Gas diverter for well and reservoir stimulation

• US 10,012,064 B2
• Filed: 12/02/2015
• Issued: 07/03/2018
• Est. Priority Date: 04/09/2015
• Status: Active Grant

• Current Assignee: Diversion Technologies, LLC
• Original Assignee: Diversion Technologies, LLC, Highlands Natural Resources, Plc
• Inventors: Mendell, Paul E.
• Primary Examiner(s): DiTrani, Angela M
• Application Number:
  US14/957,182
• Publication Number:
  US 20160298437A1
• Time in Patent Office: 944 Days
• Field of Search: None
• CPC Class Codes: C09K 8/594 Compositions used in combination with injected gas , e.g. CO2 orcarbonated gasC09K8/592 takes precedence
• CPC Class Codes: C09K 8/62 Compositions for forming crevices or fractures
• CPC Class Codes: C09K 8/703 Foams
• CPC Class Codes: C09K 8/94 Foams
• CPC Class Codes: E21B 43/2605 using gas or liquefied gas
• CPC Class Codes: E21B 43/261 Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation

Abstract

The disclosure provides fracturing methods having advantage over current fracturing methods. The disclosed fracturing methods can change the fracture gradient of the downhole subterranean formation. For example, one or more of the fracture gradients of the low and high stress zones of the downhole subterranean formation can be changed. Furthermore, in relation to current practices, the methods can decrease the extent and/or degree of fracturing within low stress downhole formations and increase the degree of fracturing within high stress formations.

Claims

1. A method, comprising:

injecting a gas composition into a wellbore, wherein the injected gas composition passes through a perforation tunnel in the wellbore and occupies and pressurizes a subterranean formation, wherein the subterranean formation comprises first and second portions, wherein the gas composition comprises no more than about 1% by volume solid particulates;

maintaining an injection pressure of the injected gas composition below a fracture gradient of the subterranean formation during substantially the duration of the injecting step; and

thereafter, introducing a fracturing liquid comprising proppant into the subterranean formation at a sufficient pressure above the fracture gradient to fracture the subterranean formation.

2. The method of claim 1, wherein a volume of gas composition injected into the subterranean formation is at least about 500 scf/1f_CA, wherein the gas composition comprises no more than about 0.1% by volume solid particulates, wherein the gas composition is injected into the wellbore at a rate from about 30 to about 500,000 scf/min, wherein the first portion comprises a previously stimulated area, wherein the second portion has not previously been stimulated, wherein the first portion is a lower stress zone of the subterranean formation, wherein the second portion is a higher stress zone of the subterranean formation, wherein the gas composition comprises at least about 50% gas by volume, wherein the injection pressure of the injected gas composition is no more than about 75% of the fracture gradient, wherein the subterranean formation has a first hydrocarbon production rate prior to the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, and wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate.

3. The method of claim 1, wherein the gas composition comprises no more than about 45 volume % liquid, wherein the gas composition comprises no more than about 0.75% by volume solid particulates, wherein the second portion of the subterranean formation is fractured to a greater extent than the first portion of the subterranean formation, wherein the injection pressure of the injected gas composition is no more than about 80% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 50,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 30 scf/min or more, wherein the gas composition comprises at least about 50% gas by volume, and wherein the volume of injected gas composition is at least about 550 scf/1f_CA.

4. The method of claim 1, wherein the gas composition comprises no more than about 0.5% by volume solid particulates, wherein the first portion of the subterranean formation comprises first portion fractures and pore volumes, wherein the second portion of the subterranean formation comprises second portion fractures and pore volumes, wherein the injection pressure of the injected gas composition is no more than about 85% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 100,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 100 scf/min or more, wherein the gas composition comprises at least about 70% gas by volume, and wherein the volume of injected gas composition is at least about 575 scf/1f_CA.

5. The method of claim 1, wherein, during the injecting of the gas composition into the wellbore, the gas composition is in the form of one or more of gas phase, liquid phase, foam, or combination thereof, wherein the gas composition comprises no more than about 0.25% by volume solid particulates, wherein the first portion of the subterranean formation comprises one of first pressure stress zone, a previously hydraulic fractured zone, a combination thereof, wherein the second portion of the subterranean formation comprises one of second pressure stress zone, a non-previously hydraulic fractured zone, a previously unstimulated zone, a previously under stimulated zone, or a combination thereof, wherein the pressure in the second pressure zone is greater that the pressure in the first pressure zone, wherein the injection pressure of the injected gas composition is no more than about 90% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 150,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 200 scf/min or more, wherein the gas composition comprises at least about 80% gas by volume, and wherein the volume of injected gas composition is at least about 600 scf/1f_CA.

