阅读说明：本技术 利用远偏移的增加的炮点间隔的地震勘探 (Seismic exploration with increased shot spacing for far migration ) 是由 M.贝茨 C.斯特兰德 于 2017-12-13 设计创作，主要内容包括：公开了与配置海洋地震勘探有关的技术。在一些实施例中,船(210)可以耦合至一个或多个地震源(220)和一个或多个地震拖缆(250),并且第二船(230)可以耦合至一个或多个远偏移地震源(240)。近偏移源(220)可以配置成根据炮点间隔致动；远偏移源(240)可以配置成根据更长炮点间隔致动。在一些实施例中,更长炮点间隔可以是近偏移源炮点间隔的倍数。确定第一和第二炮点间隔可以部分地基于例如远偏移源的波频率、全波反演过程的要求或地震勘探的各种配置参数。(Techniques related to configuring marine seismic surveys are disclosed. In some embodiments, the vessel (210) may be coupled to one or more seismic sources (220) and one or more seismic streamers (250), and the second vessel (230) may be coupled to one or more far-offset seismic sources (240). The near offset source (220) may be configured to actuate according to shot spacing; the far offset source (240) may be configured to actuate according to a longer shot interval. In some embodiments, the longer shot spacing may be a multiple of the near offset source shot spacing. Determining the first and second shot spacing may be based in part on, for example, the wave frequency of the far offset source, the requirements of the full wave inversion process, or various configuration parameters of the seismic survey.)

1. A method, comprising:

In marine seismic exploration, actuating one or more near offset seismic sources according to a first shot interval;

actuating one or more far-offset seismic sources according to a second shot interval, wherein the second shot interval is longer in distance or time than the first shot interval, and wherein the one or more far-offset seismic sources are located at a greater distance from the plurality of seismic streamers than the one or more near-offset seismic sources; and

Collecting seismic data via the plurality of seismic streamers in response to actuation of the one or more near offset seismic sources and the one or more far offset seismic sources.

2. The method of claim 1, wherein:

Actuating the one or more near offset seismic sources comprises alternately actuating each of two near offset seismic sources;

actuating the one or more far offset seismic sources comprises alternately actuating each of two far offset seismic sources; and

The second shot spacing is substantially three times the first shot spacing.

3. The method of claim 1 or 2, wherein the determination of the first and second shot spacing is based at least in part on a wave frequency of a far-offset source.

4. The method of any of claims 1-3, wherein the one or more far-offset sources comprise sources configured to emit seismic energy, wherein a majority of the seismic energy is emitted at a frequency below 25 Hz.

5. the method of any preceding claim, wherein the second shot spacing is an integer multiple of the first shot spacing such that when the one or more far offset sources are actuated, the one or more far offset sources are actuated substantially simultaneously with the one or more near offset sources.

6. The method of any preceding claim, wherein:

the plurality of seismic streamers includes at least two arrays coupled to at least two seismic streamer vessels, respectively.

7. The method of any preceding claim, further comprising:

Actuating one or more intermediate migration sources, wherein the one or more intermediate migration sources are located farther from the seismic streamer than the one or more near migration sources and the one or more intermediate migration sources are located closer to the seismic streamer than the one or more far migration sources, and wherein the one or more intermediate migration sources are actuated according to the first shot interval.

8. The method of claim 7, wherein the one or more intermediate migration sources and the one or more far migration sources are located on the same side of the seismic streamer in a cross-line direction.

9. The method of any of the preceding claims, wherein at least one of the one or more near offset sources or at least one of the one or more far offset sources comprises an airgun.

10. The method of any of the preceding claims, wherein at least one of the one or more near offset sources or at least one of the one or more far offset sources comprises a marine vibrator.

11. the method of any preceding claim, wherein there are fewer far offset sources than near offset sources.

12. The method of any preceding claim, further comprising selecting the first and second shot spacings depending on one or more performance requirements of a full wave inversion process.

13. A survey system comprising:

A plurality of seismic streamers;

At least one near offset seismic source configured to actuate according to a first shot spacing;

at least one far-offset seismic source configured to actuate according to a second shot spacing, wherein the at least one far-offset source is located farther from the plurality of seismic streamers than the at least one near-offset source, wherein the second shot spacing is longer in time or distance than the first shot spacing, wherein the second shot spacing is an integer multiple of the first shot spacing, and wherein the at least one far-offset seismic source is further configured to actuate substantially simultaneously with the at least one near-offset seismic source;

wherein the plurality of seismic streamers are configured to receive seismic data responsive to actuation of the at least one near-offset seismic source or the at least one far-offset seismic source; and

A recording system configured to generate a stored record of the seismic data.

14. The system of claim 13, wherein the determination of the first and second shot intervals is based at least in part on a wave frequency of the at least one far-offset source.

15. The system of claim 13 or 14, wherein the seismic streamer comprises two or more arrays coupled to two or more vessels, respectively.

16. The system of claim 15, wherein the at least one near offset source comprises two or more sources coupled to the two or more vessels, respectively, and wherein the at least one far offset source is located at a substantially equal distance from the two or more vessels.

17. The system of any of claims 13-16, further comprising one or more intermediate migration sources, wherein the one or more intermediate migration sources are located farther from the seismic streamer than the at least one near migration source and the one or more intermediate migration sources are located closer to the seismic streamer than the at least one far migration source, and wherein the one or more intermediate migration sources are configured to actuate according to a third shot interval.

18. The system of any of claims 13-17, wherein the at least one near-offset source and at least one of the plurality of seismic streamers are coupled to a same vessel.

