Patent Description:
The present disclosure relates generally to seismic acquisition modeling, and more specifically, to seismic modeling techniques to be used for seismic survey design with or without simultaneous source acquisition.

A seismic survey includes generating an image or map of a subsurface region of the Earth by sending acoustic energy down into the ground and recording the reflected acoustic energy that returns from the geological layers within the subsurface region. During a seismic survey, an energy source is placed at various locations on or above the surface region of the Earth, which may include hydrocarbon deposits. Each time the source is activated, the source generates a seismic (e.g., acoustic wave) signal that travels downward through the Earth, is reflected, and, upon its return, is recorded using one or more receivers disposed on or above the subsurface region of the Earth. The seismic data recorded by the receivers may be used to create an image or profile of the corresponding subsurface region.

Seismic survey designs provide locations for the energy sources and receivers (otherwise known as acquisition geometry). The survey designs are generated with a goal of ensuring that seismic acquisition will have adequate illumination of targets of interest to allow for imaging or mapping of the subsurface region. As such, it may be useful to develop survey designs that result in improvements of the imaging or mapping of the subsurface region, such that the operations related to extracting the hydrocarbons may be modified to more efficiently extract the hydrocarbons from the subsurface region of the Earth.

<CIT> discloses a technique for estimating a depth of investigation of a seismic survey. The method includes using forward modeling on a subsurface attribute model of a subterranean region to generate a set of low frequency data, and then performing a reverse time migration to obtain a plurality of gathers with large opening angles. These gathers are then stacked to yield a diving wave illumination image to estimate a full wave inversion.

<CIT> discloses full waveform inversion depot of investigation rendering the diving wave illumination image for visual inspection without computing a contribution of a respective diving wave from each source and receiver pair of the plurality of sets of source and receiver locations to diving waves passing through the region of interest based on the seismic amplitudes extracted from the diving wave illumination image for each source and receiver pair.

It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments. It should be noted and understood that there can be improvements and modifications made of the present invention described in detail below without departing from the scope of the invention as set forth in the accompanying claims.

Seismic acquisition utilizing sources and receivers may be useful in the generation of, for example, seismic images or velocity models. Seismic images may be used, for example, in the determination of hydrocarbon deposits (e.g., areas within a subsurface that contain hydrocarbons) and/or subsurface drilling hazards. Seismic images are generally produced using seismic waveforms produced by a source, reflected off regions within a subsurface, and received by one or more receivers. The seismic images that are generated depend greatly on the locations of the sources and receivers, also known as the acquisition geometry, of a seismic survey design. Trial and error may be used to determine the acquisition geometry of a seismic survey design. However, seismic surveying is too costly to be performed using trial and error to find a suitable acquisition geometry. So computational modeling and analysis can be used to evaluate prospective acquisition geometries to determine which might yield the most desirable survey results.

Additionally, there are a number of physical attributes of the subsurface formation that are of interest to geophysicists. One such physical attribute is the velocity and it is often examined using a "velocity model. " A velocity model is a representation of the subsurface geological formation that can be used in analysis of seismic data. To convert the seismic data into the "seismic image," geophysicists use an analysis of the subsurface velocities. This calculation of the velocity model is also computationally expensive, and its accuracy and resolution directly affect the quality of the seismic image.

One technique involves the modeling of seismic acquisition when designing a survey (e.g., a wide azimuth towed streamer or ocean bottom node survey) with the goal of ensuring the proposed survey geometry will have adequate illumination of the targets of interest for imaging purposes. Illumination of targets generally refers to reflecting seismic energy off of the targets. However, in areas with a complex overburden, the difficulty in obtaining an adequate image can result from shortcomings with the velocity model used for imaging, not from shortcomings with the illumination. Thus, even if the target region is adequately illuminated, the image can be poor if the velocity model above does not allow for a good image. Accordingly, techniques and systems described herein perform acquisition modeling in order to design seismic surveys that improve the building of velocity models. The goal is to determine where to put the receivers and sources to best achieve the objective of building an adequate velocity model.

