Patent Grant
7944774
Not applicable.
1. Field of the Invention
The invention relates generally to the field of seismic surveying of the Earth's subsurface. More specifically, the invention relates to methods for determining whether seismic data have been acquired to sufficient spatial density to avoid distortions in generating images of the Earth's subsurface from seismic data.
2. Background Art
In seismic surveying, seismic energy sources are used to generate a seismic signal that propagates into the earth and is at least partially reflected by subsurface seismic reflectors. Such seismic reflectors typically are located at the interfaces between subterranean formations having different acoustic properties, specifically differences in acoustic impedance at the interfaces. The reflections are detected by seismic receivers at or near the surface of the earth, in an overlying body of water, or at known depths in boreholes. The resulting seismic data may be processed to yield information relating to the geologic structure and properties of the subterranean formations and their potential hydrocarbon content.
A purpose for various types of seismic data processing is to extract from the data as much information as possible regarding the subterranean formations. In order for the processed seismic data to accurately represent geologic subsurface properties, the reflection amplitudes need to be represented accurately. Non-geologic effects can cause the measured seismic amplitudes to deviate from the amplitude caused by the reflection from the geologic target. Amplitude distortions resulting from irregular distribution of source and receiver positions during data acquisition is a particularly troublesome non-geologic effect. If uncorrected, these non-geologic effects can distort the seismic image and obscure the geologic picture.
A seismic energy source generates an acoustic wave that reflects from or “illuminates” a portion of reflectors at different depths in the subsurface. In a three-dimensional (3D) survey, seismic signals are generated at a large number of source locations, detected at a large number of receiver locations and the survey generally illuminates large areas of the reflectors. U.S. Pat. No. 7,336,560 issued to Rekdal et al. describes certain data density issues concerning marine seismic data. According to the Rekdal et al. '560 patent, processing techniques known in the art including prestack 3D migration algorithms can produce good images of the sub-surface horizons only if the surface distribution of sources and receivers is relatively uniform. In practice, there are typically irregularities in the distribution of sources and receivers. Obtaining perfectly regular acquisition geometry is typically impracticable. Consequently, according to the Rekdal et al. '560 patent, prestack 3D migrated seismic images often include non-geologic artifacts. Such artifacts can interfere with the interpretation of the seismic image and attribute maps.
In marine seismic surveying, one or more sensor cables called streamers is towed by a survey vessel near the surface of a body of water. A seismic energy source such as an air gun or air gun array is actuated at selected times. It is well known in the art that in marine seismic surveys, the streamers generally do not form straight lines behind the survey vessel. Typically marine currents and other factors such as propeller wash from the survey vessel cause the streamers to be displaced laterally, a phenomenon called “feathering.” Changes in marine currents often cause changes in the feathering. In such circumstances, if the planned sail line (direction of motion) separation of the seismic vessel is maintained, then feathering will lead to coverage “holes” at some offsets or offset ranges. The term “coverage hole” as used in the Rekdal et al. '560 patent refers to a surface area where, for a given offset (source to sensor distance) or offset range, there are believed to be inadequately spatially sampled data recorded. Data are typically defined to be “located” at the surface midpoint positions between the seismic source position and the seismic sensor position at the time of acquisition of a seismic signal recording. Such coverage holes can vary in size, irregularity, and density of data remaining in the hole. It is possible to have holes where no data are present. Coverage holes may be of several kilometers extension in the sail line (inline) direction where streamers have feathered in the same direction for a long continuous length of the intended sail line, but are generally smaller in the crossline direction (orthogonal to the sail line), as this width is governed by the amount of feathering of the streamers.
