The present invention relates to seismic surveying. In particular, it relates to a method of and system for seismic surveying which allows the monitoring of a seismic source array.
The principle of seismic surveying is that a source of seismic energy is caused to emit seismic energy such that it propagates downwardly through the earth. The downwardly-propagating seismic energy is reflected by one or more geological structures within the earth that act as partial reflectors of seismic energy. The reflected seismic energy is detected by one or more sensors (generally referred to as “receivers”). It is possible to obtain information about the geological structure of the earth from seismic energy that undergoes reflection within the earth and is subsequently acquired at the receivers.
When a seismic source array is actuated to emit seismic energy it emits seismic energy over a defined period of time. The emitted seismic energy from a seismic source array is not at a single (temporal) frequency but contains components over a range of frequencies. The amplitude of the emitted seismic energy is not constant over the emitted frequency range, but is frequency dependent. The emitted seismic energy from a seismic source array may also vary in space due to two factors: the source array may emit different amounts of energy in different directions, and the seismic wavefronts may “expand” with time (expanding spherical waves as opposed to plane waves). The seismic wavefield emitted by a seismic source array is known as the “signature” of the source array. When seismic data are processed, knowledge of the signature of the seismic source array used is desirable, since this allows more accurate identification of events in the seismic data that arise from geological structures within the earth. In simple mathematical terms, the seismic wavefield acquired at a receiver is the convolution operation of two factors; one representative of the earth's structure, and another representative of the wavefield emitted by the source array. The more accurate is the knowledge of the source array's signature, the more accurately the earth model may be recovered from the acquired seismic data.
A manufacturer of a seismic source may provide a general source signature for the seismic source. However, each time that a seismic source is actuated the actual emitted wavefield may vary slightly from the theoretical source signature. In a typical seismic survey a seismic source array is actuated repeatedly and seismic data are acquired consequent to each actuation of the source array. Each actuation of the source array is known as a “shot”. In processing seismic data it is desirable to know to what extent a difference between the trace acquired for one shot and a trace acquired for another shot is a consequence of a difference in the source signatures for the two shots.
It has been suggested that one or more “near-field sensors” may be positioned close to a seismic source, in order to record the source signature. By positioning the near-field sensors(s) close to the seismic source the wavefield acquired by the near-field sensors should be a reliable measurement of the emitted source wavefield. WesternGeco's Trisor/CMS system provides estimates of the source wavefield from measurements with near-field hydrophones near each of the seismic sources composing the source arrays in marine seismic surveys. These estimates have been used to control the quality and repeatability of the emitted signals, and to perform compensation for shot-to-shot variations or source-array directivity. Recent comparison of signals, predicted by the Trisor/CMS system or recorded with point-receiver hydrophones (Q-marine system), indicate that the quality of the Trisor/CMS estimates is excellent over a large band of frequencies and source take-off angles.
Here, the take-off dip angle is defined as zero degrees in the vertical direction, and 90 degrees in the horizontal direction.)
The Trisor/CMS incident wavefield is the result of a computation involving several measurements or estimated quantities and some assumptions, as described for instance in Ziolkowski, A. et al., “The signature of an air gun array: Computation from near-field measurements including interactions” (1982). The key factors influencing the estimation are the position data for the guns and near-field hydrophones: as well as the estimate of the free surface reflection coefficient.
It has also been proposed to position a seismic sensor, or a plurality of seismic sensors (for example, arranged as a “ministreamer”), below a seismic source array, to determine the actual wavefield that is emitted when the source array is actuated. A significant change in the signature of a source array during a seismic survey could indicate that the source array was malfunctioning, and monitoring the output wavefield of the source array during data acquisition allows possible malfunctions of the source array to be detected as soon as possible.
The signature of a seismic source array is generally directional, even though the individual sources may behave as “point sources” that emit a wavefield that is spherically symmetrical. This is a consequence of the seismic source array generally having dimensions that are comparable to the wavelength of sound generated by the array.