Seismic image generation depends greatly on the locations of the sources and receivers, also known as the acquisition geometry, of a seismic survey design as well as well as models of subsurface attribute models, such as a velocity model. The building of a velocity model can be enhanced through the selection of acquisition geometry of a seismic survey design. Accordingly, the techniques and systems described below allow for determinations of acquisition geometry of a seismic survey design that allows for velocity model building, which may be useful, for example, in situations in which a limiting factor on seismic imaging is the accuracy of the velocity model.

By way of introduction, seismic data may be acquired using a variety of seismic survey systems and techniques, two of which are discussed with respect to <FIG> and <FIG>. Regardless of the gathering technique utilized, after the seismic data is acquired, a computing system may analyze the acquired seismic data and use results of the seismic data analysis (e.g., seismogram, map of geological formation) to perform various operations within the hydrocarbon exploration and production industries. For instance, <FIG> illustrates a flow chart of a method <NUM> that details various processes that may be undertaken based on the analysis of the acquired seismic data. Although the method <NUM> is described in a particular order, it is noted that the method <NUM> may be performed in any suitable order.

Referring now to <FIG>, at block <NUM>, locations and properties of hydrocarbon deposits within a subsurface region of the Earth associated with the respective seismic survey may be determined based on the analyzed seismic data. In one embodiment, the seismic data acquired via one or more seismic acquisition techniques may be analyzed to generate a map or profile that illustrates various geological formations within the subsurface region.

Based on the identified locations and properties of the hydrocarbon deposits, at block <NUM>, certain positions or parts of the subsurface region may be explored. That is, hydrocarbon exploration organizations may use the locations of the hydrocarbon deposits to determine locations at the surface of the subsurface region to drill into the Earth. As such, the hydrocarbon exploration organizations may use the locations and properties of the hydrocarbon deposits and the associated overburdens to determine a path along which to drill into the Earth, how to drill into the Earth, and the like.

After exploration equipment has been placed within the subsurface region, at block <NUM>, the hydrocarbons that are stored in the hydrocarbon deposits may be produced via natural flowing wells, artificial lift wells, and the like. At block <NUM>, the produced hydrocarbons may be transported to refineries, storage facilities, processing sites, and the like, via transport vehicles, pipelines, and the like. At block <NUM>, the produced hydrocarbons may be processed according to various refining procedures to develop different products using the hydrocarbons.

It is noted that the processes discussed with regard to the method <NUM> may include other suitable processes that may be based on the locations and properties of hydrocarbon deposits as indicated in the seismic data acquired via one or more seismic survey. As such, it may be understood that the processes described above are not intended to depict an exhaustive list of processes that may be performed after determining the locations and properties of hydrocarbon deposits within the subsurface region.

With the forgoing in mind, <FIG> illustrates a marine survey system <NUM> (e.g., for use in conjunction with block <NUM> of <FIG>) that may be employed to acquire seismic data (e.g., waveforms) regarding a subsurface region of the Earth in a marine environment. Generally, a marine seismic survey using the marine survey system <NUM> may be conducted in an ocean <NUM> or other body of water over a subsurface region <NUM> of the Earth that lies beneath a seafloor <NUM>.

The marine survey system <NUM> may include a vessel <NUM>, a seismic source <NUM> (which may be also be referred to as a source <NUM>), a streamer <NUM> (which may be also be referred to as a seismic streamer <NUM>), a receiver <NUM> (which may also be referred to as a seismic receiver <NUM>) and/or other equipment that may assist in acquiring seismic images representative of geological formations within a subsurface region <NUM> of the Earth. The vessel <NUM> may tow the seismic source <NUM> (e.g., an airgun array) that may produce energy, such as acoustic waves (e.g., seismic waveforms), that is directed at a seafloor <NUM>. The vessel <NUM> may also tow the streamer <NUM> having a receiver <NUM> (e.g., hydrophones) that may acquire seismic waveforms that represent the energy output by the seismic sources <NUM> subsequent to being reflected off of various geological formations (e.g., salt domes, faults, folds, etc.) within the subsurface region <NUM>. Additionally, although the description of the marine survey system <NUM> is described with one seismic source <NUM> (represented in <FIG> as an airgun array) and one receiver <NUM> (represented in <FIG> as a plurality of hydrophones), it is noted that the marine survey system <NUM> may include multiple seismic sources <NUM> and multiple seismic receivers <NUM>. In the same manner, although the above descriptions of the marine survey system <NUM> is described with one seismic streamer <NUM>, it is noted that the marine survey system <NUM> may include multiple seismic streamers <NUM>. In addition, additional vessels <NUM> may include additional seismic sources <NUM>, streamers <NUM>, and the like to perform the operations of the marine survey system <NUM>.

