Process for recovering methane and/or sequestering fluids

• US 6,412,559 B1
• Filed: 12/18/2000
• Issued: 07/02/2002
• Est. Priority Date: 11/24/2000
• Status: Expired due to Term

• Current Assignee: Alberta Innovates Technology Futures
• Original Assignee: Alberta Research Council Inc. (Alberta Science & Research Authority)
• Inventors: Mavor, Matthew John, Law, David Hin-Sum, Gunter, William Daniel
• Primary Examiner(s): SUCHFIELD, GEORGE A
• Application Number:
  US09/740,081
• Time in Patent Office: 561 Days
• Field of Search: 166/263, 166/271, 166/280, 166/308, 299/12, 405/129.35, 405/129.4
• US Class Current: 166/271
• CPC Class Codes: E21B 41/0064 Carbon dioxide sequestration storing fluids in porous layers B65G5/005
• CPC Class Codes: E21B 43/006 Production of coal-bed methane E21B43/243 takes precedence
• CPC Class Codes: Y02C 20/40 of CO2

Abstract

A process for recovering methane from a coal bed and/or sequestering a fluid more strongly adsorbing than methane (“SAG”) in a coal bed involves fracturing an injection well and cyclically injecting SAG with intervening shut-in periods. Even though the absolute permeability of the coal bed decreases with continued SAG sorption, the SAG injectivity, surprisingly and unexpectedly, increases while injecting SAG at pressures greater than reservoir pressure, but less than fracture pressure or fracture extension pressure. The increased injectivity is thought to be due to a reduction in near-well flow resistance.

Claims

1. A process for sequestering a stronger adsorbing fluid in a coal bed, having a SAG sorption time T_S−

SAG, a reservoir pressure P_R, a fracture pressure P_F, a fracture extension pressure P_E, and a crack initiation pressure P_C, wherein P_C>

P_E>

P_F>

P_R, and having at least one injection well, comprising the steps of;

(a) stimulating the injection well by

(i) inducing a fracture in the coal bed by injecting an injection fluid in the injection well at a pressure greater than or equal to P_C;

(ii) extending the fracture by injecting the injection fluid in the injection well at a pressure greater than or equal to P_E;

(b) injecting a stronger adsorbing fluid into the injection well at a pressure greater than P_R;

(c) shutting in the injection well for at least about 0.5T<sub>S−

SAG</sub>; and

(d) repeating steps (b) and (c) at least once.

2. The process of claim 1, wherein the injection pressure in one or more subsequent steps (b) is less than P_F.

3. The process of claim 1, wherein the injection pressure in one or more subsequent steps (b) is greater than P_F.

4. The process of claim 1, wherein the stronger adsorbing fluid is selected from the group consisting of carbon dioxide, nitric oxide, sulfur hexafluoride, hydrogen sulfide, sulfur dioxide, nitrogen dioxide, sulfur trioxide, trichlorofluoromethane, dichlorodifluoromethane, chlorotrifluoromethane, tetrafluoromethane, dichloromonofluoromethane, fluoroform, 1,1,2-trichloro-1,2,2-trifluoroethane, dichlorotetrafluoroethane, hexafluoroethane, chloropentafluoroethane, and combinations thereof.

5. The process of claim 1, wherein the injection fluid in step (a) is selected from the group consisting of carbon dioxide, flue gas, nitrogen, water, and combinations thereof.

6. The process of claim 1, wherein the injection fluid in step (a) is injected at a rate in a range from about 6.7 to about 11 m³/min.

7. The process of claim 1, wherein the injection time in step (a) is in a range from about 10 to about 30 minutes.

8. The process of claim 5, wherein the injection fluid further comprises a proppant.

9. The process of claim 8, wherein the proppant is selected from the group consisting of sand, sintered bauxite, and sintered ceramics.

10. The process of claim 1, wherein the injected proppant mass per unit thickness is in a range from about 1,063 to about 4,250 kg/m.

11. The process of claim 1, wherein the shut-in time in step (c) is in a range from about 0.5T_S−

SAG to about 4T<sub>S−

SAG</sub>.

12. The process of claim 1, wherein the shut-in time in step (c) is in a range from about T_S−

SAG to about 2T<sub>S−

SAG.</sub>

13. The process of claim 1, wherein the injection time in step (b) is selected so that the stronger adsorbing fluid is at least about 50% of the contacted-region-sorbed gas.

