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WO-2026095982-A1 - RELATIVE PERMEABILITY MODIFIER PACKAGE FOR PRODUCED FLUIDS FROM A SUBTERRANEAN FORMATION

WO2026095982A1WO 2026095982 A1WO2026095982 A1WO 2026095982A1WO-2026095982-A1

Abstract

A reservoir fluid can be produced from a subterranean formation. The reservoir fluid can include water and hydrocarbons such as oil. It is oftentimes desirable to limit the amount of water that is produced, so a higher ratio of hydrocarbons can be produced. Portions of the subterranean formation can have an initial permeability to water. A relative permeability modifier (RPM) package including a surfactant and a polymer can be used in these portions to restrict or prevent water from being produced. The relative permeability modifier package can increase the hydrophobicity of the portion that allows the hydrocarbons to flow through while substantially limiting the amount of water. The relative permeability modifier can coat the surfaces of substances in the formation whereby the permeability to an aqueous fluid is reduced from the initial permeability. The formation can be a high-temperature formation of 230°F (110.0°C) or greater.

Inventors

  • GEORGE, SHOY
  • EOFF, LARRY STEVEN
  • Denny, Jason Adam
  • KADAM, Sunita S
  • ELDIN, SHERIF

Assignees

  • HALLIBURTON ENERGY SERVICES, INC.

Dates

Publication Date
20260507
Application Date
20250331
Priority Date
20241030

Claims (20)

  1. 1. A method of treating a portion of a subterranean formation comprising: introducing a fluid into the portion of the subterranean formation that has an initial permeability to an aqueous fluid, wherein the fluid comprises: a liquid; and a relative permeability modifier package, wherein the relative permeability modifier package comprises: a first relative permeability modifier that is a surfactant; and a second relative permeability modifier that is a polymer; and causing or allowing the first and second relative permeability modifiers to coat surfaces of the portion of the subterranean formation, wherein after coating, a final permeability to the aqueous fluid is reduced from the initial permeability.
  2. 2. The method according to claim 1, wherein the portion of the subterranean formation is part of a sandstone-bearing formation, carbonate-bearing formation, or combinations thereof.
  3. 3. The method according to claim 1 or 2, wherein the subterranean formation contains a reservoir fluid, and wherein the reservoir fluid comprises an aqueous liquid and hydrocarbons in liquid, gas, or both liquid and gas forms.
  4. 4. The method according to claim 3, further comprising producing the reservoir fluid from the subterranean formation.
  5. 5. The method according to claim 1, wherein the portion of the subterranean formation has a bottomhole temperature greater than or equal to 230°F (110.0°C).
  6. 6. The method according to claim 1, wherein the initial permeability to the aqueous fluid is greater than or equal to 6 Darcy. Attorney Docket: 24-112475 U2 HAL 1050
  7. 7. The method according to claim 1, wherein the liquid comprises water, and wherein the water is selected from the group consisting of freshwater, seawater, brine, and any combination thereof in any proportion.
  8. 8. The method according to claim 7, wherein the first and second relative permeability modifiers are water soluble.
  9. 9. The method according to claim 7, wherein the first relative permeability modifier is water insoluble, wherein the fluid further comprises a mutual solvent, and wherein the relative permeability modifier is soluble in the mutual solvent.
  10. 10. The method according to claim 1, wherein the first relative permeability modifier is a fatty acid, a derivative of a fatty acid, or a salt thereof.
  11. 11. The method according to claim 10, wherein the fatty acid is selected from the group consisting of stearic acid, lauric acid, palmitic acid, and combinations thereof.
  12. 12. The method according to claim 1, wherein the first relative permeability modifier is in a concentration in a range of 0.01% to 50% by weight of the liquid.
  13. 13. The method according to claim 1, wherein the polymer comprises a hydrophilic monomer and a hydrophobically modified monomer.
  14. 14. The method according to claim 13, wherein the hydrophilic monomer is selected from acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, trimethylammoniumethyl methacrylate chloride, methacrylamide, or hydroxyethyl acrylate.
  15. 15. The method according to claim 13, wherein the hydrophobically modified monomer is selected from alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides, Attorney Docket: 24-112475 U2 HAL 1050 alkyl dimethylammoniumethyl methacrylate bromide, alkyl dimethylammoniumethyl methacrylate chloride, alkyl dimethylammoniumethyl methacrylate iodide, alkyl dimethylammonium-propylmethacrylamide bromide, alkyl dimethylammonium propylmethacrylamide chloride, or alkyl dimethylammonium propylmethacrylamide iodide, wherein the alkyl groups have from 4 to 22 carbon atoms.
  16. 16. The method according to claim 13, wherein the polymer has a molecular weight in a range of 100,000 to 3,000,000 and has a mole ratio of the hydrophilic monomer to the hydrophobically modified monomer in a range of 99.98:0.02 to 80:20.
  17. 17. The method according to claim 1, wherein the second relative permeability modifier is in a concentration of 50 to 400 gallons per thousand gallons (189.3 to 1,514.2 liters per 3,785.4 liters).
  18. 18. The method according to claim 1, wherein the final permeability to the aqueous fluid is reduced by at least 40% from the initial permeability.
  19. 19. The method according to claim 1, wherein the final permeability to the aqueous fluid is reduced by at least 80% from the initial permeability.
  20. 20. The method according to claim 1, wherein the relative permeability modifier increases the hydrophobicity of the coated surfaces of the portion of the subterranean formation.

