Method of Increasing the Permeability of a Subterranean Formation by Creating a Multiple Fracture Network

Abstract

The stimulated rock volume (SRV) of a subterranean formation may be increased by pumping viscous fracturing fluid into the formation in a first stage to create or enlarge a primary fracture, decreasing the pumping in order for the fluid to increase in viscosity within the primary fracture, and then continuing to pump viscous fluid into the formation in a second stage. The fluid pumped into the second stage is diverted away from the primary fracture and a secondary fracture is created. The directional orientation of the secondary fracture is distinct from the directional orientation of the primary fracture. The fluid of the first stage may contain a viscosifying polymer or viscoelastic surfactant or may be slickwater.

What is claimed is: 
     
         1 . A method for improving the recovery of hydrocarbons from a subterranean reservoir having a permeability less than 0.1 mD which comprises:
 (a) pumping a fluid into the subterranean reservoir at a pressure sufficient to enlarge or create a primary fracture, wherein the fluid has a viscosity greater than about 10,000 cP at a shear rate of 0.01 sec −1  and further wherein the fluid contains a viscoelastic surfactant and/or a viscosifying polymer;   (b) stopping the pumping when the viscous fluid is within the enlarged or created primary fracture;   (c) pumping additional fluid having a viscosity greater than about 10,000 cP at a shear rate of 0.01 sec −1  into the subterranean reservoir at a pressure sufficient to create at least one secondary fracture, wherein the least one secondary fracture is has a directional orientation distinct from the directional orientation of the primary fracture; and   (d) diverting the flow of the additional fluid of step (c) into the at least one secondary fracture.   
     
     
         2 . The method of  claim 1 , further comprising:
 (e) stopping the pumping of the additional fluid; and   
       further wherein steps (c), (d) and (e) are continuously repeated for a time sufficient to create a multiple fracture network consisting of the primary fracture and a multitude of secondary fractures. 
     
     
         3 . The method of  claim 1 , wherein the viscosity of the viscous fluid is between from about 10,000 cP to about 2,000,000 cP at a shear rate of 0.01 sec −1 . 
     
     
         4 . The method of  claim 3 , wherein the viscosity of the viscous fluid of step (a) and the additional fluid of step (c) is the same. 
     
     
         5 . The method of  claim 2 , wherein the additional fluid of step (c) is the same for each repetition of step (c). 
     
     
         6 . The method of  claim 2 , wherein the additional fluid of step (c) is the same as the viscous fluid of step (a). 
     
     
         7 . The method of  claim 1 , wherein the viscous fluid of step (a) enlarges a created primary fracture and further wherein a pad fluid is pumped into the subterranean reservoir prior to step (a) in order to initiate the primary fracture. 
     
     
         8 . The method of  claim 1 , wherein the viscous fluid of step (a) and/or the additional fluid of step (c) contains a viscoelastic surfactant as viscosifying agent. 
     
     
         9 . The method of  claim 8 , wherein the viscous fluid further contains an internal breaker. 
     
     
         10 . The method of  claim 8 , wherein the viscous fluid further contains a low shear rate viscosity enhancer. 
     
     
         11 . The method of  claim 10 , wherein the viscosity enhancer is a wormlike micelle associative agent. 
     
     
         12 . The method of  claim 1 , wherein the viscous fluid of step (a) and/or the additional fluid of step (c) contains proppants. 
     
     
         13 . The method of  claim 1 , wherein the viscous fluid of step (a) and/or the additional fluid of step (c) contains a polymeric viscosifying agent. 
     
     
         14 . The method of  claim 13 , wherein the viscous fluid and/or additional fluid, in addition to containing a polymeric viscosifying agent, further contains a crosslinking agent. 
     
     
         15 . The method of  claim 13 , wherein the amount of polymeric viscosifying agent in the viscous fluid is less than or equal to 6% by weight. 
     
     
         16 . The method of  claim 1 , wherein the pressure in step (a) and step (c) is approximately the same. 
     
     
         17 . The method of  claim 1 , wherein the pressure in step (c) is greater than the pressure in step (a). 
     
     
         18 . The method of  claim 1 , wherein the injection rate of the additional fluid pumped into the subterranean reservoir in step (c) is greater than the injection rate of the viscous fluid pumped into the subterranean reservoir in step (a). 
     
