Full waveform inversion method for seismic data processing using preserved amplitude reverse time migration

Patent metadata

Field	Value
Publication number	US-10670751-B2
Application number	US-201615080729-A
Country	US
Kind code	B2
Filing date	Mar 25, 2016
Priority date	Mar 27, 2015
Publication date	Jun 2, 2020
Grant date	Jun 2, 2020

Abstract

A preserved-amplitude RTM-based FWI method is used to obtain an image of an explored subsurface formation. Model data corresponding to detected data is generated using a velocity model of the formation. Residuals representing differences between the modeled data and the detected data are back-propagated to then update the velocity model a local optimization based on a deconvolution formula employing a backward propagating wavefield and a forward propagating wavefield. Geophysical features of the formation are imaged based on the updated velocity model.

First claim

What is claimed is:

1. A method for obtaining an image of an explored subsurface formation, the method comprising:
obtaining detected data related to waves traveling through the explored subsurface formation;
generating modeled data corresponding to the detected data, using a velocity model of the explored subsurface formation, wherein the velocity model used initially to generate the modeled data is obtained by seismic tomography;
back-propagating residuals representing differences between the modeled data and the detected data;
updating the velocity model using a local optimization based on a deconvolution formula employing a backward propagating wavefield and a forward propagating wavefield, the deconvolution formula representing a preserved amplitude reverse time migration (RTM) based full waveform inversion (FWI) for a common data-acquisition-characteristic gather;
generating the image of geophysical features of the explored subsurface formation based on the updated velocity model; and
using the image to locate and/or monitor an oil and gas reservoir.

2. The method of claim 1 , wherein the common data-acquisition-characteristic gather is in a common shot domain, a common receiver domain, a common surface offset domain, a common subsurface offset domain, a common angle domain or a common plane wave domain.

3. The method of claim 1 , wherein the generating of the model data, the calculating of the differences, the back-propagating of the residuals and the updating of the velocity model are performed iteratively until a predetermined criterion is met.

4. The method of claim 1 , further comprising:
monitoring evolution of a cost function E calculated at each iteration as

E
⁡

(
v
)

=



p
obs

⁡

(

x
r

,
t
,

x
s

)

-

p
cal

⁡

(

x
r

,
t
,

x
s

)



2

=

∑

x
r

⁢

∑

x
s

⁢

∫

d
⁢

⁢

t
⁡

(

p
obs

⁡

(

x
r

,
t
,

x
s

)

-

p
cal

⁡

(

x
r

,
t
,

x
s

)

)

2

where p obs represents the detected data, p cal represents the modeled data, x r represents a receiver position, x s represents a shot position, and t is time along a sequence of amplitude values recorded by a receiver at the receiver position after a shot at the shot position.

5. The method of claim 1 , wherein the detected data is acquired during a seismic survey.

6. The method of claim 1 , wherein the deconvolution formula in a common shot domain used to calculate a perturbation of the velocity model is:

δ
⁢

⁢

v
⁡

(
x
)

=

v
0
3

2

Assignees

• Cgg Services Sa
• Cgg Services Sas

Inventors

• Qin Botao
• Lambare Gilles

Classifications

• G01V2210/614

  Synthetically generated data · CPC title

• G01V2210/679

  Reverse-time modeling or coalescence modelling, i.e. starting from receivers · CPC title

• G01V2210/67

  Wave propagation modeling · CPC title

• G01V1/303

  for determining velocity profiles or travel times · CPC title

• G01V1/282 Primary

  Application of seismic models, synthetic seismograms · CPC title