Method of fracturing subterranean formations utilizing emulsions comprising acrylamide copolymers

• US 7,482,310 B1
• Filed: 11/12/2004
• Issued: 01/27/2009
• Est. Priority Date: 11/12/2003
• Status: Expired due to Fees

• Current Assignee: Kroff Chemical Company Incorporated, Nextier Completion Solutions Inc. (Patterson-Uti Energy Incorporated)
• Original Assignee: Kroff Chemical Company Incorporated, Superior Well Services Incorporated (Nabors Industries Limited)
• Inventors: Rey, Paul, Reese, Rhys R.
• Primary Examiner(s): Kugel; Timothy J.
• Application Number:
  US10/988,216
• Time in Patent Office: 1,537 Days
• Field of Search: 507/225, 166/270, 166/270.1, 166/271, 166/370, 166/308.1, 516/22, 516/27
• US Class Current: 507/225
• CPC Class Codes: C09K 2208/26 Gel breakers other than bacteria or enzymes
• CPC Class Codes: C09K 8/64 Oil-based compositions

Abstract

A method of treating a subterranean formation penetrated by a well bore including:

• • (a) preparing a fracturing fluid containing a mixture resulting from:
    • (I) providing a water-in-oil emulsion composition that includes:
      • (i) 5% to 99% by weight of a water-in-oil emulsion polymer comprising a polymer or copolymer containing repeat units from an acrylamide monomer;
      • (ii) 0.5% to 90% by weight of a carrier solvent; and
      • (iii) 0 to 90% by weight of a fluidizing agent; and adding
      • (iv) 0.1% to 10% by weight of one or more inorganic microparticles, where the total of all components is 100% by weight; and
    • (II) adding the water-in-oil emulsion composition to water; and
  • (b) contacting the subterranean formation with the fracturing fluid.

Claims

1. A method of treating a subterranean formation penetrated by a well bore comprising:

(a) preparing a fracturing fluid containing a mixture resulting from;

(I) providing a water-in-oil emulsion composition comprising;

(i) 5% to 99% by weight of a water-in-oil emulsion comprising;

(1) 10% to 90% by weight of a hydrophobic oil phase;

(2) 0.5% to 10% by weight of a surfactant system; and

(3) 5% to 90% by weight of a polymer-containing aqueous phase comprising water and a polymer or copolymer containing repeat units from an acrylamide monomer, wherein the polymer or copolymer comprises from 2% by weight to 89.5% by weight of the water-in-oil emulsion;

(ii) 0.5% to 90% by weight of a carrier solvent; and

(iii) 0 to 90% by weight of a fluidizing agent;

and adding

(iv) 0.1% to 10% by weight of one or more inorganic microparticles, where the total of all components is 100% by weight; and

(II) adding the water-in-oil emulsion composition to water; and

(b) contacting the subterranean formation with the fracturing fluid.

2. The method of claim 1, wherein the fracturing fluid further comprises (v) 1% to 50% by weight of a proppant material.

3. The method of claim 2, wherein the proppant material is selected from the group consisting of resin coated or uncoated sand, sintered bauxite, ceramic materials and glass beads.

4. The method of claim 2, wherein the proppant material is present in the fracturing fluid in an amount in the range of from about 0.1 to about 10 pounds of proppant material per gallon of the fracturing fluid.

5. The method of claim 1, the oil phase comprises one or more oils selected from the group consisting of mineral oil, synthetic oil, modified oil, paraffinic oil, benzene, xylene, toluene, kerosene, napthas, petroleums, blends of aromatic and aliphatic hydrocarbons containing 4 or greater carbon atoms, and vegetable oil.