6. The method of claim 1, wherein the gas composition is in form of a foam, wherein the foam composition comprises at least about 90% gas by volume, wherein the gas composition comprises no more than about 0.1% by volume solid particulates, wherein the injection pressure of the injected foam composition is no more than about 95% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 200,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 300 scf/min or more, wherein the foam composition comprises no more than about 10 volume % liquid, wherein the volume of injected gas composition is at least about 625 scf/1f_CA, and wherein pressurization of the features by the gas composition creates a barrier to the fracturing liquid and substantially inhibits fracturing of the pressurized features by the fracturing liquid.

7. The method of claim 1, wherein the subterranean formation has a first hydrocarbon production rate prior to the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, and further comprising:

introducing, after the injecting of the gas composition but before the introducing of the fracturing liquid, a diverting agent into the wellbore, wherein the first portion of the subterranean formation comprises first portion fractures and pore volumes and wherein the diverting agent is injected at sufficient pressures to occupy at least some of the first portion fractures and pore volumes, wherein the injection pressure of the injected gas composition is no more than about 96% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 300,000 scf, wherein the gas composition is injected into the wellbore at a rate of about 400 scf/min or more, wherein the gas composition comprises no more than about 35 volume % liquid, wherein the volume of injected gas composition is at least about 650scf/1f_CA, and wherein the diverting agent is one or more of a chemical diverting agent, a mechanical diverting agent, sand, a ceramic proppant, a resin coated proppant, a salt, a degradable fiber, a starch, a gel, guar, ceramic beads, benzoic acid, bauxite, glass microspheres, synthetic organic beads, a sintered material, polymeric polytetrafluoroethylene, particulates, seed shell pieces, cured resinous particulates, and a degradable polymer.

8. The method of claim 7, wherein the introducing of the diverting agent begins immediately after terminating the injection of the gas composition into the wellbore, and wherein the diverting agent is selected from the group consisting essentially of a chemical diverting agent, a mechanical diverting agent, a degradable fiber, benzoic acid, or a combination thereof, wherein a volume of the gas composition injected into the wellbore is at least about 350,000 scf, wherein the gas composition is injected into the wellbore at a rate of about 500 scf/min or more, wherein the gas composition comprises no more than about 5volume % liquid, and wherein the volume of injected gas composition is at least about 675scf/1fcA.

9. The method of claim 1, further comprising:

maintaining a dwell period between the injecting of the gas composition in the wellbore and the introducing of the fracturing liquid into the well bore, wherein in the dwell period comprises one of less than one hour, less than 24 hours, and more than 24 hours, wherein the gas composition is in the form of a foam, and wherein the foam comprises more gas by volume than liquid by volume, and wherein the gas composition infiltrates and occupies pore volumes of the subterranean formation in a far afield area of the subterranean formation to a distance of about 10 to about 3000 feet from the wellbore.

10. The method of claim 1, wherein the subterranean formation has a first hydrocarbon production rate prior to the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, wherein the gas composition comprises one or more of nitrogen (N₂), hydrogen (H₂), methane (CH₄), ethane (CH₃-CH₃), propane (C₃H₈), butane (C₄H₁₀), carbon dioxide (CO₂), and inert gas and wherein one or more of the following are true:

(a) the gas composition injected into the wellbore is at least about 750,000 scf;

(b) the gas composition injected into the wellbore is at least about 500scf/min or more;

(c) the gas composition injected in the first and second portions of the subterranean formation comprises at least about 500scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore; and

(d) the gas composition injected in the first and second portions of the subterranean formation comprises no more than about 5, scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore.

11. A method, comprising:

injecting from about 1,000 scf to about 1,000,000,000 scf of a gas composition into a wellbore, wherein the injected gas composition passes through a perforation tunnel in the wellbore and occupies and pressurizes a portion of a subterranean formation, wherein the gas composition comprises no more than about 0.1% by volume solid particulates, and wherein the gas composition comprises no more than about 2 volume % liquid;

maintaining an injection pressure of the injected gas composition below a fracture gradient of the subterranean formation during substantially the duration of the injecting step; and

thereafter, introducing a fracturing liquid into the subterranean formation at a sufficient pressure above the fracture gradient to fracture the subterranean formation.

12. The method of claim 11, wherein the fracturing liquid comprises a proppant, wherein the gas composition comprises at least about 90 volume % gas wherein the injection pressure of the injected gas composition is no more than about 75% of the fracture gradient, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, and wherein pressurization of the features by the gas composition creates a barrier to the fracturing liquid and substantially inhibits fracturing of the pressurized features by the fracturing liquid.

