Patent Description:
Additionally, one type of seismic survey is a "marine" seismic survey in which one or more seismic sources may be positioned within or on the waterline of a column of water (e.g. a sea, a lake, a bay, a tidal swamp, etc.). The one or more seismic sources may be activated to generate seismic waves which travel through a seabed positioned beneath the column of water and into and through a subterranean formation extending below the seabed which may include hydrocarbon deposits. At least some of the wave energy of the seismic waves may return towards the seabed after interacting with features of the subterranean formation and/or a portion of the earth located between the subterranean formation of interest and the seabed. The returned wave energy may be captured by nodes positioned at or above the seabed.

Publication <CIT> relates to seismic data acquisition for velocity modeling and imaging, involving acquiring first seismic data for survey area generated by operating streamer vessels, and acquiring second seismic data for survey area with ocean bottom receivers.

The invention relates to a method for performing a seismic survey of an earthen subterranean formation according to claim <NUM>.

Further details of the invention are set forth in the dependent claims.

For a detailed description of various exemplary embodiments, reference will now be made to the accompanying drawings in which:.

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the claims is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to. " Also, the term "couple" or "couples" is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection of the two devices, or through an indirect connection that is established via other devices, components, nodes, and connections. In addition, as used herein, the terms "axial" and "axially" generally mean along or parallel to a particular axis (e.g., central axis of a body or a port), while the terms "radial" and "radially" generally mean perpendicular to a particular axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. As used herein, the terms "approximately," "about," "substantially," and the like mean within <NUM>% (i.e., plus or minus <NUM>%) of the recited value. Thus, for example, a recited angle of "about <NUM> degrees" refers to an angle ranging from <NUM> degrees to <NUM> degrees.

As described above, seismic surveys, including marine seismic surveys, reflect seismic waves off of features of earthen subterranean formations in order to collect information regarding the subterranean formations. The information collected from the reflected seismic waves may be used to create seismic images which may be used to identify subterranean features of interest such as, for example, hydrocarbon deposits. Seismic surveys, including marine seismic surveys, may additionally use diving waves to collect information regarding the velocity structure of the earth between the surface and a subterranean formation of interest. In areas with a complex subsurface velocity structure, producing a clear, detailed, accurate, and correctly spatially registered image typically requires both sufficient reflected waves to form the image and an accurate knowledge of the velocity structure of the earth so that the image is well focused and correctly located.

A seismic survey of a subterranean formation may include both an imaging survey and a velocity survey. As used herein, the term "imaging survey" is defined as a survey optimized to record reflected waves to use to create an image. Additionally, as used herein, the term "velocity survey" is defined as a survey optimized to record refracted and/or diving waves to produce an accurate velocity model. The velocity survey may be used to correct a velocity model of the formation and an imaging survey used to create an image of the formation and which may be based on the velocity model corrected by the velocity survey. The velocity survey and imaging survey may be performed together during a single deployment of the same seismic sources used to perform both the imaging and velocity surveys so as to minimize the overall time and expense required for performing the seismic survey. The velocity model comprises a subterranean model of seismic wave propagation velocity which may be used to translate subsurface reflection points of the seismic waves to their true depth. The velocity survey may be used to mitigate or eliminate errors in the velocity model which may result in a poorly migrated image, particularly in instances where the subterranean area of interest (AOI) is positioned beneath an intervening subterranean feature or formation (e.g., a complex subterranean salt feature, etc.).

Although the imaging and velocity surveys may be performed together during a single deployment of the seismic sources, the imaging and velocity surveys may have different requirements. For example, in at least some applications, the imaging survey may require a dense three-dimensional (3D) source coverage to produce a seismic image having relatively better noise suppression and greater detail. For example, a source point (a location at which one of the deployed seismic sources is activated) may be obtained every <NUM> meters (m) to <NUM> in both inline (in the direction of travel of a vessel transporting the sources) and crossline (traverse to the direction of travel of the vessel transporting the sources) directions in an imaging survey. A node patch comprising a plurality of seabed located seismic receivers or nodes may be positioned above the subterranean AOI and may receive the reflected wave energy originally generated by the source points. The source points for the imaging survey may be positioned directly above or at a minor lateral offset (in the form of an imaging source halo extending about the node patch) relative to the node patch and AOI. As used herein, the term "lateral offset" refers to the lateral distance between a source point or a patch or line of source points and an outer periphery of the node patch. The nodes comprising the node patch may be spaced more widely than the source points of the imaging survey (e.g., <NUM> to <NUM> in some applications).

While the relatively small, dense patch of source points of an imaging survey may lend themselves to creating a high-definition seismic image, the relatively small offsets of the source points for the imaging survey may not be capable of resolving large-scale intervening subterranean features. Thus, in performing a velocity survey, additional source points may be acquired in the form of a velocity source halo extending laterally beyond (e.g., <NUM> kilometers (km) to <NUM> in at least some applications) and around the imaging source halo used for the imaging survey and which may have a similar density as the imaging source halo. The more horizontal reflecting seismic waves produced by the more greatly offset source points may be used by an algorithm such as, for example, a full waveform inversion (FWI) algorithm, to solve for an accurate 3D velocity model, which can then be used to create a clear registered image. However, the added number of source points included in the velocity source halo increases the amount of time (e.g., the number of passes of the vessel transporting the seismic sources across the velocity source halo) and concomitantly the expense associated with performing the seismic survey.

