Methods and materials for hydraulic fracturing
Compositions and methods are provided for treatment of a wellbore in a subterranean formation. Exemplary compositions comprise a mixture of particles, some of the particles being degradable and other particles being elongated, having good compressive strength, and not being readily degradable at the conditions of the formation. The mixture of particles can temporarily bridge or plug fractures within the formation, and thus acts as a temporary diversion agent. After the degradable particles dissolve, the particles which are not readily degradable can remain in the fracture, helping to keep the fracture open and acting as a proppant.
1. A method for treatment of a wellbore in fractured subterranean formation, the method comprising the steps of:
a. introducing into the wellbore a treatment fluid comprising:
i) 5 to 20 wt % of a first type of particle, the first type of particle having a particle size from 2 mm to 3.5 mm and comprising a first degradable material;
ii) 5 to 20 wt % of a second type of particle, the second type of particle having a particle size less than or equal to 0.6 mm and comprising a second degradable material; and
iii) 60 to 90 wt % of a third type of particle, the third type of particle being elongated in shape, having a width from 0.7 mm to 1.2 mm, having a length from 1.5 to 5 times the width, and comprising a ceramic material;
iv) a fourth type of particle, the fourth type of particle being a flake, and having a width of about 0.10 in to 0.5 in, a length of about 0.08 in to about 0.2 in, and a thickness of about 0.01 in to 0.02 in; and
v) a carrier fluid; and
b. forming a plug to seal at least one fracture in the fractured subterranean formation, the plug comprising particles of the first, second, third, and fourth type.
2. The method of claim 1 , wherein the particle size of the first type of particle is greater than 2.3 mm to less than 3.4 mm.
3. The method of claim 1 , wherein the particle size of the second type of particle is less than or equal to 0.5 mm.
4. The method of claim 1 , wherein the width of the third type of particle is from 0.8 mm to 1.4 mm.
5. The method of claim 1 , wherein the first and the second degradable material is each a polymeric material.
6. The method of claim 5 , wherein the specific gravity of the polymeric material is from 1.0 g/cc to 1.7 g/cc.
7. The method of claim 6 , wherein the polymeric material is selected from the group consisting of polylactic acid, polyglycolic acid, polyhdoxybutyrate, polyepsilon caprolactone and copolymers thereof.
8. The method of claim 1 wherein the specific gravity of the ceramic material is from 3.0 g/cc to 3.98 g/cc.
9. The method of claim 1 , wherein the third type of particle is rod shaped.
10. The method of claim 1 , wherein the treatment fluid includes from 0.1-0.5 pounds per gallon of the combination of the first, second and third type of particle.
11. The method of claim 1 , wherein the carrier fluid is water-based.
12. The method of claim 1 , wherein the carrier fluid is oil-based.
13. A method for treatment of a wellbore in fractured subterranean formation, the method comprising the steps of:
a. introducing into the wellbore a treatment fluid comprising:
i) 5 to 20 wt % of a first type of particle, the first type of particle having a particle size from 2 mm to 3.5 mm and comprising a first degradable material;
ii) 5 to 20 wt % of a second type of particle, the second type of particle having a particle size less than or equal to 0.6 mm and comprising a second degradable material; and
iii) 60 to 90 wt % of a third type of particle, the third type of particle being elongated in shape, having a width from 0.7 mm to 1.2 mm, having a length from 1.5 to 5 times the width, and comprising a ceramic material, the ceramic material comprising aluminum oxide; and
iv) a carrier fluid; and
b. forming a plug to seal at least one fracture in the fractured subterranean formation, the plug comprising particles of the first, second and third type.
14. The method of claim 13 , wherein the ceramic material comprises at least 80% aluminum oxide.
15. The method of claim 13 , wherein the particle size of the first type of particle is greater than 2.3 mm to less than 3.4 mm.
16. The method of claim 13 , wherein the particle size of the second type of particle is less than or equal to 0.5 mm.
17. The method of claim 13 , wherein the width of the third type of particle is from 0.8 mm to 1.4 mm.
18. The method of claim 13 , wherein the first and the second degradable material is each a polymeric material.
19. The method of claim 18 , wherein the specific gravity of the polymeric material is from 1.0 g/cc to 1.7 g/cc.
20. The method of claim 19 , wherein the polymeric material is selected from the group consisting of polylactic acid, polyglycolic acid, polyhdoxybutyrate, polyepsilon caprolactone and copolymers thereof.
21. The method of claim 13 wherein the specific gravity of the ceramic material is from 3.0 g/cc to 3.98 g/cc.
22. The method of claim 13 , wherein the third type of particle is rod shaped.
23. The method of claim 13 , wherein the treatment fluid includes from 0.1-0.5 pounds per gallon of the combination of the first, second and third type of particle.
24. The method of claim 13 , wherein the carrier fluid is water-based.
25. The method of claim 13 , wherein the carrier fluid is oil-based.