Formation measurements using downhole noise sources

Patent metadata

Field	Value
Publication number	US-10126448-B2
Application number	US-201615133454-A
Country	US
Kind code	B2
Filing date	Apr 20, 2016
Priority date	Apr 20, 2016
Publication date	Nov 13, 2018
Grant date	Nov 13, 2018

Abstract

A method of performing measurements of an earth formation includes disposing at least a first receiver and a second receiver in one or more monitoring boreholes in a formation, and injecting fluid into the formation from an injection borehole, wherein injecting includes operating a fluid control device to generate seismic and/or acoustic noise having an identifiable characteristic. The method also includes detecting seismic and/or acoustic signals at the first receiver and detecting seismic and/or acoustic signals at a second receiver, the seismic and/or acoustic signals corresponding to the seismic and/or acoustic noise, calculating an estimate of a Green's function between the first receiver and the second receiver by processing seismic and/or acoustic waves detected by the first receiver and the second receiver to at least partially reconstruct the Green's function, and estimating variations in a velocity of a region of the formation by determining variations in the reconstructed Green's function.

First claim

The invention claimed is:

1. A method of performing measurements of an earth formation, the method comprising:
disposing at least a first receiver and a second receiver in one or more monitoring boreholes in the earth formation, the first receiver and the second receiver configured to detect at least one of seismic signals and acoustic signals;
injecting fluid into the earth formation from an injection borehole in the earth formation during an energy industry operation, wherein injecting includes operating a fluid control device to generate seismic and/or acoustic noise having an identifiable characteristic;
detecting seismic and/or acoustic signals at the first receiver and detecting seismic and/or acoustic signals at a second receiver, the seismic and/or acoustic signals corresponding to the seismic and/or acoustic noise;
calculating an estimate of a Green's function between the first receiver and the second receiver by processing seismic and/or acoustic waves detected by the first receiver and the second receiver to at least partially reconstruct the Green's function;
estimating variations in a velocity of a region of the formation by determining variations in the reconstructed Green's function; and
evaluating the energy industry operation based on the estimated variations in the velocity.

2. The method of claim 1 , wherein estimating the Green's function includes performing one of a deconvolution and a cross-correlation of the seismic and/or acoustic waves detected by the first receiver and the seismic and/or acoustic waves detected by the second receiver.

3. The method of claim 2 , wherein performing the cross-correlation includes determining an estimate of the Green's function, and estimating the variations in the velocity includes estimating a velocity of body waves emanating from an injection location.

4. The method of claim 1 , wherein evaluating includes estimating changes in a velocity of the seismic and/or acoustic noise, and estimating progress of injected fluids in the formation based on the changes.

5. The method of claim 4 , wherein the energy industry operation is a fluid injection operation that includes injecting the fluid into the formation via the injection borehole, and producing hydrocarbons from a production borehole disposed in the formation.

6. The method of claim 5 , wherein evaluating includes monitoring displacement of formation fluids due to injection of the fluid based on the changes in the velocity.

7. The method of claim 6 , wherein evaluating includes predicting a time at which the injected fluid is expected to break through to the production borehole.

8. The method of claim 1 , wherein the fluid control device is disposed in the injection borehole at a known location during fluid injection.

9. The method of claim 1 , wherein injecting includes controlling the flow control device according to a selected pattern to generate the seismic and/or acoustic noise.

10. The method of claim 9 , wherein the injection borehole includes components of an intelligent well system including at least one flow control device.

11. A system for performing measurements of an earth formation, the system comprising:
a fluid control device configured to control injection of fluid into the earth formation from an injection borehole as part of an energy industry operation, the fluid control device configured to be operated to generate seismic and/or acoustic noise having an identifiable characteristic;
a processing device configured to perform:
receiving seismic and/or acoustic signals detected during the energy industry operation by a first receiver and a second receiver disposed in one or more monitoring boreholes in the earth formation, the seismic and/or acoustic signals corresponding to the seismic and/or acoustic noise;
calculating an estimate of a Green's function between the first receiver and the second receiver by processing seismic and/or acoustic waves detected by the first receiver and the second receiver to at least partially reconstruct the Green's function;
estimating variations in a velocity of a region of the formation by determining variations in the reconstructed Green's function; and
evaluating the energy industry operation based on the estimated variations in the velocity.

12. The system of claim 11 , wherein estimating the Green's function includes performing one of a deconvolution and a cross-correlation of the seismic and/or acoustic waves detected by the first receiver and the seismic and/or acoustic waves detected by the second receiver.

13. The system of claim 12 , wherein performing the cross-correlation includes determining an estimate of the Green's function, and estimating the variations in the velocity includes estimating a velocity of body waves emanating from an injection location.

14. The system of claim 11 , wherein evaluating includes estimating changes in a velocity of the seismic and/or acoustic noise, and estimating progress of injected fluids in the formation based on the changes.

15. The system of claim 14 , wherein the energy industry operation is a fluid injection operation that includes injecting the fluid into the formation via the injection borehole, and producing hydrocarbons from a production borehole disposed in the formation.

16. The system of claim 15 , wherein evaluating includes monitoring displacement of formation fluids due to injection of the fluid based on the changes in the velocity.

17. The system of claim 16 , wherein evaluating includes predicting a time at which the injected fluid is expected to break through to the production borehole.

18. The system of claim 11 , wherein the fluid control device is disposed in the injection borehole at a known location during the injecting.

19. The system of claim 11 , wherein injecting includes controlling the flow control device according to a selected pattern to generate the seismic and/or acoustic noise.

20. The system of claim 19 , wherein the injection borehole includes components of an intelligent well system including at least one flow control device.

Assignees

• Jutila Heikki Armas
• Roux Pierre Francois
• Kshirsagar Atul H
• Chattopadhyay Arijit
• Gohari Kousha
• Mascagnini Carlos
• Kidd Peter J
• Baker Hughes Oilfield Operations Llc

Inventors

• Jutila Heikki Armas
• Roux Pierre-Francois
• Kshirsagar Atul H
• Chattopadhyay Arijit
• Gohari Kousha
• Mascagnini Carlos
• Kidd Peter J

Classifications

• G01V2210/30

  Noise handling · CPC title

• E21B43/162

  Injecting fluid from longitudinally spaced locations in injection well · CPC title

• G01V1/50

  Analysing data · CPC title

• G01V1/42

  using generators in one well and receivers elsewhere or vice versa (G01V1/52 takes precedence) · CPC title

• G01V1/308

  Time lapse or 4D effects, e.g. production related effects to the formation (fluid flow per se E21B47/00) · CPC title