MULTICOMPONENT SEISMIC INVERSION OF VSP DATA

• US 20110267921A1
• Filed: 04/30/2010
• Published: 11/03/2011
• Est. Priority Date: 04/30/2010
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Mortel, Jan van de, Ross, Andrew Ronald, D'Aubeterre Reyes, Maria Gabriela, Nielsen, Jacob Thymann
• Granted Patent: US 8,576,663 B2
• Time in Patent Office: Days
• US Class Current: 367/25
• CPC Class Codes: G01V 1/28 Processing seismic data, e.g. for interpretation or for event detection G01V1/48 takes precedence
• 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 2210/67 Wave propagation modeling

Abstract

A method for seismic inversion of vertical seismic profile (VSP) data in an oilfield. The method includes obtaining an initial velocity model of a subterranean formation including acoustic velocities of wave propagation in proximity to the wellbore, determining an acquisition geometry for obtaining the VSP data including receiver locations within the wellbore and a source location, performing a seismic survey to obtain the VSP data based on the acquisition geometry, analyzing arrival signals of the VSP data to generate transit time data for wave propagation from the source location to the receiver locations, modifying the initial velocity model to generate an updated velocity model by performing a tomographic inversion of the transit time data, generating an elastic model of the subterranean formation by performing the seismic inversion of the VSP data using the updated velocity model, and adjusting the operations of the oilfield based on the elastic model.

Claims

1. A method for seismic inversion of vertical seismic profile (VSP) data in an oilfield having a subterranean formation penetrated by a wellbore, comprising:

obtaining an initial velocity model of the subterranean formation, the initial velocity model comprising acoustic velocities of wave propagation in proximity to the wellbore;

determining an acquisition geometry for obtaining the VSP data, the acquisition geometry comprising a plurality of receiver locations within the wellbore and a source location;

performing a seismic survey to obtain the VSP data based on the acquisition geometry;

analyzing, using a central processing unit (CPU) of a computer system, direct arrival signals of the VSP data to generate transit time data for wave propagation from the source location to the plurality of receiver locations;

modifying, using the CPU, the initial velocity model to generate an updated velocity model by performing a tomographic inversion of the transit time data;

generating, using the CPU, an elastic model of the subterranean formation by performing the seismic inversion of the VSP data using the updated velocity model; and

adjusting the operations of the oilfield based on the elastic model.

2. The method of claim 1, wherein the updated velocity model comprises a two dimensional velocity model.

3. The method of claim 1, wherein the elastic model comprises at least one selected from a group consisting of acoustic impedance, shear impedance, and density of the subterranean formation in proximity to the wellbore.

4. The method of claim 1, further comprises:

generating a low frequency model based on the updated velocity model,

wherein performing the seismic inversion of the VSP data further uses the low frequency model.

5. The method of claim 1, further comprises:

identifying a portion of the subterranean formation in proximity to the wellbore based on a pre-determined criterion; and

processing the VSP data to generate a depth/time dependent angle model comprising an incidence angle of wave propagation in the portion of the subterranean formation,

wherein performing the seismic inversion of the VSP data further uses the depth/time dependent angle model.

6. The method of claim 5, further comprising:

processing the VSP data to generate pressure (P) wave to P wave reflectivity data and P wave to shear (S) wave reflectivity data,

wherein the portion of the subterranean formation is identified where both the P wave to P wave reflectivity data and the S wave to S wave reflectivity data are available.

7. The method of claim 5, further comprising:

comparing, where the elastic model intersects the wellbore, the elastic model and well logs of the wellbore to identify a difference of formation parameters;

adjusting the acquisition geometry to generate an adjusted acquisition geometry in response to identifying the difference, wherein the acquisition geometry is adjusted for at least one selected from a group consisting of expanding the portion of the subterranean formation and increasing VSP data redundancy within the portion of the subterranean formation;

performing an expanded seismic survey to obtain expanded VSP data based on the adjusted acquisition geometry; and

adjusting the elastic model based on the expanded VSP data to minimize the difference.

8. A system for seismic inversion of vertical seismic profile (VSP) data in an oilfield having a subterranean formation penetrated by a wellbore therein, the system comprising:

a seismic wave source device configured to perform a seismic survey;

a plurality of receivers disposed inside the wellbore and configured to obtain the VSP data during the seismic survey;

a VSP data inversion tool configured to;

identify a portion of the subterranean formation in proximity to the wellbore based on a pre-determined criterion;

process the VSP data to generate a depth/time dependent angle model comprising an incidence angle of wave propagation in the portion of the subterranean formation; and

perform the seismic inversion of the VSP data using the depth/time dependent angle model to generate an elastic model of the subterranean formation; and

a surface unit comprising a controller configured to adjust the operations of the oilfield based on the elastic model.