6. The method of claim 1, wherein the surfactant system comprises of one or more surfactants selected from the group consisting of alkanolamides, polyoxyethylene derivatives of sorbitan esters, sorbitan monooleate, sorbitan monostearate, C₆-C₂₂ linear or branched alkyl ethoxylates with 1 to 30 oxyethylene units, C₆-C₂₂ linear or branched alkyl propoxylate with 1 to 30 oxypropylene units, C₆-C₂₂ linear or branched alkyl ethoxylate/propoxylate with 1 to 30 combined oxyethylene and propoxylate units, alkylaryl ethoxylates containing a C₆-C₂₂ aryl group with 1 to 30 oxyethylene units, hexadecyl sodium phthalate, cetyl sodium phthalate, stearyl sodium phthalate and ethylene oxide condensates of fatty acid amides.

7. The method of claim 1, wherein the polymer or copolymer of the aqueous phase is selected from non-ionic poly(acrylamide) homopolymer, non-ionic copolymers, anionic copolymers, cationic copolymers, amphoteric copolymers and ampholytic copolymers.

8. The method of claim 1, wherein the polymer or copolymer comprises one or more repeat units according to formula I:

9. The method of claim 1, wherein the copolymer of the aqueous phase further comprises repeat units derived from acrylamidopropyl-trimethyl ammonium chloride, methacrylamidopropyltrimethyl ammonium chloride, methacryloyloxyethyl trimethyl ammonium chlorides methacryloyloxyethyl trimethyl ammonium methylsulfate, acryloyloxyethyl trimethyl ammonium chloride, dimethyl diallyl ammonium chloride, acrylic acid, methacrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, 2-methacrylamido-2-methylpropane sulfonic acid, C₁-C₃ alkyl acrylate, C₁-C₃ alkyl methacrylate, n-alkyl acrylamide, methacrylamide, n-alkylmethacrylamide and diacetone acrylamide.

10. The method of claim 1, wherein the polymer or copolymer of the aqueous phase has a reduced viscosity, measured using a Ubbelohde Capillary Viscometer at 0.05 g/dl in 1N NaCl at 30°

C. and pH of 7 of from 5 to 50 dl/g.

11. The method of claim 1, wherein the inorganic microparticles (iv) include one or more microparticles selected from the group consisting of fumed silica, precipitated silica, colloidal silica, alumina silicates, surface treated silica, calcium carbonate, talc and borosilicates.

12. The method of claim 1, wherein the inorganic microparticles (iv) include one or more microparticles selected from the group consisting of fumed silica, precipitated silica, silica flour, diatomites and colloidal silica.

13. The method of claim 1, wherein the carrier solvent (ii) is one or more selected from the group consisting of mineral oil, synthetic oil, modified oil, paraffinic oil, vegetable oil, ethylene carbonate, propylene carbonate, glycols, polyglycols, and glycol ethers.

14. The method of claim 1, wherein the carrier solvent (ii) is a solvent characterized as having Hansen Solubility parameters at 25°

C. of;

δ

_d of from 13 to 18;

δ

_p of from 6 to 12;

δ

_h of at least 20; and

δ

_t of at least 20.

15. The method of claim 1, wherein the water is selected from the group consisting of fresh water, unsaturated brine and saturated brine.

16. The method of claim 1, wherein the fracturing fluid further comprises one or more polymers selected from the group consisting of hydroxypropylguar, carboxymethylhydroxypropylguar, carboxymethylguar, hydroxyethyl cellulose, grafted hydroxyethyl cellulose, carboxymethyl cellulose and carboxymethylhydroxyethyl cellulose.

17. The method of claim 1, wherein the water-in-oil emulsion composition is present in the treating fluid in an amount in the range of from about 0.01% to about 10% by weight of the fracturing fluid.

18. The method of claim 1, wherein the fracturing fluid further comprises from 0.01% to 0.1% by weight of a surfactant selected from the group consisting of C₂-C₂₄ linear, branched and cyclic alkyl phenol ethoxylates, C₂-C₂₄ linear, branched and cyclic alkyl ethoxylates, alkyl sulfonates, alkyl aryl sulfonates such as the salts of dodecylbenzene sulfonic acid, alkyltrimethylammonium chloride, branched alkyl ethoxylated alcohols, phenol-formaldehyde nonionic resin blends, cocobetaines, dioctyl sodium sulfosuccinate, imidazolines, alpha olefin sulfonates, linear alkyl ethoxylated alcohols and trialkyl benzylammonium chloride.