19. A method of manufacturing a geophysical data product comprising:

In marine seismic exploration, actuating one or more near offset seismic sources according to a first initiation pattern;

Actuating one or more far-offset seismic sources according to a second firing pattern, wherein in the second firing pattern the one or more far-offset seismic sources fire less frequently than the one or more near-offset seismic sources, and wherein the one or more far-offset seismic sources are located at a greater distance from the plurality of seismic streamers than the one or more near-offset seismic sources;

Collecting geophysical data responsive to actuation of the one or more near offset seismic sources and the one or more far offset seismic sources via the plurality of seismic streamers; and

Storing the geophysical data on a tangible computer-readable medium, thereby completing the manufacture of the geophysical data product.

20. The method of claim 19, wherein:

Actuating the one or more near offset seismic sources comprises alternately actuating each of two near offset seismic sources;

Actuating the one or more far offset seismic sources comprises alternately actuating each of two far offset seismic sources; and

The first initiation mode initiates substantially as often as three times the second initiation mode.

Background

Drawings

FIG. 1 is a diagram illustrating a system for conducting marine seismic surveys, in accordance with some embodiments.

FIG. 2 is a diagram illustrating a layout for conducting Simultaneous Long Offset (SLO) marine seismic surveys, in accordance with some embodiments.

FIG. 3 is a diagram illustrating shot spacing for conducting an SLO marine seismic survey, in accordance with some embodiments.

FIG. 4 is a graph illustrating a relationship between frequency and trace distance according to some embodiments.

FIG. 5 is a diagram illustrating a layout for conducting Simultaneous Long Offset (SLO) marine seismic surveys, in accordance with some embodiments.

FIG. 6 is a diagram illustrating shot spacing for performing an SLO marine seismic survey with a longer far offset shot spacing, in accordance with some embodiments.

FIG. 7 is a flow diagram illustrating a method for conducting marine seismic surveys, in accordance with some embodiments.

FIG. 8 is a flow chart illustrating a method for performing an SLO marine seismic survey with a longer far offset shot spacing, in accordance with some embodiments.

FIG. 9 is a diagram illustrating a layout for conducting a Wide Azimuth (WAZ) marine seismic survey, according to some embodiments.

FIG. 10 is a diagram illustrating shot spacing for conducting WAZ marine seismic surveys with longer far offset shot spacing, in accordance with some embodiments.

FIG. 11 is a flow diagram illustrating a method for conducting WAZ marine seismic surveys with longer far-offset shot spacing, in accordance with some embodiments.

FIG. 12 is a diagram illustrating a layout for marine seismic surveying using multiple streamer arrays, according to some embodiments.

FIG. 13 is a diagram illustrating shot spacing for marine seismic surveys conducted according to the layout of FIG. 12 with longer far-offset shot spacing, in accordance with some embodiments.

FIG. 14 is a flow diagram illustrating a method for marine seismic surveying according to the layout of FIG. 12 with longer far-offset shot spacing, in accordance with some embodiments.

FIG. 15 is a flow diagram illustrating a method for conducting marine seismic surveys, in accordance with some embodiments.

FIG. 16 is a block diagram illustrating a computing system in accordance with some embodiments.

while the invention is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the disclosure to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present disclosure including the appended claims. The particular features, structures, or characteristics may be combined in any suitable manner consistent with the present disclosure.

It is to be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting. As used herein, the singular forms "a", "an" and "the" include both the singular and the plural referents unless the content clearly dictates otherwise. Moreover, throughout this application, the words "may" and "may" are used in a permissive sense (i.e., having the potential to, being able to), rather than the mandatory sense (i.e., must). The term "including" and its derivatives mean "including, but not limited to".

Within this disclosure, different entities (which may be variously referred to as "units," "circuits," other components, etc.) may be described or claimed as being "configured" to perform one or more tasks or operations. The formula entity is configured to perform one or more tasks, as used herein to refer to a structure (i.e., a physical thing, such as an electronic circuit). More specifically, the formula is used to indicate that the structure is arranged to perform one or more tasks during operation. A fabric may be said to be "configured to" perform a task even though the fabric is not currently being operated. A "mobile device configured to generate a hash value" is intended to cover, for example, a mobile device that performs this function during operation, even if the device in question is not currently in use (e.g., when its battery is not connected to it). Thus, an entity described or stated as "configured to" perform a task refers to something physical, such as a device, circuitry, memory storing program instructions (executable to perform the task), and so forth. This phrase is not used herein to refer to intangible material.

The term "configured to" is not intended to mean "configurable". For example, an unprogrammed mobile computing device would not be considered "configured to" perform a particular function, although it may be "configurable" to perform that function. After appropriate programming, the mobile computing device may then be configured to perform that function.

the statement in the appended claims that the structure "configured to" perform one or more tasks is specifically not intended to invoke 35u.s.c. § 112 (f) for that claim element. Thus, neither is it intended that any claim as filed be interpreted as having means plus function elements. If applicants wish to refer to section 112 (f) during prosecution, they will use the configuration of "means" for "performing a function to recite a claim element.

As used herein, the term "based on" is used to describe one or more factors that affect the determination. The term does not exclude the possibility that additional factors may influence the determination. That is, the determination may be based on specified factors only or on specified factors as well as other unspecified factors. Consider the phrase "determine a based on B. The phrase specifies that B is a factor used to determine A or affect the determination of A. The phrase does not exclude that the determination of a may also be based on some other factor, such as C. The phrase is also intended to cover embodiments in which a is determined based only on B. As used herein, the phrase "based on" is synonymous with the phrase "based, at least in part, on".

As used herein, the term "coupled to" may indicate one or more connections between elements, and a coupling may include intermediate elements. That is, two elements may be indirectly coupled through intervening elements. In contrast, two elements may be said to be "directly coupled" to each other without intervening elements.