<FIG> illustrates a land survey system <NUM> (e.g., for use in conjunction with block <NUM> of <FIG>) that may be employed to obtain information regarding the subsurface region <NUM> of the Earth in a non-marine environment. The land survey system <NUM> may include a (land-based) seismic source <NUM> (which may be also be referred to as a source <NUM>) and a (land-based) seismic receiver <NUM> (which may be also be referred to as a receiver <NUM>). In some embodiments, the land survey system <NUM> may include one or more multiple seismic sources <NUM> and one or more seismic receivers <NUM> and <NUM> (which may also be referred to as a receiver <NUM> and/or a receiver <NUM>). Indeed, for discussion purposes, <FIG> includes a seismic source <NUM> and two seismic receivers <NUM> and <NUM>. The seismic source <NUM> (e.g., seismic vibrator) may be disposed on a surface <NUM> of the Earth above the subsurface region <NUM> of interest. The seismic source <NUM> may produce energy (e.g., acoustic waves, seismic waveforms) directed at the subsurface region <NUM> of the Earth. Upon reaching various geological formations (e.g., salt domes, faults, folds) within the subsurface region <NUM>, the energy output by the seismic source <NUM> may be reflected off of the geological formations and acquired or recorded by one or more land-based receivers (e.g., <NUM> and <NUM>).

In some embodiments, the seismic receivers <NUM> and <NUM> may be dispersed across the surface <NUM> of the Earth to form a grid-like pattern. As such, each seismic receiver <NUM> or <NUM> may receive a reflected seismic waveform in response to energy being directed at the subsurface region <NUM> via the seismic source <NUM>. In some cases, one seismic waveform produced by the seismic source <NUM> may be reflected off of different geological formations and received by different receivers. For example, as shown in <FIG>, the seismic source <NUM> may output energy that may be directed at the subsurface region <NUM> as seismic waveform <NUM>. A first seismic receiver <NUM> may receive the reflection of the seismic waveform <NUM> off of one geological formation and a second receiver <NUM> may receive the reflection of the seismic waveform <NUM> off of a different geological formation. As such, the first seismic receiver <NUM> may receive a reflected seismic waveform <NUM> and the second receiver <NUM> may receive a reflected seismic waveform <NUM>.

Regardless of how the seismic data are acquired, a computing system (e.g., for use in conjunction with block <NUM> of <FIG>) analyzes the seismic waveforms acquired by the (marine-based) seismic receivers <NUM> or the (land-based) seismic receivers <NUM> and <NUM> to determine information regarding the geological structure, the location and property of hydrocarbon deposits, and the like within the subsurface region <NUM>. <FIG> illustrates an example of such a computing system <NUM> that may perform various data analysis operations to analyze the seismic data acquired by the receivers <NUM>, <NUM>, or <NUM> to determine the structure of the geological formations within the subsurface region <NUM>.

Referring now to <FIG>, the computing system <NUM> may include a communication component <NUM>, a processor <NUM>, memory <NUM> (e.g., a tangible, non-transitory, machine-readable media), storage <NUM> (e.g., a tangible, non-transitory, machine-readable media), input/output (I/O) ports <NUM>, a display <NUM>, and the like. The communication component <NUM> may be a wireless or wired communication component that may facilitate communication between the receivers <NUM>, <NUM>, <NUM>, one or more databases <NUM>, other computing devices, and other communication capable devices. In one embodiment, the computing system <NUM> may receive receiver data <NUM> (e.g., seismic data, seismograms) previously acquired by seismic receivers via a network component, the database <NUM>, or the like. The processor <NUM> of the computing system <NUM> analyzes or processes the receiver data <NUM> to ascertain various features regarding geological formations within the subsurface region <NUM> of the Earth.