Velocity surveys typically do not require the same crossline source density of an imaging survey, and instead the sources can be much more widely spaced because the most useful frequencies in a velocity survey are lower than in an imaging survey. To minimize the number of additional source points required for performing the velocity survey, in some applications high-powered, low-frequency (e.g., <NUM> Hertz (Hz) or less) specialized seismic sources (or source arrays) have been utilized for the velocity source halo such that, in lieu of a densely populated patch of source points, separate and distinct lines of source points (referred to herein as "activation lines") may be acquired outside of the imaging source halo for performing the velocity survey. In some applications, each activation line may comprise a single pass of the vessel transporting the seismic sources used in performing the imaging and velocity surveys, and neighboring activation lines may be spaced up to several kms apart. Such wide activation line spacings are generally sufficient for the purposes of velocity surveying if the sources are powerful enough at low frequencies that a single pass generates sufficient signal.

Conventional large airgun arrays are primarily designed to produce energy over frequencies of about <NUM>-<NUM>, optimized for imaging surveys. The amplitude of the airgun array typically drops below <NUM> decibels (dB) (referenced to <NUM> microPascal (µPa) per Hertz (Hz) at <NUM> meter in the far field, i.e. including the source ghost, as per the Society of Exploration Geophysics (SEG) Standard for measuring the acoustic energy released per activation of marine sources) at approximately <NUM> - <NUM> and continues dropping at about <NUM> dB per octave for lower frequencies. The SEG Standard referred to herein is described in detail at <NPL>. Additionally, the naturally occurring seismic background noise of the Earth steadily increases in amplitude for frequencies below <NUM>. For the purposes of a velocity survey recording usable data at frequencies below about <NUM> may be key, with the lower the usable frequency the better. Specialized low-frequency seismic sources or source arrays optimized for velocity surveys, which can produce amplitudes of greater than <NUM> dB for frequencies below <NUM>, currently exist but are not widely available as compared to conventional seismic sources. Thus, most velocity surveys are currently acquired using conventional sources optimized for the higher frequencies of imaging surveys.

Accordingly, embodiments disclosed herein include systems and methods for performing seismic surveys using spaced activation lines, wherein each activation line is comprised of velocity-source activation patterns containing multiple lines of shots. Embodiments disclosed herein include velocity activation patterns comprising the spaced activation lines which may be formed using conventional seismic sources such as seismic airguns. The activation lines may have a crossline width and/or density sufficient to achieve a signal-to-noise ratio such that a seismic velocity model may be accurately corrected by seismic data obtained using the velocity activation pattern within each activation line. For example, the centers of adjacent activation lines may be spaced <NUM> to <NUM> apart. The optimal spacing between adjacent activation lines may be determined by modeling the survey beforehand, using estimates of the size and depth of the velocity anomalies within the Earth to be resolved and the minimum usable frequencies of the recorded data. If seismic datasets that are good analogues for the expected challenges have already been acquired with a uniform dense sampling, then those existing datasets can be decimated to empirically determine the necessary minimal widths and spacing of the activation lines to achieve the survey goals.

Within each activation line, the velocity source activation patterns may have a minimum crossline source point spacing of <NUM> to <NUM> meters. The optimal crossline source point spacing may again be determined by modeling, in this case to find what density of source points is required to obtain the necessary signal quality in the recorded data. In some embodiments, the activation lines may have an activation density that is greater than an activation density of an imaging activation pattern executed in conjunction with the velocity activation pattern. As used herein, the term "activation density" is defined as the number of "shots" or activations of seismic sources per unit of area.

Conventional practice is to use the same activation density throughout the entire area of the survey. By instead grouping the shot points of the velocity-survey halo into spaced activation lines as described in embodiments herein, with the width and activation density within each activation line determined by the signal-to-noise requirements of the velocity survey, the number of activations comprising the velocity activation pattern may be minimized relative to conventional practice. For example, the number of activations in the velocity activation patterns described herein may have <NUM>% or less of the number of activations in a similarly sized (e.g., having a similarly sized outer periphery) conventional velocity activation pattern (e.g., a uniformly dense patch or halo of activations). In this manner, the overall time and expense associated with performing the seismic survey may be minimized without the need of resorting to exotic, low-frequency and/or high-powered seismic sources.

Referring to <FIG>, a system <NUM> for performing a marine seismic survey is shown. In this exemplary embodiment, survey system <NUM> comprises a system for performing marine seismic surveys offshore. Additionally, in this exemplary embodiment, survey system <NUM> comprises a system for performing both a velocity survey for correcting a velocity model and for performing an imaging survey for creating an image of an earthen subterranean formation based on the velocity model corrected by the velocity survey.