Detailed Description

Performing marine seismic surveys can be a difficult and expensive operation. Actuating more seismic sources than necessary may increase cost, environmental impact, or other undesirable effects. In some configurations, a survey may generate data that is unnecessary, or at least useless, relative to the cost of acquiring the data. For example, very large offset data may be discarded due to problems in image quality or relatively small improvements to the image. As another example, the Full Wave Inversion (FWI) process discussed below may be performed using only lower frequencies, which may not require as dense spatial sampling as the rest of the data set. Thus, in some embodiments of marine seismic exploration, seismic sources located at relatively far offsets are not actuated as often as seismic sources at relatively close offsets. Various survey configurations may be implemented in this manner, including simultaneous time offset (SLO), Wide Azimuth (WAZ), and multiple streamer arrays, all of which are discussed in turn below.

Turning now to FIG. 1, a diagram of one embodiment of an arrangement for marine geophysical surveying using a towed submerged streamer array is shown. In the illustrated embodiment, the towing vessel 100 tows an array of submerged streamers 104. Each of the submerged streamers may include a plurality of seismic sensors. The types of sensors that may be implemented in a given streamer include, but are not limited to, hydrophones and geophones. Further, a given streamer may include more than one type of sensor (e.g., a combination of hydrophones and geophones). Various operational considerations may make a certain towing depth advantageous. In some embodiments, a single sensor streamer 104 may be towed at a depth of between about 4 meters and 30 meters. In some embodiments, the dual-sensor streamer may be towed at a depth of between about 15 meters and 30 meters.

the towboat 100 may also tow multiple sources 102 via tow cables 103. In some embodiments, the source 102 may be towed by another vessel or vessels (not shown). The source 102 may include various seismic sources, such as marine vibrators, air guns, and the like. In some embodiments, the source 102 may transmit acoustic waves into the water, the echoes of which may be detected by seismic sensors of the streamer 104. The sensors and receivers of the streamers 104 may be coupled (e.g., electrically coupled, wirelessly coupled, etc.) to electronics on the towing vessel 100, which may be used to record or analyze geophysical data, such as received echoes or detected signals. Using the arrangement shown in FIG. 1, a marine geophysical survey may be conducted. One of the uses of the information obtained from these surveys may be to identify geological formations indicative of oil and/or gas deposits.

FIG. 2 illustrates an embodiment of a system configured for conducting seismic surveys. In the illustrated embodiment, a Simultaneous Long Offset (SLO) configuration is depicted: streamer vessel 210 tows at least two near offset sources 220 and an array of seismic streamers 250, while source vessel 230 tows at least two far offset sources 240. (in other embodiments, a single far-offset source 240 may be used, or multiple different source vessels 230 may be employed.) in the illustrated embodiment, the source vessel 230 is located in front of the streamer vessel 210 in the longitudinal direction. The axes of fig. 2 depict the longitudinal direction as the y-direction and the crossline direction as the x-direction. The distance between vessels 210 and 230 may vary depending on the configuration of the survey system; non-limiting examples of distances between vessels 210 and 230 include 4, 6, and 8 kilometers, although the range is not limited in principle.

In some embodiments, at least one near-offset source and at least one seismic streamer are coupled to the same vessel. In other embodiments, a closer offset source may be coupled to the vessel. In still other embodiments, the seismic streamers 250 may be coupled to vessels separate from the near-offset source.

Fig. 3 illustrates an embodiment of shot interval (SPI) mode corresponding to the SLO configuration system of fig. 2. In the illustrated embodiment, the source is actuated according to SPI mode: the far offset source is actuated according to pattern 320 and the near offset source is actuated according to pattern 310. For each of the SPI modes 310 and 320, shots are numbered 1 through 4, where like numbers between modes 310 and 320 indicate the location of the source at a common point in time. For example, shot 1 in near offset mode 310 and shot 1 in far offset mode 320 occur at approximately the same time. For the purposes of this disclosure, simultaneous actuation of the sources includes actuating the sources within a time window such that the energy recorded from the source activations overlaps to the extent that a demixing of the overlapping energies must be performed. Furthermore, in some embodiments, the source actuations may be timed such that the far and near offset data partially overlap or completely separate in time, rather than being substantially simultaneous.

In the illustrated embodiment, each of the two near offset sources is actuated alternately, and each of the two far offset sources is also actuated alternately. In the illustrated embodiment, for example, first far offset source 240 is actuated at shots 1 and 3, and the second is actuated at shots 2 and 4. Similarly, in the illustrated embodiment, each of the two near offset sources 220 is alternately actuated: the first source is activated at points 1, 3, etc., and the second source is activated at points 2, 4, etc. The relative positions of the stars in figure 3 illustrate the physical position of the source in this embodiment when actuated. The axes of fig. 3 depict the longitudinal direction as the y-direction and the crossline direction as the x-direction. In the illustrated embodiment, far offset source vessel 240 moves in the same direction and at the same speed as vessel 210, such that the distance between shots with the same number is the same for the near and far shot spacing patterns. In the illustrated embodiment, for example, the distance between the near offset point 1 and the far offset point 1 is the same as the distance between the near offset point 4 and the far offset point 4. In other embodiments, there may be additional sources that may actuate according to different modes; for example, there may be three sources each actuated in sequence, or there may be a single source actuated at each point, or there may be other modes of actuation corresponding to the configuration of the various sources. In some embodiments, vessels 210 and 230 may not have the same number of sources.

In some embodiments, the advantages of actuating the seismic source at each point of the far-offset source mode 320 may not outweigh the disadvantages. Disadvantages of actuating more than necessary include increased cost (e.g., a larger vessel may be required to support increased average power), environmental impact, more seismic noise, or other unwanted effects. In some seismic surveys, the benefit of actuating the source at each shot point may be small; for example, seismic surveys implementing Full Wave Inversion (FWI) techniques may not benefit from having as many far offset source actuations as near offset source actuations.