The signature of a seismic source array further varies with distance from the array. This is described with reference to
In processing geophysical data, knowledge of the far-field signature of the source array is desirable, since most geological features of interest are located in the far-field region 8. Direct measurement of the far-field signature of the array, or the far-field signature of one of the individual guns of the array, is difficult, however, even when measuring the far-field signature in the water layer. For instance, one would have to ensure that no reflected energy is received during the measurement of the far-field signature or, if reflected energy is received, that a method exists to separate the reflected energy. Another complication for direct measurements is that the signature depends on the take-off direction.
The near-field signature of an individual seismic source may in principle be measured, for example in laboratory tests or in field experiments. However, knowledge of the source signatures of individual seismic sources is not sufficient to enable the far-field signature of a source array to be determined, since the sources of an array do not behave independently from one another.
Interactions between the individual sources of a seismic source array were considered in U.S. Pat. No. 4,476,553. The analysis specifically considered airguns, which are the most common seismic source used in marine surveying, although the principles apply to all marine seismic sources. An airgun has a chamber which, in use, is charged with air at a high pressure and is then opened. The escaping air generates a bubble which rapidly expands and then oscillates in size, with the oscillating bubble acting as a generator of a seismic wave. In the model of operation of a single airgun it is assumed that the hydrostatic pressure of the water surrounding the bubble is constant, and this is a reasonable assumption since the movement of the bubble towards the surface of the water is very slow. If a second airgun is discharged in the vicinity of a first airgun, however, it can no longer be assumed that the pressure surrounding the bubble generated by the first airgun is constant since the bubble generated by the first airgun will experience a seismic wave generated by the second airgun (and vice versa).
U.S. Pat. No. 4,476,553 proposed that, in the case of seismic source array containing two or more seismic sources, each seismic source could be represented by a notional near-field signature. In the example above of an array of two airguns, the pressure variations caused by the second airgun is absorbed into the notional signature of the first airgun, and vice versa, and the two airguns may be represented as two independent airguns having their respective notional signatures. The far-field signature of the array may then be found, at any desired point, from the notional signatures of the two airguns.
In general terms, U.S. Pat. No. 4,476,553, the contents of which are hereby incorporated by reference, discloses a method for calculating the respective notional signatures for the individual seismic sources in an array of n sources, from measurements of the near-field wavefield made at n independent locations. The required inputs for the method of U.S. Pat. No. 4,476,553 are:
For the simple source array containing two seismic sources 9,10 shown in
If a source array is not rigid it is necessary to obtain information about the positions of the seismic sources within the array before the method of U.S. Pat. No. 4,476,553 may be used. (For example, if the source array of
Determination of a notional source according to the method of U.S. Pat. No. 4,476,553 ignores the effect of any component of the wavefield reflected from the sea bed and so is limited to application in deep water seismography. The method of U.S. Pat. No. 4,476,553 has been extended in GB Patent No. 2 433 594 to use “virtual sources” so as to take account of reflections at the sea-surface or at the sea bottom.
A first aspect of the present invention provides a method of monitoring a marine seismic source array, comprising:
a) consequent to actuation of the seismic source array, (i) measuring seismic energy emitted by the source array, using at least one near field sensor and (ii) acquiring seismic data using at least one seismic receiver;
b) predicting the far-field signature of the source array at one or more of the receiver location(s) from the seismic energy measured by the near-field sensor(s); and
c) for one or more of the receivers, comparing the predicted far-field signature at the receiver location with seismic data acquired at the receiver.
The present invention makes use of the seismic receivers that are provided in a seismic survey for acquiring seismic data in order to monitor the actual wavefield that is emitted by the source array. In the prior art approach in which one or more additional receivers are provided below the source array to determine the actual emitted wavefield, the additional receivers are -provided solely to monitor the output wavefield and are not used to acquire seismic data from which information about the earth's interior may be obtained. The present invention in contrast does not require any further equipment to be provided in the seismic survey.
Furthermore, the inventors have realised that the prior art approach in which one or more additional receivers are provided below the source array to determine the actual emitted wavefield suffers from the disadvantage that the position of the additional receiver(s) is not exactly known. While it is intended that the additional receiver(s) are positioned vertically below the source array, the action of towing the source array through the water, influenced by the speed of the boat and the currents in the water, means that it is possible for the additional receiver(s) to be horizontally displaced from their intended position relative to the source array. It is therefore not possible to tell whether apparent changes in the emitted wavefield arise from displacement of the additional receiver(s) from their intended position of vertically below the source array. This disadvantage is overcome by the present invention.
