Restimulation process using coiled tubing and fiber optics

Patent metadata

Field	Value
Publication number	US-10774635-B2
Application number	US-201616095127-A
Country	US
Kind code	B2
Filing date	Jun 10, 2016
Priority date	Jun 10, 2016
Publication date	Sep 15, 2020
Grant date	Sep 15, 2020

Abstract

In accordance with presently disclosed embodiments, a method and system for performing real-time evaluation of a restimulation operation using coiled tubing with fiber optics is provided. The method involves performing a restimulation treatment by pumping a slurry with diverter materials through an annulus in the wellbore surrounding the coiled tubing, and using fiber optics in the coiled tubing to identify the order and magnitude of fractures being created during the restimulation treatment. The fiber optics in the coiled tubing may include one or more fiber optic cables designed to collect distributed acoustic sensing (DAS) or distributed temperature sensing (DTS) data. The evaluation of the restimulation operation may be used to validate and/or adjust the restimulation treatment as needed to improve the lateral distribution of transverse fractures through a subterranean formation. The coiled tubing may also be used to remove sand bridges from the wellbore throughout the restimulation treatment.

First claim

What is claimed is:

1. A method, comprising:
positioning coiled tubing in a wellbore proximate a plurality of entry points formed between the wellbore and a subterranean formation;
pumping a slurry comprising diverter material into an annulus of the wellbore surrounding the coiled tubing;
collecting distributed acoustic sensing (DAS) data along a fiber optic cable disposed in the coiled tubing while pumping the slurry;
analyzing the DAS data to evaluate changes in fracture planes in the subterranean formation due to interaction of the diverter material with the plurality of entry points; and
wherein analyzing the DAS data comprises determining a velocity of fluid moving through the annulus based on the DAS data and determining a quantity and direction of fluid moving through the annulus based on the velocity.

2. The method of claim 1 , further comprising removing residual particulates from the wellbore proximate the plurality of entry points via the coiled tubing.

3. The method of claim 1 , further comprising raising the coiled tubing to a location above the plurality of entry points prior to pumping a treatment fluid into the wellbore.

4. The method of claim 3 , further comprising lowering the coiled tubing from the location above the plurality of entry points to a position proximate the plurality of entry points to collect DAS data multiple times during breaks in pumping the treatment fluid.

5. The method of claim 3 , further comprising pumping the treatment fluid into the wellbore when the coiled tubing is disposed at least partially in the wellbore.

6. The method of claim 3 , further comprising pumping the treatment fluid into the wellbore when the coiled tubing is entirely removed to a surface of the wellbore.

7. The method of claim 1 , further comprising shutting in the wellbore and performing a baseline DAS data survey of the wellbore proximate the plurality of entry points via the fiber optic cable prior to pumping the slurry.

8. The method of claim 1 , further comprising blocking one or more entry points of the plurality of entry points via the diverter material in the slurry, and redirecting fluids from the wellbore into different entry points.

9. The method of claim 1 , further comprising collecting the DAS data along a length of the wellbore spanning all of the plurality of entry points.

10. The method of claim 1 , further comprising pumping a tracer fluid with the slurry and collecting the DAS data to detect a flow of the tracer fluid.

11. The method of claim 1 , further comprising displaying an injectivity profile indicative of the changes in fracture planes in the subterranean formation.

12. The method of claim 1 , further comprising adjusting an amount of diverter material in the slurry based on the changes in fracture planes in the subterranean formation.

13. A system, comprising:
a coiled tubing member comprising a distributed acoustic sensing (DAS) fiber optic cable for collecting DAS data along a length of the coiled tubing member;
a processing component communicatively coupled to the DAS fiber optic cable; and
a memory component containing a set of instructions that, when executed by the processing component, cause the processing component to:
receive DAS data collected by the DAS fiber optic cable when the coiled tubing member is disposed in a wellbore and a slurry containing diverter material is being pumped through the wellbore and into a subterranean formation via entry points;
analyze the DAS data to evaluate changes in fracture planes in the subterranean formation due to interaction of the diverter material with the plurality of entry points; and
determine a change in fracture planes in the subterranean formation based on the collected DAS data, wherein analyzing the DAS data comprises determining a velocity of fluid moving through the annulus based on the DAS data and determining a quantity and direction of fluid moving through the annulus based on the velocity.

14. The system of claim 13 , further comprising a slurry pump coupled to the wellbore to pump the slurry through the wellbore and into the subterranean formation.

15. The system of claim 13 , wherein a section of the wellbore having the entry points is horizontally oriented.

16. The system of claim 13 , wherein the coiled tubing member further comprises a distributed temperature sensing (DTS) fiber optic cable for collecting DTS data along the length of the coiled tubing member, wherein the DTS fiber optic cable is coupled to the processing component.

17. The system of claim 13 , further comprising a display coupled to the processing component to display an injectivity profile indicative of the change in fracture planes.

18. A method, comprising:
positioning coiled tubing in a wellbore proximate a plurality of entry points formed between the wellbore and a subterranean formation;
pumping a slurry comprising diverter material into an annulus of the wellbore surrounding the coiled tubing;
collecting distributed acoustic sensing (DAS) data along a first fiber optic cable disposed in the coiled tubing while pumping the slurry;
analyzing the DAS data to evaluate changes in fracture planes in the subterranean formation due to interaction of the diverter material with the plurality of entry points;
collecting distributed temperature sensing (DTS) data along a second fiber optic cable disposed in the coiled tubing while pumping the slurry;
analyzing the DTS data with the DAS data to evaluate changes in fracture planes in the subterranean formation; and
pumping a thermal tracer into the wellbore with the slurry and collecting the DTS data to detect a flow of the thermal tracer.

19. The method of claim 18 , further comprising one or more of:
raising the coiled tubing to a location above the plurality of entry points prior to pumping a treatment fluid into the wellbore; and
lowering the coiled tubing from a location above the plurality of entry points to a position proximate the plurality of entry points to collect DAS data multiple times during breaks in pumping the treatment fluid.

20. The method of claim 19 , further comprising one or more of:
shutting in the wellbore and performing a baseline DAS data survey of the wellbore proximate the plurality of entry points via the first fiber optic cable prior to pumping the slurry;
blocking one or more entry points of the plurality of entry points via the diverter material in the slurry, and redirecting fluids from the wellbore into different entry points;
collecting the DAS data along a length of the wellbore spanning all of the plurality of entry points;
pumping a tracer fluid with the slurry and collecting the DAS data to detect a flow of the tracer fluid;
displaying an injectivity profile indicative of the changes in fracture planes in the subterranean formation; and
adjusting an amount of diverter material in the slurry based on the changes in fracture planes in the subterranean formation.

Assignees

• Halliburton Energy Services Inc

Inventors

• Ruhle William Owen Alexander
• Gullickson Geoffrey
• Sahdev Neha

Classifications

• E21B47/11

  using tracers; using radioactivity · CPC title

• E21B43/26

  by forming crevices or fractures · CPC title

• E21B47/107

  using acoustic means · CPC title

• E21B47/07

  Temperature · CPC title

• E21B47/135 Primary

  using light waves, e.g. infrared or ultraviolet waves · CPC title