14. The process of claim 1, wherein the injection time in step (b) is selected so that the stronger adsorbing fluid is at least about 65% of the contacted-region-sorbed gas.

15. The process of claim 1, wherein the injection time in step (b) is selected so that the stronger adsorbing fluid is at least about 80% of the contacted-region-sorbed gas.

16. The process of claim 1, further comprising a production well for recovering methane from the coal bed.

17. The process of claim 1, wherein the coal bed has an absolute permeability less than or equal to 20 md prior to step (a).

18. The process of claim 1, wherein the coal bed has an absolute permeability less than or equal to 10 md prior to step (a).

19. The process of claim 1, wherein the coal bed has an absolute permeability less than or equal to 5 md prior to step (a).

20. A process for recovering methane from a coal bed, having a SAG sorption time T_S−

SAG, a reservoir pressure P_R, a fracture pressure P_F, a fracture extension pressure P_E and a crack initiation pressure P_C, wherein P_C>

P_E>

P_F>

P_R, and having at least one injection well and at least one production well, comprising the steps of;

(a) stimulating the injection well by

(i) inducing a fracture in the coal bed by injecting an injection fluid in the injection well at a pressure greater than or equal to P_C; and

(ii) extending the fracture by injecting the injection fluid in the injection well at a pressure greater than or equal to P_E;

(b) injecting a stronger adsorbing fluid into the injection well at a pressure greater than P_R and recovering methane from the formation;

(c) shutting in the injection well for at least about 0.5T<sub>S−

SAG</sub>; and

(d) repeating steps (b) and (c) at least once.

21. The process of claim 20, wherein the injection pressure in one or more subsequent steps (b) is less than P_F.

22. The process of claim 20, wherein the injection pressure in one or more subsequent steps (b) is greater than P_F.

23. The process of claim 20, wherein the stronger adsorbing fluid is selected from the group consisting of carbon dioxide, nitric oxide, sulfur hexafluoride, hydrogen sulfide, sulfur dioxide, nitrogen dioxide, sulfur trioxide, trichlorofluoromethane, dichlorodifluoromethane, chlorotrifluoromethane, tetrafluoromethane, dichloromonofluoromethane, fluoroform, 1,1,2-trichloro-1,2,2-trifluoroethane, dichlorotetrafluoroethane, hexafluoroethane, chloropentafluoroethane, and combinations thereof.

24. The process of claim 20, wherein the injection fluid in step (a) is selected from the group consisting of carbon dioxide, flue gas, nitrogen, water, and combinations thereof.

25. The process of claim 20, wherein the injection fluid in step (a) is injected at a rate in a range from about 6.7 to about 11 m³/min.

26. The process of claim 20, wherein the injection time in step (a) is in a range from about 10 to about 30 minutes.

27. The process of claim 20, wherein the injection fluid further comprises a proppant.

28. The process of claim 27, wherein the proppant is selected from the group consisting of sand, sintered bauxite, and sintered ceramics.

29. The process of claim 27, wherein the injected proppant mass per unit thickness is in a range from about 1,063 to about 4,250 kg/m.

30. The process of claim 20, wherein the shut-in time in step (c) is in a range from about 0.5T_S−

SAG to about 4T<sub>S−

SAG</sub>.

31. The process of claim 20, wherein the shut-in time in step (c) is in a range from about T_S−

SAG to about 2T<sub>S−

SAG</sub>.

32. The process of claim 20, wherein the injection time in step (b) is selected so that the stronger adsorbing fluid is at least about 50% of the contacted-region-sorbed gas.

33. The process of claim 20, wherein the injection time in step (b) is selected so that the stronger adsorbing fluid is at least about 65% of the contacted-region-sorbed gas.

34. The process of claim 20, wherein the injection time in step (b) is selected so that the stronger adsorbing fluid is at least about 80% of the contacted-region-sorbed gas.

35. The process of claim 20, wherein the coal bed has an absolute permeability less than or equal to 20 md prior to step (a).

36. The process of claim 20, wherein the coal bed has an absolute permeability less than or equal to 10 md prior to step (a).

37. The process of claim 20, wherein the coal bed has an absolute permeability less than or equal to 5 md prior to step (a).