Heterogeneous proppant placement in a fracture with removable channelant fill

Patent metadata

Field	Value
Publication number	US-9670764-B2
Application number	US-201414313831-A
Country	US
Kind code	B2
Filing date	Jun 24, 2014
Priority date	Dec 8, 2006
Publication date	Jun 6, 2017
Grant date	Jun 6, 2017

Abstract

A method of heterogeneous proppant placement in a subterranean fracture is disclosed. The method comprises injecting well treatment fluid including proppant ( 16 ) wherein the proppant comprises from 1 to 100 percent in weight of stiff, low-elasticity and low-deformability elongated particles ( 34 ) and proppant-spacing filler material called a channelant ( 18 ) through a wellbore ( 10 ) into the fracture ( 20 ), heterogeneously placing the proppant in the fracture in a plurality of proppant clusters or islands ( 22 ) spaced apart by the channelant ( 24 ), and removing the channelant filler material ( 24 ) to form open channels ( 26 ) around the pillars ( 28 ) for fluid flow from the formation ( 14 ) through the fracture ( 20 ) toward the wellbore ( 10 ). The proppant and channelant can be segregated within the well treatment fluid, or segregated during placement in the fracture. The channelant can be dissolvable particles, initially acting as a filler material during placement of the proppant in the fracture, and later dissolving to leave the flow channels between the proppant pillars. The well treatment fluid can include fibers to provide reinforcement and consolidation of the proppant and, additionally or alternatively, to inhibit settling of the proppant in the treatment fluid.

First claim

What is claimed is:

1. A method of placing a proppant pack into a fracture formed in a subterranean formation, the method comprising:
injecting well treatment fluid comprising proppant and channelant through a wellbore into a fracture in a subterranean formation, wherein the proppant comprises from 1 to 100 percent in weight of stiff, low-elasticity and low-deformability elongated particles;
placing the proppant in the fracture in a plurality of proppant clusters forming pillars spaced apart by the channelant; and
removing the channelant to form open channels around the pillars for fluid flow from the formation through the fracture toward the wellbore;
where the treatment fluid comprises alternating volumes of proppant rich fluid with the particles form 1 to 100 percent in weight separated by volumes containing the channelant.

2. The method of claim 1 , wherein the elongated particles have a maximal cross-sectional dimension, h 1 , and a minimal cross-sectional dimension, h 2 , of from 0.1 to 10 mm; a length, L, of from 0.1 to 20 mm; for 1D particles, a ratio L/h 1 from 1.2 to 10 and a ratio h 2 /h 1 from 0.8 to 1; for 2D particles, a ratio L/h 1 from 1 to 1.19 and a ratio h 2 /h 1 from 0.1 to 0.79; a curvature, χ, of from 0 to 2/h 2 in units of 1/mm; for 1D particles, a stiffness, k, of from 0 to 4.90•10 8 in units of N-mm 2 ; and for cylindrical particles, a stiffness, k, of from 0 to 10 8 N-mm 2 ; a range of a particle unevenness d 0 (or d 1 ) is from 0 to 0.5*h 1 in units of mm.

3. The method of claim 2 , wherein the elongated particles comprise a mixture of elongated particles differing from one another in at least one parameter selected from the group consisting of length, a cross-sectional dimension, density, curvature, and stiffness.

4. The method of claim 1 wherein the channelant comprises solid particles.

5. The method of claim 4 comprising segregating the proppant and channelant during injection of the well treatment fluid.

6. The method of claim 4 wherein the channelant particles are maintained in a solid state within the fracture.

7. The method of claim 1 wherein the injection comprises:
injecting a proppant-lean carrier stage to initiate the fracture; and
thereafter injecting into the fracture proppant and channelant.

8. The method of claim 1 , wherein the injection further comprises injecting a tail-in stage to form a permeable proppant pack in the fracture between the open channels and the wellbore.

9. The method of claim 1 wherein the treatment fluid comprises mixed phases including a proppant-rich phase with elongated particles from 1 to 100 percent in weight and a channelant-rich phase.

10. The method of claim 1 wherein the treatment fluid comprises a mixture of the proppant with elongated particles from 1 to 100 percent in weight and channelant, further comprising segregating the proppant and channelant for the fracture placement.

