Real-time reservoir fracturing process

• US 6,439,310 B1
• Filed: 04/27/2001
• Issued: 08/27/2002
• Est. Priority Date: 09/15/2000
• Status: Expired due to Fees

• Current Assignee: Gary L. Covatch, George L. Scott III
• Original Assignee: Gary L. Covatch, George L. Scott III
• Inventors: Scott, George L. III, Covatch, Gary L.
• Primary Examiner(s): DANG, HOANG C
• Application Number:
  US09/844,951
• Time in Patent Office: 487 Days
• Field of Search: 166/308, 166/250.1, 166/250.12
• US Class Current: 166/308.1
• CPC Class Codes: E21B 43/2605 using gas or liquefied gas
• CPC Class Codes: E21B 43/267 reinforcing fractures by propping
• CPC Class Codes: E21B 47/11 using tracers; using radioactivity

Abstract

Methods are disclosed for hydraulic fracturing of subterranean reservoir formations using various combinations of gelled fluid, nitrogen, and carbon dioxide base components, in association with proppant and other additives. Selected base components are pumped down a wellbore tubing while other selected base components are simultaneously pumped down the wellbore tubing-casing annulus for downhole mixing into a composite fracturing fluid in the downhole region of the wellbore proximal to the reservoir objective. Thereby, changes may be timely effected in the composite fluid composition and fluid properties, substantially immediately prior to the composite fluid entering the formation. Such real-time modifications may be effected to readily preempt screenout occurrences and may facilitate composite fluid compositions which otherwise are frequently undesirable to pump from the surface. Such composite fluid combinations include components phases of each of carbon dioxide, nitrogen and a base fluid. Proppant concentrations within the composite fluid entering the formation may be effected in real time without the wellbore-volume lag-time inherent in prior art methods.

Claims

1. A method of hydraulically fracturing a subterranean formation penetrated by a wellbore, at least a portion of the wellbore including a tubing string having a tubing bore and a casing string, the casing string and tubing string forming a casing annulus, a portion of the well bore not including the tubing string therein forming a casing bore, the method comprising:

injecting carbon dioxide into the wellbore via one of the tubing bore and the casing annulus at a first injection flow rate;

simultaneously injecting nitrogen into the wellbore via the other of the tubing string and casing annulus at a second injection flow rate;

simultaneously injecting an aqueous fracturing fluid into the wellbore with at least one of the carbon dioxide and nitrogen, at a third injection flow rate;

combining the carbon dioxide, the nitrogen and the aqueous fracturing fluid in the casing bore to form a downhole mixed composite fracturing fluid having a mixed fluid composition;

injecting the downhole mixed composite fracturing fluid from the casing bore into the subterranean formation at a hydraulic pressure sufficient to hydraulically fracture the formation; and

selectively varying one or more of the first injection flow rate, the second injection flow rate, and the third injection flow rate to modify in real time the mixed fluid composition of the downhole mixed composite fracturing fluid, forming a modified downhole mixed composite fracturing fluid.

2. The method as defined in claim 1, further comprising:

adding a solid material proppant to the aqueous fracturing fluid to form a proppant laden downhole mixed composite fracturing fluid having another mixed fluid composition; and

thereafter injecting the proppant laden downhole mixed composite fracturing fluid from the casing bore into the subterranean formation at hydraulic pressures sufficient to hydraulically fracture the formation.

3. The method as defined in claim 2, further comprising:

selectively varying one or more of the first injection flow rate, the second injection flow rate, and the third injection flow rate to modify in real time the another mixed fluid composition of the proppant laden downhole mixed composite fracturing fluid.

4. The method as defined in claim 2, wherein a quantity of proppant in the proppant laden downhole mixed composite fracturing fluid is selectively adjusted in real time by varying at least one of the first injection flow rate, the second injection flow rate, and the third injection flow rate.

5. The method as defined in claim 2, further comprising:

monitoring in real time within the well bore a location in the formation of at least one radioactive tracer provided in at least a portion of one or more of the downhole mixed composite fracturing fluid and the proppant laden downhole mixed composite fracturing fluid by monitoring radioactive emissions from the at least one radioactive tracer; and

varying at least one of the first injection flow rate, the second injection flow rate, and the third injection flow rate in response to the monitored radioactive emissions.

6. The method as defined in claim 1, further comprising:

while selectively varying one or more of the first injection flow rate, the second injection flow rate and the third injection flow rate, increasing a viscosity of the modified downhole mixed composite fracturing fluid as compared to the downhole mixed composite fracturing fluid and cause viscous inter-fingering of the modified downhole mixed composite fracturing fluid within the downhole mixed composite fracturing fluid within the subterranean formation.

7. The method as defined in claim 1, further comprising:

adding to the aqueous fracturing fluid a selected amount of one or more additives from a group comprising chemical additives, gelling agents, alcohols, salts, fluid loss additives, and encapsulated additives; and

selectively varying the selected amount of the one or more of additives added to the aqueous fracturing fluid in response to selectively varying one or more of the first injection flow rate, the second injection flow rate and the third injection flow rate.

8. The method as defined in claim 1, further comprising:

adding a cross-linkable gelling agent to at least one of the carbon dioxide, the nitrogen and the aqueous fracturing fluid; and

adding a cross-linking agent to another of the carbon dioxide, the nitrogen, and the aqueous fracturing fluid such that the cross-linkable gelling agent and the cross-linking agent mix downhole in the casing bore in the composite fracturing fluid and cross-link at least a portion of the cross-linkable gelling agent.