Description

Attorney Docket: 24-112475 U2 HAL 1050 RELATIVE PERMEABILITY MODIFIER PACKAGE FOR PRODUCED FLUIDS FROM A SUBTERRANEAN FORMATION Technical Field [0001] Relative permeability modifiers can be used to limit the amount of water produced from a subterranean formation while allowing production of a hydrocarbon liquid. A relative permeability modifier package that includes two or more relative permeability modifiers can be used in carbonate/ sandstone-bearing areas of the formation having high permeabilities. Detailed Description [0002] Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or offshore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid. [0003] As used herein, a "fluid" is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of 71°F (22°C) and a pressure of one atmosphere "atm" (0.1 megapascals "MPa"). A fluid can be a liquid or gas. [0004] A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a "well" includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term "wellbore" includes any cased, and any uncased, open- hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a "well" also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, "into a subterranean formation" means and includes into any portion of the well, including into the wellbore, into the nearwellbore region via the wellbore, or into the subterranean formation via the wellbore. Attorney Docket: 24-112475 U2 HAL 1050 [0005] Hydrocarbons, for example oil and gas, can be produced from a subterranean formation. The subterranean formation can have different zones or regions that can also contain water in addition to the hydrocarbons. Oftentimes it is desirable to prevent or limit the amount of water that is produced along with hydrocarbons. If water is produced with hydrocarbons, then the water must be separated from the hydrocarbons and either disposed of, cleaned up, or injected back into another formation via an injection well. As production continues over time, the ratio of produced water to produced hydrocarbons can increase to the point that it presents a significant economic loss. [0006] Relative permeability modifiers have been used to prevent or limit the amount of water that is produced. The relative permeability modifiers can adsorb onto the surfaces of substances, such as rocks including sandstone and minerals, making up the formation thereby rendering the surfaces hydrophobic. Hydrophobic materials repel water; whereas hydrophilic materials are attracted to water. Thus, substances of a formation that are hydrophilic will typically allow water to flow through the formation and into a wellbore; and substances that are hydrophobic will typically repel water, thus hindering its ability to flow through the formation. However, the relative permeability modifier’s effectiveness depends on the type of substances of a subterranean formation as well as the permeability of the formation. By way of example, some polymers have been used effectively in sandstone-bearing formations and/or carbonate-bearing formations. However, these polymers may not be effective when the permeability of the formation is high (e.g, above 6 darcy “D”). As the permeability of the formation increases, the size of the pore throats also increases. As such, these polymers might not have the desired effectiveness possibly because the molecular weight of the polymers is not enough to decrease fluid flow through the larger pores. Other relative permeability modifiers, such as surfactants have been used effectively in sandstone-bearing formations and/or carbonate-bearing formations when the permeability of the formation is high. However, these surfactants may not be effective in higher temperature formations (e.g., above 200°F (93.3°C)). Thus, there is a need for relative permeability modifiers that can be used in high permeability, high-temperature formations. [0007] A method of treating a portion of a subterranean formation can include introducing a fluid into the portion of the subterranean formation that has an initial perm