9. The system of claim 8, wherein the elastic model comprises at least one selected from a group consisting of acoustic impedance, shear impedance, and density of the subterranean formation in proximity to the wellbore.

10. The system of claim 8, wherein the VSP data inversion tool is further configured to:

process the VSP data to generate pressure (P) wave to P wave reflectivity data and P wave to shear (S) wave reflectivity data,

wherein the portion of the subterranean formation is identified where both the P wave to P wave reflectivity data and the S wave to S wave reflectivity data are available.

11. The system of claim 8, wherein the VSP data inversion tool is further configured to:

obtain an initial velocity model of the subterranean formation, the initial velocity model comprising acoustic velocities of wave propagation in proximity to the wellbore;

determine an acquisition geometry comprising locations of the seismic source and the plurality of receivers;

analyze direct arrival signals of the VSP data to generate transit time data for wave propagation from a location of the seismic source to locations to the plurality of receivers;

modify the initial velocity model to generate an updated velocity model by performing tomographic inversion of the transit time data; and

perform the seismic inversion of the VSP data further based on the updated velocity model to generate the elastic model of the subterranean formation.

12. The system of claim 11, wherein the updated velocity model comprises a two dimensional velocity model.

13. The system of claim 11, wherein the VSP data inversion tool is further configured to:

generate a low frequency model based on the updated velocity model,

wherein performing the seismic inversion of the VSP data further uses the depth/time dependent angle model.

14. The system of claim 11, wherein the VSP data inversion tool is further configured to:

compare, where the elastic model intersects the wellbore, the elastic model and well log of the wellbore to identify a difference of formation parameters; and

adjust the acquisition geometry to generate an adjusted acquisition geometry in response to identifying the difference, wherein the acquisition geometry is adjusted for at least one selected from a group consisting of expanding the portion of the subterranean formation and increasing VSP data redundancy within the portion of the subterranean formation;

perform expanded seismic survey to obtain expanded VSP data based on the adjusted acquisition geometry; and

adjust the elastic model based on the expanded VSP data to minimize the difference.

15. A computer readable medium storing instructions for seismic inversion of vertical seismic profile (VSP) data in an oilfield having a subterranean formation penetrated by a wellbore, the instructions when executed causing a processor to:

obtain an initial velocity model of the subterranean formation, the initial velocity model comprising acoustic velocities of wave propagation in proximity to the wellbore;

determine an acquisition geometry for obtaining the VSP data, the acquisition geometry comprising a plurality of receiver locations within the wellbore and a source location;

perform a seismic survey to obtain the VSP data based on the acquisition geometry;

analyze, using a central processing unit (CPU) of a computer system, direct arrival signals of the VSP data to generate transit time data for wave propagation from the source location to the plurality of receiver locations;

modify, using the CPU, the initial velocity model to generate an updated velocity model by performing a tomographic inversion of the transit time data;

generate, using the CPU, an elastic model of the subterranean formation by performing the seismic inversion of the VSP data using the updated velocity model; and

adjust the operations of the oilfield based on the elastic model.

16. The computer readable medium of claim 15,

wherein the updated velocity model comprises a two dimensional velocity model, and

wherein the elastic model comprises at least one selected from a group consisting of acoustic impedance, shear impedance, and density of the subterranean formation in proximity to the wellbore.

17. The computer readable medium of claim 15, the instructions when executed further causing the processor to:

generate a low frequency model based on the updated velocity model,

wherein performing the seismic inversion of the VSP data further uses the low frequency model.

18. The computer readable medium of claim 15, the instructions when executed further causing the processor to:

identify a portion of the subterranean formation in proximity to the wellbore based on a pre-determined criterion; and

process the VSP data to generate a depth/time dependent angle model comprising an incidence angle of wave propagation in the portion of the subterranean formation,

wherein performing the seismic inversion of the VSP data further uses the depth/time dependent angle model.

19. The computer readable medium of claim 18, the instructions when executed further causing the processor to:

process the VSP data to generate pressure (P) wave to P wave reflectivity data and P wave to shear (S) wave reflectivity data,

wherein the portion of the subterranean formation is identified where both the P wave to P wave reflectivity data and the S wave to S wave reflectivity data are available.

20. The computer readable medium of claim 18, the instructions when executed further causing the processor to:

compare, where the elastic model intersects the wellbore, the elastic model and well logs of the wellbore to identify a difference of formation parameters;

adjust the acquisition geometry to generate an adjusted acquisition geometry in response to identifying the difference, wherein the acquisition geometry is adjusted for at least one selected from a group consisting of expanding the portion of the subterranean formation and increasing VSP data redundancy within the portion of the subterranean formation;

perform an expanded seismic survey to obtain expanded VSP data based on the adjusted acquisition geometry; and

adjust the elastic model based on the expanded VSP data to minimize the difference.