Double hydraulic fracturing methods

Patent metadata

Field	Value
Publication number	US-9328600-B2
Application number	US-201113825107-A
Country	US
Kind code	B2
Filing date	Oct 19, 2011
Priority date	Dec 3, 2010
Publication date	May 3, 2016
Grant date	May 3, 2016

Abstract

A method for hydraulically fracturing subterranean formations in a manner resulting in improved propping of fractures, particularly in ductile rock formations such as gas-containing shales having a high clay content. The method allows for improved hydrocarbon production. The method involves injecting a first fluid having a first proppant concentration into the subsurface formation to form a fracture, reducing the pressure in the fracture and allowing the fracture to substantially close, and injecting a second fluid having a second proppant concentration into the fracture to re-open the fracture. The second proppant concentration is greater than the first proppant concentration. A portion of the proppant is effectively retained in the reopened fracture.

First claim

What is claimed is:

1. A method of forming a propped fracture outwardly from a wellbore in a subsurface formation, the method comprising:
(a) injecting a first fluid having a first proppant concentration into the subsurface formation to form a fracture having a first opening width, wherein the first proppant concentration may be zero, and wherein the subsurface formation is ductile and has at least one of a Poisson's ratio greater than or equal to 0.25 and a Young's Modulus not greater than 3.5×10 6 psi (2.4×10 4 MPa);
(b) reducing pressure in the fracture so as to allow the fracture to substantially close;
(c) injecting a second fluid having a second proppant concentration into the fracture to re-open the fracture, wherein the second proppant concentration is greater than the first proppant concentration and wherein the re-opened fracture has a second opening width which is less than the first opening width; and
(d) reducing the pressure in the fracture after injecting the second fluid into the fracture, wherein a portion of proppant from the second fluid remains in the fracture to prop the fracture.

2. The method of claim 1 , wherein the first proppant concentration is zero.

3. The method of claim 1 , wherein the first proppant concentration is less than about 10% vol.

4. The method of claim 1 , wherein:
the fracture has a first length after the first injecting step (a); and
the fracture has a second length after the second injecting step (c).

5. The method of claim 4 , wherein the second length is not greater than two times the first length.

6. The method of claim 4 , wherein the estimated second length is about 10% to 50% greater than the estimated first length.

7. The method of claim 4 , wherein the second length is not greater than the first length.

8. The method of claim 4 , wherein the second length is not more than 10% greater than the first length.

9. The method of claim 1 , wherein the amount of first fluid injected is predetermined to generate a fracture of approximately a desired first length.

10. The method of claim 9 , wherein the amount of second fluid injected is predetermined to generate a fracture of approximately a desired second length.

11. The method of claim 1 , wherein the second fluid is less viscous than the first fluid by at least a factor of 10 at a common shear rate and temperature condition.

12. The method of claim 1 , wherein (i) the first fluid, (ii) the second fluid, or (iii) both comprises an additive which reduces fluid leak-off into the formation.

13. The method of claim 12 , wherein the additive is a particulate material.

14. The method of claim 12 , wherein the additive is a viscosifier.

15. The method of claim 14 , wherein:
the first fluid comprises a viscosifying agent; and
the second fluid comprises an agent that degrades the viscosifying agent of the first fluid a period of time after the second injecting step (c).

16. The method of claim 1 , wherein:
the second injecting step (c) is performed simultaneously on two or more fractures in the subsurface formation.

17. The method of claim 1 , wherein:
the wellbore connects to at least a first interval and a second interval;
steps (a) through (c) are conducted to form a fracture in the first interval; and
the method further comprises:
isolating the first interval from the second interval by restricting fluid communication through the wellbore between the first interval and the second interval,
performing steps (a) through (c) to form a fracture in the second interval, and
re-opening fluid communication through the wellbore between the first interval and the second interval.

18. The method of claim 17 , wherein:
the wellbore is formed to have a substantially horizontal well section;
the first interval and the second interval reside along the horizontal well section;
the fractures formed from the first and second intervals propagate substantially vertically.

19. The method of claim 1 , wherein:
the wellbore connects to at least a first interval and a second interval;
steps (a) and (b) are conducted to form a fracture in the first interval; and
the method further comprises:
isolating the first interval from the second interval by restricting fluid communication through the wellbore between the first interval and the second interval,
performing steps (a) and (b) to form a first fracture in the second interval,
re-opening fluid communication through the wellbore between the first interval and the second interval, and
performing step (c) simultaneously on fractures formed by step (a) in the first and second intervals in order to re-open the fractures.

20. The method of claim 1 , wherein the first fluid vaporizes upon the reducing of pressure in step (b).

21. The method of claim 20 , wherein the first fluid comprises carbon dioxide or propane.

22. The method of claim 1 , further comprising:
producing natural gas from the subsurface formation.

23. The method of claim 22 , wherein produced natural gas after step (b) comprises a first amount and the produced natural gas after step (d) comprises a second amount and the second amount is at least 1000 times greater than the first amount.

Assignees

• Kaminsky Robert D
• El-Rabaa Abdel Wadood M
• Exxonmobil Upstream Res Co

Inventors

• Kaminsky Robert D
• El-Rabaa Abdel Wadood M

Classifications

• E21B43/267 Primary

  reinforcing fractures by propping · CPC title