In marine seismic streamer surveys, if data density criteria known in the art are used, portions of the subsurface may be believed to be inadequately covered with seismic data recordings due to streamer feathering and other causes. Thus, using such prior art seismic data density evaluation criteria, it may be believed that additional passes of the seismic vessel and streamers through the prospect survey area are required. Additional “sail-lines” (passes of the vessel and streamers through the survey area) were also thought to be needed by reason of steering the vessel to achieve acceptable coverage. That means that the lateral distance between streamer positions in all the passes made by the vessel can be on average less than in the original acquisition plan. These additional passes significantly increase the time and associated cost to complete a survey. These additional passes of the survey vessel are referred to as “infill shooting” or just “infill.” A large portion of marine seismic data acquisition in a particular survey area can be infill shooting because of perceived inadequacy of data density. The infill shooting may take up to several weeks or even months to complete. Thus, it is not uncommon to spend 15-30% of total acquisition costs on infill acquisition.
According to the Rekdal et al. '560 patent, the maximum data hole sizes that will provide acceptable subsurface coverage are typically determined prior to acquisition, and are typically independent of local factors such as geology and survey objectives. Criteria for a seismic survey, such as acceptable subsurface coverage, are commonly called “infill specifications.” An object of the method described in the Rekdal et al. '560 patent is to determine whether the coverage holes are of sufficient size so as to require infill acquisition.
The method disclosed in the Rekdal et al. '560 patent, as one example, makes use of certain assumptions about the required degree of data coverage based in part on substantially discontinued seismic data processing procedures. Such procedures, for example, consisted of “binning” the acquired seismic data, summing or “stacking” seismic data within each bin, and then “migrating” the data after stacking. The requirements for migration in such processing are that each of the stacked traces reasonably represents the same sum of a set of offset traces at each location. In order for the stacked trace to have similar properties at each location associated with a bin, it is important that the stacked trace be the sum of a set of similar “offset” (distance between the seismic source and receiver) traces.
To ensure such similarity, traces are summed over a small area (a “bin”) such that a contribution from each of the expected offset traces is present in the sum. There are several problems with such procedure. First, the traces are summed over an area. Even if normal moveout (“NMO”) has been correctly performed, in the presence of reflective horizon “dip” (change in depth with respect to position), the reflective event times will not be aligned. This is often referred to as “bin smear”, and results in the loss of high frequency data content for dipping reflective events. Second, if a trace at a particular offset is missing, then either new data should be acquired (infill data), or the bin can be expanded (overlapped into adjacent areas) to see whether a suitable trace is available. Such bin “flexing” obviously increases the “bin smear”, but if only a small number of traces are used, this may not be a large problem. If an acceptable trace is found, then it is copied into the required bin and may therefore now contribute to more than one stacked trace.
Some bins may contain more than one trace of the required offset. In order to keep the stack trace balance similar at all bin locations, extra traces in any such bin are not used. There are several criteria for which trace of a plurality of traces in a bin should be used, but most commonly the trace that is selected is the one having a position closest to the position of the bin center, as this potentially reduces the bin smear. However, such procedure means that some of the traces that have been acquired may be discarded from further processing.
It is currently common in seismic data acquisition, as explained above with reference to the Rekdal et al. '560 patent, to make decisions on whether infill data should be acquired based on an evaluation of what traces fall in each bin of the survey. A procedure known as “flex binning” may be performed (typically in real time during acquisition) to infill “holes” where some offsets are missing from certain bins. However, it is uncommon to “flex” more than a small distance either side of the nominal bin location because of the bin smear that would be associated with collecting traces from further away, and such “flexing” is usually based on a rectangular bin criteria.
It is known in the art to perform migration on seismic data prior to stacking. See, for example, U.S. Pat. No. 6,826,484 issued to Martinez et al. In a prestack migration sequence, each trace to be processed is migrated using its actual location (not the average of a stack set, or a theoretical bin center). Trace locations may be output from the migration stage at any selected location, and such locations are generally positioned on a grid which is associated with bin centers. The output traces can then be stacked. Despite the change in processing methodology from post stack migration, the traces selected for processing and the methods of infill selection used in the industry have remained essentially the same.