9. A method of hydraulically fracturing a subterranean formation penetrated by a wellbore, at least a portion of the wellbore including a tubing string having a tubing bore and a casing string, the casing string and tubing string forming a casing annulus, a portion of the well bore not including the tubing string therein forming a casing bore, the method comprising:

injecting an aqueous fracturing fluid down one of the casing annulus and the tubing bore at a first injection flow rate;

simultaneously injecting an energized fluid down the other of the casing annulus and the tubing bore at a second injection flow rate;

combining the energized fluid and the aqueous fracturing fluid in the casing bore to form a first downhole mixed composite fracturing fluid having a first mixed fluid composition;

injecting the first downhole mixed composite fracturing fluid from the casing bore into the subterranean formation at a hydraulic pressure adequate to fracture the formation; and

selectively varying one or more of the first injection flow rate and the second injection flow rate to modify in real time the first mixed fluid composition of the first downhole mixed composite fracturing fluid to form a second downhole mixed composite fracturing fluid.

10. The method as defined in claim 9, further comprising:

adding a solid material proppant to the aqueous fracturing fluid to form a proppant laden downhole mixed composite fracturing fluid having a second mixed fluid composition; and

thereafter injecting the proppant laden downhole mixed composite fracturing fluid from the casing bore into the subterranean formation at hydraulic pressures sufficient to hydraulically fracture the formation.

11. The method as defined in claim 10, wherein a quantity of proppant in the composite fracturing fluid is adjusted in real-time by varying at least one of the first injection flow rate and the second injection flow rate.

12. The method as defined in claim 10, further comprising:

selectively varying one or more of the first injection flow rate and the second injection flow rate to modify in real time the second mixed fluid composition.

13. The method as defined in claim 10, further comprising:

monitoring in real time within the well bore a location in the formation of at least one radioactive tracer provided in at least a portion of one or more of the downhole mixed composite fracturing fluid and the proppant laden downhole mixed composite fracturing fluid by monitoring radioactive emissions from the at least one radioactive tracer; and

varying at least one of the first injection flow rate and the second injection flow rate in response to the monitored radioactive emissions.

14. The method as defined in claim 9, wherein the energized fluid further comprises:

at least one of carbon dioxide and nitrogen.

15. The method as defined in claim 9, further comprising:

while selectively varying one or more of the first injection flow rate and the second injection flow rate, increasing a viscosity of the second downhole mixed composite fracturing fluid as compared to the first downhole mixed composite fracturing fluid and cause viscous inter-fingering of the second downhole mixed composite fracturing fluid within the first downhole mixed composite fracturing fluid, within the subterranean formation.

16. The method as defined in claim 9, further comprising:

adding a gelling agent to one of the aqueous fracturing fluid and the energized fluid; and

adding a cross-linking agent to the other of the aqueous fracturing fluid and the energized fluid, such that the gelling agent and the cross-linking agent mix downhole in the casing bore.

17. A method of hydraulically fracturing a subterranean formation penetrated by a wellbore, at least a portion of the wellbore including a tubing string having a tubing bore and a casing string, the casing string and tubing string forming a casing annulus, a portion of the well bore not including the tubing string therein forming a casing bore, the method comprising:

injecting a first aqueous fracturing fluid including a cross-linkable gelling agent down one of the casing annulus and tubing at a first injection rate;

injecting a second aqueous fracturing fluid including a gel cross-linking agent down the other of the casing annulus and the tubing at a second injection rate;

combining the first aqueous fracturing fluid and the second aqueous fracturing fluid in the casing bore to form a downhole mixed composite fracturing fluid having a first mixed fluid composition;

injecting the downhole mixed composite fracturing fluid from the casing bore into the subterranean formation at pressures sufficient to hydraulically fracture the formation; and

selectively varying one or more of the first injection flow rate and the second injection flow rate to modify in real time the first mixed fluid composition of the downhole mixed composite fracturing fluid.

18. The method as defined in claim 17, further comprising:

adding a solid material proppant to one or more of the first aqueous fracturing fluid and the second aqueous fracturing fluid to form a proppant laden downhole mixed composite fracturing fluid having a second mixed fluid composition; and

thereafter injecting the proppant laden downhole mixed composite fracturing fluid from the casing bore into the subterranean formation at pressures sufficient to hydraulically fracture the formation.

19. The method as defined in claim 18, further comprising:

varying at least one of the first injection flow rate and the second injection flow rate to selectively modify in real time at least one of a physical property and a chemical property of at least one of the first mixed fluid composition and the second mixed fluid composition.

20. The method as defined in claim 19, wherein selectively adjusting in real time at least one of a physical property and a chemical property further comprises:

selectively varying a viscosity physical property to cause viscous inter-fingering of fluids in the subterranean formation.

21. The method as defined in claim 18, wherein a quantity of proppant in the proppant laden downhole mixed composite fracturing fluid is selectively adjusted in real time by varying at least one of the first injection flow rate and the second injection flow rate.

22. The method as defined in claim 17, further comprising:

monitoring in real time within the well bore a location in the formation of at least one radioactive tracer provided in at least a portion of one or more of the downhole mixed composite fracturing fluid and the proppant laden downhole mixed composite fracturing fluid by monitoring radioactive emissions from the at least one radioactive tracer; and

varying at least one of the first injection flow rate and the second injection flow rate in response to the monitored radioactive emissions.

23. The method as defined in claim 17, further comprising:

injecting an energizing fluid comprising one or more of carbon dioxide and nitrogen with one or more of the first aqueous fracturing fluid and the second aqueous fracturing fluid.