A further disadvantage of the prior art approach of providing one or more additional receivers below the source array is that a seismic source array is generally configured such that its output wavefield in the vertical direction is as consistent as possible—so that the output in the vertical direction is relatively insensitive to faults in the source array. This disadvantage is also overcome by the present invention.
The results of monitoring the seismic source array may be used to allow operation of the source array to be adjusted, if this should be necessary. Additionally or alternatively, processing of seismic data acquired at the receiver may take account of the results of monitoring the seismic source array.
The method may comprise obtaining information about the operation and/or positions of the source array and/or the receiver from the result of comparing the predicted far-field signature at the receiver location with seismic data acquired at the receiver. If the predicted far-field signature at the receiver location agrees with seismic data acquired at the receiver this suggests that the source array, the receiver, and any position determining systems associated with the source array and/or the receiver, are operating correctly. However, if the predicted far-field signature at the receiver location does not agree with seismic data acquired at the receiver this suggests that (at least) one of the source array, the receivers (near or far-field), and any position determining systems associated with the source array and/or the receiver, is not operating correctly—and the operator may then take corrective action.
Comparing the predicted far-field signature at the receiver locations with seismic data acquired at the receiver location(s) may comprise determining, for at least one receiver, the difference between the predicted far-field signature at the receiver location and seismic data acquired at the receiver.
Comparing the predicted far-field signature at the receiver locations with the seismic data acquired at the receiver location(s) may comprise determining, for at least one receiver, the difference between the predicted far-field signature at the receiver location and the direct arrival acquired at the receiver. In comparing the predicted far-field signature at the receiver locations with the seismic data acquired at the receiver location(s) it is necessary to take account of propagation effects (i.e., the fact that the waveform of a pulse of seismic energy changes as it propagates through a medium). The path of the direct arrival passes only through water, so that the expected waveform of the direct arrival is given by the convolution of the source signature with the known function describing propagation of signals from a point source through water in the presence of a free-surface—so that it is relatively straightforward to take account of propagation effects, as no knowledge of properties of the seabed and the medium below the seabed is required.
The method may further comprise predicting an error, for example as a function of temporal frequency, in the predicted far-field signature for another location from the difference between the predicted far-field signature at the receiver location and seismic data acquired at the receiver. The differences between the predicted far-field signature at a receiver location and seismic data acquired at the receiver can be analyzed as a function of time and/or as a function of frequency. It can be informative to look at the errors in prediction as function of frequency.
A second aspect of the invention provides a method comprising:
In an embodiment, estimating the error in the far-field signature predicted for the another location comprises adjusting the determined difference between the predicted far-field signature at the receiver location and seismic data acquired at the receiver for a difference in take-off direction between the another location and the receiver location.
The method may further comprise activating a seismic source array and acquiring seismic data at the receiver consequent to actuation of the source.
Other aspects of the invention provide corresponding computer-readable medium and apparatus.
Preferred embodiments of the present invention will be described by way of illustrative example, with reference to the accompanying figures in which:
a is a block schematic flow diagram showing principal steps of a method according to one embodiment of the present invention;
b shows one of the steps of
In the appended figures, similar components and/or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a dash and a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label.
The ensuing description provides preferred exemplary embodiment(s) only, and is not intended to limit the scope, applicability or configuration of the invention. Rather, the ensuing description of the preferred exemplary embodiment(s) will provide those skilled in the art with an enabling description for implementing a preferred exemplary embodiment of the invention. It being understood that various changes may be made in the function and arrangement of elements without departing from the scope of the invention as set forth in the appended claims.
Specific details are given in the following description to provide a thorough understanding of the embodiments. However, it will be understood by one of ordinary skill in the art that the embodiments maybe practiced without these specific details. For example, circuits may be shown in block diagrams in order not to obscure the embodiments in unnecessary detail. In other instances, well-known circuits, processes, algorithms, structures, and techniques may be shown without unnecessary detail in order to avoid obscuring the embodiments.
