Heterogeneous proppant placement in a fracture with removable extrametrical material fill

Patent metadata

Field	Value
Publication number	US-9863230-B2
Application number	US-201213494503-A
Country	US
Kind code	B2
Filing date	Jun 12, 2012
Priority date	Jun 15, 2011
Publication date	Jan 9, 2018
Grant date	Jan 9, 2018

Abstract

A method of injecting well treatment fluid including proppant and proppant-spacing filler material through a wellbore into the fracture, heterogeneously placing the proppant in the fracture in a plurality of proppant clusters or islands spaced apart by the material, and removing the filler material to form open channels around the pillars for fluid flow from the formation through the fracture toward the wellbore. The proppant and channelant can be segregated within the well treatment fluid, or segregated during placement in the fracture. The filler material 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 extrametrical materials to provide reinforcement and consolidation of the proppant and/or to inhibit settling of the proppant.

First claim

The invention claimed is:

1. A method, comprising:
injecting a well treatment fluid comprising proppant and an extramerical material through a wellbore and into a fracture in a subterranean formation wherein the injecting is achieved with varied and pulsed proppant concentration in a pumping schedule, the pumping schedule being optimized based on fluid and formation properties, and wherein the introducing is achieved by varying pumping rate during pulses; and
placing the proppant in the fracture in a plurality of proppant clusters;
wherein the extramerical material and the proppant are disposed within the fracture,
wherein the extramerical material is segregated from the proppant to reinforce the proppant clusters,
wherein the extramerical material is selected to have a size and shape to facilitate segregation from the proppant;
wherein the extramerical material is a removable material;
wherein the pumping schedule is regulated in real-time mode to ensure maximum fracture conductivity, effective fracture length, or both;
wherein the pumping schedule is combined with a homogeneous stage at the end of a treatment.

2. The method of claim 1 , wherein the extramerical material is degraded by softening, dissolving, melting or reacting.

3. The method of claim 1 , wherein the degradation of the extramerical material further enables fluid flow from the formation through the fracture toward the wellbore.

4. The method of claim 3 , wherein the extramerical material comprises a solid acid-precursor capable of generating acid in the fracture, a solid base-precursor capable of generating a base in the fracture, or both.

5. The method of claim 3 , wherein the extramerical material comprises extramerical materials capable of generating acid in the fracture.

6. The method of claim 1 , wherein the wellbore is a vertical wellbore, a wellbore deviated at any angle relative a vertical wellbore, or any combination of both.

7. The method of claim 1 , wherein the method is repeated at another fracture in the wellbore.

8. The method of claim 1 , wherein the proppant clusters are in transverse or longitudinal fractures along a wellbore deviated at any angle relative a vertical wellbore.

9. The method of claim 1 , wherein a zone contacted by the treatment fluid in the formation comprises fine grained sedimentary rock formed by consolidation of clay and silt sized particles into thin, relatively impermeable layers.

10. The method of claim 1 , further comprising injecting a fluid comprising extramerical materials in a higher concentration than the well treatment fluid into the fracture.

11. The method of claim 1 , wherein the extramerical material is a channelant.

12. The method of claim 11 , wherein the extramerical material is not a channelant during the introducing and forming.

13. The method of claim 1 , wherein the extramerical material further maintains a structural integrity of the clusters.

14. The method of claim 1 , wherein the extramerical material further maintains a separation of the proppant clusters.

15. The method of claim 1 wherein optimization is performed in real time by processing data from surface and bottomhole gauges.

16. The method of claim 1 wherein proppant slurry pulse and clean fluid pulse durations are optimized to ensure maximum fracture conductivity and effective fracture length.

17. The method of claim 1 wherein proppant slurry concentration in pulses is optimized to ensure maximum fracture conductivity and effective fracture length with reduced risk of premature screen-out.

18. The method of claim 1 wherein proppant slurry concentration in pulses is optimized to ensure maximum fracture conductivity and effective fracture length, with minimum proppant volume.

19. The method of claim 1 wherein the extrametrical material has a size and shape matching the size and shape of the proppant to promote segregation.

20. The method of claim 1 wherein the proppant is non-adherent to the extrametrical material after placement in the fracture.

21. A method, comprising:
a) constructing a system in a subterranean formation penetrated by a wellbore, comprising:
i. fracturing the subterranean formation;
ii. injecting a well treatment fluid comprising proppant and a proppant spacing solid extramerical material through a wellbore and into a fracture, wherein the injecting is achieved with varied and pulsed proppant concentration in a pumping schedule, the pumping schedule being optimized based on fluid and formation properties, and wherein the introducing is achieved by varying pumping rate during pulses; and wherein the extramerical material is a non-fibrous degradable material; and
iii. placing the proppant in the fracture in a plurality of proppant clusters; wherein the proppant and the extramerical material are disposed within the fracture in such a way that the extramerical material is segregated from the proppant to reinforce the plurality of proppant clusters, and wherein the extramerical material is selected to have a size and shape to facilitate segregation of the proppant; and

b) producing formation fluids from the formation, through the system of a);
wherein the pumping schedule is regulated in real-time mode to ensure maximum fracture conductivity, effective fracture length, or both;
wherein the pumping schedule is combined with a homogeneous stage at the end of a treatment.

22. The method of claim 21 , wherein the extrametrical material consolidates the proppant clusters.

23. The method of claim 21 , further comprising injecting a fluid comprising extrametrical materials in a higher concentration than the well treatment fluid into the fracture.

24. The method of claim 21 , wherein the extrametrical material is a channelant.

25. The method of claim 21 , wherein the extrametrical material is not a channelant during the introducing and forming.

26. The method of claim 21 wherein optimization is performed in real time by processing data from surface and bottomhole gauges.

27. The method of claim 21 wherein proppant slurry pulse and clean fluid pulse durations are optimized to ensure maximum fracture conductivity and effective fracture length.

28. The method of claim 21 wherein proppant slurry concentration in pulses is optimized to ensure maximum fracture conductivity and effective fracture length with reduced risk of premature screen-out.

29. The method of claim 21 wherein proppant slurry concentration in pulses is optimized to ensure maximum fracture conductivity and effective fracture length, with minimum proppant volume.

Assignees

• Litvinets Fedor Nikolaevich
• Bogdan Andrey Vladimirovich
• Makarychev-Mikhaliov Sergey Mikhailovich
• Medvedev Oleg
• Pena Alejandro
• Lyapunov Konstantin Mikhailovich
• Mikhaylov Alexander Vuacheslavovich
• Lesko Timothy M
• Brown J Ernest
• Willberg Dean M
• Kosarev Ivan Vitalievich
• Medvedev Anatoly Vladimirovich
• Abbott Jonathan
• Burukhin Alexander Alexandrovich
• Schlumberger Technology Corp

Inventors

• Litvinets Fedor Nikolaevich
• Bogdan Andrey Vladimirovich
• Makarychev-Mikhaliov Sergey Mikhailovich
• Medvedev Oleg
• Pena Alejandro
• Lyapunov Konstantin Mikhailovich
• Mikhaylov Alexander Vuacheslavovich
• Lesko Timothy M
• Brown J Ernest
• Willberg Dean M
• Kosarev Ivan Vitalievich
• Medvedev Anatoly Vladimirovich
• Abbott Jonathan
• Burukhin Alexander Alexandrovich

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