Data processing: measuring – calibrating – or testing – Measurement system in a specific environment – Earth science
Reexamination Certificate
2000-12-07
2003-06-03
McElheny, Jr., Donald E. (Department: 2862)
Data processing: measuring, calibrating, or testing
Measurement system in a specific environment
Earth science
C702S017000
Reexamination Certificate
active
06574563
ABSTRACT:
BACKGROUND OF THE INVENTION
The present invention relates to a method of processing two or more sets of seismic data signals obtained from the same subsurface area and in particular to a non-rigid method of matching sets of seismic data signals from the same subsurface area. This method is particularly adapted for use in analyzing time-lapsed seismic images of petroleum reservoirs to monitor the movement of fluids within the reservoirs.
Seismic data signals are collected to remotely sense subsurface geologic conditions, particularly in connection with the exploration for and production of hydrocarbons such as oil and natural gas. To gather seismic data signals, acoustic sources such as explosives, airguns, or vibrators are typically used to produce an acoustic pulse that is transmitted through the subsurface geologic formations. Changes in acoustic impedance between different geologic layers cause a portion of the acoustic energy to be reflected and returned toward the earth's surface. These reflected signals are received by seismic sensors and are processed to create images of the subsurface geology.
Often two or more sets of seismic data signals are obtained from the same subsurface area. These sets of seismic data signals may be obtained, for instance, by conducting two or more seismic surveys over the same subsurface area at different times, typically with time lapses between the seismic surveys varying between a few months and a few years. In some cases, the seismic data signals will be acquired to monitor changes in subsurface reservoirs caused by the production of hydrocarbons. The acquisition and processing of time-lapsed three dimensional seismic data signals over a particular subsurface area (commonly referred to in the industry as “4D” seismic data) has emerged in recent years as an important new seismic prospecting methodology.
The purpose of a 4D seismic survey is to monitor changes in the seismic data signals that can be related to detectable changes in geologic parameters. These (not necessarily independent) geologic parameters include fluid fill, propagation velocities, porosity, density, pressure, temperature, settlement of the overburden, etc. Of primary interest are changes taking place in the hydrocarbon reservoir zones of the imaged subsurface volume. Analyzing these changes together with petroleum production data assists the interpreter in understanding the complex fluid mechanics of the system of migration paths, traps, draining or sealing faults making up the hydrocarbon reservoir. This provides information regarding how to proceed with the exploitation of the field: where to place new production wells to reach bypassed pay zones and where to place injectors for enhanced oil recovery. This helps to produce a maximum quantity of hydrocarbons from the reservoir at a minimum of cost.
An important precondition to being able to map detectable changes of geological parameters is that the sets of seismic data signals, which have been acquired at different time instances or by using different acquisition methods, must be calibrated so they match each other. The phrase “match each other” in this context means that images of the seismic data signals reflected from places where no geological parameter changes have taken place must appear (virtually) identical in the different seismic data signal sets. In reality, this ideal situation is never met due to the limited repeatability of multiple state-of-the-art seismic surveys. Those familiar with marine seismic surveying know that navigating the surveying vessel and, more particularly, navigating the seismic source(s) and the streamers with the recording hydrophones can be repeated only with limited accuracy due to weather and tidal conditions. Further, changes in the system responses of the acquisition system are possible due to natural variability of the airguns or when sources or streamers have to be exchanged because of a defect. Other changes can be introduced due to different types of acquisition equipment, changes in data acquisition parameters, etc. Differences between the sets of seismic data signals that are attributable to noise, such as acquisition or processing artifact effects, make comparisons of images of the sets of seismic data signalsextremely difficult. These differences also reduce the confidence the interpreter is likely to have that the observable changes are due to changes in geologic parameters rather than noise such as acquisition or processing artifact effects.
Conventional methods for attempting to address these types of differences include compensating for changes in acquisition parameters or environmental conditions by appropriately interpolating, linear filtering and scaling the seismic data signals. Even when these compensation techniques have been employed, however, significant differences between images obtained from the sets of seismic data signals can often be observed that can be attributed solely to noise such as acquisition or processing artifact effects, not changes in the underlying geologic parameters.
Similar problems exist when attempting to compare images of different types of seismic data signals obtained from a particular subsurface area, such as seismic data signals associated with different seismic energy transmission modes (such as P-P and P-S transmission modes), seismic data signals acquired through the use of different types of seismic sensors (such as geophones and hydrophones), or seismic data signals acquired through the use of seismic sensors that simultaneously sense the orientation of the seismic energy (such as multi-component seismic sensors). At times, different types of seismic data signals that have been obtained simultaneously during a seismic survey of a particular subsurface area will show differences that can only be attributed to noise such as acquisition or processing artifact effects.
It is an object of the present invention to provide an improved method of processing seismic data signals that produces a seismic image of the subsurface area that is more readily comparable to an image obtained from a reference set of seismic data signals.
An advantage of the present invention is that the seismic image of the subsurface area allows changes in geologic parameters to be more readily detected
Another advantage of the present invention is that differences between the seismic image of the subsurface area and the image obtained from the reference set of seismic data signals that are attributable to noise such as acquisition or processing artifact effects are often substantially attenuated.
A further advantage of the present invention is that the matching occurs locally rather than globally, thus providing the method an opportunity to properly produce a seismic image of a petroleum reservoir even when seismic data signals received from overburden above the petroleum reservoir may be corrupted.
SUMMARY OF THE INVENTION
The present invention relates generally to the processing of seismic data signals and more particularly to a non-rigid method of matching sets of seismic data signals obtained from the same subsurface area. In one embodiment, the method involves the steps of decomposing the sets of seismic data signals into sample sets, generating displacement vectors indicating the directions and amounts samples from the second sample set may be translated to better match samples from the first sample set, and translating samples from the second sample set along the displacement vectors to produce a seismic image of the subsurface area. This method is particularly adapted for use in analyzing time-lapsed seismic images of petroleum reservoirs to monitor the movement of fluids within the reservoirs. The invention and its benefits will be better understood with reference to the detailed description below and the accompanying figures.
REFERENCES:
patent: 2317451 (1998-03-01), None
patent: 9627141 (1996-09-01), None
patent: 9811455 (1998-03-01), None
Figatner David S.
McElheny Jr. Donald E.
Schlumberger Technology Corporation
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