The assumptions concerning data coverage as explained above have caused the development of marine seismic survey techniques in which is it is desirable to maintain the geometry of the streamers as closely as possible in a straight line, parallel pattern behind the survey or towing vessel. There are devices known in the art for steering seismic streamers, and methods for using such devices have been developed that have as an objective the arrangement of streamers in such straight, parallel patterns despite factors such as propeller wash from the survey vessel and cross currents in the water (transverse to the direction of motion of the survey vessel). See, for example, U.S. Pat. Nos. 6,932,017, 7,080,607 and 7,162,967 issued to Hillesund et al. with reference to streamer steering methods and systems. An example streamer steering device is described in U.S. Pat. No. 6,144,342 issued to Bertheas et al.
There continues to be a need for marine seismic acquisition techniques that reduce the amount of infill coverage and increase overall survey efficiency.
A method for marine seismic surveying according to one aspect of the invention includes towing a plurality of seismic sensors in a body of water. The sensors are disposed in a plurality of laterally spaced apart streamers. A seismic energy source in the body of water is actuated at selected times, and seismic signals are detected at the sensors resulting from the actuation of the seismic energy source. A data trace is created for each of the detected signals. At least one Fresnel zone is determined for at least some of the seismic data traces. A contribution of each of the traces to each one of a plurality of output location bins defined in a predetermined pattern is computed, based on the Fresnel zone associated with each trace. Based on the computed contributions, a maximum lateral distance between corresponding seismic sensors is determined that will result in a contribution sum above a selected threshold in each bin.
In one example, the maximum distance is used to operate streamer steering devices so that the distance is maintained along each streamer.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
A device for determining the geodetic position of the survey vessel 10 such as a global positioning satellite (“GPS”) receiver, shown schematically at 12A, may be disposed on the survey vessel 10. Other geodetic position determination devices are known in the art. The foregoing elements of the recording system 12 are familiar to those skilled in the art, and with the exception of the geodetic position detecting receiver 12A, are not shown separately in the figures herein for clarity of the illustration.
The seismic sensors 22 can be any type of seismic sensor known in the art. Non-limiting examples of such sensors may include particle motion-responsive seismic sensors such as geophones and accelerometers, pressure-responsive seismic sensors and pressure time gradient-responsive seismic sensors, or combinations of the foregoing. The seismic sensors 22 may measure, for example, seismic energy primarily reflected from or refracted by various structures in the Earth's subsurface below the bottom of the water 11 in response to energy imparted into the subsurface by a seismic energy source 17 or an array of such sources, deployed in the water 11 and towed by the survey vessel 10 or by another vessel. The recording system 12 may also include energy source control equipment (not shown separately) for selectively operating the seismic energy source 17.
In the survey system shown in
The sensor streamers 20 can each be coupled, at the axial end thereof nearest the vessel 10 (the “forward end”), to a respective lead-in cable termination 20A. The lead-in cable terminations 20A can be coupled to or associated with the spreader ropes or cables 24 so as to fix the lateral positions of the streamers 20 with respect to each other and with respect to the centerline of the vessel 10. Electrical and/or optical connection between the appropriate components in the recording system 12 and, ultimately, the geophysical sensors 22 (and/or other circuitry) in the ones of the streamers 20 inward of the lateral edges of the system may be made using inner lead-in cables 18, each of which terminates in a respective lead-in cable termination 20A. A lead-in termination 20A is disposed at the forward end of each streamer 20. Corresponding electrical and/or optical connection between the appropriate components of the recording unit 12 and the sensors 22 in the laterally outermost streamers 20 may be made through respective lead-in terminations 20A, using outermost lead-in cables 16. Each of the inner lead-in cables 18 and outermost lead-in cables 16 may be deployed by a respective winch 19 or similar spooling device such that the deployed length of each cable 16, 18 can be changed. The type of towing equipment coupled to the forward end of each streamer shown in
The acquisition system shown in
In the present example, each LFD device 26 may include an associated relative position determination device. In one example, the relative position determination device may be an acoustic range sensing device (“ARD”) 26A. Such ARDs typically include an ultrasonic transceiver or transmitter and electronic circuitry configured to cause the transceiver to emit pulses of acoustic energy. Travel time of the acoustic energy between a transmitter and a receiver disposed at a spaced apart position such as along the same streamer and/or on a different streamer, is related to the distance between the transmitter and a receiver, and the acoustic velocity of the water. The acoustic velocity can be assumed substantially not to change during a survey, or it can be measured by a device such as a water velocity test cell. Alternatively or additionally, acoustic range sensing devices (“ARDs”) may be disposed at selected positions along each one of the streamers not collocated with the LFD devices 26. Such additional ARDs are shown at 23 in
The streamers 20 may additionally or alternatively include a plurality of heading sensors 29 disposed at spaced apart positions along each streamer 20. The heading sensors 29 may be geomagnetic direction sensors such as magnetic compass devices affixed to the exterior of the streamer 20. One type of compass device is described in U.S. Pat. No. 4,481,611 issued to Burrage and incorporated herein by reference. The heading sensors 29 provide a signal indicative of the geomagnetic heading (direction with respect to magnetic north) of the streamer 20 at the axial position of the heading sensor 29 along the respective streamer 20. Measurements of such heading at spaced apart locations along each streamer may be used to interpolate the geometry (spatial distribution) of each streamer 20.
