Compositions and methods for increasing fracture conductivity

Patent metadata

Field	Value
Publication number	US-10526531-B2
Application number	US-201313832938-A
Country	US
Kind code	B2
Filing date	Mar 15, 2013
Priority date	Mar 15, 2013
Publication date	Jan 7, 2020
Grant date	Jan 7, 2020

Abstract

A method for treating a subterranean formation penetrated by a wellbore, comprising: providing a treatment slurry comprising a carrying fluid, a solid particulate and an agglomerant; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the solid particulate and the agglomerant; and transforming the substantially uniform mixture into areas that are rich in solid particulate and areas that are substantially free of solid particulate, wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the fracture and wherein said transforming results from said substantially dissimilar velocities is provided.

First claim

We claim:

1. A method comprising:
providing a treatment slurry comprising a carrying fluid having a yield stress, a solid particulate and an agglomerant;
injecting the treatment slurry into a fracture to form a substantially homogeneous mixture of the solid particulate and the agglomerant; and
causing settling of the solid particulate, in the presence of the agglomerant, within the substantially homogeneous mixture to form areas rich in solid particulate and areas substantially free of solid particulate,
wherein at least one solids-free fluidly connected path is created in the fracture before fracture closure,
wherein the yield stress of the carrying fluid does not exceed a maximum acceptable yield stress defined by γ max 4/3=R(ρ P −ρ f ), where γ max is the maximum acceptable yield stress, R is a grain radius of the solid particulate, ρ P is a density of the solid particulate and ρ f is a density of the carrying fluid,
the carrying fluid having a viscosity range of 2,000 cP to 1,000,000 cP in a range of shear rates from 0.001 and 0.1 s −1 .

2. The method of claim 1 , wherein the solid particulate and the agglomerant have different shapes, sizes, densities or a combination thereof.

3. The method of claim 1 , wherein the agglomerant has an aspect ratio higher than 6.

4. The method of claim 3 , wherein the agglomerant is a fiber, a flake, a ribbon, a platelet, a rod, or a combination thereof.

5. The method of claim 1 , wherein the agglomerant is a degradable material.

6. The method of claim 5 , wherein the agglomerant is selected from the group consisting of polylactic acid, polyester, polycaprolactam, polyamide, polyglycolic acid, polyterephthalate, cellulose, wool, basalt, glass, rubber, sticky fiber, or a combination thereof.

7. The method of claim 1 , wherein the treatment slurry is a proppant-laden hydraulic fracturing fluid and the solid particulate is a proppant.

8. The method of claim 1 , wherein the allowing settling of the solid particulate is achieved by allowing the substantially uniformly injected solid particulate to settle in the fracture for a period of time.

9. The method of claim 1 , wherein the injecting is achieved by pumping the treatment slurry under a pressure sufficient to create the fracture or maintain the fracture opened in the subterranean formation.

10. The method of claim 1 , wherein the allowing the settling of the solid particulate is achieved before the treatment slurry flows back.

11. The method of claim 1 , wherein the allowing the settling of the solid particulate is achieved before the fracture closes.

12. The method of claim 1 , wherein the substantially homogeneous mixture is formed in at least a portion of the fracture.

13. A method, comprising:
providing a slurry comprising a carrying fluid having a yield stress, a solid particulate and an agglomerant;
flowing the slurry into a void to form a substantially homogeneous mixture of the solid particulate and the agglomerant; and
transforming the substantially homogeneous mixture, in the presence of the agglomerant, into areas rich of solid particulate and areas substantially free of solid particulate,
wherein the solid particulate and the agglomerant have substantially dissimilar velocities,
wherein at least one solids-free fluidly connected path is created in the void before fracture closure,
wherein the yield stress of the carrying fluid does not exceed a maximum acceptable yield stress defined by γ max =4/3R(ρ P −ρ f ), where γ max is the maximum acceptable yield stress, R is a grain radius of the solid particulate, ρ P is a density of the solid particulate and ρ f is a density of the carrying fluid,
the carrying fluid having a viscosity range of 2,000 cP to 1,000,000 cP in a range of shear rates from 0.001 and 0.1 s −1 .

14. A method of designing a treatment, comprising:
considering a fracture dimension;
selecting an agglomerant having a dimension comparable to the fracture dimension;
selecting a solid particulate having a substantially different settling velocity from the agglomerant;
formulating a treatment fluid comprising a homogeneous mixture comprising the solid particulate and the agglomerant, the fluid capable of transforming, in the presence of the agglomerant, to a state comprising portions rich in the solid particulates and portions substantially free of the solid particulates,
wherein at least one solids-free fluidly connected path is created in the fracture before fracture closure,
wherein a yield stress of the carrying fluid does not exceed a maximum acceptable yield stress defined by γ max =4/3R(ρ P −ρ f ), where γ max is the maximum acceptable yield stress, R is a grain radius of the solid particulate, ρ P is a density of the solid particulate and ρ f is a density of the carrying fluid,
the carrying fluid having a viscosity range of 2,000 cP to 1,000,000 cP in a range of shear rates from 0.001 and 0.1 s −1 .

15. The method of claim 14 , wherein the fracture dimension is width.

16. A method for treating a subterranean formation penetrated by a wellbore, comprising:
providing a treatment slurry comprising a carrying fluid having a yield stress, a solid particulate and an agglomerant;
injecting the treatment slurry into a fracture to form a substantially homogeneous mixture of the solid particulate and the agglomerant;
wherein the substantially homogeneous mixture is transformable, in the presence of the agglomerant, into areas rich in solid particulate and areas substantially free of solid particulate, and
wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the fracture,
wherein at least one solids-free fluidly connected path is created in the fracture before fracture closure,
wherein the yield stress of a carrying fluid does not exceed a maximum acceptable yield stress defined by γ max =4/3R(ρ P −ρ f ), where γ max is the maximum acceptable yield stress, R is a grain radius of the solid particulate, ρ P is a density of the solid particulate and ρ f is a density of the carrying fluid,
the carrying fluid having a viscosity range of 2,000 cP to 1,000,000 cP in a range of shear rates from 0.001 and 0.1 s −1 .

17. A method, comprising:
providing a slurry comprising a carrying fluid having a yield stress, a solid particulate and an agglomerant; and
flowing the slurry into a void to form a substantially homogeneous mixture of the solid particulate and the agglomerant
wherein the substantially homogeneous mixture is transformable, in the presence of the agglomerant, into areas rich in solid particulate and areas substantially free of solid particulate,
wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the void
wherein at least one solids-free fluidly connected path is created in the fracture before fracture closure,
wherein the yield stress of the carrying fluid does not exceed a maximum acceptable yield stress defined by γ max =4/3R(ρ P −ρ f ), where γ max is the maximum acceptable yield stress, R is a grain radius of the solid particulate, ρ P is a density of the solid particulate and ρ f is a density of the carrying fluid,
the carrying fluid having a viscosity range of 2,000 cP to 1,000,000 cP in a range of shear rates from 0.001 and 0.1 s −1 .

Assignees

• Schlumberger Technology Corp

Inventors

• Potapenko Dmitriy Ivanovich
• Ramsey Leland
• Lesko Timothy M
• Willberg Dean M
• Lafferty Theodore
• Still John W

Classifications

• E21B43/267

  reinforcing fractures by propping · CPC title

• C09K8/92

  characterised by their form or by the form of their components, e.g. encapsulated material (C09K8/70 takes precedence) · CPC title

• C09K8/80 Primary

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

• C09K8/845

  containing inorganic compounds · CPC title

• C09K2208/08

  Fiber-containing well treatment fluids · CPC title