Use of reactive solids and fibers in wellbore clean-out and stimulation applications

Abstract

A method and apparatus to treat a subterranean formation including introducing a fluid comprising degradable material into a wellbore, contacting a surface of the wellbore with the fluid, and stimulating a surface of a subterranean formation, wherein the contacting the wellbore surface and stimulating the formation occur over a time period that is tailored by the properties of the degradable material. In some embodiments, the properties of the degradable material include a chemical composition, a surface area, a geometric shape of a particle of the material, a concentration of the material in the fluid, a density of the material, a dimension of a particle of the material, or a combination thereof.

1 . A method for treating a subterranean formation, comprising:
 introducing a fluid comprising degradable material into a wellbore;   contacting a surface of the wellbore with the fluid; and   stimulating a surface of a subterranean formation,   wherein the contacting the wellbore surface and stimulating the formation occur over a time period that is tailored by the properties of the degradable material.   
     
     
         2 . The method of  claim 1 , wherein the properties of the degradable material comprise a chemical composition, a surface area, a geometric shape of a particle of the material, a concentration of the material in the fluid, a density of the material, a dimension of a particle of the material, or a combination thereof. 
     
     
         3 . The method of  claim 1 , further comprising allowing the degradable material to degrade. 
     
     
         4 . The method of  claim 3 , wherein the degradable material releases acid as it degrades. 
     
     
         5 . The method of  claim 1 , wherein the surface of the subterranean formation comprises carbonate. 
     
     
         6 . The method of  claim 1 , wherein the surface of the wellbore comprises carbonate. 
     
     
         7 . The method of  claim 1 , wherein the time period is 48 hours or less. 
     
     
         8 . The method of  claim 1 , wherein the time period is 48 hours or more. 
     
     
         9 . The method of  claim 1 , wherein the time period is 72 hours or more. 
     
     
         10 . The method of  claim 1 , wherein the time period is 12 days or more. 
     
     
         11 . The method of  claim 1 , wherein the fluid comprises water. 
     
     
         12 . The method of  claim 1 , wherein the fluid comprises oil. 
     
     
         13 . The method of  claim 1 , wherein the fluid further comprises surfactant. 
     
     
         14 . The method of  claim 13 , wherein the surfactant comprises viscoelastic surfactant. 
     
     
         15 . The method of  claim 14 , wherein the viscoelastic surfactant comprises betaine. 
     
     
         16 . The method of  claim 1 , wherein the fluid comprises corrosion inhibitor. 
     
     
         17 . The method of  claim 1 , wherein the fluid comprises mutual solvent. 
     
     
         18 . The method of  claim 1 , wherein the degradable material is a chelating agent. 
     
     
         19 . The method of  claim 1 , wherein the degradable material has an amount of particulates with average particle size and a second amount of particulates with a second average particle size, wherein the second average particle size is between three to twenty times smaller than the first average particle size. 
     
     
         20 . The method of  claim 19 , wherein the second average particle size is between five to ten times smaller than the first average particle size. 
     
     
         21 . The method of  claim 19 , wherein the degradable material has a further amount of particulates having a third average particle size, wherein the third average particle size is between three to twenty times smaller than the second average particle size. 
     
     
         22 . The method of  claim 21 , wherein the third average particle size is between five to ten times smaller than the second average particle size. 
     
     
         23 . The method of  claim 19 , wherein the wellbore further comprises a screen. 
     
     
         24 . The method of  claim 1 , wherein the fluid further comprises calcium carbonate particles. 
     
     
         25 . The method of  claim 1 , wherein the fluid comprises corrosion inhibitor, mutual solvent, surfactant. 
     
     
         26 . The method of  claim 1 , wherein the temperature of the formation is 150 degF or higher. 
     
     
         27 . The method of  claim 1 , wherein the pH of the fluid while introducing a fluid comprising degradable material into a wellbore is 5 to 8. 
     
     
         28 . A method for treating a subterranean formation, comprising:
 introducing a fluid comprising degradable material and oleaginous fluid into a wellbore;   contacting a surface of the wellbore with the fluid; and   stimulating a surface of a subterranean formation,   wherein the contacting the wellbore surface and stimulating the formation occur over a time period that is tailored by the properties of the degradable material.   
     
     
         29 . A method for forming a filtercake in a subterranean formation, comprising:
 introducing a fluid comprising degradable material and oleaginous phase into a wellbore;   contacting a surface of the wellbore with the fluid; and   stimulating a surface of a subterranean formation,   wherein the contacting the wellbore surface and stimulating the formation occur over a time period that is tailored by the properties of the degradable material.