymer flooding solution, an AP flooding solution, a SP flooding solution, an ASP flooding solution, carbon dioxide, or any combination thereof into the subsurface reservoir following step (e), and producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.
  • SSPP Salinity sensitive polymeric particles
  • Carbonate reservoirs contain about 50-60% of the world's oil and gas reserves. Many carbonate reservoirs are heterogeneous and fractured with their fracture permeability several times higher than their matrix permeability. Because of the fractures, carbonate reservoirs have very low oil recovery during water or gas floods. Injected fluids flow through the high- permeability fractures bypassing the oil in the low permeability matrix.
  • Size-controlled microgels are preformed particles by crosslinking polymers under shear. When injected into a porous medium, they can flow through the pores but adsorb, thus reducing the conductivity of flow channels. They can be injected into porous media to reduce the permeability of flow channels. They can reduce water relative permeability higher than the oil relative permeability; however, it is difficult to place these particles selectively in different layers.
  • Bright water includes polymeric microparticles (0.1 to 3 micron) with both labile and stable internal crosslinks. These particles are temperature and time sensitive. They can be injected into the formation with a cooler brine (than the reservoir temperature) in a shrunken state. As the temperature increases inside the reservoir, the labile bonds de-crosslink and the particles expand, blocking the flow in the porous medium. The original particles are small enough to flow through the pores of the rock and can be placed very deep into the reservoirs. The residual resistance factors increase due to particle expansion over a large volume to provide the deep diversion of the fluids. The particles have to be of a prescribed size to invade the desired high permeability zone and not the other zones. These particles are too small for blocking fractures.
  • PPG Preformed particle gels
  • PPGs include swellable polymeric particles.
  • the swelling of PPGs is a function of temperature and pH. These particles can have a particle size on the order of microns to mm and can plug high permeability channels as well as fractures.
  • PPGs are environmentally friendly and not sensitive to reservoir minerals and formation water salinity. Swollen particles can pass through pore throats smaller than their size depending on the pressure gradient.
  • PPGs overcome some drawbacks of other methods, including gelation time and uncertainties of gelation because of segregation, temperature, and pressure. Studies suggest that preformed gel has a better placement than gels formed in situ. Microgels can be injected into porous media without plugging. As a consequence, these microgels are good candidates for water shutoff.
  • stimuli-responsive preformed polymeric gel particles are synthesized and investigated for application in formation fractures. These particles are sensitive to brine salinity, and hence are called salinity- sensitive polymeric particles (SSPP). In some cases, these particles can swell in low salinity brines.
  • SSPP salinity- sensitive polymeric particles
  • a slurry of these particles in a high salinity brine can be injected into a fractured well which would place the SSPP in the fractures. Then, a low salinity brine can be injected, which would expand the particles and plug the fractures, thereby diverting fluids into the tighter matrix of the formation. In other cases, these particles can swell in high salinity brines.
  • a slurry of these particles in a low salinity brine can be injected into a fractured well which would place the SSPP in the fractures. Then, a high salinity brine can be injected, which would expand the particles and plug the fractures, thereby diverting fluids into the tighter matrix of the formation.
  • the SSPP polymer is synthesized by polymerization reaction consisting of an aqueous mixture of acrylamide, 2-Acrylamido-2- methylpropanesulfonic acid, water, pentasodium diethylenetriamine pentaacetate,
  • an aqueous phase was prepared by mixing 16.49 gm acrylamide, 37.5 gm of 58% 2-Acrylamido-2-methylpropanesulfonic acid, 2 gm water, 0.1 gm of 40% pentasodium diethylenetriamine pentaacetate, 0.3 gm of 1% solution of methylenebisacrylamide, and 3.6 gm polyethyleneglycol diacrylate.
  • a continuous organic phase was prepared by mixing 33.6 gm of kerosene, 6 gm Polyoxyethylene (20) sorbitan monooleate (Tween-80), and 0.4 gm sorbitan sesquiolate.
  • a monomer emulsion was then prepared by mixing the aqueous phase and the organic phase, followed by stirring for about 4 hours.
  • the emulsion was then deoxygenated with nitrogen for 30 minutes, and polymerization was initiated using a sodium bisulfite/sodium bromate redox pair at room temperature.
