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US-12624277-B2 - Injection fluids for stimulating fractured formations

US12624277B2US 12624277 B2US12624277 B2US 12624277B2US-12624277-B2

Abstract

Embodiments of the disclosure include compositions and methods that stabilize a injection fluid when exposed to reservoir conditions, reducing formation damage and increasing the amount of hydrocarbon recovered. Specifically, the formulation is a single-phase liquid surfactant package which comprises a surfactant and optionally one or more secondary surfactants. Also provided are methods of using the stabilized injection fluids in stimulation operations.

Inventors

  • Dustin L. Walker
  • Gayani W. PINNAWALA
  • Nabijan Nizamidin
  • Varadarajan Dwarakanath
  • Guo-Qing Tang
  • Dustin J. LOWRY
  • Tetsuo A. INOUYE
  • Taimur Malik

Assignees

  • CHEVRON U.S.A. INC.

Dates

Publication Date
20260512
Application Date
20231027

Claims (20)

  1. 1 . A method for stimulating an unconventional subterranean formation with a fluid, comprising: (a) introducing a low particle size injection fluid through a wellbore into the unconventional subterranean formation, the low particle size injection fluid comprising an aqueous-based injection fluid and a single-phase liquid surfactant package comprising an anionic surfactant comprising a C10-C16 disulfonate, wherein the low particle size injection fluid is aqueous stable and has a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of the unconventional subterranean formation; (b) allowing the low particle size injection fluid to imbibe into a rock matrix of the unconventional subterranean formation for a period of time; and (c) producing fluids from the unconventional subterranean formation through the wellbore.
  2. 2 . The method of claim 1 , wherein the anionic surfactant further comprises a sulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate, a carboxylate, a dicarboxylate, a polycarboxylate, or any combination thereof.
  3. 3 . The method of claim 1 , wherein the anionic surfactant further comprises: a branched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate; a surfactant defined by the formula below R 1 —R 2 —R 3 wherein R 1 comprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking R 1 and R 2 ; R 2 comprises an alkoxylated chain comprising at least one oxide group selected from the group consisting of ethylene oxide, propylene oxide, butylene oxide, and combinations thereof; and R 3 comprises a branched or unbranched hydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5 carboxylate groups; a C10-C30 internal olefin sulfonate; a C8-C30 alkyl benzene sulfonate (ABS); a sulfosuccinate surfactant; a surfactant defined by the formula below wherein R 4 is a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and M represents a counterion; or any combination thereof.
  4. 4 . The method of claim 1 , wherein the anionic surfactant has a concentration within the low particle size injection fluid of less than 1%, based on the total weight of the low particle size injection fluid.
  5. 5 . The method of claim 1 , wherein the low particle size injection fluid further comprises one or more secondary surfactants, and wherein the one or more secondary surfactants comprise one or more non-ionic surfactants, one or more anionic surfactants, one or more cationic surfactants, one or more zwitterionic surfactants, or any combination thereof.
  6. 6 . The method of claim 5 , wherein the one or more secondary surfactants comprise a non-ionic surfactant.
  7. 7 . The method of claim 5 , wherein the one or more secondary surfactants comprise from 0.001% to 2.5% by weight based on the total weight of the low particle size injection fluid.
  8. 8 . A method for stimulating an unconventional subterranean formation with a fluid, comprising: (a) introducing a low particle size injection fluid through a wellbore into the unconventional subterranean formation, the low particle size injection fluid comprising an aqueous-based injection fluid and a single-phase liquid surfactant package comprising a non-ionic surfactant comprising a branched or unbranched a C6-C30:PO(30-40):EO(25-35) surfactant, wherein the low particle size injection fluid is aqueous stable and has a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of the unconventional subterranean formation; (b) allowing the low particle size injection fluid to imbibe into a rock matrix of the unconventional subterranean formation for a period of time; and (c) producing fluids from the unconventional subterranean formation through the wellbore.
  9. 9 . The method of claim 1 , wherein the low particle size injection fluid further comprises a friction reducer, a gelling agent, a crosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a corrosion inhibitor, a scale inhibitor, a biocide, a clay stabilizing agent, a proppant, a wettability alteration chemical, a co-solvent, or any combination thereof.
  10. 10 . The method of claim 1 , wherein the low particle size injection fluid has a total surfactant concentration of from 0.2% to 5% by weight, based on the total weight of the low particle size injection fluid.
  11. 11 . The method of claim 1 , wherein the low particle size injection fluid is introduced at a wellhead pressure of from 0 PSI to 30,000 PSI.
  12. 12 . The method of claim 1 , wherein the unconventional subterranean formation has a temperature of from 75° F. to 350° F.
  13. 13 . The method of claim 1 , wherein the unconventional subterranean formation has a salinity of at least 5,000 ppm TDS.
  14. 14 . The method of claim 1 , wherein the method further comprises ceasing introduction of the low particle size injection fluid through the wellbore into the unconventional subterranean formation before allowing step (b).
  15. 15 . The method of claim 1 , wherein the period of time is from one day to six months.
  16. 16 . The method of claim 1 , wherein method comprises stimulating a naturally fractured region of the unconventional subterranean formation proximate to a new wellbore, stimulating a naturally fractured region of the unconventional subterranean formation proximate to an existing wellbore, stimulating a previously fractured or previously refractured region of the unconventional subterranean formation proximate to a new wellbore, stimulating a previously fractured or previously refractured region of the unconventional subterranean formation proximate to an existing wellbore, or any combination thereof.
  17. 17 . The method of claim 1 , wherein the unconventional subterranean formation comprises naturally fractured carbonate.
  18. 18 . The method of claim 1 , wherein the unconventional subterranean formation comprises naturally fractured sandstone.
  19. 19 . The method of claim 1 , wherein the fluids comprise a hydrocarbon.
  20. 20 . The method of claim 13 , wherein the unconventional subterranean formation has a salinity of from 5,000 ppm TDS to 300,000 ppm TDS.

