Efficient Method For Inversion of Geophysical Data

• US 20110000678A1
• Filed: 01/26/2009
• Published: 01/06/2011
• Est. Priority Date: 03/21/2008
• Status: Active Grant

• Current Assignee: David L. Hinkley, Jerome R. Krebs
• Original Assignee: David L. Hinkley, Jerome R. Krebs
• Inventors: Krebs, Jerome R., Hinkley, David L.
• Granted Patent: US 8,812,282 B2
• Time in Patent Office: Days
• US Class Current: 166/369
• CPC Class Codes: G01V 1/282 Application of seismic models, synthetic seismograms
• CPC Class Codes: G01V 1/301 for determining seismic cross-sections or geostructures
• CPC Class Codes: G01V 2210/50 Corrections or adjustments related to wave propagation noise handling G01V2210/30

Abstract

A method for efficient inversion of measured geophysical data from a subsurface region to prospect for hydrocarbons. Gathers of measured data (40) are encoded (60) using a set of non-equivalent encoding functions (30). Then all data records in each encoded gather that correspond to a single receiver are summed (60), repeating for each receiver to generate a simultaneous encoded gather (80). The method employs iterative, local optimization of a cost function to invert the encoded gathers of simultaneous source data. An adjoint method is used to calculate the gradients of the cost function needed for the local optimization process (100). The inverted data yields a physical properties model (110) of the subsurface region that, after iterative updating, can indicate presence of accumulations of hydrocarbons.

Claims

1. A computer-implemented method for inversion of measured geophysical data to determine a physical properties model for a subsurface region, comprising:

(a) obtaining a group of two or more encoded gathers of the measured geophysical data, wherein each gather is associated with a single generalized source or, using source-receiver reciprocity, with a single receiver, and wherein each gather is encoded with a different encoding function selected from a set of non-equivalent encoding functions;

(b) summing the encoded gathers in the group by summing all data records in each gather that correspond to a single receiver (or source if reciprocity is used), and repeating for each different receiver, resulting in a simultaneous encoded gather;

(c) assuming a physical properties model of the subsurface region, said model providing values of at least one physical property at locations throughout the subsurface region;

(d) inverting the measured geophysical data, one simultaneous encoded gather at a time, using the assumed physical properties model as an initial model, and iteratively updating said model to minimize a cost function measuring degree of misfit between model-simulated data and the measured geophysical data to generate an updated physical properties model, wherein model adjustments are made using a gradient of the cost function with respect to at least one model parameter, which gradient is computed from a time integration of a product of encoded simultaneous-source data simulated forward in time and encoded simultaneous-source data simulated backward in time; and

(e) downloading the updated physical properties model or saving it to computer storage.

2. The method of claim 1, wherein inverting a simultaneous encoded gather of measured geophysical data comprises

(i) computer simulating a simultaneous encoded gather corresponding to the simultaneous encoded gather of measured data, using the assumed physical properties model, wherein the simulation uses source signatures encoded with the same encoding functions used to encode the simultaneous encoded gather of measured data, wherein an entire simultaneous encoded gather is simulated in a single simulation operation;

and

(ii) computing a cost function measuring degree of misfit between the simultaneous encoded gather of measured data and the simulated simultaneous encoded gather.

3. The method of claim 1, further comprising using a different set non-equivalent encoding functions for at least one iteration of the iterative updating of the model.

4. The method of claim 1, wherein inverting the measured geophysical data comprises:

computing a forward simulation of the encoded simultaneous-source data, in a single simulation run, using a current physical properties model M and using as a source a simultaneous source gather signature encoded with the same encoding functions c_g used to encode the measured data, to get ψ

_calc;

(ii) computing the cost function δ

by subtracting the simultaneous encoded gather of measured geophysical data from the result of step (i);

(iii) computing a reverse simulation (i.e. backwards in time) using δ

as simulation source, producing ψ

_adjoint; and

(iv) computing an integral over time of the product of ψ

_calc and ψ

_adjoint to get the gradient of the cost function; and

(v) using the gradient of the cost function to adjust and update model M.

5. The method of claim 1, wherein said encoded gathers of measured data are encoded by temporally convolving all traces from the gather with a corresponding encoded source signature, said encoded source signature being the convolution of a source function for the gather with the encoding function selected for the gather.

6. The method of claim 1, wherein the two or more encoded gathers of measured data are obtained by obtaining gathers of data from a geophysical survey in which data are acquired from a plurality of simultaneously operating, uniquely encoded source devices.

7. The method of claim 1, wherein the measured geophysical data are from a seismic survey.

8. The method of claim 7, wherein the generalized seismic sources are either all point sources or all plane-wave sources.

9. The method of claim 2, wherein the measured geophysical data include measured or estimated signatures of each source activation and the encoded source signatures used in the simulation operations are signatures made by temporally convolving the measured or estimated source signatures with the same encoding functions used to encode the corresponding measured gather in step (a).

10. The method of claim 1, wherein the encoding functions are of a type selected from a group consisting of linear, random phase, chirp, modified chirp, random time shift, and frequency independent phase encoding.

11. The method of claim 1, wherein the encoding functions are of one type for some sources and of another type for other sources, each type being selected from a group consisting of linear, random phase, chirp, modified chirp, random time shift, and frequency independent phase encoding.

12. The method of claim 1, wherein the encoding functions are optimized with respect to the cost function being used.

13. The method of claim 1, wherein the forward or backward simulation operations in step (d) are performed with a finite difference, finite element or finite volume simulation code.

14. The method of claim 7, wherein the physical properties models are models of seismic wave velocity, seismic elastic parameters, seismic anisotropy parameters or seismic anelasticity parameters.

15. The method of claim 1, wherein a local cost function optimization method such as gradient line search, conjugate gradients or Newton'"'"'s method is used to update the model.

16. The method of claim 1, wherein the cost function is the L1-norm cost function or the L2-norm cost function and the cost function may contain regularization terms.

17. The method of claim 1, wherein the non-equivalent encoding functions are substantially orthogonal functions.

19. A method for producing hydrocarbons from a subsurface region, comprising:

(a) performing a geophysical survey of the subsurface region;

(b) obtaining a physical properties model, said model having been constructed using a method as recited in claim 1, which is incorporated herein by reference;

(c) using the physical properties model to identify a hydrocarbon bearing zone in the subsurface region;

(d) drilling a well into the zone and producing hydrocarbons from the well.

18. A method for inversion of measured geophysical data from a subsurface region to prospect for hydrocarbons, comprising:

(a) obtaining a group of two or more encoded gathers of the measured geophysical data, wherein each gather is associated with a single generalized source or, using source-receiver reciprocity, with a single receiver, and wherein each gather is encoded with a different encoding function selected from a set of non-equivalent encoding functions;

(b) summing the encoded gathers in the group by summing all data records in each gather that correspond to a single receiver (or source if reciprocity is used), and repeating for each different receiver, resulting in a simultaneous encoded gather;

(c) assuming a physical properties model of the subsurface region, said model providing values of at least one physical property at locations throughout the subsurface region;

(d) inverting the measured geophysical data, one simultaneous encoded gather at a time, using the assumed physical properties model as an initial model, and iteratively updating said model to minimize a cost function measuring degree of misfit between model-simulated data and the measured geophysical data to generate an updated physical properties model, wherein model adjustments are made using a gradient of the cost function with respect to at least one model parameter, which gradient is computed from a time integration of a product of encoded simultaneous-source data simulated forward in time and encoded simultaneous-source data simulated backward in time; and

(e) using the updated physical properties model to prospect for hydrocarbons in the subsurface region.