Data processing: measuring – calibrating – or testing – Measurement system in a specific environment – Earth science
Reexamination Certificate
2000-06-15
2003-07-15
Lefkowitz, Edward (Department: 2862)
Data processing: measuring, calibrating, or testing
Measurement system in a specific environment
Earth science
C702S016000, C702S017000
Reexamination Certificate
active
06594585
ABSTRACT:
TECHNICAL FIELD
The present invention relates generally to the field of seismic exploration and, in more particular, to methods of quantifying and visualizing subsurface structural and stratigraphic features in two and three dimensions. This invention also relates to the field of seismic attribute generation and the use of seismic attributes to detect the presence of hydrocarbons in the subsurface. Additionally, it relates to the correlation of seismic attributes with subsurface features that are conducive to the migration, accumulation, and presence of hydrocarbons. The invention disclosed herein will be most fully appreciated by those in the seismic interpretation and seismic processing arts.
BACKGROUND
A seismic survey represents an attempt to 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 moved to various positions across the surface of the earth above a geological 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 straight 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 methods interrogate some volume of the 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. The term “unstacked” seismic traces is used by those skilled in the art to describe seismic traces as they are collected in field recordings. This term also is applied to seismic traces during the processing sequence up to the point where traces are “stacked” or averaged together. General background information pertaining 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, the disclosure of which is incorporated herein by reference. Chapter 1, pages 9 to 89, of Yilmaz contains general information relating to conventional 2D processing and that disclosure is also incorporated herein by reference.
A modern seismic trace is a digital recording (analog recordings were used in the past) of the energy reflecting back 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. Thus, each digital sample in a seismic trace is associated with a travel time (in the case of reflected energy, a two-way travel time from the surface to the reflector and back to the surface again). Further, the surface location of each trace in a seismic survey is carefully recorded and remains associated with that trace during subsequent processing. 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 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 2D plane of seismic data. 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 subsequently applied to seismic data collected over other exploration targets.
That being said, one of the most challenging tasks facing the seismic interpreter—one of the individuals within an oil company that is responsible for reviewing and analyzing the collected seismic data—is locating these stratigraphic and structural features of interest within individual seismic lines or, more problematically, within potentially enormous seismic volumes. By way of example only, it can be important for exploration purposes to locate regions in the subsurface in which the frequency content of seismic events reflected therefrom and transmitted therethrough are different from the surrounding rocks, as these oft-times subtle frequency changes may be indicative of the presence of fluids (including gas) in the subsurface rocks. Additionally, rock stratigraphic information may be revealed through the analysis of spatial variations in a seismic reflector's character because these variations may often be empirically correlated with changes in reservoir lithology or fluid content. Since the precise physical mechanism which gives rise to these variations may not be well understood, it is common practice for interpreters to calculate a variety of attributes from the recorded seismic data and then plot or map them, looking for an attribute that has some predictive value. Given the enormous amount of data collected in a 3-D volume, further automated methods of enhancing the appearance of subsurface features related to the migration, accumulation, and presence of hydrocarbons are sorely needed.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.
SUMMARY OF THE INVENTION
The instant inventor has discovered an improved frequency domain based method of generating a
BP Corporation North America Inc.
Fellers, Snider, Blankenship, Bailey & Tippen, P.C.
Gutierrez Anthony
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