Method of treating a well and a subterranean formation with alkali nitrate brine
Brine-based well treatment compositions containing alkali nitrate exhibit greater thermal stability when used in deep wells than substantially similar brine-based well treatment compositions which do not contain an alkali nitrate. The brine is thickened with a water-soluble crosslinkable polymer and crosslinking agent. The enhanced thermal stability of the well treatment compositions allows use of the fluids at elevated temperatures, for instance as high as 400° F.
1. A method of treating a hydrocarbon-bearing subterranean formation which comprises pumping into a well penetrating the formation a well treatment fluid having a pH greater than or equal to 9.0, the well treatment fluid comprising an alkali nitrate brine having a density greater than or equal to 12.5 ppg at 70° F., a crosslinkable polymer selected from the group consisting of guar gum, hydroxyalkyl guar and carboxyalkylhydroxyalkyl guar and a crosslinking agent; wherein the viscosity of and thermal stability exhibited by the well treatment fluid at the downhole temperature is greater than the viscosity of and thermal stability exhibited by a substantially similar brine-based well treatment fluid which does not contain an alkali nitrate salt.
2. The method of claim 1 , wherein the alkali nitrate brine further comprises an alkali halide.
3. The method of claim 2 , wherein the alkali halide is sodium bromide.
4. The method of claim 2 , wherein the alkali nitrate brine is composed a 95:5 to 5:95 weight ratio of alkali nitrate:alkali halide.
5. The method of claim 1 , wherein the downhole temperature is in excess of 150° F.
6. The method of claim 5 , wherein the downhole temperature is in excess of 300° F.
7. The method of claim 6 , wherein the downhole temperature is in excess of 350° F.
8. The method of claim 1 , wherein the density of the alkali nitrate brine is between from about 12.5 to about 13.1 at 70° F.
9. The method of claim 1 , wherein the density of the well treatment fluid is greater than or equal to 12.8 ppg at 70° F.
10. The method of claim 8 , wherein the density of the well treatment fluid is 13.1 ppg at 70° F.
11. The method of claim 1 , wherein the brine-based well treating composition is pumped into a propagated fracture or into the subterranean formation at a pressure sufficient to fracture the formation.
12. The method of claim 11 , wherein the brine-based well treatment fluid further comprises a proppant.
13. The method of claim 1 , wherein the brine-based well treatment fluid further comprises a delayed internal breaker.
14. The method of claim 1 , wherein the well treatment composition further comprises a crosslinking delaying agent.
15. The method of claim 1 , wherein the alkali nitrate brine is a sodium nitrate brine.
16. A method for reducing the loss of fluids into flow passages of a subterranean formation during well drilling, completion, or workover operations which comprises introducing into the flow passages an effective amount of a well treatment composition having a pH greater than or equal to 9.0, the well treatment composition comprising a brine containing an alkali nitrate having a density greater than or equal to 12.5 ppg at 70° F., a crosslinkable polymer selected from the group consisting of guar gum, hydroxyalkyl guar and carboxyalkylhydroxylalkyl guar and a crosslinking agent and then viscosifying the well treatment composition, thereby reducing the loss of fluids into the flow passages upon resuming of the well drilling, completion or workover operation.
17. The method of claim 16 , wherein the well treatment composition reduces the loss of drilling fluids, completion fluids or workover fluids into the flow passages of the formation.
18. The method of claim 16 , wherein the alkali nitrate is sodium nitrate.
19. The method of claim 16 , wherein the density of the well treatment composition is greater than or equal to 12.8 ppg at 70° F.
20. A method of treating a well in communication with a subterranean formation penetrated by a wellbore which comprises:
(a) introducing a pumpable well treatment composition having a pH greater than or equal to 9.0, the well treatment composition comprising a sodium nitrate brine having a density greater than or equal to 12.5 ppg at 70° F.; a crosslinkable polymer selected from the group consisting of guar, hydroxypropyl guar and carboxyalkylhydroxyalkyl guar; and a crosslinking agent into the well;
(b) increasing the viscosity of the well treatment composition; and
(c) forming a fluid-impermeable barrier within the formation or within the wellbore from the composition resulting from step (b) and thereby reducing the permeability of the formation, mitigating loss of fluid into the formation and/or reducing fluid communication within the wellbore.