13. The method of claim 11, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, wherein the fracturing liquid fractures a second portion of the subterranean formation to a greater extent than a first portion of the subterranean formation, wherein the first portion of the subterranean formation comprises first portion fractures and pore volumes, wherein the second portion of the subterranean formation comprises second portion fractures and pore volumes, wherein the first portion of the subterranean formation comprises one of a first pressure stress zone, a previously hydraulic fractured zone, a previously unstimulated zone, a previously under stimulated zone, or a combination thereof, and wherein the second portion of the subterranean formation comprises one of a second pressure stress zone, a non-previously hydraulic fractured zone, a combination thereof, wherein the pressure in the second pressure stress zone is greater than the pressure in the first pressure stress zone, wherein the injection pressure of the injected gas composition is no more than about 80% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 50,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 30 scf/min or more, wherein the gas composition comprises at least about 90 volume % gas, and wherein the volume of injected gas composition is at least about 550 scf/1f_CA.

14. The method of claim 11, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, and further comprising:

introducing, after the injecting of the gas composition but before the introducing of the fracturing liquid, a diverting agent into the wellbore, wherein the diverting agent is injected at a sufficient pressure to occupy at least some of the first portion of the subterranean formation, wherein the introducing of the diverting agent begins immediately after terminating the injection of the gas composition into the wellbore, and wherein the diverting agent is selected from the group consisting essentially of a chemical diverting agent, a mechanical diverting agent, a degradable fiber, benzoic acid, or a combination thereof, wherein the injection pressure of the injected gas composition is no more than about 85% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 100,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 100 scf/min or more, wherein the gas composition comprises at least about 90 volume % gas, and wherein the volume of injected gas composition is at least about 575 scf/1f_CA.

15. The method of claim 11, further comprising:

maintaining a dwell period between the injecting of the gas composition in the wellbore and the introducing of the fracturing liquid into the well bore, wherein in the dwell period comprises one of less than one hour, less than 24 hours, and more than 24 hours, wherein the injection pressure of the injected gas composition is no more than about 90% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 150,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 200 scf/min or more, wherein the gas composition comprises at least about 90 volume % gas, and wherein the volume of injected gas composition is at least about 600 scf/1f_CA.

16. The method of claim 11, wherein the gas composition is in the form of a foam, wherein the foam comprises more gas by volume than liquid by volume, wherein the injection pressure of the injected gas composition is no more than about 95% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 200,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 300 scf/min or more, wherein the gas composition comprises no more than about 1 volume % liquid, and wherein the volume of injected gas composition is at least about 625 scf/1f_CA.

17. The method of claim 11, wherein the injection pressure of the injected gas composition is no more than about 96% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 300,000 scf, wherein the gas composition is injected into the wellbore at a rate of about 400 scf/min or more, wherein the gas composition comprises no more than about 0.1 volume % liquid, wherein the volume of injected gas composition is at least about 650 scf/1f_CA, and wherein the gas composition injected into the wellbore comprises more than about 1×

10⁹ scf.

18. The method of claim 11, wherein the gas composition infiltrates and occupies pore volumes of the subterranean formation in a far afield area of the subterranean formation to a distance of about 10 to about 3000 feet from the wellbore and wherein the gas composition injected in the first and second portions of the subterranean formation comprises one of:

(I) at least about 500 scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore;

or.

(II) no more than about 5,000 scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore.

19. The method of claim 11, wherein the gas composition comprises one or more of nitrogen (N₂), hydrogen (H₂), methane (CH₄), ethane (CH₃-CH₃), propane (C₃H₈), butane (C₄H₁₀), carbon dioxide (CO₂), and inert gas, wherein the injection pressure of the injected gas composition is no more than about 97% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 350,000 scf, wherein the gas composition is injected into the wellbore at a rate of about 500scf/min or more, wherein the gas composition comprises no more than about 1 volume % liquid, and wherein the volume of injected gas composition is at least about 675 scf/1f_CA.

20. A method, comprising:

injecting a gas composition into a wellbore, wherein the injected gas composition passes through a perforation tunnel in the wellbore and occupies and pressurizes at least some portion of a subterranean formation, wherein the gas composition comprises no more than about 1% by volume solid particulates;

maintaining an injection pressure of the injected gas composition below a fracture gradient of the subterranean formation during substantially the duration of the injecting step; and

thereafter, introducing a fracturing liquid into the subterranean formation at a sufficient pressure above the fracture gradient to fracture the subterranean formation.

21. The method of claim 20, wherein the gas is injected in the subterranean formation at a volume of at least about 500 scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, wherein the injection pressure of the injected gas composition is no more than about 97% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 350,000 scf, wherein the gas composition comprises no more than about 2 volume % liquid, wherein the gas composition is injected into the wellbore at a rate of about 500 scf/min or more, and wherein the volume of injected gas composition is at least about 675 scf/1f_CA.

22. The method of claim 20, wherein the fracturing liquid comprises a proppant, wherein the gas composition comprises greater than about 50 volume % gas with the balance being liquid, wherein the injection pressure of the injected gas composition is no more than about 75% of the fracture gradient, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, and wherein pressurization of the features by the gas composition creates a barrier to the fracturing liquid and substantially inhibits fracturing of the pressurized features by the fracturing liquid.

