Solid incorporated reversible emulsion for a fracturing fluid

Abstract

Embodiments of this invention relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid comprising a reverse emulsion and a degradable material, introducing the fluid into a wellbore, and allowing the degradable material to degrade. Embodiments of this invention relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid comprising a reverse emulsion and a fluid loss additive, introducing the fluid into a wellbore, and allowing the fluid loss additive to degrade.

1 . A method for treating a subterranean formation permeated by a wellbore, comprising:
 forming a fluid comprising a reversible oil external emulsion and a degradable material;   introducing the fluid into a wellbore; and,   allowing the degradable material to degrade, whereby the emulsion is reversed.   
     
     
         2 . The method of  claim 1 , wherein the degradable material is poly glycolic acid, poly vinyl acetate, poly lactic acid, copolymers thereof, fumaric acid, or a combination thereof. 
     
     
         3 . The method of  claim 1 , wherein the degradable material is encapsulated. 
     
     
         4 . The method of  claim 1 , wherein the reverse emulsion comprises an amphoteric surfactant. 
     
     
         5 . The method of  claim 1 , wherein the introducing the fluid comprises at least one of fracturing, clean-up, stimulating, acidizing, scale removal, or fluid loss prevention along a surface of the wellbore and/or the subterranean formation. 
     
     
         6 . The method of  claim 1 , wherein the degradation of the material is controlled by a change in the pH of the fluid. 
     
     
         7 . The method of  claim 1 , wherein the allowing the material to degrade is controlled by the temperature of the wellbore and/or the subterranean formation. 
     
     
         8 . The method of  claim 1 , wherein the allowing the material to degrade is controlled by amount of time the degradable material is exposed to the emulsion or to formation fluid. 
     
     
         9 . The method of  claim 1 , wherein a concentration of the degradable material in the fluid is about 2 percent by weight or less. 
     
     
         10 . The method of  claim 1 , wherein a concentration of the degradable material in the fluid is about 3 percent by weight or less. 
     
     
         11 . The method of  claim 1 , wherein the fluid suspends a particle delivered to the formation at a target location. 
     
     
         12 . The method of  claim 1 , wherein the fluid suspends a particle whereby the emulsion is at least partially stabilized by the particle. 
     
     
         13 . A method for treating a subterranean formation permeated by a wellbore, comprising:
 forming a fluid comprising a reversible oil external emulsion and a fluid loss additive;   introducing the fluid into a wellbore; and,   allowing the fluid loss additive to degrade.   
     
     
         14 . The method of  claim 13 , wherein the fluid loss additive is poly glycolic acid, poly vinyl acetate, poly lactic acid, copolymers thereof, fumaric acid, or a combination thereof. 
     
     
         15 . The method of  claim 13 , wherein the fluid loss additive is encapsulated. 
     
     
         16 . The method of  claim 13 , wherein the reverse emulsion comprises an amphoteric surfactant. 
     
     
         17 . The method of  claim 13 , wherein the introducing the fluid comprises fracturing, clean-up, stimulating, and/or fluid loss preventing along a surface of the wellbore and/or the subterranean formation. 
     
     
         18 . The method of  claim 13 , wherein the allowing the fluid loss additive to degrade is controlled by change of fluid pH. 
     
     
         19 . The method of  claim 13 , wherein the allowing the fluid loss additive to degrade is controlled by the temperature of the wellbore and/or the subterranean formation. 
     
     
         20 . The method of  claim 13 , wherein the allowing the fluid loss additive to degrade is controlled by the time the degradable material is exposed to the reversible emulsion. 
     
     
         21 . The method of  claim 13 , wherein a concentration of the fluid loss additive in the fluid is about 2 percent by weight or less. 
     
     
         22 . The method of  claim 13 , wherein a concentration of the fluid loss additive in the fluid is about 3 percent by weight or less. 
     
     
         23 . The method of  claim 13 , wherein the fluid suspends a particle delivered to the formation at a target location. 
     
     
         24 . A method of fracturing a subterranean formation penetrated by a wellbore, the method comprising:
 forming a fluid comprising a reversible oil external emulsion, a degradable material, and a particle;   introducing the fluid into a wellbore at a pressure meeting or exceeding the fracture initiation pressure of the formation; and,   allowing the degradable material to degrade.