Also, it is noted that the embodiments may be described as a process which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations can be performed in parallel or concurrently. In addition, the order of the operations may be re-arranged. A process is terminated when its operations are completed, but could have additional steps not included in the figure. A process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination corresponds to a return of the function to the calling function or the main function.
Moreover, as disclosed herein, the term “storage medium” may represent one or more devices for storing data, including read only memory (ROM), random access memory (RAM), magnetic RAM, core memory, magnetic disk storage mediums, optical storage mediums, flash memory devices and/or other machine readable mediums for storing information. The term “computer-readable medium” includes, but is not limited to portable or fixed storage devices, optical storage devices, wireless channels and various other mediums capable of storing, containing or carrying instruction(s) and/or data.
Furthermore, embodiments may be implemented by hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof. When implemented in software, firmware, middleware or microcode, the program code or code segments to perform the necessary tasks may be stored in a machine readable medium such as storage medium. A processor(s) may perform the necessary tasks. A code segment may represent a procedure, a function, a subprogram, a program, a routine, a subroutine, a module, a software package, a class, or any combination of instructions, data structures, or program statements. A code segment may be coupled to another code segment or a hardware circuit by passing and/or receiving information, data, arguments, parameters, or memory contents. Information, arguments, parameters, data, etc. may be passed, forwarded, or transmitted via any suitable means including memory sharing, message passing, token passing, network transmission, etc.
The seismic survey further includes one or more receiver cables 17, with a plurality of seismic receivers 18 mounted on or in each receiver cable 17.
Typically streamers are provided with one or more position determining systems for providing information about the positions, or relative positions, of the streamers 17. For example, the streamers may be provided with depth sensors 19 for measuring the depth of the streamer below the water surface. The streamers may additionally or alternatively be provided with sonic transceivers (not shown) for transmitting and receiving sonic or acoustic signals for monitoring the relative positions of streamers and sections of streamers. The streamers may alternatively or additionally be provided with a satellite-based positioning system, such as GPS, for monitoring the positions of the streamers—for example, compass measurements along the streamers may be used in combination with a few GPS measurements, usually at the front and the tail of the streamer. As an example
One or more position determining systems (not shown) may also be provided on the source array to provide information about the position of the source array.
When one or more sources of the source array are actuated, they emit seismic energy into the water, and this propagates downwards into the earth's interior until it undergoes (partial) reflection by some geological feature 23 within the earth. The reflected seismic energy is detected by one or more of the receivers 19. In addition, when one or more sources of the source array are actuated some of the emitted seismic energy travels direct from the source array to the receivers 19 along path 24, and some travels along path 24a from the source array to the sea surface where it is reflected towards the receiver. The sum of the arrivals along paths 24 and 24a is called the ‘direct arrival’ in the water layer. (Raypath 24 would be the direct arrival for a ‘notional’ medium without a free surface interface (eg an air/water interface)).
The seismic surveying arrangement of
As mentioned above, it has been proposed to provide a seismic surveying arrangement such as the seismic surveying arrangement of
Note that features of the seismic recording system could be used to enhance the proposed workflow. For instance, when seismic data are recorded with over/under streamers, or with multi-component streamers, the streamers can be towed at a larger depth and/or closer to the source array, in order to provide an increased range of angles for the comparison step in
a illustrates a method according to one embodiment of the present invention. Initially, at step 1, the seismic source array 14 of the seismic surveying arrangement of
At step 2, near field measurements of the seismic energy emitted by the source array 14 consequent to its actuation are made by the near-field sensors 16 of the source array. Also consequent to actuation of the source array 14, other measurements (mid or far-field measurements) are made by the receivers 18 on the streamers 17 (the “mid-field” region is not shown in
At step 3 of
At step 4 of
If the expected far-field source signature calculated for the location of one or more of the receivers 18 in step 3 differs significantly from the actual far-field signature obtained from the direct arrival at the receivers, this indicates inconsistencies between the two measurements, due for instance to poor operation of the source array 14, to poor operation of the receiver array, or to inconsistent navigation data between the source and receiver measurements (so that the calculated relative positions of the source array and the receivers do not correspond to the true relative positions of the source array and the receivers). Conversely, if the actual far-field source signature agrees with the expected far-field signature, this indicates that the source and receiver arrays are operating correctly and that the navigation data are reliable.