FWI is a data processing technique that can be used to process data collected by seismic surveys. FWI may include simulating seismic sources and propagating waves through a model of the area being surveyed. The model may be iteratively updated according to a loss function that compares the simulated seismic measurements to the actual seismic measurements. In some embodiments, the complexity of calculating wave propagation limits the amount of frequencies useful for FWI. In some embodiments, limiting the frequency used may increase the speed of the calculation or the accuracy in which the iterative update process converges. In embodiments of seismic exploration where FWI is a desired technique, it may be advantageous to collect only the most useful frequencies. The desired frequency may be a lower frequency, such as below 25Hz, below 15Hz, below 10Hz, below 8Hz, and the like.

FIG. 4 is a graph illustrating one example of a relationship between the Nyquist frequency of a seismic signal and the distance between measured seismic traces (seismic traces). In the illustrated embodiment, the relationship shown on the graph by the triangular dots corresponds to a wave speed of 1600m/s and a tilt angle of 30 degrees. In some embodiments, increasing the frequency requirement of the measurement implies a non-linear reduction in trace distance. In some embodiments, the trace distance corresponds to the distance between measurement devices (e.g., hydrophones, geophones, etc.) on the seismic streamers and/or the distance between source actuations.

in some embodiments, the determination of the various SPIs is based, at least in part, on the wave frequency of the far offset source. In some embodiments, only certain frequencies may be required (by way of non-limiting example, Full Wave Inversion (FWI) or other configurations of seismic surveys), as discussed above by FWI. In embodiments such as those, fig. 4 may illustrate trace distances that may provide suitable data. As a non-limiting example, SLO for FWI may require frequencies up to 10 Hz; for certain conditions in the illustrated embodiment, the corresponding trace distance may be 75 m. Another example may be a conventional SLO, which may require frequencies up to 32 Hz; for certain conditions in the illustrated embodiment, the corresponding trace distance may be 25 m.

Turning to FIG. 5, another embodiment of a system configured for conducting seismic surveys is shown. In the illustrated embodiment, an SLO configuration similar to fig. 2 is depicted. Although the embodiments illustrated in fig. 2 and 5 are similar, other embodiments of either system may be different, e.g., the distance between vessels 510 and 530 may be closer or farther than in fig. 2, the number or configuration of sources 520 or 540 may be different, or other parameters for configuring a seismic survey may be different. Similar to the previous figures, the axes of fig. 5 and 6 depict the longitudinal direction as the y-direction and the cross-line direction as the x-direction.

The illustrated embodiment of FIG. 6 depicts an SPI mode corresponding to the survey system of FIG. 5. However, this embodiment is different from the SPI mode of fig. 3. Similar to fig. 3, the far offset source 540 may be actuated according to a far offset source pattern 620, while the near offset source 520 may be actuated according to a near offset source pattern 610. For each of SPI modes 610 and 620, shots are numbered 1 through 8, where like numbers between modes 610 and 620 indicate the location of the source at a common point in time. As discussed below, in the illustrated embodiment, the source may not be activated at certain shots. However, if multiple sources are actuated at a given shot, those actuations may be substantially simultaneous (e.g., shot 1 from 610 and shot 1 from 620 may be simultaneous, shot 2 from 610 and shot 2 from 620 may be simultaneous, etc.). In some embodiments, the proximal and distal offset sources are actuated substantially simultaneously.

In the illustrated embodiment, the far offset source mode 620 illustrates some shots that do not correspond to actuations. In the illustrated embodiment, shots 2, 3, 5, 6, and 8 from far offset source mode 620 indicate that the far offset source should not be actuated, while the same shot number from near offset source mode 610 indicates that the near offset source should be actuated. In some embodiments, the near offset sources may be activated at all shots, or they may be activated at some shots and not at others. The illustrated embodiment depicts a far offset source that actuates at every other shot, but in other embodiments, different patterns of actuation may be used (e.g., every other shot, every third shot, alternating between two and three inactive shots, etc.).

in some embodiments, the shot spacing of one set of sources is an integer multiple of another set of sources, such that a first set of sources (e.g., far offset sources) are actuated less often than a second set of sources (e.g., near offset sources). Further, in some instances, the shot spacing of the two sets of sources may be aligned such that when one of the far offset sources is actuated, one of the near offset sources performs the same operation substantially simultaneously. By way of non-limiting example, the far offset source may be configured to actuate according to a spacing that is substantially three times the shot spacing of the near offset source, similar to the embodiment depicted in fig. 6. In other embodiments, the far offset source may be actuated by other multiples; for example, and not intended to be limiting, the far offset sources may be actuated at intervals that are 4 times, 5 times, 6 times, etc. the near shot intervals. In some embodiments, sources configured in this manner may be actuated substantially simultaneously. However, it is not necessary that the shot spacing of one set of sources be an integer multiple of the other set of sources.

The reduced actuation of the far offset source mode 620 may provide sufficient data related to low frequencies from the seismic source to perform FWI analysis. As discussed with respect to fig. 4, the low frequency source may not need to be actuated as frequently as the high frequency source. In addition, higher frequencies may be attenuated at far offsets, limiting the usefulness of far offset sources for high frequency applications. The benefits associated with fewer actuations (e.g., lower cost, less environmental impact, lower seismic noise, etc., as discussed above) may be realized by the far-offset source mode 620.

FIG. 7 is a flow diagram illustrating a method for performing marine seismic surveying, in accordance with some embodiments. The method shown in fig. 7 may be used in conjunction with any computer system, device, element, or component disclosed herein, among other devices. In various embodiments, some of the illustrated method elements may be performed concurrently, may be performed in a different order than illustrated, or may be omitted. Additional method elements may also be performed as desired.

In the illustrated embodiment, at 710, one or more near offset seismic sources are actuated according to a first shot spacing in a marine seismic survey. In some embodiments, the seismic source comprises a plurality of air gun arrays; in some embodiments, the individual airgun arrays may be fired sequentially so that a particular shot spacing may be maintained. In some embodiments, the one or more near offset sources may include an air gun or marine vibrator. In some embodiments, the seismic source may be configured to emit a majority of the seismic energy at frequencies below 10 Hz.