The processor <NUM> may be any type of computer processor or microprocessor capable of executing computer-executable code or instructions to implement the methods described herein. The processor <NUM> may also include multiple processors that may perform the operations described below. The memory <NUM> and the storage <NUM> may be any suitable article of manufacture serving as media to store processor-executable code, data, or the like. These articles of manufacture may represent computer-readable media (e.g., any suitable form of memory or storage) that may store the processor-executable code used by the processor <NUM> to perform the presently disclosed techniques. Generally, the processor <NUM> may execute software applications that include programs that process seismic data acquired via receivers of a seismic survey according to the embodiments described herein.

The memory <NUM> and the storage <NUM> may also store the data, analysis of the data, the software applications, and the like. The memory <NUM> and the storage <NUM> may represent tangible, non-transitory, computer-readable media (e.g., any suitable form of memory or storage) that may store the processor-executable code used by the processor <NUM> to perform various techniques described herein. It may be noted that tangible and non-transitory merely indicates that the media is tangible and is not a signal.

The I/O ports <NUM> are interfaces that may couple to other peripheral components such as input devices (e.g., keyboard, mouse), sensors, input/output (I/O) modules, and the like. The I/O ports <NUM> may enable the computing system <NUM> to communicate with the other devices in the marine survey system <NUM>, the land survey system <NUM>, or the like.

The display <NUM> may depict visualizations associated with software or executable code processed via the processor <NUM>. In one embodiment, the display <NUM> may be a touch display capable of receiving inputs from a user of the computing system <NUM>. The display <NUM> may also be used to view and analyze results of any analysis of the acquired seismic data to determine geological formations within the subsurface region <NUM>, the location and/or properties of hydrocarbon deposits within the subsurface region <NUM>, and/or the like. The display <NUM> may be any suitable type of display, such as a liquid crystal display (LCD), plasma display, or an organic light emitting diode (OLED) display. In addition to depicting the visualization described herein via the display <NUM>, it may be noted that the computing system <NUM> may also depict the visualization via other tangible elements, such as paper (e.g., via printing), or the like.

With the foregoing in mind, the present techniques described herein may also be performed using a supercomputer employing multiple computing systems <NUM>, a cloud-computing system, or the like to distribute processes to be performed across multiple computing systems. In this case, each computing system <NUM> operating as part of a super computer may not include each component listed as part of the computing system <NUM>. For example, each computing system <NUM> may not include the display <NUM> since the display <NUM> may not be useful for a supercomputer designed to continuously process seismic data.

After performing various types of seismic data processing, the computing system <NUM> may store the results of the analysis in one or more databases <NUM>. The databases <NUM> may be communicatively coupled to a network that may transmit and receive data to and from the computing system <NUM> via the communication component <NUM>. In addition, the databases <NUM> may store information regarding the subsurface region <NUM>, such as previous seismograms, geological sample data, seismic images, or the like regarding the subsurface region <NUM>.

Although the components described above have been discussed with regard to the computing system <NUM>, it may be noted that similar components may make up the computing system <NUM>. Moreover, the computing system <NUM> may also be part of the marine survey system <NUM> or the land survey system <NUM>, and thus may monitor and/or control certain operations of the seismic sources <NUM> or <NUM>, the receivers <NUM>, <NUM>, <NUM>, or the like. Further, it may be noted that the listed components are provided as example components, and the embodiments described herein are not to be limited to the components described with reference to <FIG>.

