Granted Patent B2

US 12,247,162 · App. 18/437,986 · Granted Mar 11, 2025

Inventors: Do Hoon Kim (Katy, TX); Dennis Arun Alexis (Richmond, VA); Varadarajan Dwarakanath (Houston, TX); David Espinosa (Houston, TX); Taimur Malik (Houston, TX); Logan Jackson (Norcross, GA); Tom Lynch (Roswell, GA); Ronald Robinson (Newnan, GA); Frances Fournier (Marietta, GA); Hong Yang (Atlanta, GA); Sukhjit Aujla (The Woodlands, TX)

Assignee: CHEVRON U.S.A. INC.

C09K8/588C09K8/584E21B43/20

Abstract

Claims (47)

1. A method for mixing an inverted polymer solution for use in the recovery of hydrocarbons from a subsurface reservoir containing the hydrocarbons therewithin; the method comprising:

providing a liquid polymer (LP) composition comprising:

one or more synthetic (co) polymers having a molecular weight of from 15,000,000 g/mol to 30,000,000 g/mol;

one or more hydrophobic liquids;

one or more emulsifier surfactants; and

one or more inverting surfactants;

mixing the LP composition in an in-line mixer with an aqueous fluid in a single step to generate an inverted polymer solution having a concentration of synthetic (co) polymer of from 50 to 15,000 ppm;

wherein the inverted polymer solution does not exhibit signs of plugging in an injectivity test performed using surrogate rock for the subsurface reservoir,

wherein the injectivity test comprises a core flooding experiment performed using surrogate rock for the subsurface reservoir in which the inverted polymer solution is injected into a core comprising the surrogate rock for the subsurface reservoir at a flow rate of 0.5 mL/min at a temperature of 31° C.; and

wherein the inverted polymer solution exhibits a relative permeability of approximately 1 after 28 pore volumes of the inverted polymer solution are injected into the core during the core flooding experiment.

2. The method of claim 1 , wherein when two pore volumes of the inverted polymer solution are injected into the core comprising the surrogate rock for the subsurface reservoir at a flow rate of 0.5 mL/min at a temperature of 31° C., a pressure drop for the inverted polymer solution reaches a steady state.

3. The method of claim 1 , wherein the core comprising the surrogate rock for the subsurface reservoir is a Bentheimer sandstone core.

4. The method of claim 1 , wherein the injectivity test comprises a polymer loop yard test.

5. The method of claim 1 , wherein the method further comprises injecting the inverted polymer solution into the subsurface reservoir.

6. The method of claim 5 , wherein the inverted polymer solution is used in an enhanced oil recovery (EOR) operation.

7. The method of claim 1 , wherein the liquid polymer (LP) composition comprises at least 39% by weight of the one or more water soluble (co) polymers.

8. The method of claim 1 , wherein the liquid polymer (LP) composition comprises an inverse emulsion comprising up to 38% by weight of the one or more water soluble (co) polymers.

9. The method of claim 1 , wherein the one or more synthetic (co) polymers comprise polyacrylamide, a partially hydrolyzed polyacrylamide, acrylamide tertiary butyl sulfonic acid, 2-acrylamido-2-methylpropane sulfonic acid, a blend thereof, or a copolymer thereof.

10. The method of claim 1 , wherein the one or more synthetic (co) polymers have a molecular weight of from 15,000,000 g/mol to 25,000,000 g/mol.

11. The method of claim 1 , wherein the inverted polymer solution has a filter ratio of 1.5 or less at 15 psi using a 1.2 μm filter.

12. The method of claim 11 , wherein the inverted polymer solution has a filter ratio of from 1.1 to 1.3 at 15 psi using the 1.2 μm filter.

13. The method of claim 1 , wherein the inversion of the LP composition forms the inverted polymer solution in 30 minutes or less.

14. The method of claim 1 , wherein the inversion of the LP composition comprises a continuous process.

15. The method of claim 1 , wherein the in-line mixer comprises a mixer inlet and a mixer outlet, and the pressure difference between the mixer inlet and the mixer outlet is from 15 psi to 400 psi.

16. The method of claim 1 , wherein the in-line mixer comprises a static mixer.

17. The method of claim 1 , wherein the in-line mixer comprises a dynamic mixer.

18. The method of claim 17 , wherein the dynamic mixer comprises an impeller mixer, a turbine mixer, a rotor-stator mixer, a colloid mill, pump, or a pressure homogenizer.

19. The method of claim 17 , wherein the dynamic mixer comprises an electrical submersible pump, hydraulic submersible pump or a progressive cavity pump.

20. The method of claim 1 , wherein the in-line mixer is positioned on the surface, subsurface, subsea, or downhole.

21. The method of claim 1 , wherein the aqueous fluid comprises soft brine or hard brine.

22. The method of claim 1 , wherein the aqueous fluid comprises produced reservoir brine, reservoir brine, sea water, fresh water, produced water, water, saltwater, brine, synthetic brine, synthetic seawater brine, or any combination thereof.

23. The method of claim 1 , wherein the aqueous fluid comprises from 15,000 ppm to 100,000 ppm total dissolved solids (tds).

24. The method of claim 1 , wherein the aqueous fluid further comprises a surfactant, an alkalinity agent, a co-solvent, a chelating agent, or any combination thereof.

25. The method of claim 1 , wherein the liquid polymer (LP) composition comprises an inverse emulsion comprising up to 35% by weight of the one or more synthetic (co) polymers.

26. The method of claim 1 , wherein the one or more hydrophobic liquids have a boiling point of at least 100° C.

27. A method for hydrocarbon recovery; the method comprising:

(a) providing a subsurface reservoir containing hydrocarbons therewithin;

(b) providing a wellbore in fluid communication with the subsurface reservoir;

(c) providing a liquid polymer (LP) composition comprising:

one or more synthetic (co) polymers having a molecular weight of from 15,000,000 g/mol to 30,000,000 g/mol;

one or more hydrophobic liquids;

one or more emulsifier surfactants; and

one or more inverting surfactants;

(d) mixing the LP composition in an in-line mixer with an aqueous fluid in a single step to generate an inverted polymer solution having a concentration of (co) polymer of from 50 to 15,000 ppm, wherein the inverted polymer solution does not exhibit signs of plugging in an injectivity test performed using surrogate rock for the subsurface reservoir; and

(e) injecting the inverted polymer solution through the wellbore into the subsurface reservoir;

wherein the injectivity test comprises a core flooding experiment performed using surrogate rock for the subsurface reservoir in which the inverted polymer solution is injected into a core comprising the surrogate rock for the subsurface reservoir at a flow rate of 0 . 5 mL/min at a temperature of 31° C.; and

wherein the inverted polymer solution exhibits a relative permeability of approximately 1 after 28 pore volumes of the inverted polymer solution are injected into the core during the core flooding experiment.

Assignments (3)

Continuity (7)

References Cited (249)