Data processing: measuring – calibrating – or testing – Measurement system in a specific environment – Earth science
Reexamination Certificate
2001-06-15
2004-05-11
Hoff, Marc S. (Department: 2857)
Data processing: measuring, calibrating, or testing
Measurement system in a specific environment
Earth science
C702S016000, C702S017000
Reexamination Certificate
active
06735526
ABSTRACT:
FIELD OF THE INVENTION
The present invention is concerned with a method of processing seismic signals in order to identify and characterize subsurface features within geological formations. The invention is applicable both to onshore and offshore exploration.
BACKGROUND OF THE INVENTION
In conventional 3-D seismic surveying, seismic data is acquired along closely spaced lines to provide detailed subsurface information. With such high density coverage, large volumes of digital data must be recorded, stored and processed prior to interpretation. The processing requires extensive computer resources. When the data has been processed it is interpreted in the form of a 3-D cube which effectively represents a display of subsurface features. The information within the cube can be displayed in various forms, such as horizontal time slice maps, vertical slices or sections in any direction.
Generally, in traditional seismic interpretation, one or more seismic events is identified and tracked to yield a set of seismic horizons. Together these horizons are used to form the structural framework of the subsurface in two-way time, or depth as the case may be. All subsequent geological modeling and most of today's seismic inversion schemes rely heavily on this framework. For example, seismic attributes can be extracted around an interpreted horizon and used to characterize a reservoir unit.
SUMMARY OF THE INVENTION
It is an object of the present invention to provide an improved method of utilizing seismic data in order to provide a more reliable means of detecting, separating and identifying geological features.
According to one aspect of the invention, the extraction of seismic information from the data acquired is directed or steered along the object which is to be characterized.
This sense of directionality is lacking in current conventional seismic volume interpretations; neither the direction, nor the shape of the bodies is utilized in the current technology. In general, in the present invention, the seismic volume may be converted into a domain where a particular geological object can be detected more easily. For example, shallow-gas sands may show up as bright spots in an ‘energy’ attribute volume. Volume attribute transformations can be both single-trace and multi-trace.
Thus directional seismic attributes are used to enhance the texture of the objects of interest. Directional attributes are here defined as quantities derived from a set of seismic traces along the spatial direction of the body of interest. In a subsequent step, geometrical constraints might be applied to the enhanced texture volume to improve the detection of the geological objects of interest still further. The procedure is particularly convenient for detecting gas chimneys, but can be used equally well to detect faults, layers, and any other type of geological objects with a spatial direction and shape. The procedure is also suited for the detection of reservoir changes by the use of time lapse seismic techniques.
Conveniently, the invention provides a two step procedure aimed at detection and separation of objects from seismic data volumes. The first step may enhance the texture of seismic bodies, while post-processing the enhanced volume is the second step. In both steps the spatial direction is utilized. After the enhanced volumes are recognized they can be extracted and displayed for characterization. The procedure can be applied to multiple seismic volumes (reflectivity, impedance, near offset, far offset, gradient, intercept, etc.) in an iterative manner.
According to the invention, therefore, seismic attributes are extracted relative to the spatial direction of the objects which it is desired to detect. For example, a gas chimney is basically a vertical disturbance of the seismic response due to gas seepage. To detect such an object, seismic data attributes would be extracted in a vertical direction. This may be achieved e.g. by extracting attributes in multiple time gates (actually multiple 3D control volumes) above and below each extraction point. Stratigraphic objects (layers, channels, sequences, etc.) and faults cannot be detected as simply as vertical disturbances because their direction varies spatially. However, if the dominating direction in the seismic data at every sample position is known, this direction can be used to orient the time gates or 3D sub-volumes parallel to the direction, from which attributes are extracted. The local dominating direction, expressed as dip and azimuth, can be calculated at every seismic sample position in different ways.
The number, size and separation distance of the extraction volumes are parameters that control the importance of spatial direction in the procedure (attribute directivity). The accuracy of the spatial direction estimate and the attribute directivity can be tuned to prevent degradation in the attributes. According to another aspect of the invention, therefore, the direction and shape of the control volumes from which attributes are extracted are adjusted to provide an optimum combination, in dependence upon the nature of the geological features which is to be detected.
Not only is the directivity of the attributes important but also the type and combination of attributes may be an important factor in the procedure. Preferably, only attributes that enhance the difference between objects and background are elected. Multiple attributes, possibly extracted from different seismic volumes may subsequently be combined to yield optimal separation.
Hundreds of seismic attributes are nowadays available on seismic workstations. These include the following types with potential for use in the method of the present invention:
a) seismic amplitudes at sample positions (i.e. the raw trace data)
b) instantaneous attributes: amplitudes, phase and frequency
c) pre-stack attributes: intercept and gradient energy
d) trace to trace similarity
e) minimum and maximum amplitudes and areas
f) local dip & azimuth (used to steer the extraction volumes)
g) the number of sign changes in the derivative of the seismic traces (a new attribute).
Which of these or other attributes are chosen to enhance the texture of an object will depend upon the nature of the objects and its image quality. Gas chimneys and faults for example will generally exhibit lower trace-to-trace similarity than stratigraphic objects. This is because the images of faults and gas chimneys are degraded due to limitations in acquisition and processing. Complex overburden effects for example, cannot be removed properly from the seismic image by current processing technology. Also the spatial sampling in the acquisition pattern degrades the resolution and signal to noise ratio of gas chimneys and faults.
In general, stratigraphic objects tend to be less degraded than other objects. This is mainly due to the fact that seismic acquisition and processing techniques are currently tuned to focus on horizontal and mildly dipping objects, rather than vertical, or steeply dipping events. With these considerations in mind it is logical to use trace-to-trace similarity as one of the attributes to enhance the difference between gas chimneys (or faults) and their surroundings. Other attributes with separation power could be ‘energy’ and ‘instantaneous frequency’.
In general, the selection of attributes would be based on a study of the object and its characteristics and/or by an evaluation of the separation strength in the attribute control volumes and/or a combination of these. Each attribute in itself has separation power but maximum separation may be achieved by optimally combining the total set of attributes.
According to another aspect of the invention, a method of mapping a fault comprises extracting seismic information from data acquired using generally vertically oriented seismic control volumes sequentially in the region of the fault.
According to a further aspect of the invention, a method of mapping a gas chimney or other gas formation comprises extracting seismic information from data acquired using generally vert
Bril A. H.
De Groot P. F. M.
Heggland Roar
Meldahl Paul
Den Norske Stats Oljeselskap A.S.
Gutierrez Anthony
Hoff Marc S.
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