The shot interval may be defined in terms of the time between successive actuations of the seismic sources, or it may be defined in terms of the distance between successive actuations of the seismic sources. Examples of shot intervals (not intended to be limiting) include intervals as short as 6.25 meters and ranging up to 50 meters. In other embodiments, shot spacing may be outside of this range.

In the illustrated embodiment, at 720, one or more far-offset sources are actuated according to a second shot spacing in the marine seismic survey. In some embodiments, the second shot spacing is longer in distance or time than the first shot spacing. In some embodiments, the one or more far-offset sources are located at a greater distance from the seismic streamers than the one or more near-offset sources. The far offset source may be coupled to a vessel separate from the streamer or near offset source. In some embodiments, the one or more far-offset sources may include air guns or marine vibrators. In some embodiments, there may be fewer far offset sources than near offset sources.

In the illustrated embodiment, seismic data is collected in response to actuation of the near and far offset sources at 730. In some embodiments, the seismic streamers are configured to receive seismic data responsive to actuation of at least one near offset seismic source or at least one far offset seismic source. As discussed in more detail below, the recording system may be configured to generate a stored record of seismic data. The seismic data may include seismic traces or other data collected while the seismic source is being actuated. In some embodiments, data responsive to actuation of a near offset source may be collected simultaneously with data responsive to actuation of a far offset source. In some embodiments, data responsive to the near and far offset sources may be received by the sensor within overlapping time periods in such a way as to allow separation of the data from the respective sources. For example, de-mixing or disambiguation of multiple simultaneously activated sources may occur during post-acquisition data processing.

In contrast to the previous figures, FIG. 8 is a flow chart illustrating a more detailed method for performing marine seismic surveying, according to some embodiments. The method shown in fig. 8 may be used in conjunction with any computer system, device, element, or component disclosed herein, among other devices. In various embodiments, some of the illustrated method elements may be performed concurrently, may be performed in a different order than illustrated, or may be omitted. Additional method elements may also be performed as desired.

In the illustrated embodiment, a marine seismic survey system is configured at 810. Configuring the survey system may include selecting and configuring a plurality of vessels, configuring seismic sources and coupling them to the vessels, configuring seismic streamers, coupling them to at least one vessel, configuring the streamers to receive data, or any other operation of the survey system suitable for preparing for survey activities.

In the illustrated embodiment, at 820, the far offset SPI is selected. In some embodiments, SPI may depend on one or more performance requirements in a full-wave inversion (FWI) process, as discussed above. In some embodiments, the selection of the SPI includes choosing a multiple of the near offset source SPI, choosing a particular shot to suppress actuation, or determining the distance between consecutive shots. The performance requirements of the FWI process may include the amount of data collected at a particular frequency, the total amount of data collected, the level of noise in the collected data, or other parameters that may affect the seismic survey of the acquired data.

In the illustrated embodiment, at 830, the seismic streamers and sources are towed in the vicinity of the geological feature. Towing may include pulling streamers and sources behind the vessel in the water. The geological features may include subsurface minerals, oil or gas deposits, salt domes, or any other feature that can be imaged using seismic techniques.

In the illustrated embodiment, at 840, the near offset seismic source is actuated according to the SPI. In some embodiments, there may be two or more near offset seismic sources, and these sources may be actuated in an alternating manner.

In the illustrated embodiment, at 850, the far offset seismic source is actuated according to the SPI. In some embodiments, there may be two or more far-offset seismic sources, and these sources may be actuated in an alternating manner. In the illustrated embodiment, the SPI for the far offset source is longer than the SPI for the near offset source. As described above, in some embodiments, the SPI of the far offset source may be a multiple of the SPI of the near offset source.

In the illustrated embodiment, data responsive to actuation of the seismic source is collected and recorded at 860. For example, pressure sensors and/or particle motion sensors (e.g., hydrophones and/or geophones) coupled to the streamers may collect seismic data from each shot point, and this data may be recorded by a recording system coupled to the hydrophones or geophones. In some embodiments, the recording system may be a general purpose computing system or a computing system specifically configured to record seismic data.

FIG. 9 illustrates an embodiment of a system configured for conducting seismic surveys. Similar to fig. 3 and 5, fig. 9 illustrates a set of vessels (910, 920, and 930), a set of sources (940, 950, and 960), and a seismic streamer array 970. In the illustrated embodiment, these components are configured in a Wide Azimuth (WAZ) layout, which may facilitate the collection of seismic data in the presence of obstacles (e.g., salt domes) that are difficult to image with other survey geometries. In this embodiment, there may be two source vessels: a vessel 930 coupled to a far offset source 960 and a vessel 920 coupled to a mid offset source 950. Similar to the previous figures, the axes of fig. 9 depict the longitudinal direction as the y-direction and the cross-line direction as the x-direction. In some embodiments, all vessels may be located to one side (e.g., port or starboard) of the streamer vessel 910 in the cross-line direction, although it is possible that the source vessels are located to different sides of the streamer vessel 910 in an WAZ survey. In some embodiments, the one or more intermediate offset sources 950 and the one or more far offset sources 960 are located on the same side of the seismic streamer in the cross-line direction. The mid-offset source may be located farther from the seismic streamer than the near-offset source 940, and the mid-offset source may be located closer to the seismic streamer than the far-offset source 960. In the illustrated embodiment, a near offset source 940 and a seismic streamer 970 are coupled to the streamer vessel 910.

