Methods for reducing fluid communication between wells

Patent metadata

Field	Value
Publication number	US-10677016-B2
Application number	US-201616311140-A
Country	US
Kind code	B2
Filing date	Jul 13, 2016
Priority date	Jul 13, 2016
Publication date	Jun 9, 2020
Grant date	Jun 9, 2020

Abstract

Methods and systems for reducing fluid communication between wells. Providing a first treatment fluid comprising synthetic clay and an aqueous carrier fluid; pumping the first treatment fluid into a first fracture network in fluid communication with a first well; placing the synthetic clay in the first fracture network; pumping a second treatment fluid into the first fracture network after placing the synthetic clay in the first fracture network; wherein the second treatment fluid is not produced in a second well in fluid communication with a second fracture network, and wherein the second fracture network is in fluid communication with the first fracture network.

First claim

What is claimed is:

1. A method of reducing fluid communication between wells:
providing a first treatment fluid comprising synthetic clay and an aqueous carrier fluid; wherein the first treatment fluid does not comprise a gelling agent and viscosifying additive;
pumping the first treatment fluid into a first fracture network in fluid communication with a first well; wherein the first fracture network is in a subterranean formation and wherein the first treatment fluid is a pad fluid pumped into the first fracture network at a pressure exceeding the fracture gradient of the subterranean formation;
placing the synthetic clay in the first fracture network;
pumping a second treatment fluid into the first fracture network after placing the synthetic clay in the first fracture network; wherein the first fracture network is in fluid communication with a second fracture network; wherein the second fracture network is in fluid communication with a second well;
depositing the synthetic clay in a flow path between the first fracture network and the second fracture network; wherein the synthetic clay swells in the flow path between the first fracture network and the second fracture network as shear is reduced;
wherein the second treatment fluid is not produced in the second well after pumping the second treatment fluid into the first fracture network.

2. The method of claim 1 , wherein a temperature within the first fracture network is greater than 350° F.

3. The method of claim 1 , wherein the concentration of the synthetic clay in the first treatment fluid ranges from about 0.01% (w/v) of the first treatment fluid to about 20% (w/v) of the first treatment fluid.

4. The method of claim 1 , wherein the second treatment fluid comprises synthetic clay.

5. The method of claim 1 , further comprising a pre-pad fluid introduced prior to the first treatment fluid.

6. The method of claim 1 , wherein the second treatment fluid is a subsequent pad fluid which does not comprise synthetic clay.

7. A method of reducing fluid communication between wells:
providing a first treatment fluid comprising synthetic clay and an aqueous carrier fluid; wherein the first treatment fluid does not comprise a gelling agent F and viscosifying additive;
pumping the first treatment fluid into a first fracture network in fluid communication with a first well; wherein the first fracture network is in a subterranean formation and wherein the first treatment fluid is a pad fluid pumped into the first fracture network at a pressure exceeding the fracture gradient of the subterranean formation;
placing the synthetic clay in the first fracture network; wherein the first fracture network is in fluid communication with a second fracture network; wherein the second fracture network is in fluid communication with a second well;
depositing the synthetic clay in a flow path between the first fracture network and the second fracture network; wherein the synthetic clay swells in the flow path between the first fracture network and the second fracture network as shear is reduced;
pumping a second treatment fluid into the second fracture network in fluid communication with the second well;
wherein the second treatment fluid is not produced in the first well after pumping the second treatment fluid into the second fracture network.

8. The method of claim 7 , wherein a temperature within the first fracture network is greater than 350° F.

9. The method of claim 7 , wherein the concentration of the synthetic clay in the first treatment fluid ranges from about 0.01% (w/v) of the s treatment fluid to about 20% (w/v) of the first treatment fluid.

10. The method of claim 7 , wherein the second treatment fluid comprises synthetic clay.

Assignees

• Halliburton Energy Services Inc

Inventors

• Singh Dipti
• Inyang Ubong
• Salamat Golchehreh

Classifications

• C09K8/5045

  containing inorganic compounds · CPC title

• E21B33/138 Primary

  Plastering the borehole wall; Injecting into the formation · CPC title

• E21B33/13

  Methods or devices for cementing, for plugging holes, crevices or the like · CPC title

• C09K8/514

  of natural origin, e.g. polysaccharides, cellulose (C09K8/512 takes precedence) · CPC title

• E21B43/26

  by forming crevices or fractures · CPC title