23. The method of claim 20, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, wherein the fracturing liquid fractures a second portion of the subterranean formation to a greater extent than a first portion of the subterranean formation, wherein the first portion of the subterranean formation comprises first portion fractures and pore volumes, wherein the second portion of the subterranean formation comprises second portion fractures and pore volumes, wherein the first portion of the subterranean formation comprises one of a first pressure stress zone, a previously hydraulic fractured zone, a previously unstimulated zone, a previously under stimulated zone, or a combination thereof, and wherein the second portion of the subterranean formation comprises one of a second pressure stress zone, a non-previously hydraulic fractured zone, a combination thereof, wherein the pressure in the second pressure stress zone is greater than the pressure in the first pressure stress zone, wherein the injection pressure of the injected gas composition is no more than about 80% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 50,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 30 scf/min or more, wherein the gas composition comprises greater than about 50 volume % gas with the balance being liquid, and wherein the volume of injected gas composition is at least about 550 scf/1f_CA.

24. The method of claim 20, wherein the subterranean formation has a first hydrocarbon production rate before the injecting of the gas composition, wherein the fractured subterranean formation has a second hydrocarbon production rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, and further comprising:

introducing, after the injecting of the gas composition but before the introducing of the fracturing liquid, a diverting agent into the wellbore, wherein the diverting agent is injected at a sufficient pressure to occupy at least some of the first portion of the subterranean formation, wherein the introducing of the diverting agent begins immediately after terminating the injection of the gas composition into the wellbore, and wherein the diverting agent is selected from the group consisting essentially of a chemical diverting agent, a mechanical diverting agent, a degradable fiber, benzoic acid, or a combination thereof, wherein the injection pressure of the injected gas composition is no more than about 85% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 100,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 100 scf/min or more, wherein the gas composition comprises greater than about 60 volume % gas with the balance being liquid, and wherein the volume of injected gas composition is at least about 575 scf/1f_CA.

25. The method of claim 20, further comprising:

maintaining a dwell period between the injecting of the gas composition in the wellbore and the introducing of the fracturing liquid into the well bore, wherein in the dwell period comprises one of less than one hour, less than 24 hours, and more than 24 hours, wherein the injection pressure of the injected gas composition is no more than about 90% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 150,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 200 scf/min or more, wherein the gas composition comprises greater than about 70 volume % gas with the balance being liquid, and wherein the volume of injected gas composition is at least about 600 scf/1f_CA.

26. The method of claim 20, wherein the injection pressure of the injected gas composition is no more than about 95% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 200,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 300 scf/min or more, wherein the gas composition comprises greater than about 80 volume % gas with the balance being liquid, and wherein the volume of injected gas composition is at least about 625 scf/1f_CA.

27. The method of claim 20, wherein the injection pressure of the injected gas composition is no more than about 96% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 300,000 scf, wherein the gas composition is injected into the wellbore at a rate of about 400 scf/min or more, wherein the gas composition comprises no more than about 0.1 volume % liquid, wherein the volume of injected gas composition is at least about 650 scf/1f_CA, and wherein the gas composition injected into the wellbore comprises more than about 1×

10⁹ scf.

28. The method of claim 20, wherein the gas composition infiltrates and occupies pore volumes of the subterranean formation in a far afield area of the subterranean formation to a distance of about 10 to about 3000 feet from the wellbore and wherein the gas composition injected in the first and second portions of the subterranean formation comprises one of:

(I) at least about 500 scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore;

or.

(II) no more than about 5,000 scf/1f_CA over a 1f_CA from about 1 foot to about 15 miles of the wellbore.

29. The method of claim 20, wherein the gas composition comprises one or more of nitrogen (N₂), hydrogen (H₂), methane (CH₄), ethane (CH₃-CH₃), propane (C₃H₈), butane (C₄-H₁₀), carbon dioxide (CO₂), and inert gas, wherein the injection pressure of the injected gas composition is no more than about 97% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 350,000 scf, wherein the gas composition is injected into the wellbore at a rate of about 500 scf/min or more, wherein the gas composition comprises no more than about 1 volume % liquid, and wherein the volume of injected gas composition is at least about 675 scf/1f_CA.

30. The method of claim 20, wherein the injection pressure of the injected gas composition is no more than about 95% of the fracture gradient, wherein a volume of the gas composition injected into the wellbore is at least about 200,000 scf, wherein the fracturing fluid is substantially incompressible, wherein the injected gas composition is substantially compressible, wherein the gas composition is injected into the wellbore at a rate of about 300 scf/min or more, wherein the gas composition comprises greater than about 90 volume % gas with the balance being liquid, and wherein the volume of injected gas composition is at least about 625 scf/1f_CA.