Compositions and Methods for Treating a Water Blocked Well

• US 20100224361A1
• Filed: 12/30/2007
• Published: 09/09/2010
• Est. Priority Date: 03/23/2007
• Status: Abandoned Application

• Current Assignee: 3M Innovative Properties Company (3M Company), Board of Regents of the University of Texas System (University of Texas System)
• Original Assignee: 3M Innovative Properties Company (3M Company), Board of Regents of the University of Texas System (University of Texas System)
• Inventors: Pope, Gary A., Baran, Jimmie R. JR., Bang, Vishal, Skildum, John D., Sharma, Mukul M.
• Application Number:
  US12/532,682
• Publication Number:
  US 20100224361A1
• Time in Patent Office: Days
• US Class Current: 166/250.20
• CPC Class Codes: C09K 8/584 characterised by the use of specific surfactants
• CPC Class Codes: C09K 8/604 Polymeric surfactants
• CPC Class Codes: C09K 8/80 Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
• CPC Class Codes: C09K 8/88 macromolecular compounds

Abstract

The present invention includes a method of treating a hydrocarbon-bearing clastic formation having non-connate water, the method includes contacting the hydrocarbon-bearing clastic formation with a composition that includes a solvent and a surfactant wherein the solvent at least partially displaces or solubilizes the water in the formation.

Claims

1. A method of treating a hydrocarbon-bearing subterranean formation having non-connate water, the method comprising contacting the hydrocarbon-bearing subterranean formation with a composition comprising solvent and a wettability modifier, wherein the solvent at least partially displaces or solubilizes the water in the formation.

3. The method of claim 1, wherein the hydrocarbon-bearing formation has at least one fracture that includes a proppant.

4. The method of claim 1, wherein the hydrocarbon-bearing formation comprises at least one of a dry gas reservoir, a wet gas reservoir, a retrograde condensate gas reservoir, a tight gas reservoir, a coal-bed gas reservoir or a gas storage reservoir.

5. The method of claim 1, further comprising reducing non-Darcy flow in the formation.

7. The method of claim 1, wherein the hydrocarbon-bearing formation comprises a water damaged formation that is essentially free of condensate.

9. The method of claim 1, wherein the hydrocarbon-bearing formation is a clastic formation.

10. The method of claim 1, wherein the hydrocarbon-bearing formation is a non-clastic formation.

11. The method of claim 1, wherein the wettability modifier is not an organosilicon compound.

2. (canceled)

6. (canceled)

8. (canceled)

12. A method of reconditioning a hydrocarbon-bearing formation treated with a first wettability modifier, wherein the treated hydrocarbon-bearing formation is at least partially water-blocked, the method comprising:

contacting the treated hydrocarbon-bearing formation that is at least partially water-blocked with a fluid, wherein the fluid at least partially displaces water in the hydrocarbon-bearing formation;

obtaining performance information from the hydrocarbon-bearing formation after contacting the hydrocarbon-bearing formation with the fluid; and

making a determination based at least partially on the performance information whether to re-treat the hydrocarbon-bearing formation with a second wettability modifier.

14. The method of claim 12, wherein the performance information comprises at least one of gas permability, relative gas permeability, production rate of gas, production rate of condensate, production rate of oil or the productivity index.

15. The method of claim 12, further comprising re-treating the hydrocarbon-bearing formation with a composition comprising the second wettability modifier and at least one of solvent or water, wherein the solvent comprises at least one of a polyol or polyol ether, wherein the polyol and polyol ether independently have from 2 to 25 carbon atoms;

and wherein the solvent comprises at least one of monohydroxy alcohol, ether, or ketone independently having from 1 to 4 carbon atoms.

16. The method of claim 12, wherein the first and second wettability modifiers are the same surfactant.

19. The method of claim 12, wherein the hydrocarbon-bearing formation has condensate, and wherein the fluid at least partially displaces the condensate in the hydrocarbon-bearing formation.

21. The method of claim 12, wherein the fluid is essentially free of surfactant.

22. The method of claim 12, wherein the hydrocarbon-bearing formation is a clastic formation.

23. The method of claim 12, wherein the hydrocarbon-bearing formation is a non-clastic formation.

13. (canceled)

17. (canceled)

18. (canceled)

20. (canceled)

24. A method of treating a hydrocarbon-bearing formation having connate brine and at least one first gas relative permeability, wherein the formation is not otherwise liquid blocked or damaged by liquid, the method comprising:

contacting the hydrocarbon-bearing formation with a wettability modifier, wherein when the wettability modifier is contacting the hydrocarbon-bearing formation, the formation has at least one second gas relative permeability, and wherein the second gas relative permeability is at least 5% higher than the first gas relative permeability.

25. The method of claim 24, wherein the wettability modifier is not an organosilicon compound.

27. The method of claim 24, wherein the hydrocarbon-bearing formation is a clastic formation.

28. The method of claim 24, wherein the hydrocarbon-bearing formation is a non-clastic formation.

26. (canceled)

29-50. -50. (canceled)