Methods of zonal isolation and treatment diversion

• US 8,905,133 B2
• Filed: 05/11/2011
• Issued: 12/09/2014
• Est. Priority Date: 05/11/2011
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Potapenko, Dmitry Ivanovich, Sova, Alexey Alexandrovich, Alekseenko, Olga Petrovna, Bruno, Lecerf, Bulova, Marina Nikolaevna, Daniels, John, Nesterova, Svetlana Viktorovna
• Primary Examiner(s): DiTrani, Angela M
• Assistant Examiner(s): Ahuja, Anuradha
• Application Number:
  US13/105,397
• Publication Number:
  US 20120285692A1
• Time in Patent Office: 1,308 Days
• Field of Search: None
• US Class Current: 166/292
• CPC Class Codes: C09K 2208/08 Fiber-containing well treatment fluids
• CPC Class Codes: C09K 8/516 characterised by their form or by the form of their components, e.g. encapsulated material
• CPC Class Codes: C09K 8/70 characterised by their form or by the form of their components, e.g. foams
• CPC Class Codes: E21B 21/003 Means for stopping loss of drilling fluid plastering the borehole wall E21B33/138
• CPC Class Codes: E21B 33/138 Plastering the borehole wall; Injecting into the formation
• CPC Class Codes: E21B 43/26 by forming crevices or fractures
• CPC Class Codes: E21B 43/261 Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
• CPC Class Codes: E21B 43/267 reinforcing fractures by propping

Abstract

Methods of treating a subterranean formation penetrated by a well bore, by providing a treatment fluid comprising a blend including a first amount of particulates having a first average particle size between about 3 mm and 2 cm and a second amount of particulates having a second average size between about 1.6 and 20 times smaller than the first average particle size or a second amount of flakes having a second average size up to 10 times smaller than the first average particle size; by introducing the treatment fluid into the well bore; and by creating a plug with the treatment fluid.

Claims

1. A method of treating a subterranean formation penetrated by a well bore, comprising:

providing a treatment fluid comprising a blend including a first amount of particulates having a first average particle size between about 3 mm and 2 cm and a second amount of particulates having a second average size between about 1.6 and 20 times smaller than the first average particle size or a second amount of flakes having a second average size up to 10 times smaller than the first average particle size;

introducing the treatment fluid into the well bore; and

,

creating a plug with said treatment fluid,

wherein the first amount of particulates, the second amount of particulates and the second amount of flakes are not fibers.

2. The method of claim 1, wherein the treatment fluid comprises a carrier fluid, and a viscosifying agent or friction reducer.

3. The method of claim 2, wherein the carrier fluid is a treatment fluid selected from the group consisting of slickwater, spacer, mutual solvent, flush, formation dissolving fluid, fracturing fluid, scale dissolution fluid, paraffin dissolution fluid, asphaltene dissolution fluid, diverter fluid, water control agent, chelating agent, viscoelastic diverting acid, self-diverting acid, acid, and mixtures thereof.

4. The method according to claim 1 further comprising removing the plug.

5. The method according to claim 1 wherein the blend comprises a degradable material, a soluble material, or a meltable material at downhole conditions.

6. The method of claim 5 wherein the degradable material is a polylactic acid material.

7. The method according to claim 1 wherein the blend comprises a non-degradable material.

8. The method according to claim 1 wherein the treatment fluid further comprises fibers.

9. The method according to claim 1 wherein introducing the treatment fluid into the well bore is done with a mechanical container, or a tool comprising a mechanical container and a perforation gun.

10. The method of claim 9 wherein the container is conveyed on a drill string, a wireline, a slickline, a coil tubing or a microcoil.

11. The method of claim 9 wherein the tool or container moves downhole and the blend is released from the said tool or container.

12. The method of claim 1 wherein the method further comprises subjecting the subterranean formation to a fracturing treatment.

13. The method according to claim 1 wherein the first amount of particulates has an aspect ratio smaller than 5.

14. The method according to claim 1 wherein the first average particle size is between about 3 mm and 20 mm.

15. The method according to claim 1 wherein the first average particle size is between about 6 mm and 10 mm.

16. The method according to claim 1 wherein the treatment fluid further comprises a third amount of particulates or flakes having a third average size smaller than the second average size.

17. The method of claim 16 wherein the treatment fluid further comprises a fourth and a fifth amount of particulates or flakes having a fourth average size smaller than the third average size, and a fifth average size smaller than the fourth average size.

18. The method according to claim 1 wherein the treatment fluid is such that a packed volume fraction of the blend exceeds 0.7.

19. The method according to claim 1 wherein the treatment fluid is such that a packed volume fraction of the blend placed in a slot having width of less than 20 mm exceeds 0.7.

20. The method according to claim 1 wherein the second average size is between about 2 and 10 times smaller than the first average particle size.

21. The method of claim 1 wherein the method further comprises subjecting the subterranean formation to a fracturing treatment after the creating of the plug.

22. The method of claim 1, wherein a size of the first amount of particulates is larger than an average width of a void within the subterranean formation that is intended to be closed or temporally isolated.

23. The method of claim 1 wherein the treatment fluid further comprises a degradation accelerator.

24. The method of claim 23 wherein the degradation accelerator is a metal oxide, a base or a salt of an acid.

25. The method of claim 23 wherein the degradation accelerator is magnesium oxide (MgO).

26. The method of claim 23 wherein the degradation accelerator is a base selected from the group consisting of magnesium hydroxide and calcium hydroxide.

