S-wave anisotropy estimate by automated image registration

Patent metadata

Field	Value
Publication number	US-9784863-B2
Application number	US-201214239753-A
Country	US
Kind code	B2
Filing date	May 11, 2012
Priority date	Sep 26, 2011
Publication date	Oct 10, 2017
Grant date	Oct 10, 2017

Abstract

The present disclosure provides a system and method for estimating fracture density within a subsurface formation from S-wave seismic data. In one embodiment, the S-wave seismic data is separated into fast (“S 1 ”) and slow (“S 2 ”) data. A computer is used to compute local similarity of the S 1 and S 2 data and to compute a cumulative time-difference by which the S 2 data lags the S 1 data from the local similarity. Based on the computed cumulative time-difference, the fracture density of a subsurface formation is estimated.

First claim

What is claimed is:

1. A method, comprising:
obtaining S-wave seismic data of a subsurface formation, wherein the S-wave seismic data is acquired from the subsurface formation using multi-component receivers adapted to measure a plurality of motion vector components including two horizontal components, the S-wave seismic data comprising a plurality of seismic time samples;
separating the S-wave seismic data into fast (“S 1 ”) and slow (“S 2 ”) data;
using a computer to compute local similarity of the S 1 and S 2 data at each time sample;
using a computer to compute at each time sample a cumulative time-difference by which the S 2 data lags the S 1 data from the local similarity, wherein computing the cumulative time-difference includes,
performing a local similarity attribute scan between the S 1 and S 2 data;
generating a warping function, w(t), by detecting areas of similarity in the local similarity attribute scan, and
determining the cumulative time-difference, ΔT S cum (t), based upon w(t);

calculating an instantaneous S-wave time-difference, δt S ins (t), at each seismic time sample from the cumulative S-wave time difference;
estimating fracture density within the subsurface formation from the cumulative time-difference, ΔT S cum (t); and
drilling a well into the subsurface formation based at least in part on the fracture density.

2. The method of claim 1 , wherein the cumulative time-difference, ΔT S cum (t), is determined using a formula that can be expressed as
Δ T S cum ( t )=( w ( t )−1) t,

where t is reflection travel time.

3. The method of claim 1 , further comprising:
generating time-compensated S 2 data based upon the →T S cum (t) to time shift the S 2 data.

4. The method of claim 1 , wherein the subsurface formation has a primary fracture direction, the S 1 and S 2 data is generated by vector-rotating the horizontal components to directions parallel and normal to the primary fracture direction.

5. The method of claim 1 , wherein the S 1 and S 2 data are generated by performing a layer stripping process on the S-wave seismic data to generate the S 1 data and a registered S 2 data which has a time-difference applied and removing the time-difference applied to the registered S 2 data to generate the S 2 data.

6. The method of claim 1 , wherein the instantaneous S-wave time-difference is calculated using a formula that can be expressed as

δ
⁢

⁢

t
S
ins

⁡

(
t
)

=

d
⁢

⁢
Δ
⁢

⁢

T
S
cum

⁡

(
t
)

d
⁢

⁢
t

.

7. The method of claim 6 , further comprising:
estimating the fracture density based on δ S ins (t).

8. The method of claim 1 , further comprising:
producing hydrocarbons from the well.

Assignees

• Bansal Reeshidev
• Fomel Sergey
• Matheney Michael P
• Exxonmobil Upstream Res Co

Inventors

• Bansal Reeshidev
• Fomel Sergey
• Matheney Michael P

Classifications

• G01V1/284 Primary

  Application of the shear wave component and/or several components of the seismic signal · CPC title