In this exemplary embodiment, the seismic survey performed by survey system <NUM> may conducted in a survey area <NUM> which includes a water column <NUM> extending from a sea bottom or seabed <NUM> to a water's surface or waterline <NUM>. The survey area <NUM> additionally includes an earthen subterranean formation <NUM> extending beneath the seabed <NUM> and which includes a 3D AOI <NUM> positioned beneath the seabed <NUM>. The AOI <NUM> may be an area or section of the subterranean formation <NUM> which may include hydrocarbon deposits or other materials of interest. Additionally, in this exemplary embodiment, a subterranean intervening feature <NUM> is positioned between the AOI <NUM> and the seabed <NUM>. The intervening feature <NUM> may comprise a variety of subterranean features such as, for example, allochthonous salt or other features which may distort a seismic image unless adequately accounted for in a velocity model corrected by a velocity survey. In some applications, a plurality of intervening features <NUM> may be positioned between the AOI <NUM> and the seabed <NUM>.

In this exemplary embodiment, survey system <NUM> generally includes a node gird or patch <NUM> positioned at the seabed <NUM>, an array <NUM> of seismic sources (indicated generally by arrow <NUM> in <FIG>) transported by a surface vessel <NUM> located at the waterline <NUM>, and a computer system <NUM>. Node patch <NUM> comprises a plurality of seismic receivers or nodes (indicated generally by arrow <NUM> in <FIG>) configured to receive seismic energy or waves (indicated by arrows <NUM> in <FIG>) produced by the seismic sources <NUM> that have interacted with the subterranean formation <NUM> and returned towards the surface, either by reflection, refraction, and/or by turning as diving waves. In some embodiments, seismic nodes <NUM> may be positioned at the seabed <NUM> by surface vessel <NUM> and/or another vessel of survey system <NUM> prior to the performance of the seismic survey.

Seismic nodes <NUM> may comprise hydrophones, geophones, or other devices configured to detect seismic or acoustic energy. Seismic nodes <NUM> are also configured to record seismic energy <NUM> produced by seismic sources <NUM> as active seismic data. The node patch <NUM> may be defined by an outer periphery <NUM> within which nodes <NUM> are positioned at a substantially uniform node density throughout the node patch <NUM>. In some embodiments, seismic nodes <NUM> may be spaced approximately between <NUM> and <NUM> from each other within the node patch <NUM>; however, in other embodiments, the spacing of seismic nodes <NUM> may vary. In some embodiments the density of nodes will be higher in the area above the AOI <NUM>. The density of seismic nodes <NUM> may be lower for nodes <NUM> that are not expected to be useful for imaging, but only for the purposes of the velocity survey. Although the outer periphery <NUM> is shown as circular in this exemplary embodiment, in other embodiments, the outer periphery <NUM> of node patch <NUM> may be a variety of regular or irregular shapes.

In this exemplary embodiment, in addition to the seismic nodes <NUM> located within node patch <NUM>, survey system <NUM> includes additional seismic nodes <NUM> extending from node patch <NUM> in the form of outrigger node lines <NUM> (individual nodes <NUM> of each line <NUM> are hidden in <FIG>). Each outrigger node line <NUM> comprises a plurality of seismic nodes <NUM> spaced along the node line <NUM>. Additionally, in this exemplary embodiment, each outrigger node line <NUM> extends from the node patch <NUM>. However, in other embodiments, outrigger node lines <NUM> may extend in other directions such as, for example, in a circumferentially spaced pattern extending radially outwards from node patch <NUM>. Outrigger node lines <NUM> may provide enhanced wide lateral offset coverage. However, in other embodiments, survey system <NUM> may not include outrigger node lines <NUM>. For example, in some embodiments, survey system <NUM> may only include the seismic nodes <NUM> forming node patch <NUM>.

In this exemplary embodiment, each seismic source <NUM> is connected to one of a pair of laterally spaced tow lines <NUM> each of which are connected to surface vessel <NUM>. Although in this exemplary embodiment seismic sources <NUM> are connected to a pair of tow lines <NUM>, in other embodiments, seismic sources <NUM> may be connected to surface vessel <NUM> via a single tow line <NUM> or more than two tow lines <NUM>. During the performance of a seismic survey, surface vessel <NUM> travels in an inline direction (indicated by arrow <NUM> in <FIG>) as the seismic sources <NUM> are each activated (sources <NUM> being positioned near but below the waterline <NUM>) to generate seismic energy which is eventually received by at least some of the seismic nodes <NUM> of node patch <NUM>. The pair of tow lines <NUM> of this embodiment are spaced orthogonal to the inline direction <NUM> in a crossline direction (indicated by arrow <NUM> in <FIG>).

In this exemplary embodiment, the array <NUM> of seismic sources <NUM>, upon activation, is configured to produce seismic waves at a combined average amplitude below <NUM> dB, integrated over about <NUM> seconds, at frequencies below <NUM>, and thus are not as powerful as the specialized sources powerful enough that widely spaced single lines of source activations provide sufficient signal. The seismic sources <NUM> may comprise conventional seismic airguns, vibratory sources, and/or other seismic sources, for example low-pressure high-volume compressed-air-release sources. For the purposes of this invention, the precise type of source does not matter; what matters is its low-frequency performance. In other embodiments, the frequency and power output of the array <NUM> of seismic sources <NUM> may vary. For example, in other embodiments, the array <NUM> of seismic sources <NUM>, upon activation, is configured to produce seismic waves at a combined average amplitude level below about <NUM> dB, integrated over about <NUM> seconds, at frequencies below <NUM>, such that they are more powerful than conventional airguns but still not powerful enough that widely spaced single lines of source activations provide sufficient signal. Additionally, in this exemplary embodiment, survey system <NUM> comprises approximately <NUM> seismic sources <NUM> forming the source array <NUM>, with the sources <NUM> of the source array <NUM> spaced approximately <NUM> in the crossline direction <NUM>; however, in other embodiments, the number of seismic sources <NUM> and their relative spacing may vary. Depending on the type of source, in some embodiments a "source point" may correspond to the activation of a single source, while in others a "source point" may correspond to the activation of an array of sources.

