Gas diverter for well and reservoir stimulation

• US 10,344,204 B2
• Filed: 06/19/2017
• Issued: 07/09/2019
• Est. Priority Date: 04/09/2015
• Status: Expired due to Fees

• Current Assignee: Diversion Technologies, LLC
• Original Assignee: Diversion Technologies, LLC
• Inventors: Mendell, Paul E., Miller, Stephen
• Primary Examiner(s): DiTrani Leff, Angela M
• Application Number:
  US15/627,160
• Publication Number:
  US 20170283689A1
• Time in Patent Office: 750 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 8/703 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 fracturing methods described in the present disclosure provide advantage over the 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, the methods of present disclosure, in relation to current practices, 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 into a wellbore comprising a tubing string having inner and outer tubing string walls, a well casing having inner and outer well casing walls, and an annular space defined by the inner well casing wall and the outer tubing string wall, wherein the wellbore is at least partly contained within a subterranean formation, wherein the gas is injected into the annular space of the wellbore is at a rate from about 1 to about 500,000 scf/min and occupies one or more portions of the subterranean formation surrounding the wellbore at an injected pressure, wherein the gas comprises no more than about 1% by volume solid particulates;

maintaining the gas at the injected pressure, wherein the injected pressure is below a fracture gradient of the subterranean formation during substantially the duration of the injecting step; and

injecting a fracturing liquid into a tubing space defined by the inner tubing string wall at a sufficient pressure to fracture a target portion of the subterranean formation surrounding the wellbore, wherein the one or more portions of the subterranean formation and the target portion of the subterranean formation differ.

2. The method of claim 1, further comprising:

positioning a packer within the wellbore, wherein the packer substantially isolates the injected gas from the injected fracturing liquid.

3. The method of claim 1, further comprising:

setting a packer within the wellbore to isolate at least one of the one or more portions of the subterranean formation from the other of the one or more portions of the subterranean formation, wherein the gas, during the injecting of the gas into the wellbore and maintaining the gas at the injection pressure, occupies the least one of the one or more portions of the subterranean formation, and wherein the fracturing liquid, during the injecting the fracturing liquid, is injected at a sufficient pressure to fracturing the other of the one or more portions of the subterranean formation.

4. The method of claim 1, wherein the wellbore comprises a vertical wellbore.

5. The method of claim 1, wherein the wellbore comprises a horizontal wellbore, wherein the target portion of the subterranean formation comprises a heel target wellbore portion and a toe target wellbore portion, and wherein the other of the one or more portions of the subterranean formation is closer to the toe target wellbore portion than to the heel target wellbore portion.

6. The method of claim 1, wherein the one or more portions of the subterranean formation occupied by the gas are substantially devoid of any fractures formed by the injecting of the fracturing liquid into the target portion of the wellbore at sufficient pressure to fracture the target portion of the subterranean formation.

7. The method of claim 1, wherein the target portion of the subterranean formation has a first hydrocarbon production rate prior to the injecting of the gas, wherein the fractured target portion of the subterranean has a second hydrocarbon rate, wherein the second hydrocarbon production rate is greater than the first hydrocarbon production rate, wherein the target portion of the subterranean formation comprises first and second portions of the subterranean formation, and wherein the second portion of the subterranean formation is fractured to a greater extent than the first portion of the subterranean formation.

8. The method of claim 1, wherein during the injecting of the gas into the wellbore, the gas is in the form of a foam, and further comprising:

maintaining a dwell period between the injecting of the gas into the one or more portions of the subterranean formation and the injecting of fracturing liquid into the target portion of the subterranean formation, and wherein one of the following is true;

(i) the foam comprises more gas by volume than liquid by volume; and

(ii) the foam comprises less gas by volume than liquid by volume.

9. The method of claim 1, wherein the gas comprises one or more of nitrogen (N₂), hydrogen (H₂), methane (CH₄), ethane (C₂H₆), propane (C₃H₈), butane (C₄H₁₀), carbon dioxide (CO₂), steam, oxygen, air, and an inert gas and wherein one or more of the following are true:

(a) the gas injected into the wellbore comprises from about 1,000 scf to about 1,000,000,000 scf;

(b) the gas injected into the wellbores comprises more than about 1×

10⁹ scf;

(c) the gas injected into the one or more portions of the subterranean formation comprises at least about 1 scf/lfcA over a lfcA from about 1 foot to about 15 miles of the wellbore; and

(d) the gas injected into the one or more portions of the subterranean formation comprises no more than about 5 scf/lfcA over a lfcA from about 1 foot to about 15 miles of each of the two or more wellbores.