Methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove calcium carbonate and similar materials from the matrix of a formation or a proppant pack

Abstract

A method for treating a portion of a subterranean formation or a proppant pack is provided. In general, the method comprises the steps of: (A) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.

1 . A method for treating a portion of a subterranean formation or a proppant pack, the method comprising the steps of:
 (A) forming or providing a treatment fluid comprising:
 (i) water; 
 (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and 
 (iii) a viscosity-increasing agent, wherein the viscosity-increasing agent comprises a viscoelastic surfactant; and 
   (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.   
     
     
         2 . The method according to  claim 1 , wherein the pH of the treatment fluid is equal to or greater than 2. 
     
     
         3 . The method according to  claim 1 , wherein the pH of the treatment fluid is equal to or greater than 5. 
     
     
         4 . The method according to  claim 1 , wherein the pH of the treatment fluid is in the range of 6-12. 
     
     
         5 . The method according to  claim 1 , wherein the chelating agent is effective for chelating at least calcium ions. 
     
     
         6 . The method according to  claim 1 , wherein the chelating agent is soluble in distilled water at standard temperature and pressure at a concentration of at least 0.2 mole-equivalent for calcium ions per liter of the distilled water. 
     
     
         7 . The method according to  claim 6 , wherein a test solution of the chelating agent at a concentration of 0.2 mole-equivalent for calcium ions per liter of the distilled water is effective for chelating at least 0.1 mole calcium ions from calcium carbonate per liter. 
     
     
         8 . The method according to  claim 7 , wherein prior to exposing the test solution of the chelating agent to the calcium carbonate, the test solution is adjusted to have a pH in the range of 5-6. 
     
     
         9 . The method according to  claim 1 , wherein the chelating agent is selected from the group consisting of ethylenediamine tetraacetic acid (“EDTA”), nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid (“HEDTA”), diethylenetriaminepentaacetic acid (“DTPA”), propylenediaminetetraacetic acid (“PDTA”), ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), a sodium or potassium salt of any of the foregoing, dicarboxymethyl glutamic acid tetrasodium salt (“GLDA”), a derivative of any of the foregoing, or any combination of any of the foregoing in any proportion. 
     
     
         10 . The method according to  claim 1 , wherein chelating agent is at a concentration in the range of 1 to 80% by weight of the water. 
     
     
         11 . The method according to  claim 1 , wherein the viscoelastic surfactant is selected from the group consisting of: methyl ester sulfonates, sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols, lauryl alcohol ethoxylate, ethoxylated nonyl phenol, ethoxylated fatty amines, ethoxylated alkyl amines, cocoalkylamine ethoxylate, betaines, modified betaines, alkylamidobetaines, cocoamidopropyl betaine, quaternary ammonium compounds, trimethyltallowammonium chloride, trimethylcocoammonium chloride, an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl dimethylamine oxide, cocoamidopropyl hydroxysultaine, tallow dihydroxyethyl betaine, derivatives of any of the foregoing, and any combination of the foregoing in any proportion. 
     
     
         12 . The method according to  claim 1 , wherein the viscosity-increasing agent is at a concentration in the treatment fluid that is at least sufficient to make the viscosity of the treatment fluid greater than 5 cP when measured at 511 reciprocal seconds on a Fann 35A model viscometer with a number 1 spring and bob. 
     
     
         13 . The method according to  claim 1 , wherein the viscosity-increasing agent is at a concentration in the range of 0.05% to 10% by weight of the water. 
     
     
         14 . The method according to  claim 1 , wherein the treatment fluid further comprises a breaker adapted to break the viscosity-increasing agent. 
     
     
         15 . The method according to  claim 14 , further comprising the step of: after introducing the treatment fluid into the wellbore, allowing the viscosity of the treatment fluid to break to while down hole. 
     
     
         16 . The method according to  claim 1 , wherein the treatment fluid further comprises a breaker to be carried by the treatment fluid into the wellbore for breaking a viscosity-increasing agent that is external of the treatment fluid. 
     
     
         17 . The method according to  claim 1 , wherein the treatment fluid further comprises:
 an additive for foaming.   
     
     
         18 . The method according to  claim 1 , wherein the step of introducing the treatment fluid into the wellbore further comprises:
 introducing the treatment fluid at a rate and pressure below the fracture gradient of the subterranean formation.   
     
     
         19 . The method according to  claim 18 , wherein the portion to be treated is a portion of the subterranean formation surrounding the wellbore, and wherein the treatment fluid is introduced such that the portion of the formation surrounding the wellbore is expected to be saturated to a depth of at least 1 foot. 
     
     
         20 . The method according to  claim 18 , wherein the portion to be treated is a portion of the subterranean formation surrounding a pre-existing fracture extending into the formation, and wherein the treatment fluid is introduced such that the portion of the subterranean formation surrounding the pre-existing fracture is expected to be saturated to a depth of at least 0.1 inches. 
     
     
         21 . The method according to  claim 1 , further comprising the step of: after the step of introducing the treatment fluid, introducing a non-viscosified treatment fluid into the wellbore, wherein the non-viscosified treatment fluid comprises: water and a chelating agent, without any concentration of any viscosity-increasing agent. 
     
     
         22 . The method according to  claim 21 , wherein the injection pressure is maintained from the step of introducing the treatment fluid to the step of introducing the non-viscosified treatment fluid. 
     
     
         23 . A method for treating a portion of a subterranean formation or a proppant pack, the method comprising the steps of:
 (A) forming or providing a treatment fluid comprising:
 (i) water; 
 (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions, wherein the chelating agent is effective for chelating at least calcium ions, and wherein chelating agent is at a concentration in the range of 1% to 80% by weight of the water; and 
 (iii) a viscosity-increasing agent, wherein the viscosity-increasing agent comprises a viscoelastic surfactant; 
   wherein the pH of the treatment fluid is equal to or greater than 5; and   (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the formation or the proppant pack, wherein the portion to be treated is a portion of the subterranean formation surrounding a pre-existing fracture extending into the formation, and wherein the treatment fluid is introduced such that the portion of the subterranean formation surrounding the pre-existing fracture is expected to be saturated to a depth of at least 0.1 inches.