Fracturing method using a low-viscosity fluid with low proppant settling rate

Abstract

A fluid design with enhanced proppant-carrying capacity utilizes a low-viscosity fluid with high proppant carrying capacity and low required power for injection into a hydrocarbon-bearing, subterranean formation. A preferred viscosifying agent that comprises a copolymer polymerized from an acrylic acid monomer and a monomer selected from: a) at least one carboxylic acid monomer; b) at least one C1 to C5 alkyl ester and/or at least one C1 to C5 hydroxyalkyl ester of acrylic acid or methacrylic acid; c) one crosslinking monomer; and optionally d) at least one α,β-ethylenically unsaturated monomer, may be used to produce a fracturing fluid that has the pumpability of a slick water fluid and the proppant-carrying ability of a cross-linked gel. An optimization process to optimize hydraulic fracture design evaluates and quantifies the proppant-carrying capacity of the invented fluid and its impact in the proppant transport during fracturing.

1 . A viscosifying agent for a hydraulic fracturing fluid comprising:
 a copolymer polymerized using two different monomers wherein the first monomer is an acrylic acid monomer and the second monomer is selected from the group consisting of
 a) a carboxylic acid monomer, 
 b) a C 1  to C 5  alkyl ester and/or a C 1  to C 5  hydroxyalkyl ester of acrylic acid or methacrylic acid, and 
 c) a crosslinking monomer. 
   
     
     
         2 . The viscosifying agent recited in  claim 1  further comprising at least one α,β-ethylenically unsaturated monomer selected from the group consisting of:
   CH 2 ═C(R)C(O)OR 1  
 
 where R is selected from hydrogen or methyl and R 1  is selected from C 6 -C 10  alkyl, C 6  to C 10  hydroxyalkyl, —(CH 2 ) 2 OCH 2 CH 3 , and —(CH 2 ) 2 C(O)OH and salts thereof.
   CH 2 ═C(R)X
 
 
 where R is hydrogen or methyl; and X is selected from —C 6 H 5 , —CN, —C(O)NH 2 , —NC 4 H 6 O, —C(O)NHC (CH 3 ) 3 , —C(O)N(CH 3 ) 2 , —C(O)NHC(CH 3 MCH 2 ) 4 CH 3 , and —C(O)NHC(CH 3 ) 2 CH 2 S(O)(O)OH and salts thereof.
   CH 2 ═CHOC(O)R 1  
 
 
 where R 1  is a linear or branched C 1 -C 18  alkyl; and
   CH 2 ═C(R)C(O)OAOR 2  
 
 
 where A is a divalent radical selected from —CH 2 CH(OH)CH 2 —, and —CH 2 CH(CH 2 OH)—, R is selected from hydrogen or methyl, and R 2  is an acyl residue of a linear or branched, saturated or unsaturated C 10  to C 22  fatty acid. 
 
     
     
         3 . The viscosifying agent recited in  claim 2  wherein the at least one α,β-ethylenically unsaturated monomer comprises about 1% to about 35% by weight of the copolymer. 
     
     
         4 . The viscosifying agent recited in  claim 1  wherein the carboxylic acid monomer is selected from the group consisting of acrylic acid, methacrylic acid, itaconic acid, fumaric acid, crotonic acid, aconitic acid, maleic acid, and combinations thereof. 
     
     
         5 . The viscosifying agent recited in  claim 1  wherein the carboxylic acid monomer comprises about 20% to about 80% by weight of the copolymer. 
     
     
         6 . The viscosifying agent recited in  claim 1  wherein the C 1  to C 5  alkyl ester and/or a C 1  to C 5  hydroxyalkyl ester of acrylic acid or methacrylic acid comprises about 80% to about 15% by weight of the copolymer. 
     
     
         7 . The viscosifying agent recited in  claim 1  wherein the C 1  to C 5  alkyl ester is a C 1  to C 5  hydroxyalkyl ester of acrylic acid. 
     
     
         8 . The viscosifying agent recited in  claim 1  wherein the C 1  to C 5  alkyl ester is a C 1  to C 5  hydroxyalkyl ester of methacrylic acid. 
     
     
         9 . The viscosifying agent recited in  claim 1  wherein the crosslinking monomer comprises about 0.01% to about 5% by weight of the copolymer. 
     
     
         10 . The viscosifying agent recited in  claim 1  wherein the copolymer is a random copolymer. 
     
