Patent ID: 12216238

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

An exemplary marine seismic data acquisition system1, where the streamer spacing is substantially constant over the entire length of the streamers, is shown inFIG.1. As shown inFIG.1, the data acquisition system1employs a marine vessel10to tow seismic sources12and a system14of steerable seismic streamers16through a body of water18. Each of the seismic streamers16includes a streamer cable20, a series of seismic receivers22coupled to the cable20, and a series of steering devices24coupled to the cable20. During marine seismic data acquisition, the steering devices24are used to maintain a desired spacing between the seismic streamers16.

An exemplary marine seismic data acquisition system1, where the streamer spacing is increasing rearwardly at a substantially constant rate over the entire length of the streamers, is shown inFIG.2. As shown inFIG.2, the data acquisition system1employs a marine vessel30to tow seismic sources32and a system34of steerable seismic streamers36through a body of water18is shown inFIG.2. Each of the seismic streamers36includes a streamer cable38, a series of seismic receivers40coupled to the cable38, and a series of steering devices42coupled to the cable38. During marine seismic data acquisition, the steering devices42are used to maintain a desired spacing between the seismic streamers36.

Alternatively, the marine vessel10,30may have two or more seismic sources12,32, or the vessel10,30may not have any seismic sources12,32, such as in the case where the vessel10,30is only towing streamers16,36. Further, it may be desirable to use one or more seismic sources12,32in either single or multiple vessel operations. One skilled in the art will recognize that a variety of types of equipment can be employed as the seismic sources12,32depending on the conditions of the marine environment and design parameters of the seismic survey.

The marine vessel10,30should be capable of towing the seismic sources12,32and the system14,34of seismic streamers16,36through the body of water18at an appropriate speed. Generally, for the marine seismic data acquisition, appropriate vessel speeds are in the range of about 2 to 10 knots, or, preferably, about 4 to 6 knots.

The marine seismic sources12,32may be any submersible acoustic wave source capable of generating wave energy powerful enough to propagate through the body of water18and into a subsea region of the earth, where it is reflected and/or refracted to thereby produce reflected/refracted energy that carries information about the structure of the subsea region and is detectable by marine seismic receivers. The seismic sources12,32employed in the present invention can be selected from a wide variety of commonly known marine seismic sources such as an air gun. These seismic sources are commercially available from a number of companies including ION Geophysical of Houston, Tex. For example, ION Geophysical has the SLEEVE GUN™ that is an air gun.

The individual seismic streamers16,36may include in the range of 10 to 300,000 individual seismic receivers22,40, in the range of 100 to 10,000 individual seismic receivers22,40, or in the range of 200 to 1,000 individual seismic receivers22,40. The seismic receivers22,40employed in the present invention can be selected from a wide variety of commonly known marine seismic receivers. These seismic receivers are commercially available from a number of companies including Teledyne Benthos in North Falmouth, Mass. For example, Teledyne Benthos has the AQ-2000™ that is a seismic receiver.

The seismic streamers16,36illustrated inFIG.1are steerable streamers whose lateral positions can be controlled by the steering devices24,42as the streamers16,36are towed through the water18. Although all the seismic streamers16,36depicted inFIG.1are steerable streamers that include steering devices24,42, it should be understood that one or more of the streamers16,36may not be equipped with any steering devices. The steering devices24,42employed in the present invention can be selected from a wide variety of commonly known steering devices. These steering devices are commercially available from a number of companies including WesternGeco, LLC in Houston, Tex. For example, WesternGeco, LLC has the Q-FIN™ that is a steering device.

As noted above,FIG.2depicts the seismic streamer system34in a flared configuration, where the rear portion of the streamer system34is wider than the front portion of the streamer system34. In accordance with one embodiment of the present invention, the seismic streamer system34is in a flared configuration when the lateral distance (dr) between the outer-most, rearward-most seismic receivers40a,bis greater than the lateral distance (df) between the outer-most, front-most seismic receivers40c,d.

The seismic streamer system34illustrated inFIG.2has a generally trapezoidal shape, with a substantially constant rate of flaring along the entire length of the seismic streamer system34. As used herein, the term “rate of flaring” is used to denote the rate at which the average spacing between adjacent seismic streamers increases rearwardly along a certain length of the seismic streamer system.

FIG.3depicts an alternative seismic streamer system50in a flared configuration. In particular, the streamer system50has a trumpet-shaped configuration, with a rearwardly increasing rate of flaring in a flared section52of the seismic streamer system50. As used herein, the “flared section” of a seismic streamer system is simply the section of the seismic streamer system that is in a flared configuration. Thus, for the streamer system34ofFIG.2, the entire length of the streamer system34would be considered a flared section. However, for the seismic streamer system50ofFIG.3, the flared section52has a length (lf) that is less than the total length (lt) of the seismic streamer system50. As depicted inFIG.3the seismic streamer system50can also include a non-flared/straight section54that exhibits substantially constant streamer spacing over its length (ls).

FIG.4depicts an alternative seismic streamer system60in a flared configuration. The streamer system60illustrated inFIG.4includes alternating short streamers62and long streamers64. In the configuration illustrated inFIG.4, the short streamers62are not in a flared configuration, but the long streamers64include a flared section66having a length (lf) that is less than the total length (lt) of the seismic streamer system60. The seismic streamer system60also includes a non-flared/straight section68having a length (ls) that is less than the total length (lt) of the seismic streamer system60.

