3-D seismic event tracking

Details 3-D seismic event tracking 3-D seismic event tracking

2001-01-31

2002-10-08

McElheny, Jr., Donald E. (Department: 2862)

Data processing: measuring, calibrating, or testing

Measurement system in a specific environment

Earth science

Reexamination Certificate

active

06463387

ABSTRACT:

TECHNICAL FIELD
This invention relates to the general subject of seismic exploration and, in particular, to seismic interpretation and to methods for improving the quality of picked and interpreted seismic data.
BACKGROUND OF THE INVENTION
The broad goal of a seismic survey is to image or map the subsurface of the earth by sending 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 systematically positioned at a variety of 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 partially reflected, and, upon its return, is recorded at a great many locations on the surface. The seismic signals are partially reflected from discontinuities of various types in the subsurface (including reflections from “rock layer” boundaries) and the reflected energy is transmitted back to the surface of the earth where it is recorded as a function of travel time. The sensors that are used to detect the returning seismic energy are usually geophones (land surveys) or hydrophones (marine surveys). The recorded returning signals, which are at least initially continuous electrical analog signals which represent amplitude versus time, are generally quantized and recorded as a function of time using digital electronic so that each data sample point may be operated on individually thereafter.
Multiple source activation/recording combinations are subsequently 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 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 that has been reflected from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the acoustic properties of the subsurface materials. The digital samples that make up the recording 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, ocean bottom surveys, etc. Further, the surface location of every receiver in a seismic survey is carefully tracked and is generally made a part of the recorded trace (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 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 3D volume by collecting and displaying the seismic traces that lie along the path of selected azimuth. 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, who is one of the individuals within an oil company whose job it is to identify 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 the seismic survey 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.
Of course, the positioning of a drilling site is often critically dependent on the seismic data as interpreted by the explorationist, with the positioning largely determining the success or failure of the venture. An integral element of the process of seismic interpretation is the creation of a map that shows the lateral extent and depth (or time) of one or more target horizons. Although this map might be assembled in many ways, in a typical case the explorationist uses both printed and computer-displayed seismic records to trace the occurrence of specific seismic reflectors and/or seismic features throughout the survey, these reflectors and/or features being ones that are associated with a subsurface rock unit of interest. The general process of identification and selection of seismic events throughout a seismic section or volume is known as “picking” to those skilled in the arts.
Operationally, the explorationist usually begins the process of interpretation by locating the reflector of interest on seismic traces near a location where there is substantial confidence that it can be found and accurately characterized in the seismic data. For example, seismic traces that have been collected near an existing well are good candidates for use as a starting point, because the location of the target subsurface unit can often be verified via the use of synthetic seismograms that have been calculated from well logs that were taken in the well. In other cases, the explorationist might “tie” an unpicked seis

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