Following the deployment of seismic nodes <NUM> to the seabed <NUM> by a deployment vessel (not shown in <FIG>) of survey system <NUM>, surface vessel <NUM> travels across the waterline <NUM> as the array <NUM> of seismic sources <NUM> is activated in a predefined sequence, whereby a predefined pattern of source points (each corresponding to a location at which one or more of the seismic sources <NUM>, forming the source array <NUM>, is activated) are obtained, as will be described further herein. The seismic nodes <NUM> of node patch <NUM> capture seismic energy generated by the seismic sources <NUM> and reflected by the subterranean formation <NUM> and record the captured seismic energy as active seismic data.

Once the predefined pattern of source points has been obtained and the seismic energy generated by seismic sources <NUM>, returning to the surface after interacting with subterranean formation <NUM>, has been recorded by seismic nodes <NUM> as active seismic data, the seismic nodes <NUM> may be retrieved from the seabed <NUM> by a retrieval vessel (not shown in <FIG>) to the waterline <NUM> to complete the seismic survey (including both the imaging survey and the velocity survey). Once retrieved from the seabed <NUM>, the active seismic data recorded by seismic sources <NUM> may be transferred to the computer system <NUM> of survey system <NUM>. In this exemplary embodiment, at least part of computer system <NUM> is remote to the survey area <NUM> and is in communication with component of survey system <NUM> positioned at or proximal to the survey area <NUM> by a communication system <NUM> including, for example, a satellite. For example, computer system <NUM> may comprise a plurality of separate computer systems, with one or more of the computer systems being located in the survey area <NUM> and one or more others remote from the survey area <NUM>. For example, the computer system <NUM> may comprise one or more virtual servers in a cloud computing environment. In other embodiments, computer system <NUM> may be entirely located at or proximal to the survey area <NUM>.

In this exemplary embodiment, computer system <NUM> is generally configured to analyze the seismic waveforms acquired by the seismic nodes <NUM> to determine seismic information regarding the geological structure, the location and property of hydrocarbon deposits, and the like within the subterranean formation <NUM>. For example, computer system <NUM> may correct a velocity model associated with the subterranean formation <NUM> based on the active seismic data captured by the seismic nodes <NUM> and associated with the velocity survey performed by survey system <NUM>. Additionally, computer system <NUM> is configured to create one or more seismic images associated with the subterranean formation <NUM> (including AOI <NUM>) based on both the active seismic data captured by nodes <NUM> associated with the imaging survey performed by survey system <NUM> and on the corrected velocity model.

Referring now to <FIG>, features of the computer system <NUM> of survey system <NUM> are shown in greater detail. In this exemplary embodiment, computer system <NUM> may include a communication component <NUM>, a processor <NUM>, memory <NUM>, storage <NUM>, input/output (I/O) ports <NUM>, and a display <NUM>. In some embodiments, computer system <NUM> may omit one or more of the display <NUM>, the communication component <NUM>, and/or the input/output (I/O) ports <NUM>. The communication component <NUM> may be a wireless or wired communication component that may facilitate communication between the seismic nodes <NUM>, one or more databases <NUM>, other computing devices, and/or other communication capable devices. In one embodiment, computer system <NUM> may receive receiver or node data <NUM> (e.g., seismic data, seismograms, etc.) via a network component, the database <NUM>, or the like. The processor <NUM> of computer system <NUM> may analyze or process the receiver data <NUM> to ascertain various features regarding geological formations within the superannuation formation <NUM> (including the AOI <NUM>) of the Earth.

The processor <NUM> may be any type of computer processor or microprocessor capable of executing computer-executable code. 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 articles of manufacture that can serve 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 be used to store the data, analysis of the data, the software applications, and the like. The memory <NUM> and the storage <NUM> may represent 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 should be noted that non-transitory merely indicates that the media is tangible and not a signal.

The I/O ports <NUM> may be 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. I/O ports <NUM> may enable computer system <NUM> to communicate with the other devices in the survey system <NUM> or the like via the I/O ports <NUM>.

The display <NUM> may depict visualizations associated with software or executable code being processed by the processor <NUM>. In one embodiment, the display <NUM> may be a touch display capable of receiving inputs from a user of computer system <NUM>. The display <NUM> may also be used to view and analyze results of the analysis of the acquired seismic data to determine the geological formations within the subterranean formation <NUM>, the location and property of hydrocarbon deposits within the subterranean formation <NUM>, predictions of seismic properties associated with one or more wells in the subterranean formation <NUM>, and 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, for example. In addition to depicting the visualization described herein via the display <NUM>, it should be noted that computer system <NUM> may also depict the visualization via other tangible elements, such as paper (e.g., via printing) and the like.

