Data processing: measuring – calibrating – or testing – Measurement system in a specific environment – Earth science
Reexamination Certificate
1999-04-22
2001-07-17
Oda, Christine (Department: 2862)
Data processing: measuring, calibrating, or testing
Measurement system in a specific environment
Earth science
C702S016000
Reexamination Certificate
active
06263284
ABSTRACT:
TECHNICAL FIELD
This invention relates to the general subject of seismic exploration and, in particular, to methods for using offset dependent reflectivity in the exploration for hydrocarbons.
BACKGROUND OF THE INVENTION
A seismic survey represents an attempt to image or map the subsurface of the earth by sending sound energy down into the ground and recording the “echoes” that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is placed at various locations near the surface of the earth above a geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data “cube” or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both 2D and 3D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. Chapter 1, pages 9-89, of Seismic
Data Processing
by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2D processing and that disclosure is incorporated herein by reference. General background information pertaining to 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Yilmaz, the disclosure of which is also incorporated herein by reference.
A modern seismic trace is a digital recording (analog recordings were used in the past) of the acoustic energy reflecting from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials.
The digital samples are usually acquired at 0.002 second (2 millisecond or “ms”) intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Each discrete sample in a conventional digital seismic trace is associated with a travel time, and in the case of reflected energy, a two-way travel time from the source to the reflector and back to the surface again, assuming, of course, that the source and receiver are both located on the surface. Many variations of the conventional source-receiver arrangement are used in practice, e.g. VSP (vertical seismic profiles) surveys. Further, the surface location of every trace in a seismic survey is carefully tracked and is generally made a part of the trace itself (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data—and attributes extracted therefrom—on a map (i.e., “mapping”).
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal “constant time slices” may be taken extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a horizontal 2D plane of seismic data. By animating a series of 2D planes it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
One particular branch of seismic attribute analysis that has been given increasing attention in recent years is amplitude-versus-offset (“AVO” hereinafter, or sometimes “AVA” amplitude-variation-with-angle-of-incidence) analysis, the broad goal of which is to make more easily visible to the explorationist offset-dependent reflectivity effects that may be found in some seismic data sets. The physical principle upon which AVO analyses are based is that the reflection and transmission coefficients at the top of an acoustic impedance boundary are dependent on the angle at which the seismic signal strikes that boundary. This property is true of all rock interfaces, but varies according to the particular properties of the rocks at the reflecting boundary. By way of example, gas-filled and water-filled sands have different reflection and transmission coefficients: these coefficients are also different for differing rock types, such as limestone (as compared with sandstone). Thus, by examining changes in seismic amplitude versus incidence angle (or its surrogate, shot-receiver offset) it is sometimes possible to make inferences about the subsurface lithology of a particular reflector that often could not otherwise be obtained without drilling.
These effects can sometimes be identified visually by arranging the moved-out seismic traces from a single gather (or from a composite “super” gather that includes more than one conventional gather) in order of the offset of each trace from the shot and then visually comparing the amplitudes on the near traces with the amplitudes on the far traces at the same time point. (See, for example, page 25 of “AVO Analysis: Tutorial & Review”, by J. Castagna, appearing in
Offset
-
Dependent Reflectivity—Theory and Practice of AVO Analysis
, John Castagna and Milo Backus (editors), SEG Press, pp. 3-36, 1993, the disclosure of which is incorporated herein by reference). Alternatively, various AVO attributes may be calculated from the unstacked gather, each gather conventionally yielding one AVO attribute trace. By combining many of these attribute traces, entire sections or volumes may be formed that superficially resemble conventional seismic data, but which are, in reality, displays that can be used to quickly identify AVO-type effects.
The traditional AVO-type analysis involves fitting a parametric curve (i.e., a function characterized by
Beaudoin Gerard
Crider Richard L.
Thomsen Leon
BP Corporation North America Inc.
Gabala James A.
Oda Christine
Taylor Victor J.
Watt T.
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