  • the reaction mixture was then heated at about 80°C for an additional 2 hours.
  • the mixture was cooled to room temperature and filtered to remove any remaining liquid.
  • the white solid polymer was heated at 60°C for 2 days to remove solvent, and the dry polymer was crushed and sieved to isolate a population of SSPP particles having the desired particle size.
  • Synthesis ofSSPP2 (Chitosan-Alginate) Particles 5 wt% sodium alginate was dissolved in DI by stirring. 0.8 wt% chitosan solution was prepared by the addition of chitosan to distilled water. Then, chitosan solution and alginate solution were mixed to prepare a solution that was 2.5 wt% sodium alginate and 0.4 wt% chitosan. The solution was stirred for several hours, then poured or injected dropwise to a 1 wt% CaCl 2 solution to afford spherical polymer droplets. Once the particles were formed, the particles were dried in an oven at 60°C for about two days. The size of the spherical particles prepared by this process could be varied by injecting the solution into the calcium chloride solution using different sized syringe needles.
  • the SSPP2 particles were found to be salinity sensitive, though in a slightly different fashion than the SSPP particles. SSPP2 particles swell as the salinity increases in the range of 0-10%, beyond 10% salinity the swelling decreases. The pH also affects the size slightly; the size is slightly larger in the range of 3-5.5 pH compared to the neutral pH. Notably, the SSPP2 particles were found to be stable when held at a salinity and temperature. The SSPP2 particles were found to be stable for at least for a month at 80°C. The salinity sensitivity of these particles was opposite that of the SSPP (more swelling at low salinity for SSPP). As such, SSPP2 particles could have particular utility in high salinity reservoirs.
  • Salt solutions were prepared using sodium chloride (NaCl), calcium chloride (CaCl 2 ), magnesium chloride (MgCl 2 ), sodium iodide (Nal), sodium phosphate (Na 3 P04), or combinations thereof.
  • Crude oil Crude oil (of 52 cp viscosity at the room temperature) diluted with 20 wt% cyclohexane was used; viscosity of the diluted oil at room temperature was 14 cp.
  • Rock Texas cream limestone cores of low permeability (about 35 mD or lower) were used.
  • Swelling of the SSPP was tested at different concentrations of salts. Either one particle or a known amount (by volume) of particles were mixed with several brines and equilibrated for a few days with continuous recording of the size or volume change. To see the effect of salts other than NaCl, experiments were conducted with CaCl 2 , MgCk, Nal and Na 3 P04. The swelling property and stability of these particles was studied at different temperatures ranging from 25°C (room temperature) to 125°C at three different salinities (0 wt% NaCl, 0.1 wt% NaCl, and 20 wt% NaCl) for more than a month.
  • the 20 wt% NaCl brine is referred to here as the "high salinity brine” and the 0.1 wt% brine is referred to here as the “low salinity brine.”
  • high salinity brine The 20 wt% NaCl brine is referred to here as the "high salinity brine” and the 0.1 wt% brine is referred to here as the “low salinity brine.”
  • low salinity brine 20 wt% NaCl brine
  • brine pH was varied from 2 to 12.6 at 25°C.
  • Core Flood Experiments Four core flood experiments were performed. Table 1 lists the core properties for the core floods. Cores were approximately 1.5" in diameter and 12" in length. The cores were first vacuum saturated with oil. One core flood experiment (Core flood #1) was performed in a core without a fracture, as a reference. Rest of the core floods were conducted in cores with fractures. Cores were fractured after being saturated with oil. Sand was used to prop the fractures; sand size was 300 ⁇ in all the experiments. The SSPP used in Core flood #2 was about 500 ⁇ , but in the rest of the experiments, 32 ⁇ SSPP was used. Each experiment is described in detail in the Table 1.
  • Core Flood #1 During Core flood #1, the oil-saturated core was flooded with the high salinity brine (at a superficial velocity of lft/day) followed by the low salinity brine. The lower salinity water flood does not do much in this core flood, but is used in the other experiments to swell the polymeric particles. Toluene was injected next to mimic a miscible (e.g. CO2) flood at a low pressure. Oil recovery and pressure drop were monitored. This is the base case for an unfractured core.