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

After performing various types of seismic data processing, computer 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 computer system <NUM> via the communication component <NUM>. In addition, the databases <NUM> may store information regarding the subterranean formation <NUM>, such as previous seismograms, geological sample data, seismic images, and the like regarding the subterranean formation <NUM>. Although the components described above have been discussed with regard to computer system <NUM>, it should be noted that similar components may make up computer system <NUM>. Moreover, computer system <NUM> may also be part of the survey system <NUM>, and thus may monitor and control certain operations of the seismic sources <NUM>, the nodes <NUM>, and the like. Further, it should 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, computer system <NUM> may generate a two-dimensional representation or a three-dimensional representation of the subterranean formation <NUM> based on the seismic data received via the seismic nodes <NUM> described above. Additionally, seismic data associated with multiple source/node combinations may be combined to create a near continuous profile of the subterranean formation <NUM> that can extend for some distance. In a two-dimensional (<NUM>-D) seismic survey, the node locations may be placed along a single line, whereas in a three-dimensional (<NUM>-D) survey the node locations may be distributed across the surface in a grid pattern. As such, a <NUM>-D seismic survey may provide a cross sectional picture (vertical slice) of the Earth layers as they exist directly beneath the recording locations. A <NUM>-D seismic survey, on the other hand, may create a data "cube" or volume that may correspond to a <NUM>-D picture of the subterranean formation <NUM>. In addition, a <NUM>-D (or time-lapse) seismic survey may include seismic data acquired during a <NUM>-D survey at multiple times. Using the different seismic images acquired at different times, computer system <NUM> may compare the two images to identify changes in the subterranean formation <NUM>.

In any case, a seismic survey may be composed of a very large number of individual seismic recordings or traces. As such, computer system <NUM> may be employed to analyze the acquired seismic data to obtain an image representative of the subterranean formation <NUM> and to determine locations and properties of hydrocarbon deposits. To that end, a variety of seismic data processing algorithms may be used to remove noise from the acquired seismic data, migrate the preprocessed seismic data, identify shifts between multiple seismic images, align multiple seismic images, and the like.

After computer system <NUM> analyzes the acquired seismic data, the results of the seismic data analysis (e.g., seismogram, seismic images, map of geological formations, etc.) may be used to perform various operations within the hydrocarbon exploration and production industries. As an example, locations and properties of hydrocarbon deposits within subterranean formation <NUM> associated with the respective seismic survey performed using survey system <NUM> may be determined based on the analyzed seismic data. Based on the identified locations and properties of the hydrocarbon deposits, certain positions or parts of the subterranean formation <NUM> (e.g., the AOI <NUM>) may be explored. After exploration equipment has been placed within the subsurface region, the hydrocarbons that are stored in the hydrocarbon deposits may be produced via natural flowing wells, artificial lift wells, and the like. The produced hydrocarbons may then be transported to refineries and the like via transport vehicles, pipelines, and the like for processing.

In some embodiments, the results of the seismic data analysis may be generated in conjunction with a seismic processing scheme that includes seismic data collection, editing of the seismic data, initial processing of the seismic data, signal processing, conditioning, and imaging (which may, for example, include production of imaged sections or volumes (which may, for example, include production of imaged sections or volumes) in prior to any interpretation of the seismic data, any further image enhancement consistent with the exploration objectives desired, generation of attributes from the processed seismic data, reinterpretation of the seismic data as needed, and determination and/or generation of a drilling prospect or other seismic survey applications. As a result, location of hydrocarbons within a subterranean formation <NUM> may be identified.

Referring again to <FIG>, as described above, seismic system <NUM> may be used to perform both a velocity survey and an imaging survey in a single deployment of node patch <NUM> and seismic sources <NUM> via surface vessel <NUM>. Particularly, surface vessel <NUM> may travel across the waterline <NUM> as the array <NUM> of seismic sources <NUM> is activated in a predefined sequence, whereby a predefined pattern of source points are obtained. wherein a first or imaging activation pattern of the source point pattern is associated with the imaging survey while a second or velocity activation pattern, different from but potentially overlapping the imaging activation pattern, is associated with the velocity survey. Data obtained from the velocity activation pattern of the source point pattern may be used to correct the velocity model while data obtained from the imaging activation pattern of the source point pattern may be used to create one or more seismic images that are based on the corrected velocity model.

Referring now to <FIG>, a seismic survey design <NUM> associated with the survey system <NUM> shown in <FIG> is conceptually illustrated in <FIG>. Particularly, survey system <NUM> may be used to execute the seismic survey design <NUM> as part of performing a seismic survey that includes both a velocity survey and an imaging survey. The methodology disclosed herein does not necessarily render the seismic survey design <NUM> in a human perceptible form. <FIG> is used only to illustrate selected aspects of the seismic survey design <NUM> to further an understanding of the presently disclosed subject matter. In this exemplary embodiment, seismic survey design <NUM> includes a densely shot imaging activation pattern <NUM> and a relatively sparsely shot velocity activation pattern <NUM>.