Moreover, if the expected far-field source signature calculated for the location of one or more of the receivers disagree with the actual far-field signature obtained from the direct arrival at the receiver(s), it may be possible to obtain information about the likely cause from the manner in which the expected and actual far-field signatures disagree with one another. Thus, the results of the comparison may be used to obtain information about the operation of the source array and/or the receiver or to obtain information about the position of the source array relative to the receiver.
Since the components 24 and 24aof the direct arrival propagate only through water, using the direct arrival for the comparison between the predicted far-field signature at a receiver location and the seismic data acquired at that receiver location) has the advantage of relatively straightforward interpretation, where knowledge of medium properties below the water layer is not required. The prediction of the direct arrivals is typically done assuming constant water velocity and density and a flat sea surface. These assumptions are most often appropriate for the marine seismic applications, where the frequencies of interest are up to about 100 Hz. For higher frequencies, a more detailed model of the direct arrivals may be needed, including sea-surface shape estimates (as per U.S. Pat. No. 6,529,445 B1, Robert Laws, Mar. 4, 2003), and/or measurements of water velocity and density.
For example, when comparing the expected far-field source signature calculated for the location of one or more of the receivers with the actual far-field signature obtained from the direct arrival at the receiver(s), it may be found that the expected and actual signatures have similar wavelet shapes but a difference in arrival time. This would indicate inconsistency in position measurements between the source and the receivers—and the difference in arrival time may be converted to a distance error, using the speed of sound in water. This distance error represents the distance between the estimated distance from the source array to the receiver and the actual distance. This position information may be taken into account in subsequent processing of seismic data.
Another possible result when comparing the expected far-field source signature with the actual far-field signature is that there is good agreement at low frequencies, but increasing errors at high frequencies. This may indicate errors in the position measurements/estimates for the source array.
Another possible result when comparing the expected far-field source signature with the actual far-field signature is that there is poor agreement at all frequencies, and differences in amplitude and shape between the expected wavelet and the actual wavelet. This may point to problems with the source array. The operator should double-check with other quality-control indicators for the source array, for example to check for: timing delays between guns, incorrect pressure of supply of air to the guns, whether some guns are not firing. If incorrect operation of the source array is found, the operator may adjust operation of the source array as necessary.
The operator may apply one or more thresholds for the comparison, and disregard any differences less than the thresholds. For example, the operator may place a threshold on the difference between the expected arrival time and the actual arrival time, and/or on the amplitude difference.
The method of the invention may be carried out in real-time or in near-real time, so that the survey operators are alerted of any possible problem very soon after the source array has been actuated. They are able to investigate and, if necessary, take corrective action such as, for example, replacing or repairing a malfunctioning source, a malfunctioning receiver or a malfunctioning position determining system (either on the source array or on the streamer), or suspending data acquisition until the fault has been rectified.
In the method of the present invention, the notional signatures of the sources are calculated from the measurements made by the near-field sensors 16 when the sources are actuated to fire a shot, and the data acquired at the receivers are also obtained for that shot. Thus, any variations in the output of the source array from one shot to another do not affect the accuracy of the comparison.
If the expected far-field source signature calculated for the location of one or more of the receivers 18 in step 3 agrees (to within some chosen limit) with the actual far-field signature obtained from the direct arrival at the receivers, this provides confirmation that the source array is operating correctly. In this case, the seismic data acquired at the receivers 18 may undergo further processing to obtain information about the earth's geological structure, for example to obtain information about a parameter of the earth's interior or to locate and/or characterise a hydrocarbon reservoir within the earth. The seismic data may be processed using any suitable processing steps, and the further processing of the seismic data will not be described in detail.