     
         11 . The viscosifying agent recited in  claim 1  wherein acrylic acid is the predominant monomer in the copolymer. 
     
     
         12 . The viscosifying agent recited in  claim 1  wherein the molecular weight of the copolymer is about 1×10 9  Daltons. 
     
     
         13 . The viscosifying agent recited in  claim 1  wherein the molecular weight of the copolymer is at least 1×10 9  Daltons. 
     
     
         14 . The viscosifying agent recited in  claim 1  wherein the molecular weight of the copolymer is greater than 1×10 9  Daltons. 
     
     
         15 . A method of hydraulically fracturing a subterranean formation comprising:
 suspending a proppant in a fluid comprising a viscosifying agent comprising a copolymer polymerized using two different monomers wherein the first monomer is an acrylic acid monomer and the second monomer is selected from the group consisting of
 a) a carboxylic acid monomer, 
 b) a C 1  to C 5  alkyl ester and/or a C 1  to C 5  hydroxyalkyl ester of acrylic acid or methacrylic acid, and 
 c) a crosslinking monomer; and 
   injecting the fluid comprising the viscosifying agent and suspended proppant into the formation.   
     
     
         16 . The method recited in  claim 15  further comprising:
 injecting a breaker into the formation; and 
 recovering at least a portion of the fracturing fluid by flow back. 
 
     
     
         17 . The method recited in  claim 16  wherein the breaker is an oxidative breaker. 
     
     
         18 . The method recited in  claim 17  wherein the breaker is selected from the group consisting of ammonium persulfate and peroxide breakers. 
     
     
         19 . A method for hydraulically fracturing a hydrocarbon-producing subterranean formation comprising:
 ranking candidate wells or well sections for hydraulic fracturing;   performing numerical analysis to quantify and assess the proppant-carrying capacity of a selected fracturing fluid;   selecting the fracturing parameters; and   delivering the fracturing fluid to the formation at the selected fracturing parameters.   
     
     
         20 . The method recited in  claim 19  wherein selecting the fracturing parameters comprises selecting a fracturing fluid, a proppant type, a proppant concentration, and a pumping rate. 
     
     
         21 . The method recited in  claim 19  wherein ranking candidate wells or well sections comprises a consideration of one or more factors selected from the group consisting of reservoir depth, pore pressure gradient, porosity, permeability, TOC, water saturation, Young's modulus, Poisson's ratio, rock strength, cohesion and shmin gradient. 
     
     
         22 . The method recited in  claim 19  further comprising performing numerical analysis to quantify the proppant-carrying capacity of the fracturing fluid. 
     
     
         23 . The method recited in  claim 19  further comprising performing numerical analysis to quantify the proppant-carrying capacity of the fracturing fluid with respect to fluid viscosity and density. 
     
     
         24 . The method recited in  claim 19  further comprising performing numerical analysis to quantify the proppant-carrying capacity of the fracturing fluid with various proppant types and concentrations. 
     
     
         25 . The method recited in  claim 19  wherein selecting the fracturing parameters, comprises:
 performing a simulation to predict the hydraulic fracture propagation, fracture height growth and natural fracture reactivation; 
 performing a simulation to model the proppant transport within both main hydraulic fractures and a reactivated natural fracture network; 
 performing a simulation to assess the proppant embedment and crush and fracture surface closure behavior during production; 
 performing a simulation to forecast the production efficiency; and 
 choosing a best stimulation design by a comparison of the predicted result corresponding to a typical design plan, 
 wherein fracturing parameters of the planned stimulation operations are optimized based upon the extent of conductive reservoir volume and production efficiency. 
 
     
     
         26 . The method recited in  claim 25 , wherein the fracturing parameters include a modified pumping schedule. 
     
     
         27 . The method recited in  claim 26 , wherein the modified pumping schedule includes changing an injection time, rate, proppant type and fluid properties. 
     
     
         28 . The method recited in  claim 27 , wherein the fluid properties includes viscosity and density affecting the proppant transport process. 
     
     
         29 . The method recited in  claim 27 , wherein the change of fluid properties and its impact on the proppant carrying capacity is quantified or estimated by numerical analysis. 
     
     
         30 . The method recited in  claim 19  wherein selecting the fracturing parameters is performed with respect to a certain geological condition using an integrated fluid-geomechanics workflow.