Compositions containing friction reducers and methods of using thereof in oil and gas operations

Patent metadata

Field	Value
Publication number	US-12352149-B2
Application number	US-202318326409-A
Country	US
Kind code	B2
Filing date	May 31, 2023
Priority date	May 31, 2022
Publication date	Jul 8, 2025
Grant date	Jul 8, 2025

Abstract

Described are compositions and methods for use in oil and gas operations. The methods can decrease pressure drop along a lateral segment of a wellbore in an unconventional subterranean formation.

First claim

What is claimed is:

1. A method of decreasing pressure drop along a lateral segment of a wellbore in an unconventional subterranean formation, the method comprising:
injecting an aqueous fluid into the unconventional subterranean formation via the wellbore in fluid communication with the unconventional subterranean formation, wherein the aqueous fluid comprises:
(i) a well treatment agent; and
(ii) a friction reducer in a concentration of from 0.1 gpt to 5 gpt;

wherein injection of the aqueous fluid decreases pressure drop along the lateral segment of the wellbore;
wherein the decrease in pressure drop along the lateral segment of the wellbore is measured as a drag reduction percentage (DR %) calculated using the equation below:

DR
⁢

%

=

dP
water

-

dP
FR

dP
water

*
100
⁢
%

,

wherein dP water is the calculated value for pressure drop along the lateral segment of the wellbore for water, and dP FR is the pressure drop along the later segment of the wellbore for the aqueous fluid;
wherein the drag reduction percentage (DR %) is from 50% to 95%.

2. The method of claim 1 , wherein the decrease in pressure drop along the lateral segment of the wellbore improves fluid distribution along the lateral segment and into a toe of the wellbore;
wherein the pressure drop along the lateral segment of the wellbore is calculated using the equation below:
dP FR =dP water −( DR×dP water ),

wherein drag reduction factor (DR) ranges from 0.5 to about 0.95, wherein dP water is the calculated value for pressure drop along the lateral segment of the wellbore for water, and dP FR is the pressure drop along the later segment of the wellbore for the aqueous fluid.

3. The method of claim 1 , wherein the pressure drop along the lateral segment of the wellbore when the aqueous fluid is injected is from 10 psi/1000 ft to 600 psi/1000 ft.

4. The method of claim 1 , wherein the method further comprises producing a hydrocarbon from the wellbore.

5. The method of claim 1 , wherein the wellbore comprises tubing having an inner diameter of from 1.5 inches to less than 4 inches, casing having an inner diameter of from 4 inches to 9 inches, or any combination thereof.

6. The method of claim 5 , wherein the tubing comprises a coating layer having a roughness of from 1 μm to 50 μm.

7. The method of claim 6 , wherein the coating layer comprises a coating material comprising a thermoplastic material, a ceramic material, or any combination thereof.

8. The method of claim 1 , wherein the aqueous fluid comprises an anionic surfactant and a non-ionic surfactant.

9. The method of claim 8 , wherein the anionic surfactant comprises a disulfonate surfactant.

10. The method of claim 8 , wherein the non-ionic surfactant comprises one or more alkoxylated alcohols.

11. The method of claim 1 , wherein the friction reducer comprises a synthetic polymer selected from polyacrylamides, polyacrylic acid (PAA), polyvinyl alcohol (PVA), co-polymers of polyacrylamide (PAM) and 2-acrylamido 2-methylpropane sulfonic acid, or any combination thereof.

12. The method of claim 1 , wherein the aqueous fluid comprises an alkoxylated C6-C32 alcohol, a disulfonate, and a polyacrylamide.

13. The method of claim 1 , wherein the wellbore has a reservoir pressure that is less than original reservoir pressure.

14. The method of claim 1 , wherein the aqueous fluid is injected at a pressure and flowrate effective to increase a wellbore pressure without substantially fracturing or refracturing the wellbore.

15. The method of claim 14 , wherein the wellbore pressure is from 20% to 70% of an original reservoir pressure prior to injection of the aqueous fluid.

16. The method of claim 14 , wherein injection of the aqueous fluid comprises injecting the aqueous fluid at a pressure and flowrate effective to increase the wellbore pressure by at least 30%, to increase the wellbore pressure to from greater than an original reservoir pressure to 150% of the original reservoir pressure, to increase the wellbore pressure to within 15% of original reservoir fracture pressure, or any combination thereof.

17. The method of claim 14 , wherein the method further comprises injecting a fracturing fluid into the unconventional subterranean formation via a new wellbore at a sufficient pressure to create or extend at least one fracture in the unconventional subterranean formation.

18. The method of claim 17 , wherein injection of the aqueous fluid comprises injecting the aqueous fluid into the unconventional subterranean formation via the wellbore at least 1 day before injecting the fracturing fluid into the unconventional subterranean formation via the new wellbore.

19. The method of claim 1 , wherein injection of the aqueous fluid in the wellbore increases a relative permeability in a region of the unconventional subterranean formation proximate to the wellbore, optionally wherein injection of the aqueous fluid in the wellbore releases hydrocarbons from pores in the region of the unconventional subterranean formation proximate to the wellbore.

20. The method of claim 1 , wherein the method further comprises modeling the wellbore to determine a volume of the aqueous fluid to be injected into the unconventional subterranean formation via the wellbore.

21. The method of claim 1 , wherein the method further results in increased hydrocarbon recovery from the wellbore, a new wellbore of the unconventional subterranean formation, or any combination thereof.

22. The method of claim 1 , wherein the method further comprises allowing the aqueous fluid to imbibe into the unconventional subterranean formation for a period of time.

23. The method of claim 1 , wherein the method further comprises monitoring a fluid distribution in the wellbore using a production logging tool, fiber optics equipment, or any combination thereof.

24. The method of claim 1 , wherein the well treatment agent comprises one or more of an acid, an alkali agent, a polymer, a gelling agent, a crosslinker, a biocide, a scale inhibitor, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a chelating agent, a corrosion inhibitor, a clay stabilizing agent, a wettability alteration chemical, an anti-foam agent, a sulfide scavenger, a mobility control agent, a co-solvent, a surfactant, a surfactant package, or any combination thereof.

25. A method of improving fluid distribution along a lateral segment of a wellbore and into a toe of the wellbore in an unconventional subterranean formation, the method comprising:
injecting an aqueous fluid into the unconventional subterranean formation via the wellbore in fluid communication with th

Assignees

• Chevron Usa Inc

Inventors

• Matovic Gojko
• Nizamidin Nabijan
• Unomah Michael Ogechukwuka
• Kim Do Hoon
• Dwarakanath Varadarajan
• Malik Taimur
• Pinnawala Gayani W
• Alexis Dennis A
• Lau Samuel Wei-En

Classifications

• C09K8/588

  characterised by the use of specific polymers {(polymeric surfactants C09K8/584)} · CPC title

• C09K8/584 Primary

  characterised by the use of specific surfactants · CPC title

• C09K2208/28

  Friction or drag reducing additives · CPC title

• E21B43/26

  by forming crevices or fractures · CPC title

• E21B43/267 Primary

  reinforcing fractures by propping · CPC title