FIG.5depicts an alternative seismic streamer system70in a flared configuration that is comparable to the streamer system60illustrated inFIG.4and includes alternating short streamers72and long streamers74. In the configuration illustrated inFIG.5, the short streamers72are not in a flared configuration but are not the same length. The short streamers72are longer at the center of the system70and shorter at the outer edges of the system70. As inFIG.4, the long streamers74include a flared section76having a length (lf) that is less than the total length (lt) of the seismic streamer system70. The seismic streamer system70also includes a non-flared/straight section78having a length (ls) that is less than the total length (lt) of the seismic streamer system70.

A method determining an optimal flare spacing for a configuration for streamers is described below. As discussed above, a wide variety of streamer configurations can be employed in the seismic data acquisition process. These streamer configurations include, but are not limited to, the non-flared configuration similar to that illustrated inFIG.1, or the flared configurations similar to those illustrated inFIGS.2-5.

The method uses a computer system that is specially adapted with a seismic data analysis package to analyze seismic data. The seismic analysis package is commercially available from a number of companies including Karl Thompson & Associates, GEDCO and Halliburton. For example, GEDCO has the VISTA® 9.0 2D/3D, and Halliburton has the ProMAX® 4D seismic data processing software. In a preferred embodiment, the Karl Thompson & Associates Seisbase™ III software is used as the seismic data analysis package.

In an embodiment, the method analyses geophysical migration broadcast patterns to estimate a maximum sampling distance before adversely compromising the seismic data (i.e., aliasing the data) using the specially-adapted computer system describe above. This estimated maximum sampling distance is a function of the velocities in the survey area, and, therefore, the estimated sampling distance is site dependent. A potentially acceptable flare spacing (for further evaluation) should be less than or equal to the estimated maximum sampling distance.

In an embodiment, the method uses prior 2D or 3D seismic data and a geological model from the survey area, and calculates a wavelet expansion as a function of flare spacing. The wavelet expands with flare spacing (and travel time) so a maximum flare spacing may be estimated to prevent any loss of seismic data quality.

In an embodiment, the method creates synthetic gaps in the seismic data coverage by dropping traces at different flare spacing in the prior data set. The synthetic gap prevents the trace data from being processed. After a synthetic gap is created, the method closes the gaps from the traces, if possible, by testing different interpolation algorithms. Generally, the synthetic gap created by three missing traces can be in-filled accurately using currently available interpolation algorithms, but a gap by four to five traces may be in-filled with varying results, and the gap by six traces cannot be in-filled with current technology. The process may be repeated until all the available interpolation algorithms are exhausted. The gaps that cannot be closed using the available algorithms identify the flare spacing(s) that is/are too large for the current technology. However, it is possible that wider gaps may be closed as the interpolation technology improves, and that larger flare spacing may be implemented without any loss in the seismic data quality.

Available technologies of interpolation algorithms can easily close gaps at flare spacing within about 15% expansion of nominal, and developing technologies may be able to close gaps at flare spacing within about 20 to 30% expansion. For example, one such technology includes interpolation algorithms beyond the nominal Nyquist frequency for digital cameras. See e.g., R. Szeliski, S. Winder and M. Uyttendaele, HIGH-QUALITYMULTI-PASSIMAGERESAMPLING, Technical Report No. MSR-TR-2010-10 (Microsoft Pub., February 2010); J. A. Tropp, J. N. Laska, M. F. Duarte, J. K. Romberg and R. G. Baraniuk,Beyond Nyquist: Efficient Sampling of Spare Bandlimited Signals,IEEE TRANSACTIONS ON INFORMATION THEORY56(1) (January 2010) 520-44. In particular, a digital image may be accurately wavefield reconstructed beyond the normal aliasing when the pixels are non-uniformly sampled. However, a disadvantage of these types of antialias filters is the potential reduction of final image sharpness with current implementations of the theory.

Another such technology includes a bi-linear quasi-interpolation algorithm. See e.g., L. Condat, T. Blu and M. Unser,Beyond Interpolation: Optimal Reconstruction By Quasi Interpolation, IEEE INTERNATIONALCONFERENCE ONIMAGEPROCESSING1 (November 2005) 33-36. This algorithm has also shown that about a 20 to 30% expansion is possible. Accordingly, the developing algorithm technology should be able to close gaps at flare spacing within about 20 to 30% expansion of nominal.

In an embodiment, the method uses an actual flare spacing between about eighty percent and about one hundred percent of the maximum flare spacing for marine seismic data acquisition. In another embodiment, the actual flare spacing is between about ninety percent and about one hundred percent of the maximum flare spacing.

From the above-described tests, an optimal flare spacing may be estimated to avoid oversampling the wavefield and to prevent leaving any unpopulated gaps in the seismic data that cannot be in-filled by available interpolation algorithms. Based upon current technology, optimal flare spacing is within about 15% expansion of nominal, and possibly within about 20 to 30% expansion. At a flare spacing within about 15% expansion of nominal, available interpolation algorithms should be capable of closing (i.e., in-filling) any gaps in the seismic data. Further, optimal flare spacing for the current technology can be identified prior to any data acquisition for a new survey.

In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as an additional embodiment of the present invention.

Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

REFERENCES

All of the references cited herein are expressly incorporated by reference. The discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication data after the priority date of this application. Incorporated references are listed again here for convenience:1. US 2010-0002536-A1 (Peter M. Eick and Joel D. Brewer); “CUTTING MARINE SEISMIC ACQUISITION WITH CONTROLLED STREAMER FLARING” (2010).