Method of sand consolidation in petroleum reservoirs

1. A method of consolidating sands in a subterranean formation penetrated by a wellbore, the method comprising:

contacting sand particles in the subterranean formation with a treatment fluid to form coated sands; where the treatment fluid has a viscosity from 25 to 75 cP at 100 RPM and comprises a multicomponent epoxy, a base fluid, wherein the base fluid comprises water, and an amine hardening agent, the multicomponent epoxy comprising a di glycidyl ether resin and a monoglycidyl ether resin; and

allowing the amine hardening agent to cure the multicomponent epoxy and form the consolidated sands.

2. The method of claim 1 , in which the diglycidyl ether resin comprises a Bisphenol-A diglycidyl ether or a 1,6-hexanediol diglycidyl ether.

3. The method of claim 1 , in which the monoglycidyl ether resin comprises 2,3-epoxypropyl-o-tolyl ether.

4. The method of claim 1 , in which the monoglycidyl ether comprises a C12-C14 alkyl glycidyl ether resin.

5. The method of claim 1 , in which the amine hardening agent comprises diethylenetriamine (DETA), triethylenetetramine (TETA), isophoronediamine (IPDA), tetraethylenepentamine (TEPA), or a combination of these.

6. The method of claim 1 , in which the method further comprises contacting sand particles in the subterranean formation with one or more preflush solutions before contacting sand particles in the subterranean formation with the treatment fluid.

7. The method of claim 6 , in which at least one of the preflush solution is aqueous.

8. The method of claim 6 , in which the method further comprises contacting the consolidated sands with an overflush fluid and the overflush fluid is the same as the preflush fluid.

9. The method of claim 1 , in which the method further comprises isolating a treatment zone of the subterranean formation before contacting sand particles in the subterranean formation with one or more preflush solutions.

10. The method of claim 1 , in which the method further comprises displacing at least some liquid with in the oil bearing formation with brine before contacting sand particles in the subterranean formation with the treatment fluid.

11. The method of claim 1 , in which the method further comprises performing a step rate test on the oil bearing formation after isolating the treatment zone.

12. The method of claim 1 , in which the method further comprises contacting the consolidated sands with an overflush fluid after contacting sand particles in the subterranean formation with the treatment fluid.

13. The method of claim 12 , in which the overflush fluid is aqueous or nonaqueous.

14. The method of claim 1 , in which the method further comprises pumping a final displacement fluid into the subterranean formation after contacting sand particles in the subterranean formation with the treatment fluid.

15. The method of claim 1 , in which the method further comprises waiting a shut-in period after contacting sand particles in the subterranean formation with the treatment fluid, before returning the well to service.

16. The method of claim 1 , in which the treatment fluid penetrates at least 1 ft outside the wellbore into the formation.

17. The method of claim 1 , in which the treatment fluid comprises from 5 to 95 weight percent (wt. %) of the multicomponent epoxy when compared with the total weight of the treatment fluid.

18. The method of claim 1 , in which a weight ratio of diglycidyl ether resin:monoglycidyl ether resin in the multicomponent epoxy is from 1:100 to 99:1.

19. The method of claim 1 , in which a weight ratio of multicomponent epoxy:amine hardening agent is from 4:1 to 99:1.

20. The method of claim 1 , in which the subterranean formation contains less than or equal to 10 wt. % clay.