  • a miscible e.g. CO2
  • Core Flood #2 In this core flood experiment, the oil-saturated core was taken out from the core -holder and cut longitudinally into two halves. A layer of sand and SSPP mixture was placed between the two halves and the composite core was put back into the same core-holder. The core was again flooded with oil to fill the fracture with oil. The core was then flooded with the high salinity brine (at a superficial velocity of 1 ft/day) followed by the low salinity brine (0.1 wt% NaCl brine). The low salinity brine was supposed to swell the SSPP and redirect the brine in to the matrix. This flood was followed by an acidified low salinity brine injection to test the sensitivity of SSPP to acids. This flood was followed by toluene injection (which mimics a miscible CO2 flood). This experiment was designed to show the effect of SSPP in a fractured rock if it can be placed properly in the fracture.
  • Core flood #3 In Core flood #3, the oil saturated core was taken out from the core- holder and cut in to two halves similar to the core in Core flood #2. A layer of sand (0.5 ml) was placed between the two halves and the composite core was put back into the same core- holder. No SSPP was placed in the fracture. The core was flooded with oil to fill the fracture. Water flood was conducted with a 20 wt% NaCl brine, the high salinity brine (at the rate of lft/day) until no more oil was produced. Then a slurry of 32 micron SSPP in the high salinity brine was injected at the same flow rate.
  • Core Flood #4 This core flood experimental procedure was exactly the same as that of Core flood #3 with one exception. The fracture was placed only in the upstream half of the core. The amount of SSPP injected was half the amount in Core flood #3. In many reservoirs, the fractures do not go all the way from injection wells to the production wells. This "half fracture" mimics that scenario.
  • FIG. 1 0.1 cc of SSPP particles was immersed in brines of NaCl concentration ranging from 0 wt % (DI water) to 20 wt% at 25°C and the swelling factor was measured after an hour.
  • Figures 2A- 2C detail the experimental result.
  • Figure 2A shows the 0.1 cc dry particles in different vials before the addition of salt solutions.
  • Figure 2B shows the swollen particles after an hour in salt solutions.
  • Figure 2C shows a plot of salinity vs. the swelling factor. These particles swell about 35 times in DI water; the swelling factor decreases sharply with salinity up to about 1 wt% salinity and then gradually decreases with salinity. At the 20 wt% salinity, the swelling factor is only about 3.
  • SSPP particles swell to their short-term equilibrium size within an hour.
  • the swelling factor increases slightly (30 to 35 for DI water) over a month.
  • the particles are stable for more than two months all the salinities studied.
  • the swelling factor more than doubles within 25 days and attains a second equilibrium value (about 70 for DI water and 32 for 0.1 wt% NaCl brine).
  • the SSPP particles were stable in all the brines studied for more than two months.
  • the swelling factor more than doubles within 20 days and attains a second equilibrium value (about 70 for DI water and 40 for 0.1 wt% NaCl brine).
  • the SSPP particles do not degrade much in 20% NaCl brine, but swell only about 3 times.
  • the SSPP particles begin degrading after approximately one month in DI water.
  • the swelling factor generally increases as the temperature increases.
  • Core floods Four core floods were conducted to evaluate the effect of SSPP in fractured media.
  • the injection schemes for the core floods are summarized in Table 2.
  • Core flood #1 is the base case in a non-fractured core.
  • Core flood #2 was conducted in a fractured core, but a mixture of sand and SSPP was placed in the fracture during the core assembly.
  • Core flood #3 was similar to Core flood #2, but the core was assembled with only sand in the fracture.
  • SSPP was injected into the fracture after the first water flood.
  • Core flood #4 was similar to Core flood #3, but the fracture was only six inch long at the upstream half of the core.
  • Core Flood #1 The core properties are listed in Table 1 and the injection sequence is summarized in Table 2. This core flood was conducted in a Texas cream limestone core without fractures, as a base case. About 6.7 PV of high salinity brine (20 wt% NaCl) was injected at a flow rate of 0.065 ml/min (1 ft/day). The high salinity brine was followed by a low salinity brine (0.1 wt% NaCl), which was further followed by toluene. Figure 4 shows the oil recovery and pressure drop during the flood. This flood recovered 58% OOIP during high salinity brine injection and about 2% additional oil was produced during the low salinity injection.