The imaging activation pattern <NUM> of seismic survey design <NUM> comprises a dense pattern of "shots" or activations of the array <NUM> of seismic sources <NUM> located within an outer periphery <NUM> of the imaging activation pattern <NUM>. While the outer periphery <NUM> is shown as circular in <FIG>, it may be understood that the outer periphery <NUM> of imaging activation pattern <NUM> may comprise any regular or irregular shape and may be different than the shape imaging activation pattern <NUM> of seismic survey design <NUM>. The seismic survey design <NUM> may thus be formed by transporting seismic sources <NUM> via surface vessel <NUM> and repeatedly activating the array <NUM> of seismic sources <NUM> across the location defined by outer periphery <NUM> until the final predefined pattern of imaging source points is obtained within the outer periphery <NUM>. In this exemplary embodiment, imaging activation pattern <NUM> may have an average crossline spacing between adjacent sources of approximately between <NUM> and <NUM>. For example, in some embodiments, the source points of imaging activation pattern <NUM> may be spaced approximately between an average of <NUM> and <NUM> in the inline direction (indicated by arrow <NUM> in <FIG>) and approximately between <NUM> and <NUM> apart in the crossline direction (indicated by arrow <NUM> in <FIG>). However, in other embodiments, the density and spacing of the source points comprising imaging activation pattern <NUM> may vary.

The node patch <NUM> may be centrally positioned with respect to the imaging activation pattern <NUM> and velocity activation pattern <NUM>. Additionally, the imaging activation pattern <NUM> may correspond in size and shape to the size and shape of node patch <NUM> (the outer periphery <NUM> of node patch <NUM> is shown in <FIG> to indicate the relative positioning of node patch <NUM> relative to activation patterns <NUM>, <NUM>). The imaging activation pattern <NUM> may be positioned directly above the seabed <NUM> located node patch <NUM>. In this exemplary embodiment, the imaging activation pattern <NUM> has a diameter that is greater than the diameter of the node patch <NUM>, thereby forming an annular imaging shot halo <NUM> which entirely surrounds the node patch <NUM>. Imaging shot halo <NUM> provides a region having a greater lateral offset (e.g., the lateral distance between the activated seismic source <NUM> and the outer periphery <NUM> of the node patch <NUM>) than the region of imaging activation pattern <NUM> aligned or formed within node patch <NUM> and which may allow for greater illumination of the AOI <NUM>. In other embodiments, imaging activation pattern <NUM> may not include imaging shot halo <NUM>.

The velocity activation pattern <NUM> of seismic survey design <NUM> comprises a pattern of shots or activations of the array <NUM> of seismic sources <NUM> located within an outer periphery <NUM> of the velocity activation pattern <NUM> and which envelopes the outer periphery <NUM> of imaging activation pattern <NUM>. While the outer periphery <NUM> is shown as rectangular in <FIG>, it may be understood that the outer periphery <NUM> of velocity activation pattern <NUM> may comprise any regular or irregular shape. As with the imaging activation pattern <NUM>, velocity activation pattern <NUM> may be formed by transporting seismic sources <NUM> via surface vessel <NUM> and repeatedly activating the array <NUM> of seismic sources <NUM> across the location defined by outer periphery <NUM> until the final predefined pattern of velocity source points is obtained within the outer periphery <NUM>.

However, unlike imaging activation pattern <NUM>, velocity activation pattern <NUM> does not comprise a substantially uniform pattern of densely spaced shots. Instead, in this exemplary embodiment, velocity activation pattern <NUM> comprises a plurality of spaced velocity activation lines <NUM> separated by gaps <NUM> and each extending in the inline direction <NUM>. As used herein, the term "activation line" is defined as a zone formed by repeated activations of an array of seismic sources towed by a surface vessel passing through the single activation line in an inline direction. A single activation line may be formed by multiple passes of surface vessel through the single activation line (the array of seismic sources being activated during each pass).

Some, if not all, of the velocity activation lines <NUM> are laterally spaced (e.g., in the crossline direction <NUM>) from the imaging activation pattern <NUM> such that velocity source points of the velocity activation lines <NUM> are positioned at a significantly greater lateral offset relative to the node patch <NUM> than the imaging source points of the imaging activation pattern <NUM> relative to the node patch <NUM>. For reference, a single lateral offset <NUM> between an outermost velocity activation line <NUM> and the outer periphery <NUM> of node patch <NUM> is shown in <FIG>. As will be discussed further herein, the greater lateral offset provided by velocity activation lines <NUM> permits the velocity survey conducted using system <NUM> to successfully probe intervening subterranean features such as, for example, the subterranean intervening feature <NUM> positioned between AOI <NUM> and the node patch <NUM>.

Referring to <FIG>, an additional view of some of the velocity activation lines <NUM> and corresponding gaps <NUM> are shown in <FIG>. In this exemplary embodiment, each velocity activation line <NUM> comprises a "fat activation line" defined herein as an activation line having a minimum crossline width of at least <NUM>. For this reason, velocity activation lines <NUM> may also be referred to as "fat" source or activation lines given their greater width <NUM> in the crossline direction <NUM> relative to a single activation line. Fat activation lines may be formed by repeatedly activating an array of seismic sources towed by a surface vessel several which makes a plurality of passes back and forth through the fat activation line with the array of seismic sources being activated during each pass. Alternatively, fat activation lines could be formed by a single pass of a surface vessel utilizing a sufficiently wide source array towed behind the surface vessel. Further, the crossline spacing of the seismic source points could also be halved by shooting the same shot line again, but with a lateral shift of half the crossline source point spacing. Once they become available, these methods could be used in conjunction with the acquisition designs shown in <FIG>.