Fig. 10 illustrates an embodiment of an SPI configuration corresponding to the WAZ configuration illustrated in fig. 9. Similar to fig. 6, fig. 10 illustrates a set of shots arranged in space, where the number of each shot corresponds to the location of a source at a point in time at which the source may be actuated. Similar to the previous figures, the axes of fig. 10 depict the longitudinal direction as the y-direction and the cross-line direction as the x-direction.

Fig. 10 includes an intermediate offset source firing pattern 1020. In some embodiments, the intermediate offset sources may be configured to actuate according to the same SPI as either the near offset source or the far offset source, or they may be configured to actuate according to a different SPI than either the near or far offset source SPI.

In the illustrated embodiment, the far offset source firing pattern 1030 includes shots where no source actuation is indicated: shots 2, 3, 5, 6 and 8. The illustrated embodiment shows a far offset source induced at an SPI three times as long as the near and intermediate offset SPIs; however, this is not intended to be a limiting example, and other configurations as previously discussed may be used.

FIG. 11 is a flow diagram illustrating a method for performing marine seismic surveying, in accordance with some embodiments. The method shown in fig. 11 may be used in conjunction with any computer system, device, element, or component disclosed herein, among other devices. In various embodiments, some of the illustrated method elements may be performed concurrently, may be performed in a different order than illustrated, or may be omitted. Additional method elements may also be performed as desired.

The method illustrated in FIG. 11 includes several elements that are substantially similar to the elements of FIG. 8. In the illustrated embodiment, elements 1110, 1120, and 1130 may accordingly be implemented similarly to elements 810, 820, and 830 of fig. 8 and will not be discussed further herein. Element 1170 may be implemented similarly to element 860 of fig. 8. The differences between the methods of fig. 8 and 11 will be discussed below; note that in other embodiments, the method of fig. 11 may be implemented with more, fewer, or different elements, and need not employ elements similar to those of fig. 8.

In the illustrated embodiment of FIG. 11, at 1140, the intermediate offset source vessel and the far offset source vessel are arranged in a crossline direction. In some embodiments, the intermediate offset source vessel may be closer to the seismic streamer array than the far offset source vessel, and the intermediate offset source vessel may be further from the seismic streamer array than the near offset source vessel. In some embodiments, the near-offset source vessel may tow both the near-offset source and the seismic streamer array.

In the illustrated embodiment of FIG. 11, at 1150, one or more near offset sources and one or more intermediate offset sources are actuated as a function of shot spacing. In the illustrated embodiment, the SPI for the near and intermediate sources is the same. In some embodiments, the near offset source and the intermediate offset source are actuated according to the same shot spacing. In other embodiments, the near and intermediate offset sources may be activated according to different intervals, or the intermediate offset sources may not be activated at each shot. In some embodiments, the intermediate offset source and the near offset source actuate substantially simultaneously; however, in other embodiments they may not be actuated at the same time.

Step 1160 is similar to element 850 of FIG. 8. However, in the illustrated embodiment of fig. 11, the SPI of the far offset source may have a relationship with the intermediate offset source SPI and the near offset source. In some embodiments, the far offset source may have a longer SPI than both the near and intermediate offset sources, or it may have a longer SPI than the near offset source and a shorter SPI than the intermediate offset source, or it may have a longer SPI than the near offset source and the same SPI as the intermediate offset source, and so on.

FIG. 12 illustrates another embodiment of a system configured for conducting seismic surveys. Similar to fig. 3, 5, and 9, fig. 12 illustrates a collection of vessels (1210, 1230, and 1250), a collection of sources (1220, 1240, and 1260), and seismic streamer arrays (1270 and 1280). Similar to the previous figures, the axes of fig. 12 depict the longitudinal direction as the y-direction and the cross-line direction as the x-direction. In the illustrated embodiment, these components are configured in a multiple streamer array layout, which, like the WAZ layout, may improve the survey quality for certain types of subsurface conditions. In this embodiment, there may be three source vessels: vessel 1250 coupled to far offset source 1260, vessel 1210 coupled to near offset source 1220, and vessel 1230 coupled to near offset source 1240. In the illustrated embodiment, two near offset vessel towable seismic streamer arrays 1270 and 1280, and may be positioned such that vessel 1230 is in a cross-line direction with vessel 1210; additionally, far offset source vessel 1250 may be positioned in front of the two vessels 1210 and 1230 in the longitudinal direction and positioned approximately midway between the vessels 1210 and 1230 in the crossline direction. In some embodiments, one or more additional near offset sources (not shown) may be deployed between vessels 1210 and 1230.

In some embodiments, boats 1250 are located at substantially equal distances from boats 1210 and 1230. However, vessel 1250 may be deployed at any suitable location, extending from, for example, directly in front of vessel 1210 to directly in front of vessel 1230. In some embodiments, the seismic streamer includes at least two streamer arrays coupled to at least two seismic streamer vessels, respectively. In some embodiments, at least two near offset sources 1220 and 1240 are coupled to at least two vessels 1210 and 1230, respectively, and at least one far offset source 1260 is located at a substantially equal distance from vessels 1210 and 1230.

In some embodiments, like the survey configurations discussed above, the near-offset sources 1220 and 1240 may contain more or fewer seismic sources than in the illustrated embodiment, and the seismic streamer arrays 1270 and 1280 may be comprised of more or fewer seismic streamers than in the illustrated embodiment. In some embodiments, there may be additional vessels that may be coupled to additional sources or streamers. In some embodiments, far offset source vessel 1250 may be positioned closer to vessel 1210, closer to vessel 1230, farther in the crossline direction, etc. than vessel 1230, as non-limiting examples.

FIG. 13 illustrates an embodiment of SPIs corresponding to the multiple streamer array configuration illustrated in FIG. 12. Similar to fig. 10 and 6, fig. 13 illustrates a set of shots arranged in space, where the number of each shot indicates the location of the source at the point in time at which the source may be actuated; the axes of fig. 13 depict the longitudinal direction as the y-direction and the crossline direction as the x-direction.

