A process for characterising the evolution of an oil or gas reservoir over time

Patent metadata

Field	Value
Publication number	US-2016349391-A1
Application number	US-201515117370-A
Country	US
Kind code	A1
Filing date	Feb 9, 2015
Priority date	Feb 12, 2014
Publication date	Dec 1, 2016
Grant date	—

Abstract

Disclosed is a method for characterising the evolution of a reservoir by determining a seismic wavelet which links observed seismic data to a sequence of reflectivities. The method comprises obtaining seismic data ( 200 ) representing seismic changes which have occurred between a first time and a second time, said seismic data comprising a plurality of seismic traces; and performing an optimisation operation simultaneously ( 230 ) on the seismic traces so as to optimise for said seismic wavelet. The optimisation operation may be performed without using known reflectivity data as an input.

First claim

1 . A method for characterising the evolution of a reservoir by determining a seismic wavelet which links observed seismic data to a sequence of reflectivities, said method comprising:
obtaining seismic data representing seismic changes which have occurred between a first time and a second time, said seismic data comprising a plurality of seismic traces; and performing an optimisation operation simultaneously on said plurality of seismic traces so as to optimise for said seismic wavelet.

2 . The method as claimed in claim 1 wherein said optimisation operation is performed without using known reflectivity data as an input.

3 . The method as claimed in claim 1 wherein said optimisation operation comprises simultaneously optimising for said seismic wavelet and reflectivity change data occurring between said first time and said second time.

4 . The method as claimed in claim 3 wherein said optimisation step comprises minimising a cost function comprising a measurement of the difference between the seismic data and a convolution of the seismic wavelet and reflectivity change data.

5 . The method as claimed in claim 1 wherein each reflectivity change described by said reflectivity change data is defined by two parameters describing the positions of two reflectors defining the change in reflectivity and a single amplitude parameter representing the magnitude of a measured amplitude change at the positions of said two reflectors, the amplitude change being equal in magnitude and of opposite sign at these positions.

6 . The method as claimed in claim 1 comprising the steps of:
providing a base survey of the reservoir with a set of seismic traces at said first time;
providing a monitor survey of the reservoir, taken at said second time, with a set of seismic traces associated to the same positions as in the base survey;
determining said seismic data from said base survey and monitor survey.

7 . The method as claimed in claim 6 wherein said step of determining said seismic data comprises aligning said monitor and base surveys; and subtracting said base survey from said monitor survey.

8 . The method as claimed in claim 6 wherein said base and monitor surveys have been performed at a location remote from a well, or adjacent to a horizontal or sub-vertical well.

9 . The method as claimed in claim 6 , wherein said base and monitor surveys have been performed at the location of interest for the wavelet being determined.

10 . The method as claimed in claim 1 comprising a scaling step so as to determine an absolute value for the amplitude of the seismic wavelet.

11 . The method as claimed in claim 10 wherein said scaling step comprises defining a scaling factor such that ΔS=αω*1/αΔR, where α is the scaling factor, ΔS is the seismic data, ω is the seismic wavelet and ΔR is a reflectivity change data.

12 . The method as claimed in claim 10 wherein said scaling step comprises convolving the unsealed wavelet with actual reflectivity measurements taken from another location of the reservoir.

13 . The method as claimed in claim 10 wherein said scaling step comprises using travel-time information to estimate the actual reflectivity measurements.

14 . The method as claimed in claim 13 wherein said actual reflectivity measurements are determined from the product of measured relative velocity changes and a factor based on an estimated ratio between relative velocity changes and relative density changes.

15 . The method as claimed in claim 10 wherein said scaling step comprises directly inferring maximum reflectivity changes from production history data.

16 . The method as claimed in claim 1 further comprising the step of using the results of said method to aid hydrocarbon recovery from a reservoir.

17 . A computer program comprising computer readable instructions which, when run on suitable computer apparatus, cause the computer apparatus to perform the method of claim 1 .

18 . A computer program carrier comprising the computer program of claim 17 .

19 . An apparatus specifically adapted to carry out the steps of the method as claimed claim 1 .

Assignees

• Total Sa

Inventors

• Blanchard Thomas David
• Thore Pierre Daniel
• Hubans Christian

Classifications

• G01V1/308 Primary

  Time lapse or 4D effects, e.g. production related effects to the formation (fluid flow per se E21B47/00) · CPC title

• G01V2210/6122

  Tracking reservoir changes over time, e.g. due to production · CPC title