In some embodiments, the computing system <NUM> (e.g., the processor <NUM> operating in conjunction with at least one of the memory <NUM> or the storage <NUM>) may invoke an application or other computer program to perform the process <NUM> that is illustrated in <FIG>. As will be discussed, the process <NUM> (e.g., a method performed on or by computing system <NUM>) generates an acquisition geometry by determining contributions of sets of source and receiver locations to diving waves passing through a particular zone or area of the subsurface region of interest (i.e., a zone or area of the subsurface region being imaged, which also may be referred to as a depth of investigation). For example, one or more embodiments can determine which source/receiver locations produce diving waves which pass through the particular zone of interest. The method can then configure the generated acquisition geometry to use some or all of these locations which produce the diving waves which pass through the zone of interest. The depth of investigation (DOI) may be considered to be the depth at which useable information is obtained from a given survey for a given longitudinal and latitudinal coordinate within the subsurface region and it is a function of several well-known parameters such as source and receiver placement, the attributes of the seismic signal, the subsurface velocities, etc..

A velocity model may have already been generated at the time the process <NUM> of <FIG> is instituted. The velocity model is a model of a particular subterranean region of the earth that has already been surveyed or that is going to be surveyed. The velocity model can be generated using conventional techniques.

The velocity model is generated from data (not shown) representative of the subterranean region of the earth. In the illustrated embodiments, the data can include seismic data acquired in a previous seismic survey. Alternative embodiments may use other sources of data for this purpose in lieu of or in addition to seismic data if desired. Such other data sources may include, by way of example, well logs, gravity surveys, electromagnetic surveys, geological inspections, etc. Those in the art having the benefit of this disclosure may recognize still further sources of data that may be suitable for this purpose.

With seismic data of sufficiently low frequencies and sufficiently high signal-to-noise, one technique for constructing a velocity model from seismic data is full-waveform inversion ("FWI"). In an embodiment, FWI begins at low frequencies and then adds higher and higher frequencies. Within the context of the present disclosure, the term "low frequency" generally means frequencies below <NUM>, such as between <NUM> - <NUM>, or approximately between <NUM> - <NUM>. However, use of lower frequencies is contemplated, for example, when seismic sources <NUM> or <NUM> operate using frequencies lower than <NUM>.

Indeed, there may be circumstances where the "low frequency" of the modeled seismic data falls outside the range of <NUM> - <NUM>. For example, the seismic data may be known to be particularly free of noise so that frequencies lower than <NUM> may be used. Similarly, technology may advance to the point where seismic frequencies less than <NUM> are readily achievable in the field. Or, one might be testing for a particularly shallow DOI, in which case frequencies higher than <NUM> might be used. Either way, in the context of "low frequencies", the term "approximately" means that the numerical quantification is within the margin of error acceptable within the industry. For example, it is well known that during the course of a survey instrument settings and measurements may vary for a variety of reasons. Thus, a frequency of "approximately <NUM>" includes frequencies that are not precisely <NUM> but includes frequencies that vary slightly within acceptable margins of error. Similarly, a frequency range of approximately <NUM> - <NUM> may include frequencies outside the range of <NUM> - <NUM> provided they are within acceptable margins of error. What constitutes an "acceptable margin of error" will depend on circumstance readily apparent to those skilled in the art having the benefit of this disclosure.

The subsurface attribute model, of which a velocity model is one, slowly comes into focus with progressively finer features being added as rounds of inversion continue. The velocity model output by each stage of the process then becomes the starting model for the next stage. Sirgue & R. Pratt, "Efficient Waveform Inversion and Imaging: A Strategy for Selecting Temporal Frequencies", <NUM> Geophysics <NUM> (<NUM>).

In some embodiments, the velocity model of the illustrated embodiments is furthermore a "smooth" velocity model. In this context, the term "smooth" indicates that the velocity model has been low-pass filtered such that the velocity scale length is greater than the seismic wavelength of the study. However, such smoothing is not necessary to the practice all embodiments. Some alternative embodiments may use a velocity model that has not been smoothed.