Each streamer 20 may include at the distal end thereof a tail buoy 25. The tail buoy 25 may include, among other sensing devices, a geodetic position signal receiver (not shown separately) such as a GPS receiver that can determine the geodetic position of each tail buoy 25. The geodetic position receiver (not shown) in each tail buoy 25 may be in signal communication with the recording system 12.
By determining the distance between ARDs 26A, 23, including the one or more ARDs on the vessel 10, and/or by interpolating the spatial distribution of the streamers from the heading sensor 29 measurements, an estimate of the geometry of each streamer 20 may be made. Collectively, the geometry of the streamers 20 may be referred to as the “array geometry.” For purposes of defining the scope of the present invention, the various position measurement components described above, including those from the heading sensors 29, from the ARDs 26A, 23, and, if used, from the additional geodetic position receivers 25A in the tail buoys 25, may be used individually or in any combination. It is only necessary for purposes of the present invention to be able to reasonably estimate the relative position of each point along each streamer 20 with reference to the survey vessel 10. By appropriate selection of the positions along each streamer at which the various relative position measurement devices described above are disposed, it is possible to determine the array geometry without the need to measure, estimate or otherwise determine the absolute geodetic position at large numbers of positions along each streamer, such as by using a large number of GPS receivers.
The example of seismic data acquisition shown in
A result of the acquisition arrangement shown in
As explained above in the Background section herein, in seismic survey acquisition techniques known in the art, it is believed that good survey results are obtained by operating the vessel and the streamers such that the reflection points 32 are as uniformly spaced as practicable, and that inadequate imaging or “coverage” of features in the subsurface may result if the spatial density of the reflection points is irregular or below a selected threshold. Using the above explanation of bins, prior art techniques provided that a selected number of data traces were required to be assigned to each bin associated with a particular survey position. Using prior art data quality evaluation techniques, it was believed that absence of sufficient numbers of traces in certain bins was justification for infill shooting.
Each seismic data “trace” (“trace” being the term known in the art for a graphic or other representation of a recorded or interpreted seismic signal) that is input to prestack migration techniques for seismic interpretation, however, contributes to a plurality of output traces from the migration procedure. In migration, the output traces are caused to correspond to selected survey positions such as those defined above with reference to
An explanation of methods according to the invention begins with reference to
where L is depth, F is frequency, v is velocity, λ is wavelength, and t is two-way vertical travel time to depth L. Equation (1) may be used for the case of a seismic source and seismic receiver being collocated to estimate the size of the Fresnel zone for each reflective horizon in each trace acquired during a seismic survey. It should be emphasized that
wherein
x=radius of ellipse in the direction perpendicular to shot receiver azimuth.
y=radius of ellipse in the direction parallel to shot receiver azimuth.
h=half the receiver offset (source to receiver distance=offset/2)
z=depth to the horizon.