Description

CROSS REFERENCE TO RELATED APPLICATIONS This application claims the benefit of priority to U.S. Provisional Application 62/538,883, filed Jul. 31, 2017, which is incorporated by reference herein in its entirety. TECHNICAL FIELD The present disclosure relates generally to unconventional reservoirs, and more specifically to using low particle size injection fluids for treating unconventional subterranean formations. BACKGROUND Wells in unconventional or “tight” formations typically undergo multiple fracture stages which are completed in series during fracturing operations. To prop open fractures during such operations, specific cocktails of injection fluid are employed to viscosify the injection fluid and help transport proppant to the far reaches of the fracture, thereby establishing a larger propped fracture network and increased stimulated reservoir volume. Typical injection fluids can include over a dozen chemical components which are mixed into a surface water, typically brackish or recycled production water. During fracturing operations (completions stage) of an unconventional horizontal well, the injection fluids with these additive chemicals are pumped down the well in large quantities (˜10,000 bbls) and the injection fluid contacts the surfaces of the fracture network (FIG. 1A prior to fluid injection; FIG. 1B during fluid injection). Current injection fluids contain dirty water, unfiltered surface water, and/or oil carry-over in surface water. The condition of the injection fluid is such that it can be unstable when exposed to reservoir conditions, such as high temperature, high formation brine salinity, high divalent ion concentrations, etc. The unstable injection fluid can cause a loss in well productivity due to formation damage (FIG. 1C). The term “formation damage” in this context is used to refer to plugging off matrix permeability (which can be on the order of 100's of nano-Darcies) in the formation thus obstructing or hindering fluid flow, for example, due to the suspended particles in the injection fluid precipitating out of solution and causing the plugging. Embodiments of the disclosure include compositions and methods that stabilize the injection fluid when exposed to reservoir conditions, reducing formation damage and increasing the amount of hydrocarbon recovered. SUMMARY Described herein are methods for stimulating an unconventional subterranean formation with a fluid. The methods can comprise introducing a low particle size injection fluid through a wellbore into the unconventional subterranean formation; allowing the low particle size injection fluid to imbibe into a rock matrix of the unconventional subterranean formation for a period of time; and producing fluids from the unconventional subterranean formation through the wellbore. The low particle size injection fluid can comprise an aqueous-based injection fluid and an anionic surfactant comprising a hydrophobic tail comprising from 6 to 60 carbon atoms. The low particle size injection fluid can have a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of the unconventional subterranean formation. The anionic surfactant can comprise, for example a sulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate, a carboxylate, a dicarboxylate, a polycarboxylate, or any combination thereof. In some examples, the anionic surfactant can comprise a C10-C30 internal olefin sulfonate, a C10-C30 isomerized olefin sulfonate, a C10-C30 alfa olefin sulfonate, a C8-C30 alkyl benzene sulfonate (ABS), a sulfosuccinate surfactant, or any combination thereof. In some examples, the anionic surfactant can comprise a branched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate (e.g., a branched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate, a branched or unbranched C6-C12:PO(30-40):EO(25-35)-carboxylate, a branched or unbranched C6-C30:EO(8-30)-carboxylate, or any combination thereof). In some examples, the anionic surfactant can comprise a surfactant defined by the formula below R1—R2—R3 wherein R1 comprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking Rt and R2; R2 comprises an alkoxylated chain comprising at least one oxide group selected from the group consisting of ethylene oxide, propylene oxide, butylene oxide, and combinations thereof; and R3 comprises a branched or unbranched hydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5 carboxylate groups. In some examples, the anionic surfactant can comprise a surfactant defined by the formula below wherein R4 is a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and M represents a counterion (e.g., Na+, K+). In some embodiments, th