With respect to the process <NUM> of <FIG>, in step <NUM>, selection of sets of source and receiver locations (i.e., selection of source <NUM> and receiver <NUM> locations and/or selection of source <NUM> and receiver <NUM> or <NUM> locations) over the survey area is undertaken. The process <NUM> is independent of the type of modeled sources and the signals they impart. The emulated sources may be impulse sources, swept sources, or any other kind of source known to the art. As those in the art having the benefit of this disclosure will appreciate, each of these kinds of modeled sources will produce a different kind of signal. The process <NUM> may be used with each of them.

The process <NUM> continues by performing forward modeling, as step <NUM>, on the velocity model of the subterranean region to generate a set of low frequency seismic data. This forward modeling is, more particularly, what is known as "two-way" forward modeling. In other embodiments, the forward modeling may be "one-way" forward modeling, which is generally regarded as less accurate than two-way modeling. The forward modeling at step <NUM> is performed with the selected sets of sources <NUM> or <NUM> and receivers <NUM>, <NUM>, or <NUM> (which were selected in step <NUM>). Additionally, the emulated seismic signals used in the forward modeling at step <NUM> will be tailored to produce low frequency seismic data. Those in the art will appreciate that a seismic survey, or the forward modeling of a seismic survey, will typically include a range of frequencies in the resultant seismic data. For example, one embodiment uses a range of frequencies spanning three octaves, up to frequencies of interest capable of resolving subsurface structures at tens of meters in resolution. Forward modeling is computationally expensive, and restricting the forward modelling to low frequency seismic data can speed up the forward modelling process. The presently claimed process operates on low frequency seismic data, and so the seismic signals used in the forward modeling in step <NUM> may accordingly be tailored, reducing the overall computational cost of the forward modelling in step <NUM>.

The process <NUM> continues in step <NUM> by performing a reverse time migration on the low frequency seismic data that is yielded by the forward modeling at step <NUM>. The object of this reverse time migration is to obtain, at step <NUM>, a plurality of image gathers with large opening angles. It is anticipated that embodiments of the claimed process will use reverse time migration techniques that discriminate between gathers with large opening angles and those that do not. One such technique is disclosed in <CIT>, entitled, "Specular Filter (SF) and Dip Oriented Partial Imaging (DOPI) Seismic Migration", filed March <NUM>, <NUM>, in the name of the inventor Qie Zhang and commonly assigned herewith.

Within the context of this disclosure, "large opening angles" means those angles that equal or exceed approximately <NUM>°. This will typically include, as shown in <FIG>, what are known to the art as "diving waves" <NUM> and backscattered energy <NUM>. Diving waves <NUM> are those waves that are refracted rather than reflected to/by the earth's recording surface (e.g., seafloor <NUM> or surface <NUM> of the Earth). Changes in the seismic velocity characteristic of the subterranean formation (e.g., the subsurface region <NUM>) gradually change the direction of propagation for the energy to redirect it from a downward trajectory to an upward one. The opening angle is equal to <NUM>° along the path of the diving waves <NUM>. The backscattered energy <NUM> results from reflection at a reflector <NUM> in the subterranean formation (e.g., the subsurface region <NUM>). The opening angle along the backscattered wave path <NUM> has an opening angle of <NUM>°.

In this context, "approximately" means that the precise measurement for what constitutes a "large opening angle" may vary to some degree depending upon the accuracy of the reverse time migration algorithm. In this circumstance, one might relax the standard of ≥ <NUM>° to include that substantial amount of energy that is close to this angle even if not exactly what is desired. Thus, some embodiments may relax the standard in order to capture that energy. Those in the art having the benefit of the disclosure herein will be able to readily exercise such personal judgment in implementing the claimed process.

As noted above, it is contemplated that most embodiments will utilize reverse time migration ("RTM") techniques, where these techniques will discriminate for and yield gathers with large opening angles. Reverse time migration is an example of wavefield-based migration, where wavefields are generated and used to form a seismic image by forward modeling a wavefield (or source wavefield). RTM can include back-propagating a set of recorded seismic data using a same forward modeling engine (the receiver wavefield). RTM can also include applying an imaging condition, such as a zero lag cross-correlation, between the source and receiver wavefields. Wavefield-based migration methods are generally considered desirable in a subterranean region that is geologically complex and that contains steeply dipping geological structures. Though computationally more expensive than ray-based migration, RTM produces a more accurate seismic image.