     
         19 . A method of fracturing a subterranean formation penetrated by a wellbore by creating a network of fractures at near-wellbore and far-wellbore locations wherein the subterranean formation has a permeability less than 0.1 mD, the method comprising the following sequential steps:
 (a) injecting into the subterranean reservoir a fracturing fluid having a viscosity greater than about 10,000 cp at a shear rate of 0.01 sec −1  at a pressure sufficient to enlarge or create a primary fracture;   (b) decreasing the rate of injection of the fracturing fluid for a time sufficient for the viscosity of the fracturing fluid to increase within the created or enlarged fracture;   (c) injecting additional fracturing fluid into the subterranean reservoir to create one or more secondary fractures, wherein the additional fracturing fluid diverts away from the primary fracture and into the one or more secondary fractures;   (d) repeating steps (b) and (c) at least twice; and   (e) forming a network of secondary fractures at near-wellbore and far-wellbore locations from the primary fracture and the secondary fractures.   
     
     
         20 . The method of  claim 19 , wherein at least one of the following conditions prevail:
 (i) the rate of injection of the additional fracturing fluid of step (c) is different from the rate of injection of the fracturing fluid of step (a);   (ii) the viscosity of the additional fracturing fluid of step (c) is different from the viscosity of the fracturing fluid of step (a); or   (iii) the amount of pressure used to inject the additional fracturing fluid of step (c) is different from the pressure used to inject the fracturing fluid of step (a).   
     
     
         21 . The method of  claim 19 , wherein the fracturing fluid of step (a) and/or the additional fracturing fluid of step (c) contains proppants. 
     
     
         22 . The method of  claim 21 , wherein the particle size of the proppants in the fracturing fluid of step (a) is less than the particle size of the proppants in the additional fracturing fluid of step (c). 
     
     
         23 . The method of  claim 21 , wherein the size of the proppants range from 12 microns to 4 millimeters. 
     
     
         24 . The method of  claim 23 , wherein the injection of the fracturing fluid is stopped in step (b) for a time sufficient for the viscosity of the fracturing fluid to increase within the created or enlarged fracture. 
     
     
         25 . A fracturing operation for recovering hydrocarbons from a subterranean reservoir penetrated by a wellbore, wherein the subterranean reservoir has a permeability less than 0.1 mD which comprises:
 (a) pumping a fluid into the subterranean reservoir at a pressure sufficient to enlarge or create a primary fracture in the reservoir wherein the fluid has a viscosity greater than about 10,000 cP at a shear rate of 0.01 sec −1 ;   (b) temporarily stopping the pumping when the viscous fluid is within the primary fracture;   (c) resuming the pumping of the fluid; and   (d) diverting the flow of the fluid pumped in step (c) away from the primary fracture to create one or more secondary fractures in the subterranean reservoir.   
     
     
         26 . The method of  claim 25 , further comprising continuously repeating steps (a), (b), (c) and (d). 
     
     
         27 . The method of  claim 25 , wherein the fracture growth of the total surface area connected to the wellbore after step (d) is greater than the total surface area connected to the wellbore after step (a). 
     
     
         28 . The method of  claim 25 , wherein the viscosity of the fluid and/or pumping pressure of the fluid in steps (a) and (c) is the same. 
     
     
         29 . The method of  claim 25 , wherein the viscosity of the fluid and/or pumping pressure of the fluid in step (a) is greater than the viscosity of the fluid in step (c). 
     
     
         30 . The method of  claim 25 , wherein the viscosity and/or pressure of the fluid in each of repeating steps (a) and (c) in the fracturing operation decreases with each repetition. 
     
     
         31 . The method of  claim 25 , wherein the viscosity and/or pressure of the fluid in step (a) is less than the viscosity of the fluid in step (c). 
     
     
         32 . The method of  claim 26 , wherein the viscosity and/or pressure of the fluid in each of repeating steps (a) and (c) in the fracturing operation increases with each repetition. 
     
     
         33 . The method of  claim 25 , wherein the fluid pumped into the wellbore contains a viscosifying polymer. 
     
     
         34 . The method of  claim 25 , wherein prior to pumping of the pad fluid, a slickwater fluid having a viscosity less than or equal to 15 cP at a shear rate of 300 sec −1  is pumped into the subterranean reservoir. 
     
     
         35 . The method of  claim 34 , wherein the amount of slickwater fluid is between from 10 to 60 volume percent of the combination of slickwater fluid, pad fluid and viscous fluid.