Gas diverter for well and reservoir stimulation

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.

1 . A method, comprising:
 injecting a gas into a wellbore comprising a tubing string having inner and outer tubing sting 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;   maintaining the gas at the injected pressure; 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 is about wherein the other of the one or more portions of the subterranean formation is closer to the toe target wellbore portion than a heel target wellbore portion 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 a 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 method of  claim 1 , wherein during the injecting of the gas into the wellbore, the gas is in the form of one or more of gas phase, liquid phase, foam, or combination thereof, 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, wherein the dwell period comprises one of less than one hour, less than 24 hours, and more than 24 hours, wherein the gas is in the form of a foam, 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 (N 2 ), hydrogen (H 2 ), methane (CH 4 ), ethane (C 2 H 6 ), propane (C 3 H 8 ), butane (C 4 H 10 ), carbon dioxide (CO 2 ), 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 1×10 9  scf;   (c) the gas injected into the one or more portions of the subterranean formation comprises at least about 1 scf/lf CA  over a lf CA  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/lf CA  over a lf CA  from about 1 foot to about 15 miles of each of the two or more wellbore.   
     
     
         10 . A method, comprising:
 injecting a first gas into a first wellbore at least partly contained within a subterranean formation, wherein the first gas is injected, at a first injected pressure, into the first wellbore at a rate from about 1 to about 500,000 scf/min, wherein the first injected gas occupies a portion of the subterranean formation surrounding the first wellbore;   maintaining the first gas at the first injected pressure;   injecting a second gas into the first wellbore, wherein the second gas is injected, at a second injected pressure, into the first wellbore at a rate from about 1 to about 500,000 scf/min, wherein the second injected gas occupies a portion of the subterranean formation surrounding the first wellbore;   maintaining the second gas at the second injected pressure; and   injecting a fracturing liquid into a second wellbore different from the first wellbore at a sufficient pressure to fracture a target portion of the subterranean formation surrounding the second wellbore.   
     
     
         11 . The method of  claim 10 , wherein the first gas comprises at least one fluid selected from the group consisting of nitrogen (N 2 ) produced by a reverse osmosis membrane process, hydrogen (H 2 ), methane (CH 4 ), ethane (C 2 H 6 ), propane (C 3 H 8 ), butane (C 4 H 10 ), steam, air, oxygen, natural gas, and an inert gas. 
     
     
         12 . The method of  claim 10 , wherein the first injected pressure is no more than about 6,000 psi. 
     
     
         13 . The method of  claim 10 , wherein the injection rate of the first gas is no more than about four million scf/day. 
     
     
         14 . The method of  claim 10 , wherein the second gas comprises at least one fluid selected from the group consisting of nitrogen (N 2 ) produced by a cryogenic process, and carbon dioxide (CO 2 ). 
     
     
         15 . The method of  claim 10 , wherein the second injected pressure is more than about 6,000 psi. 
     
     
         16 . The method of  claim 15 , wherein the second injected pressure is between about 9,000 psi and about 12,500 psi. 
     
     
         17 . The method of  claim 10 , wherein the injection rate of the second gas is more than about four million scf/day. 
     
     
         18 . The method of  claim 10 , wherein at least one of the first gas and the second gas is in a form selected from the group consisting of a liquid, a gas, a foam, and a supercritical fluid. 
     
     
         19 . A method, comprising:
 determining at least one characteristic of a subterranean formation;   selecting, on the basis of the determined characteristic, an injection profile of a first gas and a second gas;   injecting the first gas into a first wellbore at least partly contained within the subterranean formation, according to the selected injection profile;   maintaining the first gas at a first injected pressure;   injecting a second gas into the first wellbore, according to the selected injection profile;   maintaining the second gas at a second injected pressure; and   injecting a fracturing liquid into a second wellbore different from the first wellbore at a sufficient pressure to fracture a target portion of the subterranean formation surrounding the second wellbore,   wherein the at least one characteristic of the subterranean formation comprises at least one characteristic selected from the group consisting of fracture volume of the first wellbore, fracture volume of the second wellbore, fracture volume of a third wellbore, distance between any two of the first, second, and third wellbores, the extent of fluid communication between any two of the first, second, and third wellbores, a mechanical characteristic, of the subterranean formation; pressure depletion, configuration of the first wellbore, configuration of the second wellbore, and configuration of the third wellbore.