Detecting and locating fluid flow in subterranean rock formations
View Patent ↗A method and system includes acquiring a seismic dataset while fluids are injected into the subsurface with seismic data recorded at multiple sensor locations. Seismic travel times are computed between sensors and subsurface locations using a velocity model. Travel times and travel time delays between pairs of sensors may be used as input to determine a similarity coefficient associated with subsurface positions. The similarity coefficients are determined using cross correlation, semblance calculations or eigenstructure decomposition. The coefficient values are related to the acoustic response at each subsurface position and may be summed together for each position for comparison with other subsurface positions to determine the position of a fluid front moving through the subsurface. The values may be displayed to illustrate the position of fluids in the subsurface and displayed to show the time variance of the fluid position.
1. A method, comprising: placing a plurality of sensors into a subsurface underneath of at least one surface facility at a respective plurality of subsurface positions in the subsurface; performing, by the at least one surface facility, an initial fracture stimulation treatment, comprising: i) injecting, by the at least one surface facility, at least one fluid, through one or more wellbores, at one or more subsurface positions associated with a reservoir of hydrocarbons; ii) acquiring, by a processor, for a duration of at least 10 minutes, a plurality of seismic traces from the plurality of sensors located in the subsurface to form seismic data; wherein the plurality of seismic traces has respective amplitudes that are lower than amplitudes of seismic waves caused by a microseismic event; iii) computing, by the processor, from the seismic data, seismic wave travel times between the one or more subsurface positions within the subsurface and a subset of the plurality of sensors located at a respective plurality of sensor subsurface positions in the subsurface; iv) computing, by the processor, from the computed seismic wave travel times, seismic wave travel time differences between the subset of the plurality of sensors located at the respective plurality of sensor subsurface positions in the subsurface and the one or more subsurface positions; v) determining, by the processor, seismic data similarity coefficients associated with the one or more subsurface positions based at least in part on the computed seismic wave travel time differences; vi) determining, by the processor, based at least in part on the determined seismic data similarity coefficients, a fluid flow seismic signal value associated with the one or more subsurface positions; wherein the fluid flow seismic signal value is distinct from seismic event data resulting from a tensile failure; vii) determining, by the processor, at least one position of a fluid front of the at least one fluid moving through the subsurface based at least in part on the fluid flow seismic signal value associated with the one or more subsurface positions; and performing, by the at least one surface facility, based at least in part on the at least one position of the fluid front of the at least one fluid moving through the subsurface, one or more remedial activities to drain one or more parts of the reservoir of hydrocarbons that are not fractured by the initial fracture stimulation treatment, wherein the one or more remedial activities comprise i) drilling one or more additional wellbores at one or more additional subsurface positions associated with the one or more parts of the reservoir of hydrocarbons and ii) performing one or more subsequent fracture stimulation treatments, wherein the at least one or more remedial activities further comprise: i) adjusting a fluid saturation of the at least one fluid, and ii) adjusting a pressure under which the at least one fluid is injected.
2. The method of claim 1 , wherein the determining seismic data similarity coefficients further comprises:
determining the seismic data similarity coefficients using a cross correlation of a plurality of pairs of seismic signals.
3. The method of claim 1 , wherein the determining seismic data similarity coefficients further comprises:
determining the seismic data similarity coefficients using an eigenstructure decomposition.
4. The method of claim 1 , wherein the determining seismic data similarity coefficients further comprises:
determining the seismic data similarity coefficients using at least one semblance calculation.
5. The method of claim 1 , wherein the computing seismic wave travel times further comprises:
using velocities derived from at least one selected from the group consisting of: i) a perforation shot, ii) a string shot, iii) surface seismic data, iv) a check shot, and v) VSP data.
6. The method of claim 1 , wherein at least one sensor of the plurality of sensors is a three-component sensor.
7. The method of claim 1 , further comprising:
generating, by the processor, based at least in part on the fluid flow seismic signal value associated with the one or more subsurface positions, at least one visual representation that is distinct from the seismic event data resulting from the tensile failure.
8. A system, comprising: at least one surface facility; wherein the at least one surface facility is configured to: 1) perform an initial fracture stimulation treatment, comprising: injecting at least one fluid, through one or more wellbores, at one or more subsurface positions associated with a reservoir of hydrocarbons, and 2) perform, based at least in part on at least one position of a fluid front of the at least one fluid moving through a subsurface: one or more remedial activities to drain one or more parts of the reservoir of hydrocarbons that are not fractured by the initial fracture stimulation treatment, wherein the one or more remedial activities comprise: i) drilling one or more additional wellbores at one or more additional subsurface positions associated with the one or more parts of the reservoir of hydrocarbons and ii) performing one or more subsequent fracture stimulation treatments; a plurality of sensors placed into a subsurface underneath of the at least one surface facility at a respective plurality of subsurface positions in the subsurface; and a seismic data processing unit, comprising: a non-transient computer memory, electronically storing computer executable program code; and a processor that, when executing the particular program code, is configured to: i) acquire, for a duration of at least 10 minutes, a plurality of seismic traces from the plurality of sensors located in the subsurface to form seismic data; ii) compute, from the seismic data, seismic wave travel time differences between the one or more subsurface positions within the subsurface and a subset of the plurality of sensors located at a respective plurality of sensor subsurface positions in the subsurface; iii) compute, from the computed seismic wave travel times, seismic wave travel time differences between the subset of the plurality of sensors located at the respective plurality of sensor subsurface positions in the subsurface and the least one or more subsurface positions; iv) determine seismic data similarity coefficients associated with the one or more subsurface positions based in part on the computed seismic wave travel time differences; v) determine, based at least in part on the determined seismic data similarity coefficients to obtain, a fluid flow seismic signal value associated with the one or more subsurface positions, wherein the fluid flow seismic signal value is distinct from seismic event data resulting from a tensile failure; and vi) determine the at least one position of the fluid front of the at least one fluid moving through the subsurface based at least in part on the fluid flow seismic signal value associated with the least one or more subsurface positions, wherein one or more remedial activities further comprise: i) adjusting a fluid saturation of the at least one fluid, and ii) adjusting a pressure under which the at least one fluid is injected.
9. The system of claim 8 , wherein the processor is further configured to determine the seismic data similarity coefficients by using a cross correlation of a plurality of pairs of seismic signals.
10. The system of claim 8 , wherein the processor is further configured to determine the seismic data similarity coefficients by using an eigenstructure decomposition.
11. The system of claim 8 , wherein the processor is further configured to determine the seismic data similarity coefficients by using at least one semblance calculation.
12. The system of claim 8 , the processor is further configured to compute the seismic wave travel times by using velocities derived from at least one selected from the group consisting of: i) a perforation shot, ii) a string shot, iii) surface seismic data, iv) a check shot, and v) VSP data.
13. The system of claim 8 , wherein at least one sensor of the plurality of sensors is a three-component sensor.
14. The system of claim 8 , wherein the processor is further configured to generate, based at least in part on the fluid flow seismic signal value associated with the one or more subsurface positions, at least one visual representation that is distinct from the seismic event data resulting from the tensile failure.