FIG. 13 includes two near offset source firing patterns, 1310 and 1320. In the illustrated embodiment, near offset sources 1220 and 1240 may be configured to actuate according to the same SPI, which may result in mode 1310 being the same as mode 1320. In some embodiments, sources 1220 and 1240 may be configured to actuate according to different SPIs, for example, mode 1310 may be different than mode 1320.

In the illustrated embodiment, far offset source firing pattern 1330 includes shots where no source actuation is indicated: shots 2, 3, 5, 6 and 8. The illustrated embodiment shows a far offset source induced at an SPI three times as long as the near and intermediate offset SPIs; however, this is not intended to be a limiting example, and other configurations as previously discussed may be used.

FIG. 14 is a flow diagram illustrating a method for performing marine seismic surveying, in accordance with some embodiments. The method shown in fig. 14 may be used in conjunction with any computer system, device, element, or component disclosed herein, among other devices. In various embodiments, some of the illustrated method elements may be performed concurrently, may be performed in a different order than illustrated, or may be omitted. Additional method elements may also be performed as desired.

The method illustrated in FIG. 14 includes several elements that are substantially similar to the elements of FIG. 8. In the illustrated embodiment, elements 1420 and 1430 may be implemented similarly to elements 820 and 830 of FIG. 8, respectively, and will not be discussed further herein. Element 1480 may be implemented similar to element 860 of fig. 8. The differences between the methods of fig. 14 and 8 will be discussed below; note that in other embodiments, the method of fig. 11 may be implemented with more, fewer, or different elements, and need not employ elements similar to those of fig. 8.

In the illustrated embodiment of FIG. 14, at 1410, a marine seismic survey system is illustrated that includes a seismic source, three or more vessels, and two or more seismic streamer arrays. Step 1410 illustrates a system similar to element 810 of FIG. 8; however, 1410 specifically includes 3 or more vessels and 2 or more streamer arrays. In some embodiments, the method illustrated in fig. 14 may describe a multiple streamer array process similar to the multiple streamer array process illustrated in fig. 12 and 13.

in the illustrated embodiment of fig. 14, at element 1440, the second streamer array may be arranged in a cross-line direction from the first streamer array. In some embodiments, the second streamer array may be disposed on a port side or a starboard side of the first streamer array. In some embodiments, the streamer array may have a different number of streamers, different lengths of streamers, different sensors on the streamers, and so forth.

In the illustrated embodiment, at element 1450, the far-offset source vessel is disposed longitudinally forward of the two seismic streamer vessels and crossways between the two seismic streamer vessels. In some embodiments, the far-offset source vessel may be closer to one streamer vessel or the other in the cross-line direction, or the source vessel may be located further in the port or starboard direction than either streamer vessel.

In the illustrated embodiment, at 1460, one or more near offset seismic sources associated with each streamer array are actuated as a function of shot spacing. In some embodiments, the sources associated with each streamer are actuated according to the same SPI; in other embodiments, the set of sources may be actuated according to different SPIs. In some embodiments, there is a seismic source coupled to each vessel towing the streamer array.

In the illustrated embodiment, at 1470 one or more far offset seismic sources are actuated according to a longer shot interval. This element may be similar to 850 of FIG. 8, however, in some embodiments, the far offset source may have a relationship to either of the near offset sources. In some embodiments, the SPI of the far offset source is longer than any of the SPIs of the near offset sources. In some embodiments, the near offset sources may have different SPIs, and the far offset sources may have longer SPIs than one or the other or both of the near offset sources, for example.

FIG. 15 is a flow diagram illustrating a method for performing marine seismic surveying, in accordance with some embodiments. More specifically, as described in more detail below, FIG. 15 relates to the generation of geophysical data products based on survey data. The method shown in fig. 15 may be used in conjunction with any computer system, device, element, or component disclosed herein, among other devices. In various embodiments, some of the illustrated method elements may be performed concurrently, may be performed in a different order than illustrated, or may be omitted. Additional method elements may also be performed as desired.

In some embodiments, the survey data collected may be embodied in a "geophysical data product". The geophysical data product may include a computer-readable, non-transitory medium having geophysical data stored thereon, including, for example, raw streamer data, processed streamer data, two-or three-dimensional maps based on the streamer data, or other suitable representations. Some non-limiting examples of the computer readable medium may include a hard drive, a CD, a DVD, a flash memory, a printout, and so forth. In some embodiments, raw analog data from the streamers may be stored in a geophysical data product. In other examples, the data may first be digitized and/or conditioned prior to being stored in the geophysical data product. In still other examples, the data may be fully processed into two-dimensional or three-dimensional maps of various geophysical structures before being stored in the geophysical data product. While analysis of the geophysical data product may occur contemporaneously with the survey data collection, the geophysical data product may be manufactured during the survey (e.g., by equipment on a ship) and then, in some instances, transferred to another location for geophysical analysis.

In the illustrated embodiment, at 1510 in a marine seismic survey, one or more near offset seismic sources are actuated according to a triggering pattern. Embodiments of seismic sources and configurations of seismic surveys have been previously discussed; further reference may be found in the discussion related to 710 of fig. 7. The firing pattern may indicate, among other things, the manner or sequence in which the seismic sources are actuated. In some embodiments, the initiation pattern may be described similarly to shot spacing. In some embodiments, the priming pattern may include a time or distance between actuations and may vary from one actuation to another.

in some embodiments, two or more near offset sources are alternately actuated. In embodiments with two near offset sources, this may include actuating the first source, then actuating the second source, then actuating the first source again, and so on. In some embodiments, more than two near offset sources may be actuated in an alternating manner by actuating each source in sequence or in another pattern or randomly alternating actuation. Multiple near offset sources may also be actuated simultaneously, instead of or in addition to alternating.

