Method for assessing the effectiveness of modifying transmissive networks of natural reservoirs

• US 9,442,205 B2
• Filed: 03/15/2013
• Issued: 09/13/2016
• Est. Priority Date: 03/23/2011
• Status: Active Grant

• Current Assignee: Ambient Reservoir Monitoring, Inc.
• Original Assignee: Global Ambient Seismic, Inc.
• Inventors: Geiser, Peter Anderson, Vermilye, Jan Meredith, Sicking, Charles John
• Primary Examiner(s): HULKA, JAMES R
• Application Number:
  US13/831,619
• Publication Number:
  US 20130215712A1
• Time in Patent Office: 1,278 Days
• Field of Search: 367/9
• US Class Current: 1/1
• CPC Class Codes: G01V 1/288 Event detection in seismic signals, e.g. microseismics G01V1/36 takes precedence
• CPC Class Codes: G01V 1/308 Time lapse or 4D effects, e.g. production related effects to the formation fluid flow per se E21B47/00
• CPC Class Codes: G01V 1/42 using generators in one well and receivers elsewhere or vice versa G01V1/52 takes precedence
• CPC Class Codes: G01V 2210/1234 Hydrocarbon reservoir, e.g. spontaneous or induced fracturing

Abstract

Described herein are various embodiments of methods and corresponding hardware and software that are configured to illuminate or image the permeability field around or near a well that is to be fracked, both prior to fracking and after various fracking stages. The methods and corresponding hardware and software disclosed herein permit the progress of the fracking operation to be monitored at different stages.

Claims

1. A method of monitoring or assessing the effectiveness of a fracking operation in a well, comprising:

deploying and activating an array of seismic sensors near or around a well that is to be fracked;

determining at least an initial seismic or acoustic velocity model for a first volume near or around the well that is to be fracked;

determining a fracking stage transmissive volume by illuminating a permeability field near or in the first volume by pumping gas or fluid into the well at pressures sufficient to cause slip on pre-existing fractures but not sufficient to cause new fractures;

employing near-well tomographic fracture imaging methods to process continuously or near-continuously seismic data that have been or are being acquired or recorded during said illumination of said permeability field near or in the first volume;

generating images corresponding to initial transmissive fractures and faults located in the first volume to determine a geometry of a pre-existing first fracture or fault network in, or in the vicinity of, the first volume that is characteristic of an initial permeability field;

carrying out a first fracking stage in the well and near or in the first volume, where a suitable fluid or gas is pumped into at least the first volume at a pressure sufficient to cause new fractures;

employing near-well tomographic fracture imaging methods to process continuously or near continuously seismic data that have been or are being acquired or recorded near the at least first volume that is being fractured in the first fracking stage;

employing near-well tomographic fracture imaging methods to generate images representing fractures or faults created by the first fracking stage, and

determining a second volume and geometry of a second fracture and fault network that has been created by the first fracking stage, and that is characteristic of a resulting new stage permeability field.

2. The method of claim 1, further comprising carrying out a second fracking stage to further enhance propagation and growth of the fracture and fault network created by the first fracking stage.

3. The method of any of claim 1 or 2, further comprising repeating any of the steps recited therein in accordance with the results provided thereby.

4. The method of any of claim 1, 2 or 3, further comprising repeating any of the steps recited therein until the fracture and fault network reaches a suitable or desired extent in the first or second volume.

5. The method of claim 1, further comprising employing near real time tomographic fracture imaging methods after or in conjunction with any of the near-well tomographic fracture imaging methods.

6. The method of claim 1, wherein the fluid or gas comprises nitrogen, water, carbon dioxide, methane, or natural gas.

7. The method of claim 1, wherein the fluid or gas comprises a propellant.

8. The method of claim 7, wherein at least portions of the propellant are detonated, ignited or deflagrated.

9. The method of claim 1, wherein the second volume includes at least portions of the first volume.

10. The method of claim 1, further comprising voxel value filtering the seismic data.

11. The method of claim 10, wherein the voxel value filtering further comprises computing at least one local maximum in the voxels.

12. The method of claim 10, wherein voxel value filtering further comprises passing voxel values that exceed a predetermined minimum value.

13. The method of claim 10, wherein voxel value filtering further comprises filtering the seismic data to pass a predetermined percentage of the highest voxel values associated therewith.

14. The method of claim 10, wherein voxel value filtering further comprises filtering each the seismic data to pass voxel values that exceed a calculated value computed on the basis of a range of values in the seismic data.

15. The method of claim 10, further comprising stacking the voxel value filtered data.

16. The method of claim 10, wherein the voxel values in SET spatial volumes correspond to semblance values.

17. The method of claim 1, further comprising acquiring a microseismic SET data set for use in the method.

18. The method of claim 10, further comprising disposing at least some of the sensors along the surface of the earth.

19. The method of claim 18, further comprising disposing at least some of the sensors beneath the surface of the earth in at least one borehole.