In situ channelization method and system for increasing fracture conductivity

Patent metadata

Field	Value
Publication number	US-9523268-B2
Application number	US-201313974203-A
Country	US
Kind code	B2
Filing date	Aug 23, 2013
Priority date	Aug 23, 2013
Publication date	Dec 20, 2016
Grant date	Dec 20, 2016

Abstract

A method and system for increasing fracture conductivity. A treatment slurry stage has a continuous first solid particulate concentration and a discontinuous anchorant concentration between anchorant-rich substages and anchorant-lean substages within the treatment slurry stage.

First claim

We claim:

1. A method for treating a subterranean formation penetrated by a wellbore, comprising:
injecting a treatment stage fluid above a fracturing pressure to form a fracture in the formation, wherein the fluid comprises a continuous concentration of a first solid particulate and a discontinuous concentration of an anchorant;
aggregating the first solid particulate distributed into the fracture to form spaced-apart clusters in the fracture;
anchoring at least some of the clusters in the fracture to inhibit aggregation of the at least some of the clusters; and
reducing pressure in the fracture to prop the fracture open on the clusters and form interconnected, hydraulically conductive channels between the clusters.

2. The method of claim 1 further comprising:
successively alternating concentration of the anchorant in the treatment stage fluid between a relatively anchorant-rich mode and an anchorant-lean mode during the continuous distribution of the first solid particulate into the formation in the treatment stage fluid to facilitate one or both of the cluster aggregation and anchoring.

3. The method of claim 1 , wherein the first solid particulate in the treatment stage fluid comprises disaggregated proppant at the continuous concentration.

4. The method of claim 1 , wherein the aggregation comprises triggering settling of the first solid particulate.

5. The method of claim 4 , further comprising viscosifying the treatment stage fluid for distributing the first solid particulate into the formation, and breaking the treatment stage fluid in the fracture to trigger the settling.

6. The method of claim 1 , wherein the anchorant comprises fiber.

7. The method of claim 1 , wherein the conductive channels extend in fluid communication from adjacent a face of the fracture in the formation away from the wellbore to or to near the wellbore.

8. A method for treating a subterranean formation penetrated by a wellbore, comprising:
injecting into a fracture in the formation a first solid particulate at a continuous concentration;
while maintaining the continuous rate and first solid particulate concentration during injection of the treatment fluid stage, successively alternating concentrations of an anchorant in the treatment fluid stage between a plurality of relatively anchorant-rich modes and a plurality of anchorant-lean modes within the injected treatment fluid stage.

9. The method of claim 8 , wherein the injection of the treatment fluid stage forms a homogenous region of the first solid particulate of uniform distribution within the fracture.

10. The method of claim 8 , wherein the alternation of the concentration modes of the anchorant forms heterogeneous areas within the fracture comprising anchorant-rich areas and anchorant-lean areas.

11. The method of claim 8 , wherein the injected treatment fluid stage comprises a viscosified carrier fluid, and further comprising:
reducing the viscosity of the carrier fluid in the fracture to induce settling of the first solid particulate prior to closure of the fracture; and
thereafter allowing the fracture to close.

12. The method of claim 8 , further comprising forming bridges with the anchorant-rich modes in the fracture and forming conductive channels between the bridges with the anchorant-lean modes.

13. A method for treating a subterranean formation penetrated by a wellbore, comprising:
injecting into a fracture in the formation at a continuous rate a treatment fluid stage comprising a viscosified carrier fluid with a continuous concentration of a first solid particulate to form a homogenous region within the fracture of continuously uniform distribution of the first solid particulate;
successively alternating concentration modes of an anchorant in the treatment fluid between relatively anchorant-rich modes and relatively anchorant-lean modes within the injected treatment fluid stage, to form heterogeneous areas comprising anchorant-rich areas and anchorant-lean areas within the homogenous region of the continuously uniform distribution of the first solid particulate;
reducing the viscosity of the carrier fluid within the homogenous region to induce settling of the first solid particulate prior to closure of the fracture to form hydraulically conductive channels in at least the anchorant-lean areas and pillars in the anchorant-rich areas; and
thereafter allowing the fracture to close onto the pillars.

14. The method of claim 13 , further comprising transforming the anchorant-rich areas into nodes rich in the first solid particulate to form the pillars.

15. The method of claim 13 , wherein the first solid particulate and the anchorant have different shapes, sizes, densities or a combination thereof.

16. The method of claim 13 , wherein the anchorant has an aspect ratio higher than 6.

17. The method of claim 13 , wherein the anchorant is a fiber, a floc, a flake, a ribbon, a platelet, a rod, or a combination thereof.

18. The method of claim 13 , wherein the anchorant is selected from the group consisting of glass, ceramics, carbon (including carbon-based compounds), elements in metallic form, metal alloys, wool, basalt, acrylic, polyethylene, polypropylene, novoloid resin, polyphenylene sulfide, polyvinyl chloride, polyvinylidene chloride, polyurethane, polyvinyl alcohol, polybenzimidazole, polyhydroquinone-diimidazopyridine, poly(p-phenylene-2,6-benzobisoxazole), rayon, cotton, or other natural fibers,cellulose, wool, basalt, glass, rubber, acrylic, mica, and combinations thereof.

19. The method of claim 13 , wherein the anchorant is a sticky fiber.

20. The method of claim 13 , wherein the anchorant is an expandable material.

21. The method of claim 13 , wherein the treatment fluid stage is a proppant-laden hydraulic fracturing fluid and the first solid particulate is a proppant.

22. The method of claim 13 , wherein the anchorant is a degradable material.

23. The method of claim 22 , wherein the anchorant is selected from the group consisting of polylactic acid (PLA), polyglycolic acid (PGA), polyethylene terephthalate (PET), polyester, polyamide, polycaprolactam and polylactone, poly(butylene Succinate, polydioxanonepolylactic acid, polyester, polycaprolactam, polyamide, polyglycolic acid, polyterephthalate, or a combination thereof.

24. A system, comprising:
a subterranean formation penetrated by a wellbore;
a treatment fluid stage disposed in the wellbore, the treatment fluid stage comprising a continuous concentration of a first solid particulate and a discontinuous concentration of an anchorant; and
a pump system to continuously deliver the treatment fluid stage from the wellbore to the formation at a pressure above fracturing pressure to inject the treatment fluid stage into a fracture in the formation.

25. The system of claim 24 , wherein the treatment fluid stage comprises a viscosified carrier fluid and a breaker to induce settling of the first solid particulate prior to closure of the fracture.

26. The system of claim 24 , wherein the discontinuous concentration of the anchorant comprises a plurality of relatively anchorant-rich substages disposed in the wellbore in an alternating sequence with a plurality of anchorant-lean substages.

27. A system to treat a subterranean formation penetrated by a wellbore, comprising:
a pump system to deliver a treatment stage fluid through the wellbore to the formation above a

Assignees

• Schlumberger Technology Corp

Inventors

• Potapenko Dmitriy Ivanovich
• Brown J Ernest
• Ganguly Partha
• Bogdan Andrey
• Ramsey Leland

Classifications

• E21B43/267 Primary

  reinforcing fractures by propping · CPC title

• C09K8/80

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

• C09K8/62

  Compositions for forming crevices or fractures · CPC title

• Y10S507/935

  Enhanced oil recovery · 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