In this exemplary embodiment, each velocity activation line <NUM> has a crossline width <NUM> that is approximately between <NUM> to <NUM>, while each gap <NUM> has a crossline width <NUM> that is approximately between <NUM> and <NUM> wide. In some embodiments, the crossline width <NUM> of each velocity activation line <NUM> is approximately <NUM>, while the crossline width <NUM> of each gap <NUM> is approximately <NUM>. However, in other embodiments, the crossline widths <NUM>, <NUM> of each velocity activation line <NUM> and/or gap <NUM>, respectively, may vary. Additionally, in this exemplary embodiment, a ratio of an average crossline width <NUM> of the velocity activation lines <NUM> to an average crossline width <NUM> of gaps <NUM> is approximately between <NUM> and <NUM>. If there is an existing library of conventional acquisitions to reference, optimal configurations can be found by processing decimated versions of the existing data to simulate various "fat shot line" acquisitions.

In this exemplary embodiment, the requirements of the velocity survey may vary from the requirements of the imaging survey of a given seismic survey. For example, in at least some applications, the imaging survey may require a dense carpet of source points (such as that provided by imaging activation pattern <NUM>) to produce a seismic image having greater detail and better noise suppression. Additionally, in at least some applications, the velocity survey of a seismic survey may require at least some source points having a greater lateral offset than the source points of the imaging survey in order to more fully and accurately probe intervening subterranean features (e.g., intervening subterranean feature <NUM> shown in <FIG>) with seismic waves which travel relatively more horizontally with respect to the intervening subterranean features. Further, while the velocity survey may require source points having a relatively greater lateral offset than the source points of the imaging survey, the velocity survey may not require a dense carpet of source points at relatively wide lateral offsets in order to correct the velocity model. Particularly, propagation via the wave equation discriminates against seismic energy that cannot be represented as a coherent wave when there is a sufficient density of source points for the seismic waves to be recorded coherently. In other words, the wave equation may be utilized to enhance the signal-to-noise ratio obtained from conventional seismic sources such as airguns. Moreover, while the quality of a seismic image created based on a velocity model corrected by a velocity survey (e.g., via a FWI algorithm based on data acquired from the velocity survey) may only increase in response to the inclusion of additional source points up to a certain point, the inclusion of additional source points at wide lateral offsets no longer meaningfully improves the quality of the seismic image.

In view of the above, the velocity activation pattern <NUM> of seismic survey design <NUM> reduces the number of velocity source points relative to the velocity activation patterns of conventional seismic survey designs which instead include a uniformly dense (e.g., less than <NUM> spacing between source points in the inline direction and less than <NUM> in the crossline direction) carpet of source points extending to wide lateral offsets (e.g., several kms from the outer periphery of the node patch). For example, velocity activation pattern <NUM> may only have <NUM>% or less (e.g., <NUM>%) of the number of source points relative to a velocity activation pattern of a conventional seismic survey design which instead relies on a uniformly dense carpet of source points for the velocity survey. The significant reduction in the number of source points for velocity activation pattern <NUM> relative to conventional seismic survey designs may in-turn significantly decrease the time and expense required in performing the seismic survey relative to conventional seismic surveys.

Additionally, the velocity activation pattern <NUM> need not rely on low-frequency sources and instead may be formed with conventional seismic sources such as airguns and the like. Particularly, a sufficient signal-to-noise ratio may be maintained by the velocity activation pattern <NUM> via providing each velocity activation line <NUM> with a sufficient minimal crossline width <NUM> (e.g., <NUM> to <NUM>) in order to provide a sufficient crossline shot density for purposes of correcting the velocity model. The power output at low frequencies for different types of commonly available seismic sources may vary. In-turn, the minimal crossline width required to provide a sufficient shot density for purposes of correcting the velocity model may vary based on the configuration of the seismic sources used in conducting the velocity survey. Particularly, the crossline width of velocity activation patterns <NUM> may be negatively correlated with the power output at low frequencies of the seismic sources utilized in the seismic survey.

Referring now to <FIG>, another embodiment of a seismic survey design <NUM> which may be executed by the survey system of <FIG> is shown in <FIG>. Seismic survey design includes features in common with the seismic survey design <NUM> shown in <FIG>. For example, seismic survey design <NUM> includes imaging activation pattern <NUM>. However, in contrast to the substantially rectilinear velocity activation lines <NUM> of velocity activation pattern <NUM> shown in <FIG>, seismic survey design <NUM> comprises a velocity activation pattern <NUM> including orbital or circumferential activation lines <NUM> which comprise fat activation lines (formed via multiple passes of a surface vessel with the array of seismic sources towed by the surface vessel activated during each pass) and extend at least partially, circumferentially about the outer periphery <NUM> of the imaging activation pattern <NUM>. Additionally, circumferential activation lines <NUM> are separated by annular gaps <NUM> which also extent at least partially, circumferentially about the outer periphery <NUM> of imaging activation pattern <NUM>.

