Fracturing fluids and methods for treating hydrocarbon-bearing formations

1. A method for treating a hydrocarbon-bearing formation comprising:

blending a carrier fluid with a copolymer, an oxidizing agent, and a reducing agent to form a fracturing fluid; the copolymer being a synthetic polymer, wherein the synthetic polymer comprises a labile group that is operative to facilitate decomposition of the synthetic polymer upon activation of the labile group, the labile group comprising ester groups, carbonate groups, azo groups, disulfide groups, orthoester groups, acetal groups, etherester groups, ether groups, silyl groups, phosphazine groups, urethane groups, esteramide groups, etheramide groups, anhydride groups, a derivative thereof, or a combination thereof; the oxidizing agent comprising a brominated compound; and the reducing agent comprising sodium erythorbate, iron sulfate, oxalic acid, formic acid, ascorbic acid, erythorbic acid, a compound comprising a metal ion wherein the metal ion is a copper ion, an iron ion, a tin ion, a manganese ion or a sulfur ion, or a combination comprising at least one of the foregoing; and the oxidizing agent and the labile group being selected such that the oxidizing agent is effective to activate the labile group and the activated labile group facilitates the decomposition of the synthetic polymer;

discharging the fracturing fluid into a downhole fracture in the hydrocarbon-bearing formation;

crosslinking the synthetic polymer in the fracturing fluid, the fracturing fluid having a viscosity of about 200 to about 3000 centipoises;

activating the labile group on the synthetic polymer with the oxidizing agent;

decomposing the synthetic polymer upon activation of the labile group to provide a decomposed polymer; and

removing the decomposed polymer from the hydrocarbon-bearing formation,

wherein the synthetic polymer is devoid of guar.

2. The method of claim 1 , further comprising adding a reducing agent to the fracturing fluid.

3. The method of claim 1 , further comprising adding a crosslinking agent to the fracturing fluid.

4. The method of claim 3 , wherein the crosslinking agent is present in an amount of 0.01 wt % to about 2.0 wt % based on the total weight of the fracturing fluid.

5. The method of claim 1 , wherein the synthetic polymer comprises polyacrylamide.

6. The method of claim 1 , wherein the fracturing fluid is free of a naturally occurring polymer.

7. The method of claim 1 , wherein the wherein the polymer is a water-soluble polymer.

8. The method of claim 1 , wherein the synthetic polymer has a number average molecular weight of about 2,000,000 to about 20,000,000 grams per mole.

9. The method of claim 1 , wherein the synthetic polymer is present in an amount of about 0.1 wt % to about 10 wt %, based on the total weight of the fracturing fluid.

10. The method of claim 1 , wherein the weight ratio of the oxidizing agent to the reducing agent is about 4:1 to about 12:1.

11. The method of claim 1 , wherein the fracturing fluid having a viscosity of about 1200 to about 3000 centipoises.

12. The method of claim 1 , wherein the oxidizing agent is sodium bromate.

13. The method of claim 1 , wherein the oxidizing agent is present in an amount from about 0.001 wt % to about 0.5 wt %, based on the total weight of the fracturing fluid, and the reducing agent is present in an amount from about 0.0006 wt % to about 0.12 wt %, based on the total weight of the fracturing fluid.

14. The method of claim 1 , wherein the oxidizing agent is present in an amount of about 0.02 wt. % to about 0.12 wt. %, the reducing agent is present in an amount of about 0.002 wt. % to about 0.012 wt. %, each based on the total weight of the fracturing fluid; and the weight ratio of the oxidizing agent to the reducing agent is about 1:1 to about 20:1.

15. The method of claim 1 , wherein the fracturing fluid further comprises a clay control agent or a breaker catalyst.

16. The method of claim 1 , wherein the reducing agent is iron sulfate.

17. The method of claim 1 , wherein the fracturing fluid further comprises acetyl triethyl citrate.

18. The method of claim 1 , wherein the acetyl triethyl citrate is included in the fracturing fluid in an amount of from about 0.0011 wt % to about 1.1 wt %, based on the total weight of the fracturing fluid.

19. A method for treating a hydrocarbon-bearing formation comprising:

blending a carrier fluid with a copolymer to form a fracturing fluid; the copolymer being a synthetic polymer, wherein the synthetic polymer comprises a labile group that is operative to facilitate decomposition of the synthetic polymer upon activation of the labile group, the labile group comprising ester groups, amide groups, carbonate groups, azo groups, disulfide groups, orthoester groups, acetal groups, etherester groups, ether groups, silyl groups, phosphazine groups, urethane groups, esteramide groups, etheramide groups, anhydride groups, a derivative thereof, or a combination thereof;

discharging the fracturing fluid into a downhole fracture in the hydrocarbon-bearing formation;

crosslinking the synthetic polymer in the fracturing fluid, the fracturing fluid having a viscosity of about 200 to about 3000 centipoises;

adding an oxidizing agent and a reducing agent to the fracturing fluid; wherein the oxidizing agent comprising a brominated compound; and the reducing agent comprising sodium erythorbate, iron sulfate, oxalic acid, formic acid, ascorbic acid, erythorbic acid, a compound comprising a metal ion wherein the metal ion is a copper ion, an iron ion, a tin ion, a manganese ion or a sulfur ion, or a combination comprising at least one of the foregoing; and the oxidizing agent and the labile group being selected such that the oxidizing agent is effective to activate the labile group and the activated labile group facilitates the decomposition of the synthetic polymer;

activating the labile group on the synthetic polymer with the oxidizing agent;

decomposing the synthetic polymer upon activation of the labile group to provide a decomposed polymer; and

removing the decomposed polymer from the hydrocarbon-bearing formation,

wherein the synthetic polymer is devoid of guar, and

the synthetic polymer is present in an amount of about 0.1 wt. % to about 10 wt. %, the oxidizing agent is present in an amount of about 0.02 wt. % to about 0.12 wt. %, and the reducing agent is present in an amount of about 0.002 wt. % to about 0.012 wt. %, each based on the total weight of the fracturing fluid; and the weight ratio of the oxidizing agent to the reducing agent is about 4:1 to about 12:1.

20. The method of claim 19 , wherein the fracturing fluid further comprises acetyl triethyl citrate in an amount of from about 0.011 wt % to about 0.55 wt %, based on the total weight of the fracturing fluid.

21. The method of claim 19 , wherein the fracturing fluid reaches its maximum viscosity within 10 to 40 seconds after introduction of the synthetic polymer into the carrier fluid.