19. The method of claim 1, wherein the fracturing fluid further comprises from 0.01% to 1% by weight a fluid loss control agent selected from the group consisting of silica flour, starches, waxes and resins.

20. The method of claim 1, wherein the fracturing fluid further comprises from 0.01 to 2% by weight of a delayed breaker for causing the treating fluid to revert to a thin fluid comprising oxidizers and encapsulated oxidizers selected from the group consisting of sodium persulfate, potassium persulfate, ammonium persulfate, magnesium peroxide, sodium chlorite, sodium bromate, halogenated isocyanurate, and hypochlorites.

21. The method of claim 1, further comprising the step of (c) mixing a proppant material with at least a portion of the fracturing fluid.

22. The method of claim 1, wherein the polymer or copolymer containing repeat units from an acrylamide monomer further comprises one or more repeat units according to Formula I:

23. A method of treating a subterranean formation penetrated by a well bore comprising:

(a) preparing a fracturing fluid containing a mixture resulting from;

(I) providing a water-in-oil emulsion composition comprising;

(i) 5% to 99% by weight of a water-in-oil emulsion comprising a polymer or copolymer containing repeat units from an acrylamide monomer;

(ii) 0.5% to 90% by weight of a carrier solvent; and

(iii) 0 to 90% by weight of a fluidizing agent;

and adding

(iv) 0.1% to 10% by weight of one or more inorganic microparticles, where the total of all components is 100% by weight; and

(II) adding the water-in-oil emulsion composition to water; and

(b) contacting the subterranean formation with the fracturing fluid, wherein the fracturing fluid further comprises 0.01% to 0.3% by weight of a pH adjusting compound for elevating the pH of the treating fluid selected from the group consisting of sodium hydroxide, potassium hydroxide and lithium hydroxide.

24. A method of treating a subterranean formation penetrated by a well bore comprising:

(a) preparing a fracturing fluid containing a mixture resulting from;

(I) providing a water-in-oil emulsion composition comprising;

(i) 5% to 99% by weight of a water-in-oil emulsion comprising a polymer or copolymer containing repeat units from an acrylamide monomer;

(ii) 0.5% to 90% by weight of a carrier solvent; and

(iii) 0 to 90% by weight of a fluidizing agent;

and adding

(iv) 0.1% to 10% by weight of one or more inorganic microparticles, where the total of all components is 100% by weight; and

(II) adding the water-in-oil emulsion composition to water; and

(b) contacting the subterranean formation with the fracturing fluid, wherein the fracturing fluid further comprises from 0.01% to 0.3% by weight of a pH adjusting compound selected from the group consisting of sodium hydroxide, potassium hydroxide, lithium hydroxide, ammonia, sodium carbonate, potassium carbonate, sodium bicarbonate, potassium bicarbonate, sodium diacetate, potassium diacetate, sodium phosphate, potassium phosphate, sodium dihydrogen phosphate, potassium dihydrogen phosphate, and mixtures thereof.

25. A method of treating a subterranean formation penetrated by a well bore comprising:

(a) preparing a fracturing fluid containing a mixture resulting from;

(I) providing a water-in-oil emulsion composition comprising;

(i) 5% to 99% by weight of a water-in-oil emulsion comprising a polymer or copolymer containing repeat units from an acrylamide monomer;

(ii) 0.5% to 90% by weight of a carrier solvent; and

(iii) 0 to 90% by weight of a fluidizing agent;

and adding

(iv) 0.1% to 10% by weight of one or more inorganic microparticles, where the total of all components is 100% by weight; and

(II) adding the water-in-oil emulsion composition to water; and

(b) contacting the subterranean formation with the fracturing fluid, wherein the fracturing fluid further comprises from 0.1% to 10% by weight of a clay stabilizer selected from the group consisting of potassium chloride, sodium chloride, ammonium chloride, tetramethyl ammonium chloride and temporary clay stabilizers.