Fracturing of subsurface formations with Bingham plastic fluids

• US 3,948,325 A
• Filed: 04/03/1975
• Issued: 04/06/1976
• Est. Priority Date: 04/03/1975
• Status: Expired due to Term

• Current Assignee: Amoco Corporation (BP PLC)
• Original Assignee: The Western Company of North America (Baker Hughes Company)
• Inventors: Carver, Julius C., Winston, Fred F.
• Primary Examiner(s): Novosad, Stephen J.
• Application Number:
  US05/564,989
• Time in Patent Office: 369 Days
• Field of Search: 166/308, 166/307, 166/281, 166/282, 166/283, 166/259, 166/271, 252/8.55 A
• US Class Current: 166/308.5
• CPC Class Codes: C09K 8/685 containing cross-linking agents
• CPC Class Codes: E21B 43/26 by forming crevices or fractures

Abstract

A method of increasing the permeability of a subsurface formation by the utilization of a Bingham plastic fracture fluid. The Bingham plastic fracture fluid is pumped into a preformed fracture or a fracture formed with the Bingham plastic fluid and hydraulic pressure is imparted to the formation which is greater than that which was required to initially fracture the formation (i.e., the formation is overpressurized) by either (1) relieving the pumping pressure on the Bingham plastic fluid in the fracture and allowing the fracture to heal and thereafter reapplying the pumping pressure on the Bingham plastic fluid in an increased amount, e.g., an amount sufficient to move the Bingham plastic fluid in the fracture; or (2) continuing pumping of the Bingham plastic fluid into the fracture such that the friction drop caused by the continued pumping results in such increase in pressure.

Claims

1. A method of treating a fractured subsurface formation traversed by a well bore to increase its permeability comprising:

a. pumping a Bingham plastic fluid into said well bore at a pressure such that it enters a fracture of said formation;

b. relieving pumping pressure on said Bingham plastic fluid after it is positioned within said fracture such that the pumping pressure on said Bingham plastic fluid is less than the fracture pressure of said formation; and

thereafter

c. reapplying pumping pressure on said Bingham plastic fluid and said formation which is greater than said fracture pressure of said formation.

2. The method of claim 1 further comprising:

a. pumping a second quantity of Bingham plastic fluid into said well bore at a pressure such that it enters a fracture of said formation;

b. discontinuing said pumping pressure on said second quantity of Bingham plastic fluid after it is contained within said fracture; and

thereafter

c. reapplying pumping pressure on said Bingham plastic fluid and said formation which is greater than said fracture pressure.

3. The method of claim 2 wherein a stage of a non-Bingham plastic fluid is pumped into said formation through said well bore between the pumping of the first quantity of Bingham plastic fluid and the said second quantity of Bingham plastic fluid.

4. The method of claim 1 wherein said Bingham plastic fluid comprises an aqueous fluid containing from about 40 to about 100 pounds per 1000 gallons of water with an organic compound selected from guar gum, locust bean gum and derivatives thereof and complexed with borate ions.

5. The method of claim 4 wherein said Bingham plastic fluid comprises from about 60 to about 80 pounds of guar gum per 1000 gallons of water which has been complexed with from about 6 to about 10 pounds of (NH₄)₂ B₄ O₇.4H₂ O per 1000 gallons of water.

6. The method of claim 4 wherein said Bingham plastic fluid further comprises an effective amount of a breaker which will degrade said Bingham plastic fluid to a material which does not have Bingham plastic fluid properties after said reapplying of said pumping pressure.

7. The method of claim 6 wherein said Bingham plastic fluid further comprises from about 1 to about 14 pounds of a propping agent per gallon thereof.

8. The method of claim 7 wherein said Bingham plastic fluid contains from about 1 to about 8 pounds of a propping agent per gallon thereof.

9. A method of fracturing a subsurface formation traversed by a well bore comprising:

a. pumping a hydraulic fracture fluid into said formation from said well bore at a sufficient pressure to fracture said formation;

b. pumping a Bingham plastic fluid into said fracture from said well bore;

c. relieving pumping pressure on said Bingham plastic fluid after it is positioned within said fracture such that the pumping pressure on said Bingham plastic fluid is less than the pressure required to form said fracture in said formation; and

thereafter

d. reapplying pumping pressure on said Bingham plastic fluid and said formation which is greater than the pressure that was required to form said fracture, to thereby increase the permeability of said formation.

10. The method of claim 9 wherein said pumping pressure is reapplied on said formation by pumping a stage of a non-Bingham plastic hydraulic fluid into said formation.

11. The method of claim 10 further comprising:

a. pumping a second quantity of Bingham plastic fluid into said well bore at a pressure such that it enters the fracture of said formation;

b. discontinuing said pumping pressure on said second quantity of Bingham plastic fluid after it is contained within said fracture; and

thereafter

c. reapplying pumping pressure on said Bingham plastic fluid and said formation with a fluid which is sufficient to result in a pressure on said formation which is greater than that required to form said fracture.

12. The method of claim 11 wherein said pumping pressure is reapplied on said second quantity of Bingham plastic fluid by pumping a second stage of non-Bingham plastic hydraulic fluid into said formation.

13. The method of claim 9 wherein said Bingham plastic fluid comprises an aqueous fluid containing from about 40 to about 100 pounds per 1000 gallons of water with an organic compound selected from guar gum, locust bean gum and derivatives thereof complexed with borate ions.