27. The method of claim 1 wherein the treatment fluid further comprises a material selected from the group consisting of calcium carbonate and magnesium carbonate.

28. A method of treating a subterranean formation of a well bore, wherein the well bore comprises a casing and at least one hole on said casing, said hole having a diameter, the method comprising:

providing a treatment fluid comprising a blend including a first amount of particulates having a first average particle size between about 50 to 100% of said diameter and a second amount of particulates having a second average size between about 1.6 and 20 times smaller than the first average particle size or a second amount of flakes having a second average size up to 10 times smaller than the first average particle size;

introducing the treatment fluid into the hole;

creating a plug of the hole with said treatment fluid; and

removing the plug,

wherein the first amount of particulates, the second amount of particulates and the second amount of flakes are not fibers.

29. The method of claim 28 wherein the first average particle size is between about 3 mm and 2 cm.

30. The method of claim 29 wherein the first average particle size is between about 6 mm and 10 mm.

31. The method according to claim 28 wherein the first amount of particulates has an aspect ratio smaller than 5.

32. The method according to claim 28 wherein the treatment fluid is such that a packed volume fraction of the blend exceeds 0.7.

33. The method according to claim 28 wherein the treatment fluid is such that a packed volume fraction of the blend placed in a slot having width of less than 20 mm exceeds 0.7.

34. The method according to claim 28 wherein the treatment fluid comprises a carrier fluid, and a viscosifying agent or friction reducer.

35. The method of claim 34 wherein the carrier fluid is a treatment fluid selected from the group consisting of slickwater, spacer, mutual solvent, flush, formation dissolving fluid, fracturing fluid, scale dissolution fluid, paraffin dissolution fluid, asphaltene dissolution fluid, diverter fluid, water control agent, chelating agent, viscoelastic diverting acid, self-diverting acid, acid, and mixtures thereof.

36. The method according to claim 28 wherein the blend comprises a degradable material, a soluble material, or a meltable material at downhole conditions.

37. The method of claim 36 wherein the degradable material is a polylactic acid material.

38. The method according to claim 28 wherein the blend comprises a non-degradable material.

39. The method according to claim 28 wherein the treatment fluid further comprises fibers.

40. The method according to claim 28 wherein introducing the treatment fluid into the well bore is done with a mechanical container or a tool comprising a mechanical container and a perforation gun.

41. The method of claim 40 wherein the container is conveyed on a wireline, a drill string, a slickline, a coil tubing or a microcoil.

42. The method of claim 41 wherein the tool or container moves downhole and the blend is released from the said tool or container.

43. The method of claim 28 wherein the method further comprises subjecting the subterranean formation to a fracturing treatment.

44. The method according to claim 28 wherein the treatment fluid further comprises a third amount of particulates or flakes having a third average size smaller than the second average size.

45. The method of claim 44 wherein the treatment fluid further comprises a fourth and a fifth amount of particulates or flakes having a fourth average size smaller than the third average size, and a fifth average size smaller than the fourth average size.

46. The method according to claim 28 wherein the second average size is between about 2 and 10 times smaller than the first average particle size.

47. The method of claim 28 wherein the method further comprises subjecting the subterranean formation to a fracturing treatment after the creating of the plug.

48. The method of claim 28, wherein a size of the first amount of particulates is larger than an average width of a void within the subterranean formation that is intended to be closed or temporally isolated.

49. The method of claim 28 wherein the treatment fluid further comprises a degradation accelerator.

50. The method of claim 49 wherein the degradation accelerator is a metal oxide, a base or a salt of an acid.

51. The method of claim 49 wherein the degradation accelerator is magnesium oxide (MgO).

52. The method of claim 49 wherein the degradation accelerator is a base selected from the group consisting of magnesium hydroxide and calcium hydroxide.

53. The method of claim 28 wherein the treatment fluid further comprises a material selected from the group consisting of calcium carbonate and magnesium carbonate.

54. A method of fracturing a subterranean formation of a well bore, wherein the well bore comprises a casing and at least one hole on said casing, said hole having a diameter, the method comprising:

providing a diverting fluid comprising a blend including a first amount of particulates having a first average particle size between about 50 to 100% of said diameter and a second amount of particulates having a second average size between about 1.6 and 20 times smaller than the first average particle size or a second amount of flakes having a second average size up to 10 times smaller than the first average particle size;

introducing the diverting fluid into the hole;

creating a diverting plug of the hole with said diverting fluid;

fracturing the subterranean formation by using said diverting plug; and

removing the diverting-plug plug,

wherein the first amount of particulates, the second amount of particulates and the second amount of flakes are not fibers.

55. The method of claim 54 wherein the first average particle size is between about 6 mm and 20 mm.

56. The method of claim 54 wherein the fracturing the subterranean formation occurs after the creating of the diverting plug.

57. The method of claim 54, wherein a size of the first amount of particulates is larger than an average width of a void within the subterranean formation that is intended to be closed or temporally isolated.

58. The method of claim 54 wherein the treatment fluid further comprises a degradation accelerator.

59. The method of claim 58 wherein the degradation accelerator is a metal oxide, a base or a salt of an acid.

60. The method of claim 58 wherein the degradation accelerator is magnesium oxide (MgO).

61. The method of claim 58 wherein the degradation accelerator is a base selected from the group consisting of magnesium hydroxide and calcium hydroxide.

62. The method of claim 54 wherein the treatment fluid further comprises a material selected from the group consisting of calcium carbonate and magnesium carbonate.