Step 4 of
It should be noted that
The present invention provides a number of advantages over the prior art seismic surveying arrangement of
In the prior art seismic surveying arrangement of
A further disadvantage of the prior art approach of
The method of
b is a schematic flow diagram that shows one way in which step 3 of the method of
Initially, at step 1, the notional signatures of the sources 15 of the source array 14 are determined from the near-field measurements of the seismic energy emitted by the source array in step 2 of
At step 2, the positions of one or more of the receivers 18 on the streamer 17, relative to the source array, are determined. The positions may be determined from the position information provided by position-determining systems on the receiver array (such as the GPS receivers 22 in
Preferably, step 2 also determines the orientation of the source array. The output of a seismic source array is generally not isotropic so, in order accurately to estimate the far-field signature at a receiver location, it is desirable to know how the source array is oriented as well as knowing the position of the receiver relative to the source array.
At step 3, the expected far-field signature at the locations of one or more of the receivers are estimated, from the notional signatures obtained in step 1 and from the relative positions, and possibly orientation of the source array, obtained in step 2. This may be carried out as explained above with regard to
A further feature of the present invention is that it enables an estimate to be made of the error in the estimation of the far-field signature at any desired location, for example at a point directly below the source array. As explained above, the far-field signature at any desired location may be estimated once the notional signatures of the sources of the source array have been determined—but any errors in the estimation of the notional signatures of the sources will lead to errors in the estimation of the far-field signature.
In the present invention, the comparison of the expected far-field signature at the locations of one or more of the receivers with the data actually acquired at the receiver(s) provides a quantitative indication of the error in the estimation of the far-field signature at the receiver location(s); any discrepancy between the expected far-field signature and the data actually acquired and suitably pre-processed as described above with reference to
The error in the estimation of the far-field signature will be dependent on the take-off direction. For the case in which two take-off directions have the same angle in a horizontal plane (eg the same azimuth) and differ only in take-off angle (that is, the two take-off directions lie in a common vertical plane), the comparison of the expected far-field signature at the location of one of the receivers with the data actually acquired at that receiver is a measure of the error in the estimation of the far-field signature at the take-off angle of that receiver, that is E1 where E1 denotes the error at a first location which has take-off angle θ1 . The estimated error E2 in the estimation of the far-field signature for a second location with a different take-off angle, θ2 where θ2≠θ1, may be found from the error E1, by adjusting the error to take account of the different take-off angle. Simulations of prediction errors have been made which show how these errors vary with take-off direction from the source array and frequency content of the signal, as described in, for example, co-pending U.K. patent application No. ______ filed on the same day as this application, entitled “Processing Seismic Data”, temporarily referenced herewith by its attorney docket number 57.0913 GB NP, the contents of which are hereby incorporated by reference. These may be used to provide scaling factors that enable the likely error E2 in the estimated far-field signature for the second location to be estimated, with take-off angle θ2, to be obtained by suitably scaling the error E1 determined from step 4 of
In the general case, the take-off direction to one location may have a different heading and/or a different take-off angle from the take-off direction to another location. In order to estimate the likely error E2 in the estimated far-field signature for a second location, the error E1 determined at one location must be scaled for a change in heading and/or for a change in take-off angle between the two locations, as appropriate.
The scaling may for example be performed using a suitable look-up table, computed from simulations.
The program for operating the system and for performing a method as described hereinbefore is stored in the program memory 28, which may be embodied as a semi-conductor memory, for instance of the well-known ROM type. However, the program may be stored in any other suitable storage medium, such as magnetic data carrier 28a, such as a “floppy disk” or CD-ROM 28b.
The invention has been described above with reference to a seismic surveying arrangement in which the receivers are provided on/in towed marine seismic streamers. The invention is not however limited to this and may, for example, be carried out with a seismic surveying arrangement in which the receivers are provided on/in seabed seismic cable, or seabed nodes.
Where the invention is applied with a towed marine seismic surveying arrangement, the invention may in principle be used with any towed marine seismic surveying arrangement having the general form shown in
These features are found in the Q-marine systems from WesternGeco.
While the principles of the disclosure have been described above in connection with specific apparatuses and methods, it is to be clearly understood that this description is made only by way of example and not as limitation on the scope of the invention.
Number | Date | Country | Kind |
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0905260.6 | Mar 2009 | GB | national |
Filing Document | Filing Date | Country | Kind | 371c Date |
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PCT/IB10/00343 | 2/19/2010 | WO | 00 | 12/16/2011 |