14. The method of claim 9 wherein said Bingham plastic fluid comprises from about 60 to about 80 pounds of guar gum per 1000 gallons of water which has been complexed with from about 6 to about 10 pounds of (NH₄)₂ B₄ O₇.4H₂ O per 1000 gallons of water.

15. The method of claim 14 wherein said Bingham plastic fluid further comprises an effective amount of a breaker which will degrade said Bingham plastic fluid to a material which does not have Bingham plastic fluid properties after said reapplying of said pumping pressure.

16. The method of claim 15 wherein said Bingham plastic fluid further comprises from about 1 to about 14 pounds of a propping agent per gallon thereof.

17. The method of claim 16 wherein said Bingham plastic fluid contains from about 1 to about 8 pounds of a propping agent per gallon thereof.

18. In a method of treating a subsurface formation traversed by a well bore by passing a fracture fluid therewithin to increase the permeability thereof, the improvement comprising:

pumping a Bingham plastic fluid into a permeable portion of said subsurface formation at a point where said formation is traversed by said well bore and next relieving the externally applied pumping pressure from said formation allowing the pressure within said formation to self equalize, and thereafter reapplying pumping pressure on said Bingham plastic fluid and said formation which is greater than the fracture pressure of said formation.

19. A method of treating a subsurface formation traversed by a well bore to increase its permeability comprising:

a. pumping a Bingham plastic fluid into said well bore at a pressure such that it enters the more permeable portions of said formation which are traversed by said well bore;

b. discontinuing said pumping pressure after said Bingham plastic fluid is positioned within said permeable portions of said formation; and

thereafter

c. reapplying pumping pressure on said Bingham plastic fluid and said formation with a fluid which is greater than the pressure initially required to pump said Bingham plastic fluid into said more permeable portions of said formation and thereby result in an increase of permeability of said formation.

20. The method of claim 19 wherein said Bingham plastic fluid comprises an aqueous fluid containing from about 40 to about 100 pounds per 1000 gallons of water with an organic compound selected from guar gum, locust bean gum and derivatives thereof complexed with borate ions.

21. The method of claim 20 wherein said Bingham plastic fluid comprises from about 60 to about 80 pounds of guar gum per 1000 gallons of water which has been complexed with from about 6 to about 10 pounds of (NH₄)₂ B₄ O₇.4H₂ O per 1000 gallons of water.

22. The method of claim 21 wherein said Bingham plastic fluid further comprises an effective amount of a breaker which will degrade said Bingham plastic fluid to a material which does not have Bingham plastic fluid properties after said reapplying of said pumping pressure.

23. The method of claim 22 wherein said Bingham plastic fluid further comprises from about 1 to about 14 pounds of a propping agent per gallon thereof.

24. The method of claim 23 wherein said Bingham plastic fluid contains from about 1 to about 8 pounds of a propping agent per gallon thereof.

25. In a method of treating a subsurface formation traversed by a well bore by passing a fracture fluid therewithin and pumping said fracture fluid at a pressure greater than the fracture pressure of said formation for at least one of the following purposes;

(1) forming new fractures within the formation, and (2) extending existing fractures within the formation, to thereby increase the permeability of the formation, the improvement comprising;

pumping a Bingham plastic fluid into said formation and continuing said pumping at increasing pressures caused by the friction loss of said Bingham plastic fluid being pumped into said formation until a pumping pressure in excess of the fracture pressure of said formation is obtained and maintaining said pumping at said excess of said fracture pressure to thereby further increase the permeability of said formation.

26. The method of claim 25 wherein said Bingham plastic fluid is pumped into an existing fracture in said formation and thereafter pumped at a pressure in excess of the pressure which was required to initially fracture said formation.

27. The method of claim 25 wherein said Bingham plastic fluid is initially pumped into said formation and causes a fracturing thereof and thereafter it is pumped into said fracture at a pressure in excess of the pressure which was required to initially form said fracture.

28. The method of claim 26 wherein a first stage of a non-Bingham plastic hydraulic fluid is pumped into said formation to fracture the same and thereafter a contiguous stage of said Bingham plastic fluid is pumped into said fracture at said excess of said fracture pressure.

29. The method of claim 28 wherein a second stage of a non-Bingham plastic hydraulic fluid is pumped into said formation behind said first stage of Bingham plastic fluid.

30. The method of claim 25 wherein said Bingham plastic fluid comprises an aqueous fluid containing from about 40 to about 100 pounds per 1000 gallons of water with an organic compound selected from guar gum, locust bean gum and derivatives thereof complexed with borate ions.

31. The method of claim 30 wherein said Bingham plastic fluid comprises from about 60 to about 80 pounds of guar gum per 1000 gallons of water which has been complexed with from about 6 to about 10 pounds of (NH₄)₂ B₄ O₇.4H₂ O per 1000 gallons of water.

32. The method of claim 31 wherein said Bingham plastic fluid further comprises an effecitve amount of a breaker which will degrade said Bingham plastic fluid to a material which does not have Bingham plastic fluid properties after said reapplying of said pumping pressure.

33. The method of claim 32 wherein said Bingham plastic fluid further comprises from about 1 to about 14 pounds of a propping agent per gallon thereof.

34. The method of claim 33 wherein said Bingham plastic fluid contains from about 1 to about 8 pounds of a propping agent per gallon thereof.