  • the extra oil is due to the continuation of the water flood and has little to with the salinity change.
  • the residual oil saturation to waterflood is about 40%.
  • oil was displaced miscibly; the cumulative oil recovery increased to about 75%.
  • the remaining oil saturation is still 25% because the rock is tight and
  • the pressure drop during the high salinity brine injection increased from about 8 psi initially to about 11 psi and gradually decreased to about 5 psi, typical of a waterflood.
  • the pressure drop did not change much during the low salinity water injection, but the pressure drop increased to about 11 psi during toluene injection and again decreased to about 4.5 psi.
  • the pressure drop increased during toluene injection because of the mobilization of oil.
  • Core Flood #2 In this flood, the core had a fracture along its length which was filled with a mixture of sand and SSPP.
  • the core properties are given in the Table 1 ; oil production and pressure drop are shown in Figure 5.
  • the core was first flooded with a high salinity brine (20 wt% NaCl) for about 4.3 PV.
  • the high salinity brine swelled the SSPP in the fracture slightly (about 3 times) and thus the water was forced into the matrix to some extent.
  • the oil recovery was 43% OOIP at the end of the high salinity waterflood.
  • the low salinity brine (0.1 wt% NaCl) was injected for about 4.5 PV.
  • the acidified water flood was further followed by toluene injection; this flood mimics a
  • Core flood #3 Core flood #2 showed that the SSPP can be effective if placed in the fractures.
  • Core flood 3 we test if SSPP can be pumped into an existing fracture and be swollen in place.
  • the fracture had a layer of sand.
  • the properties of the core are listed in Table 1 and the injection scheme is summarized in Table 2.
  • the oil recovery and pressure drop are shown in Figure 6.
  • the core was first flooded with the high salinity brine until no more oil was produced.
  • the oil recovery was about 23% OOIP. It was low because most of the water was channeling through the fracture; some water did imbibe into the matrix.
  • the pressure drop was very low (less than 1 psi) indicating fracture-dominated flow.
  • the SSPP used in this flood was 32 micron size. 4 cc of SSPP was dispersed in 100 cc of 20 wt% NaCl and 0.8 PV of the suspension was injected from an accumulator which has piston. This injection was followed by 7 cc of high salinity brine to clear the inlet line. The SSPP in the high salinity brine was slightly swollen and got injected into the fracture. Then the low salinity brine (0.1 wt% NaCl) was injected for about 6 PV; this brine expanded the particles in the fracture. Thus the pressure drop increased to about 180 psi. This pressure drop forced the brine into the matrix and oil got displaced.
  • Cumulative oil recovery increased to 59% OOIP, again similar to the water flood recovery of the unfractured core.
  • This experiment demonstrates that it is possible to place the SSPP in the fracture where it can be swollen to blocking the fracture and redirect water into the matrix.
  • 2 PV of toluene was injected as a miscible injectant. Pressure drop remained high and toluene was redirected into the matrix where it displaced the oil.
  • the cumulative oil recovery increased to 80% OOIP.
  • the SSPP is useful in blocking the fractures for both water floods and miscible floods.
  • Figure 7, panel a shows the Texas Cream lime stone core before oil saturation
  • Figure 7, panel b shows the oil saturated core before creating a fracture.
  • the oil saturated core was cut in to two halves (Figure 7, panel c) and in the flat surface of one half piece many scratches were made and a layer of sand was placed (Figure 7, panel d).
  • the two core halves were combined ( Figure 7, panel e) and put inside a core holder. After core flood experiment was over, the core was taken out of the core holder ( Figure 7, panel f) and the two halves were separated to see the placement of SSPP.
  • Figure 7, panel g shows SSPP throughout the length of the core.
  • Figure 7, panel h shows the upstream side of the core before injecting SSPP and Figure 7, panel i shows the upstream side at the end of the experiment.
  • a lot of SSPP can be seen on the inlet surface of the core.
  • Figures 7, panel k and Figure 7, panel 1 show the downstream end of the core; many SSPP particles can be seen in the outlet end. Thus the polymeric particles did propagate through the fracture. The deposition of these particles in the inlet and outlet faces increased the pressure drop.