Returning to <FIG>, the process <NUM> continues, at step <NUM>, by stacking the image gathers with large opening angles to yield a diving wave illumination image. This step <NUM> may operate to reposition the diving wave energy of the diving waves <NUM> to the subsurface model. In this manner, steps <NUM> and <NUM>, taken in conjunction, may be considered to perform a reverse time migration on low frequency seismic data to reposition energy of diving waves <NUM> (i.e., diving wave energy) of each source <NUM> and receiver <NUM> pair of the plurality of sets of source <NUM> and receiver <NUM> locations. Such repositioning of energy of diving waves <NUM> can migrate the low frequency seismic data of step <NUM> to reposition energy of diving waves <NUM> of each source <NUM> and receiver <NUM> pair of the plurality of sets of source <NUM> and receiver <NUM> locations. Such repositioning can be performed to generate a diving wave illumination image. Note that the diving wave illumination image described above contains not only the diving waves <NUM>, but also the backscattered energy <NUM> whose opening angles are ≥ <NUM>° as discussed above. Stacking comprises a summation of the gathers to generate the diving wave illumination image.

The process <NUM> continues in step <NUM> by extracting seismic amplitudes along DOIs of the subsurface region <NUM> (i.e., target reservoir horizons/surfaces). These DOIs may be velocity problematic regions of the subsurface region <NUM>, where source and receiver locations (i.e., selection of source <NUM> and receiver <NUM> locations and/or selection of source <NUM> and receiver <NUM> or <NUM> locations) may be selected to improve building of the velocity model. An example of this extraction is illustrated in conjunction with <FIG>.

<FIG> illustrates the modeled and migrated data from steps <NUM> and <NUM>. Regions <NUM> and <NUM> inclusive of locations of sources <NUM> as well as a region <NUM> inclusive of locations of receivers <NUM> are illustrated in <FIG>. In the example of <FIG>, region <NUM> can correspond to a problematic region in which use of the velocity model results in poor image quality. For region <NUM>, seismic amplitudes between pairs of sources <NUM> and receivers <NUM> may be extracted. The region <NUM> may, for example, be a DOI of the subsurface region <NUM> (i.e., a target reservoir horizon/surface). Returning to <FIG>, for every source <NUM> and receiver <NUM> pair, there will be an individual volume extracted as a portion of step <NUM>.

Continuing with process <NUM> of <FIG>, in step <NUM>, the contributions of individual source <NUM> and receiver <NUM> pairs to the target region(s) (e.g., one or more DOIs of the subsurface region <NUM>) are calculated. This calculation includes determining whether diving waves <NUM> between the pairs of sources <NUM> and receivers <NUM> are transmitted to the target region(s). In this manner, locations for source <NUM> and receivers <NUM> (i.e., source <NUM> and receiver <NUM> pairs) can be determined as being able to transmit diving waves <NUM> into a DOI of the subsurface <NUM>. In some embodiments, step <NUM> may additionally include a comparison of an attribute of the diving waves <NUM> (e.g., the strength of the diving waves <NUM>, the amount of diving waves <NUM>, the location of the diving waves <NUM> in the DOI of the subsurface <NUM>, etc.) passing through the DOI of the subsurface <NUM> against a threshold value so as to determine whether to include potential locations for source <NUM> and receivers <NUM> in the seismic survey design (i.e., to determine the acquisition geometry of the seismic survey design).

In some embodiments, one or more maps of seismic acquisition geometry of the survey design may be generated as an output to be used in determining the final acquisition geometry of a survey design. <FIG> illustrates a map <NUM> (e.g., a map of seismic acquisition geometry) illustrating an example of the source <NUM> and receiver <NUM> locations. <FIG> also illustrates indications (e.g., represented as shades or other indications of intensity plots of the sources <NUM>, which are indicative of the extracted seismic amplitudes of step <NUM> of process <NUM>) of the pairs of sources <NUM> and receivers <NUM> that transmit diving waves <NUM> into a DOI of the subsurface <NUM> (i.e., region <NUM>). <FIG> additionally illustrates a map <NUM> illustrating a corresponding version of map <NUM>, which may be used in conjunction with or in place of map <NUM> in determining the final acquisition geometry of the survey design. Additionally or alternatively, result(s) (as data or another indication) indicative of the extracted seismic amplitudes of step <NUM> of process <NUM> of the locations for sources <NUM> and receivers <NUM> may be generated and/or output to be utilized in determining the final acquisition geometry of the survey design.

