Low temperature diversion in well completion operations using natural mineral compound
Treatment fluids for use in fluid loss control, diversion, and plugging operations and methods of use are disclosed. The treatment fluids contain a degradable particular langbeinite material that temporarily creates a physical barrier to fluid flow before degrading over time with little to no effect on the environment. This degradable additive can be combined with other traditional downhole additives such as surfactants, viscosifying agents, biocides and the like, allowing for a wide variety of applications in hydrocarbon reservoirs.
1. A method of plugging an opening in a subterranean formation comprising:
a) injecting a treatment fluid comprising a carrier fluid and a particulate langbeinite material into a subterranean formation;
b) blocking at least one opening in said subterranean formation with the particulate langbeinite material, wherein the langbeinite material has a particle size from 4 mesh to 150 mesh on the U.S. Sieve Series scale; and
c) allowing the particulate langbeinite material to degrade; and,
d) flowing a fluid through the at least one opening.
2. The method of claim 1 , wherein said particulate langbeinite material is selectively degraded by injecting an acid treatment fluid into the subterranean formation.
3. The method of claim 1 , wherein said opening is an annulus, casing, tubing, screens, slots, ports, a void space within a sand or proppant pack, perforations, washouts, hole, an opening in a downhole tool, a parting in the casing or tubing, a natural fracture, vug, wormhole, pore throat, induced fracture, formation face, or a combination thereof.
4. The method of claim 1 , wherein said degrading takes between about 3 to about 14 hours.
5. The method of claim 1 , wherein the bottom hole temperature of the wellbore is between 75° F. (−23° C.) and 140° F. (−60° C.).
6. The method of claim 1 , wherein the particle size of said particulate langbeinite material is from 12-14 mesh on the U.S. Sieve Series scale or from about 5 to about 50 microns.
7. The method of claim 1 , further comprising injecting a hydrochloric acid solution and soaking the particulate langbeinite material in said hydrochloric acid solution until the particulate langbeinite material degrades completely.
8. The method of claim 1 , wherein said particulate langbeinite material is present in an amount between about 50 pounds per thousand gallons (pptg) of the carrier fluid and about 400 pptg of the carrier fluid.
9. The method of claim 1 , further comprising at least one additive selected from a group comprising salts, viscosifying agents, pH control additives, surfactants, breakers, biocides, crosslinkers, additional fluid loss control agents, stabilizers, chelating agents, scale inhibitors, gases, mutual solvents, particulates, corrosion inhibitors, oxidizers, reducers, friction reducer, and any combination thereof.
10. The method of claim 1 , further comprising alternating injections of an acid treatment fluid with injections of said treatment fluid.
11. The method of claim 1 , wherein the opening is a porous section of said subterranean formation, wherein the treatment fluid is injected at fracturing pressures to fracture the subterranean formation and the particulate langbeinite material blocks the porous section to stop fluid loss in the porous section.
12. A method of plugging a conduit, comprising
a) injecting a plug molded from a composition comprising a particulate langbeinite material into a subterranean formation, wherein the langbeinite material has a particle size from 4 mesh to 150 mesh on the U.S. Sieve Series scale;
b) blocking a passage in said subterranean formation with the plug;
c) allowing the particulate langbeinite material in the plug to degrade; and,
d) flowing a fluid or downhole tool through the passage.
13. The method of claim 12 , further comprising injecting an acidic fluid to selectively degrade the particulate langbeinite material.