  • Core Flood #4 In this flood the oil- saturated core was cut longitudinally in the upstream half and a layer of sand was placed in this fracture. As in other experiments, the core was first flooded with the high salinity brine for about 6.4 PV. After no more oil was recovered, 10 cc of SSPP dispersion in the high salinity brine was injected. The total amount of SSPP injected was 1 cc dry SSPP. SSPP concentration in the dispersion was about 10%; SSPP could be injected quicker to prevent sedimentation of the particles. After injecting 10 cc of the dispersion, 7 cc of the high salinity brine was injected again to prevent plugging in the inlet line. Then 5.7 PV of the low salinity brine was injected followed by 2 PV of toluene injection.
  • Figure 8 shows the oil recovery and pressure drop during the flood. About 39% OOIP was recovered during the high salinity brine injection. The upstream half of this core is fractured and the downstream half is non-fractured. In the fractured core (Core flood #3), the water flood recovery was about 20% and it was 60% in the non-fractured core (Core flood #1).
  • the pressure drops during different stages of the floods are presented in Table 3 along with the initial oil permeability.
  • the core did not have a fracture in Core flood #1.
  • the oil permeability for core #1 is same because it was not fractured.
  • the effective oil permeability increased from 19 md to 293 md because the fracture was filled with both sand and SSPP.
  • the effective oil permeability increased even higher (from 36 md to 2970 md) because the fracture was propped with some sand.
  • the oil permeability changes slightly before and after fracture in Core flood #4 because the fracture goes through only half the length.
  • the pressure drop with the high salinity brine is higher in the fractured cores #2 and #3, because the SSPP swell about 3 times in this brine.
  • cores #1 and #4 the pressure drop after the water flood is dominated by the matrix flow and depends on the end point water relative permeability.
  • the pressure drop increases significantly with the low salinity brine because SSPP expands more than 15 times.
  • Similar high pressure drops are also observed in toluene floods. This increased pressure gradient diverts the fluid into the matrix and displaces oil.
  • Salinity sensitive polymeric particles are synthesized in this study which can plug fractures in reservoir rocks and divert fluid flow into the matrix. These polymeric particles decrease bypassing due to high permeability fractures.
  • SSPPs swell in brine; the swelling is a function of brine sanility. SSPP expand many times (-70 times) in DI water, but swell only about 3 times in very high salinity (20 wt% NaCl) brine.
  • the swelling of the particles is independent of pH in the range of 2 to 12.6.
  • the oil recovery in a fractured core depends on the ratio of the fracture permeability to matrix permeability.
  • Core flood #3 the oil recovery due to water flood before SSPP injection was 22% OOIP.
  • SSPP injection also increases waterflood recovery in a core with a half fracture connected to the inlet.
  • the SSPP placement also increases oil recovery due to a miscible injectant after water flood.
  • compositions and methods of the appended claims are not limited in scope by the specific compositions and methods described herein, which are intended as illustrations of a few aspects of the claims. Any compositions and methods that are functionally equivalent are intended to fall within the scope of the claims. Various modifications of the compositions and methods in addition to those shown and described herein are intended to fall within the scope of the appended claims. Further, while only certain representative compositions and methods steps disclosed herein are specifically described, other combinations of the compositions and method steps also are intended to fall within the scope of the appended claims, even if not specifically recited. Thus, a combination of steps, elements, components, or constituents may be explicitly mentioned herein or less, however, other combinations of steps, elements, components, and constituents are included, even though not explicitly stated.

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Abstract

L'invention concerne des compositions qui comprennent des articles polymères sensibles aux stimuli (par exemple, sensibles à la salinité), ainsi que des procédés d'utilisation des compositions dans des applications de récupération d'huile.
PCT/US2017/046095 2016-08-09 2017-08-09 Particules polymères sensibles aux stimuli et leurs procédés d'utilisation WO2018031655A1 (fr)

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CN115160500A (zh) * 2022-07-27 2022-10-11 中国地质大学（武汉） 一种多种响应可控交联降解凝胶颗粒暂堵剂及其制备方法和应用

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