Technical effects of this disclosure include systems and methods for determining acquisition geometry of a survey design. More particularly, the acquisition geometry may be focused on a particular region of interest and the acquisition geometry may be particularly selected to transmit diving waves <NUM> into that region of interest. The acquisition geometry may also be selected to improve a velocity model that is subsequently generated, since generation of an updated velocity model is related to (i.e., can be generated based upon) source <NUM> and receiver <NUM> location, and the location of a DOI of a subsurface region <NUM>. Thus, the systems and techniques described herein utilize (via process <NUM>) a relationship between a velocity model (e.g., a known value, such as an initial velocity model), a DOI of a subsurface region <NUM> (e.g., a known value), and source <NUM> and receiver <NUM> locations (e.g., unknown values) to test locations for sources <NUM> and receivers <NUM> (i.e., source <NUM> and receiver <NUM> pairs) as being able to transmit diving waves <NUM> into the DOI of the subsurface <NUM>. These locations for sources <NUM> and receivers <NUM> may then be used for a particular acquisition geometry of a survey design used to, for example, solve for a velocity model (e.g., an unknown value) using the acquisition geometry of the survey design (e.g., known values for the locations of the source <NUM> receiver <NUM> pairs) and the DOI of the subsurface region <NUM> (e.g., a known value). This allows for generation of an updated velocity model when the initial velocity model, for example, is a limitation on the quality of a seismic image (i.e., if a target region [DOI] is adequately illuminated, a generated image can be poor if the velocity model above it is not accurate). Thus, the systems and techniques described herein perform acquisition modeling to design seismic surveys optimized for velocity model building, so as to determine where to put the receivers and sources to achieve the objective of building an improved velocity model. This may lead to improvements in the seismic images generated, causing an improvement of a representation of hydrocarbons in a subsurface region of Earth or of subsurface drilling hazards.

Claim 1:
A computer-implemented method, comprising:
selecting (<NUM>) a plurality of sets of source (<NUM>) and receiver (<NUM>) locations over a survey area to improve a velocity model of a region of interest, wherein the region of interest corresponds to a problematic region (<NUM>) in which use of the velocity model results in poor image quality;
performing forward modeling (<NUM>) on the velocity model based on each source (<NUM>) and receiver (<NUM>) pair of the plurality of sets of source (<NUM>) and receiver (<NUM>) locations to generate low frequency seismic data;
performing (<NUM>) a reverse time migration on the low frequency seismic data to reposition refraction wave and/or diving wave energy of each source (<NUM>) and receiver (<NUM>) pair of the plurality of sets of source (<NUM>) and receiver (<NUM>) locations to generate a diving wave illumination image;
extracting (<NUM>), for each source (<NUM>) and receiver (<NUM>) pair of the plurality of sets of source (<NUM>) and receiver (<NUM>) locations, seismic amplitudes from the diving wave illumination image around the region of interest;
computing (<NUM>) a contribution of a respective diving wave (<NUM>) from each source (<NUM>) and receiver (<NUM>) pair of the plurality of sets of source (<NUM>) and receiver (<NUM>) locations to diving waves (<NUM>) passing through the region of interest based on the seismic amplitudes for each source (<NUM>) and receiver (<NUM>) pair; and
designing an acquisition geometry of a survey design based on the computing of the contribution of the respective diving wave (<NUM>) from each source (<NUM>) and receiver (<NUM>) pair of the plurality of sets of source (<NUM>) and receiver (<NUM>) locations to the diving waves (<NUM>) passing through the region of interest.