In the illustrated embodiment, at 1520, in marine seismic surveys, one or more far offset sources are actuated according to a less frequent triggering pattern. In some embodiments, the far-offset source is located at a greater distance from the seismic streamer than the near-offset source. The far offset source may be coupled to a vessel separate from the streamer or near offset source. In some embodiments, less frequent initiation patterns may correspond to longer shot intervals; for example, actuating a source less frequently may mean a longer distance or time between actuations.

In some embodiments, two or more far-offset seismic sources are alternately actuated. The alternate actuation of the far offset seismic sources may be accomplished in a similar manner as described above for the near offset sources. In some embodiments, the firing pattern of the near offset source fires substantially as often as three times the firing pattern of the far offset source.

in the illustrated embodiment, at 1530, geophysical data responsive to actuation of the one or more near offset sources and the one or more far offset sources is collected. Geophysical data may include seismic traces or other data collected during a seismic survey. In some embodiments, the geophysical data includes seismic data, such as data recorded by pressure and/or particle motion sensors. In some embodiments, data responsive to actuation of a near offset source may be collected simultaneously with data responsive to actuation of a far offset source. In some embodiments, data responsive to the near and far offset sources may be indistinguishable, or it may be collected in such a way as to separate the data from the respective sources.

In the illustrated embodiment, the geophysical data is stored 1540 on a tangible computer readable medium to complete the manufacture of the geophysical data product. As noted above, non-limiting examples of media may include: magnetic hard drives, computer memory, non-volatile memory, DVD, tape drives, magnetic cassettes, optical media, combinations of the foregoing, and the like.

Referring now to fig. 16, a block diagram illustrating an embodiment of a computing system 1600 is shown. In some embodiments, the illustrated processing elements may be used to implement all or part of a marine seismic survey system or a data recording system. While fig. 16 illustrates an example organization of computing devices, many variations are possible and contemplated, and the illustrated configuration is expressly intended to be non-limiting. In the illustrated embodiment, computing system 1600 includes an interconnect 1610, processors 1620, input/output (I/O) bridge 1650, storage 1652, geophysical data 1654, cache/memory controller 1645, cache/memory 1646, code 1648, and graphics/display unit 1660.

The interconnect 1610 may include various devices configured to facilitate communication between various elements of the computing system 1600. In some embodiments, portions of interconnect 1610 may be configured to implement a variety of different communication protocols. In other embodiments, the interconnect 1610 may implement a single communication protocol, and elements coupled to the interconnect 1610 may internally convert from the single communication protocol to other communication protocols.

In the illustrated embodiment, processor 1620 includes a Bus Interface Unit (BIU) 1625, a cache 1630, and cores 1635 and 1640, although many variations of the illustrated organization are possible. For example, other numbers of processor cores may be employed. BIU 1625 may be configured to manage communications between processor 1620 and other elements of computing system 1600. Processor cores, such as cores 1635 and 1640, may be configured to execute instructions of a particular Instruction Set Architecture (ISA), which may include operating system instructions and user application instructions.

The cache/memory controller 1645 may be configured to manage the transfer of data between the interconnect 1610 and one or more caches and/or memories (including cache/memory 1646). For example, the cache/memory controller 1645 may be coupled to an L3 cache, which in turn may be coupled to system memory. In other embodiments, the cache/memory controller 1645 can be coupled directly to memory.

In the illustrated embodiment, the cache/memory 1646 stores code 1648. In some embodiments, code 1648 may be used to configure computing system 1600. In other embodiments, code 1648 may include instructions for processor 1620 to execute (such as instructions related to control of any of the systems or devices discussed above), such as for operation of survey equipment and/or collection of survey data. Code 1648 may include other information not described herein, including but not limited to data, configurations for other components of computing system 1600, or instructions executed by computing system 1600.

Graphics/display unit 1660 may include one or more processors and/or one or more graphics processing units (of a GPU). In contrast to the processor 1620, the graphics/display unit 1660 can be specifically configured to perform graphics-related processing operations to present information on a display. In some embodiments, element 1660 may be omitted; its operations may alternatively be performed by the processor 1620 or integrated within the processor 1620.

I/O bridge 1650 may include various elements configured to: such as Universal Serial Bus (USB) communication, security, audio, and/or low power always-on functionality. I/O bridge 1650 may also include interfaces such as, for example, Pulse Width Modulation (PWM), general purpose input/output (GPIO), Serial Peripheral Interface (SPI), and/or inter-integrated circuit (I2C). Various types of peripherals and devices can be coupled to device 1600 via I/O bridge 1650. In the illustrated embodiment, I/O bridge 1650 is coupled to storage 1652.

In some embodiments, storage 1652 may be a hard disk drive or a solid state drive. In some embodiments, storage 1652 may be a tape drive, a magnetic drive, a removable media drive, or the like. In the illustrated embodiment, the storage device 1652 includes geophysical data 1654. In some embodiments, the storage device 1652 on which the geophysical data 1654 is stored corresponds to a geophysical data product as discussed above.

***

Although specific embodiments have been described above, even where only a single embodiment is described with respect to a particular feature, these embodiments are not intended to limit the scope of the present disclosure. Unless otherwise specified, examples of features provided in the present disclosure are intended to be illustrative and not limiting. The above description is intended to cover such alternatives, modifications, and equivalents as would be apparent to those skilled in the art having the benefit of this disclosure.

The scope of the present disclosure includes any feature or combination of features disclosed herein (either explicitly or implicitly), or any generalization thereof, whether or not it mitigates any or all of the problems addressed herein. Thus, new claims may be formulated to any such combination of features during prosecution of this application (or of an application claiming priority thereto). In particular, with reference to the appended claims, features from dependent claims may be combined with those of the independent claims and features from respective independent claims may be combined in any appropriate manner and not merely in the specific combinations enumerated in the appended claims.