11. The method of claim 1 wherein the channelant comprises a solid acid-precursor to generate acid in the fracture.

12. The method of claim 11 wherein the generated acid etches surfaces of the formation to enlarge the open channels.

13. The method of claim 1 wherein the channelant particles are selected from the group consisting of polylactic acid (PLA), polyglycolic acid (PGA), polyol, salt, polysaccharide, wax, calcium carbonate, benzoic acid, naphthalene based materials, magnesium oxide, sodium bicarbonate, soluble resins, polyvinyl alcohol (PVOH) and combinations thereof.

14. The method of claim 1 wherein the channelant comprises a fluoride source.

15. The method of claim 1 , further comprising producing fluids from the formation through the open channels and the wellbore.

16. The method of claim 1 , wherein the treatment fluid further comprises fibers.

17. The method of claim 16 wherein the fibers are selected from the group consisting of glass, ceramics, carbon and carbon-based compounds, metals and metallic alloys, polylactic acid, polyglycolic acid, polyethylene terephthalate, polyol and combinations thereof.

18. The method of claim 16 wherein the fibers comprise a mixture of first and second fiber types, the first fiber type providing reinforcement and consolidation of the proppant and the second fiber type inhibiting settling of the proppant in the treatment fluid.

19. The method of claim 18 wherein the first fiber type is selected from the group consisting of glass, ceramics, carbon and carbon-based compounds, metals and metallic alloys, and combinations thereof, and the second fiber type is selected from the group consisting of polylactic acid, polyglycolic acid, polyethylterephthalate (PET), polyol and combinations thereof.

20. The method of claim 16 wherein the fibers comprise a thermoplastic coating able to interact with at least part of the proppant to provide reinforcement and consolidation of the proppant or to inhibit settling of the proppant or to retard movement of the proppant within the subterranean formation.

21. The method of claim 1 , wherein the subterranean formation comprises at least in part shale rock.

22. The method of claim 1 , wherein the treatment is done in a well and at least part of the well is horizontal.

23. A method of placing a proppant pack into a fracture formed in a subterranean formation, the method comprising:
injecting well treatment fluid comprising elastic and deformable material, proppant and channelant through a wellbore into a fracture in a subterranean formation, wherein the proppant comprises from 1 to 100 percent in weight of stiff, low-elasticity and low-deformability elongated particles;
placing the proppant in the fracture in a plurality of proppant clusters forming pillars spaced apart by the channelant; and,
removing the channelant to form open channels around the pillars for fluid flow from the formation through the fracture toward the wellbore;
wherein the treatment fluid comprises alternating volumes of proppant rich fluid with the particles form 1 to 100 percent in weight separated by volumes containing the channelant.

24. The method of claim 23 , wherein the elongated particles have a maximal cross-sectional dimension, h 1 , and a minimal cross-sectional dimension, h 2 , of from 0.1 to 10 mm; a length, L, of from 0.1 to 20 mm; for 1D particles, a ratio L/h 1 from 1.2 to 10 and a ratio h 2 /h 1 from 0.8 to 1; for 2D particles, a ratio L/h 1 from 1 to 1.19 and a ratio h 2 /h 1 from 0.1 to 0.79; a curvature, χ, of from 1 to 2/h 2 in units of 1/mm; for 1D particles, a stiffness, k, of from 0 to 4.90•10 8 in units of N-mm 2 ; and for cylindrical particles, a stiffness, k, of from 0 to 10 8 N-mm 2 ; a range of a particle unevenness d 0 (or d 1 ) is from 0 to 0.5*h 1 in units of mm.

25. The method of claim 24 , wherein the elongated particles comprise a mixture of elongated particles differing from one another in at least one parameter selected from the group consisting of length, a cross-sectional dimension, density, curvature, and stiffness.

26. The method of claim 23 , wherein the deformable and elastic material is rod, oval, plate, disk, sphere, platelet, particle, fiber or ribbon.

27. The method of claim 23 , wherein the deformable and elastic material is a thermoplastic polymer.

28. The method of claim 27 , wherein the deformable and elastic material is a coating on another material not necessarily made of deformabl

Assignees

• Schlumberger Technology Corp

Inventors

• Lesko Timothy M
• Brown James Ernest
• Willberg Dean M
• Kosarev Ivan Vitalievich
• Medvedev Anatoly Vladimirovich
• Abbott Jonathan
• Burukhin Alexander

Classifications

• C09K8/72

  Eroding chemicals, e.g. acids · CPC title

• E21B43/267 Primary

  reinforcing fractures by propping · CPC title

• C09K8/665

  containing inorganic compounds (proppants C09K8/80) · CPC title

• C09K8/80

  Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open · CPC title

• C09K8/68

  containing organic compounds · CPC title