Evaluating a hydraulic fracture treatment in a wellbore

• US 5,743,334 A
• Filed: 04/04/1996
• Issued: 04/28/1998
• Est. Priority Date: 04/04/1996
• Status: Expired due to Fees

• Current Assignee: Chevron USA Incorporated (Chevron Corp.)
• Original Assignee: Chevron USA Incorporated (Chevron Corp.)
• Inventors: Nelson, Donald G.
• Primary Examiner(s): Suchfield, George A.
• Application Number:
  US08/627,564
• Time in Patent Office: 754 Days
• Field of Search: 166/250.02, 166/250.07, 166/250.1, 166/250.17, 73/152.05, 73/152.17, 73/152.51, 73/152.54
• US Class Current: 166/250.07
• CPC Class Codes: E21B 49/008 by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor measuring pressure E21B47/06

Abstract

A method is provided for evaluating the quality of a hydraulic fracture treatment performed in a completed wellbore penetrating a subterranean hydrocarbon-bearing formation. The method is initiated by creating a pressure differential or utilizing an existing pressure differential between the wellbore and the formation and placing a lower packer and an upper packer in the wellbore. The lower and upper packers are positioned in the wellbore at or near the bottom of the producing interval to enclose one or more lower perforations within a wellbore chamber sealed to the remainder of the wellbore. Pressure values of the wellbore chamber are measured for a predetermined time period and then the lower and upper packers are repositioned to enclose the next one or more perforations in sequence within a new wellbore chamber. This procedure is repeated until pressure values have been measured in all wellbore chambers enclosing perforations of interest. The pressure values are used to the determine rate of pressure change in each wellbore chamber. By comparing the rates of pressure change of the wellbore chambers, the character and quality of a fracture and/or fracture network at the casing perforations can be evaluated. A relatively high rate of pressure change in a given wellbore chamber is indicative that the one or more casing perforations of the wellbore chamber are in fluid communication with one or more high quality fractures having a high degree of networking and/or vertical connectivity with other casing perforations. A relatively low rate of pressure change in a given wellbore chamber is indicative that the one or more casing perforations of the wellbore chamber are in fluid communication with one or more low quality fractures having little or no networking and/or vertical connectivity.

Claims

1. A method for evaluating a fracture treatment comprising:

a) providing a wellbore penetrating a subterranean hydrocarbon-bearing formation, wherein a pressure differential exists between said wellbore and said formation, and further wherein said formation and said wellbore are bounded by a wellbore face of a production or injection interval across which said formation and said wellbore fluid communicate, said formation having at least one fracture formed therein;

b) placing a first fluid seal across a first cross-section of said wellbore at a first point of said wellbore face in said production or injection interval to block fluid flow across said first cross-section;

c) placing a second fluid seal across a second cross-section of said wellbore at a second point of said wellbore face in said production or injection interval spaced a first wellbore distance from said first point to block fluid flow across said second cross-section, wherein said first and second seals define a wellbore chamber bounded by said first and second seals and a segment of said wellbore face positioned between said first and second points;

d) measuring a plurality of pressure values in said wellbore chamber over a period of time to obtain a pressure rate for said wellbore chamber;

e) repeating steps b) through d) at at least one different sequential pair of points in said production or injection interval to define a plurality of wellbore chambers across the length of said production or injection interval in said wellbore; and

f) comparing said pressure rates for said wellbore chambers to determine whether each of said wellbore chambers is in fluid communication with said fracture.

2. The method of claim 1, wherein said lower seal is a packer.

3. The method of claim 1, wherein said upper seal is a packer.

4. The method of claim 1, wherein said lower and upper seals are integrally connected in a dual packer assembly.

5. The method of claim 1 further comprising repeating steps b) through d) at a plurality of different pairs of lower and upper points in said wellbore to define a plurality of sequential wellbore chambers across substantially the entire length of a production or injection interval in said wellbore.

6. The method of claim 1, wherein said wellbore has a casing positioned at said wellbore face, said casing having a plurality of perforations formed therethrough.