L1=0.5(2L+ΔL)
L=one way ray path distance (=√{square root over (h2+z2)})
ΔL=half wavelength=v/(2f)
v=velocity
f=frequency
Once the Fresnel zone size has been determined, a weight function may be defined based on the distance from the position corresponding to the particular recorded data trace used. The weight function may be set to unity or other convenient value at the position of the data trace (the center of the Fresnel zone) and may decrease to zero at the outer limit of the Fresnel zone. The Fresnel zone for each input data trace for each reflective horizon may be overlaid on a grid of the output bin locations. A weighted trace amplitude value may be defined for each trace for each bin based on the distance between the center of each bin and the center of the Fresnel zone for each data trace. For each bin, the weighted trace amplitudes are summed for all traces whose bin centers are within Fresnel zones of each data trace for each such reflective horizon. For each bin having a summed weighted trace amplitude exceeding a selected threshold, such bin may be deemed to have sufficiently dense seismic data coverage to avoid spatial aliasing in an output image trace corresponding to that particular bin. It should be noted that while a Fresnel zone may be calculated for each of the seismic traces actually recorded, the method of the invention may also be used by computing Fresnel zones for only a subset of the seismic data traces. Fresnel zone may be interpolated for the traces not used to compute a Fresnel zone.
In some examples, the weighted trace amplitude for each bin may be determined during seismic acquisition operations, such as explained above with reference to
The thresholds selected for the assessment of coverage based on Fresnel zones will be related to the amplitude of the final image (that is, the image made by migration) of the seismic data at any particular image output or bin center location. The foregoing is not true of current methods of seismic coverage assessment where a completely empty bin (no traces), deemed to represent inadequate coverage, may still have a seismic image after migration.
It is well known in the art that imaging of shallow layers or horizons in the subsurface uses seismic traces which have smaller offsets (distance between source position and receiver position), whereas longer offset seismic data is useful for imaging deeper layers in the subsurface. Furthermore, the seismic reflections from shallow depths in the subsurface occur at an earlier time in a seismic record. The size of the Fresnel zone is a function of both seismic travel time and offset, and is smaller at shorter time and smaller offset. For imaging of very shallow targets, only the shortest offset seismic data at very early time are useful. The Fresnel zone associated with these images is therefore relatively small. However, as the offset increases, the size of the Fresnel zone increases.
As a result of the foregoing analysis of Fresnel zones, and referring once again to
In one example, the recording system 12 may be configured to cause the LFD devices 26 to operate to laterally deflect the streamers 20 until measurements from the ARDs 23, 26A indicate that the streamers attain lateral distance between them that is determined as explained above. It will be appreciated by those skilled in the art that while the lateral spacing or distance between streamers may generally increase with respect to offset, it is within the scope of the present invention for the relationship between the lateral spacing and the offset to be other than monotonic. For example, the distance may remain constant for a selected offset range, and then increase with respect to offset. Such increase may be linear or non-linear, and may revert to constant spacing at a selected further offset distance along the streamers.
Referring to
In
An illustration of calculation of Fresnel zones is shown in
Offsets for each of the seismic sensors in the calculation shown in
Methods according to the invention may provide more efficient seismic survey operations than is possible using seismic survey techniques known in the art prior to the present invention.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
Continuation in part of U.S. patent application Ser. No. 12/116,373 filed on May 7, 2008.
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| 4481611 | Burrage | Nov 1984 | A |
| 5717655 | Beasley | Feb 1998 | A |
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| 6691075 | Winbow et al. | Feb 2004 | B1 |
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| 6932017 | Hillesund et al. | Aug 2005 | B1 |
| 7027927 | Matsuoka et al. | Apr 2006 | B2 |
| 7080607 | Hillesund et al. | Jul 2006 | B2 |
| 7162967 | Hillesund et al. | Jan 2007 | B2 |
| 7336560 | Rekdal et al. | Feb 2008 | B2 |
| 7376045 | Falkenberg et al. | May 2008 | B2 |
| 20040054477 | Bernitsas | Mar 2004 | A1 |
| 20040215396 | Christie et al. | Oct 2004 | A1 |
| Number | Date | Country | |
|---|---|---|---|
| 20090279388 A1 | Nov 2009 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 12116373 | May 2008 | US |
| Child | 12409577 | US |