7. The method of claim 6, wherein each of said wellbore chambers contains a different perforation of said plurality of perforations.

8. The method of claim 1, wherein a first of said pressure rates is substantially greater than a second of said pressure rates, thereby indicating said wellbore chamber having said first of said pressure rates has a higher degree of fluid communication with said formation via said fracture than said wellbore chamber having said second of said pressure rates.

9. A method for evaluating the degree of fluid communication between a subterranean formation and a wellbore penetrating the formation comprising:

a) providing a wellbore penetrating a subterranean hydrocarbon-bearing formation and bounding said formation at a wellbore face, wherein said wellbore is segmented into a plurality of wellbore chambers, including a first and a second wellbore chamber, and said wellbore face is segmented into a plurality of wellbore face segments, including a first and a second wellbore face segment, each of said wellbore face segments having a lower bound and an upper bound and each of said wellbore face segments corresponding to one of said wellbore chambers, and further wherein said formation fluid communicates with each said wellbore chamber across said corresponding wellbore face segment and a pressure differential exists between said wellbore and said formation;

b) placing a lower fluid seal across a first lower cross-section of said wellbore at said lower bound of said first wellbore face segment to block fluid flow across said first lower cross-section;

c) placing an upper fluid seal across a first upper cross-section of said wellbore at said upper bound of said first wellbore face segment to block fluid flow across said second cross-section, wherein said lower and upper seals bound said first wellbore chamber;

d) measuring a plurality of first pressure values in said first wellbore chamber over a first time period to obtain a first pressure rate, while maintaining fluid communication between said formation and each of said wellbore chambers across said corresponding wellbore face segments;

e) repositioning said lower and upper seals to said lower and upper bounds of said second wellbore face segment, wherein said lower and upper seals bound said second wellbore chamber;

f) measuring a plurality of second pressure values in said second wellbore chamber over a second time period to obtain a second pressure rate, while maintaining fluid communication between said formation and each of said wellbore chambers across said corresponding wellbore face segments; and

g) comparing said first pressure rate to said second pressure rate.

10. The method of claim 9 further comprising:

repositioning said lower and upper seals to said lower and upper bounds of said third wellbore face segment, wherein said lower and upper seals bound said third wellbore chamber;

measuring a plurality of third pressure values in said third wellbore chamber over a third time period to obtain a third pressure rate, while maintaining fluid communication between said formation and each of said wellbore chambers across said corresponding wellbore face segments; and

comparing said third pressure rate to said first and second pressure rates.

11. The method of claim 9, wherein said upper bound of said first wellbore face segment is between said lower bound of said first wellbore face segment and said lower bound of said second wellbore face segment.

12. The method of claim 9, wherein said second wellbore chamber is substantially adjacent to said first wellbore chamber.

13. The method of claim 10, wherein said upper bound of said first wellbore face segment is between said lower bound of said first wellbore face segment and said lower bound of said second wellbore face segment and said upper bound of said second wellbore face segment is between said lower bound of said second wellbore face segment and said lower bound of said third wellbore face segment.

14. The method of claim 10, wherein said second wellbore chamber is substantially adjacent to said first wellbore chamber and said third wellbore chamber is substantially adjacent to said second wellbore chamber.

15. The method of claim 9 further comprising repeating steps f) through h) at all of said plurality of wellbore chambers across substantially the entire length of a production or injection interval in said wellbore.

16. The method of claim 9, wherein said wellbore has a casing positioned at said wellbore face, said casing having a plurality of perforations formed therethrough.

17. The method of claim 16, wherein said first wellbore chamber contains a first perforation and said second wellbore chamber contains a second perforation.

18. The method of claim 15, wherein said wellbore has a casing positioned at said wellbore face, said casing having a plurality of perforations formed therethrough.

19. The method of claim 18, wherein each of said plurality of wellbore chambers contains one or more different perforations.

20. The method of claim 9, wherein said first pressure rate is substantially greater than said second pressure rate, thereby indicating said first wellbore chamber has a higher degree of fluid communication with said formation and than said second wellbore chamber.