Circumferential activation lines <NUM> and annular gaps <NUM> may each have a crossline width that is similar to the crossline widths <NUM>, <NUM> of the velocity activation lines <NUM> and corresponding gaps <NUM> shown in <FIG>. In some embodiments, an outermost of the circumferential activation lines may extend approximately <NUM> to <NUM> from the node patch <NUM>. The circumferential activation lines <NUM> may present a relatively more efficient pattern for acquiring source points (e.g., fewer passes of the surface vessel <NUM> required to execute the velocity activation pattern <NUM> relative to velocity activation pattern <NUM> for the same number of source points) in at least some applications.

Unlike the imaging activation pattern <NUM> shown in <FIG>, in some applications, the area of the imaging activation pattern may nearly overlap with the area of the velocity activation pattern. In such instances multiple surface vessels (e.g., a plurality of surface vessels <NUM>) each towing a separate set of one or more seismic sources (e.g., seismic sources <NUM>) may be utilized for executing the imaging activation pattern and the velocity activation pattern. Additionally, in some embodiments, to ensure sufficient density of source points or seismic source activations for the velocity survey, the crossline spacing of individual source points of each velocity activation line <NUM> may be less than the crossline spacing of individual source points of the imaging activation pattern <NUM>. For example, in some embodiments, the crossline spacing between individual source points of each velocity activation line <NUM> may be half as much as the crossline spacing between individual source points of imaging activation pattern <NUM> (e.g., <NUM> vs <NUM>, for example).

Referring to <FIG>, another embodiment of a seismic survey design <NUM> which may be executed by the survey system of <FIG> is shown in <FIG>. Seismic survey design <NUM> includes an imaging activation pattern <NUM> and a velocity activation pattern <NUM>. In this exemplary embodiment, imaging activation pattern <NUM> comprises separate imaging activation lines <NUM> each positioned between a plurality of velocity activation lines <NUM> comprising the velocity activation pattern <NUM>. Additionally, in this exemplary embodiment, each velocity activation line <NUM> may have a greater activation density (the number of source points per surface area) than the imaging activation lines <NUM> forming the imaging activation pattern <NUM>. For example, each velocity activation line <NUM> may have a crossline spacing between individual source points of approximately <NUM> while each imaging activation line <NUM> may have a crossline spacing between individual source points of approximately <NUM>. In other embodiments, the crossline spacing of the source points of the imaging activation lines <NUM> and velocity activation lines <NUM> may vary. In some embodiments, a ratio of the crossline spacing of adjacently located source points of the imaging activation lines <NUM> to the crossline spacing of adjacently located source points of the velocity activation lines <NUM> may be approximately between <NUM>:<NUM> to <NUM>:<NUM>.

In some embodiments, the imaging activation lines <NUM> of imaging activation pattern <NUM> may be formed by a first surface vessel towing a first plurality of seismic sources while the velocity activation lines <NUM> of imaging activation pattern <NUM> may be formed by a second vessel towing a second plurality of seismic sources, the second surface vessel and the second plurality of seismic sources being different from the first surface vessel and the second plurality of seismic sources. For example, the first surface vessel and first plurality of seismic sources may be configured to produce source points spaced a first distance apart (e.g., <NUM> apart) while the second surface vessel and second plurality of seismic sources may be configured to produce source points spaced a second distance apart (e.g., <NUM> apart) that is less than the first distance. Alternatively, a single surface vessel and a single plurality of seismic sources may be used to form both the imaging activation lines <NUM> and the velocity activation lines <NUM>. For example, the single vessel may form the relatively denser velocity activation lines <NUM> by making more passes over a given crossline distance than when forming the less dense imaging activation lines <NUM>.

Referring to <FIG>, a method <NUM> for performing a seismic survey of an earthen subterranean formation is shown. Beginning at block <NUM>, method <NUM> comprises deploying a node patch (e.g., node patch <NUM> shown in <FIG>) comprising a plurality of seismic receivers (e.g., seismic receivers <NUM> shown in <FIG>) to an offshore seabed in a survey area (e.g., survey area <NUM> shown in <FIG>). At block <NUM>, method <NUM> comprises deploying a surface vessel (e.g., surface vessel <NUM> shown in <FIG>) towing an array of seismic sources (e.g., seismic sources <NUM> shown in <FIG>) to the survey area located, wherein each of the seismic sources comprises an airgun.

At block <NUM>, method <NUM> comprises activating the array of seismic sources to generate seismic waves as the array of seismic sources are transported in an inline direction (e.g., inline direction <NUM> shown in <FIG>) through the survey area whereby an imaging activation pattern (e.g., imaging activation pattern <NUM> shown in <FIG>) and a velocity activation pattern (e.g., imaging activation pattern <NUM> shown in <FIG>) are formed, wherein a lateral offset between the velocity activation pattern and the node patch is greater than a lateral offset between the imaging activation pattern and the node patch. In some embodiments, the node patch may be centrally positioned with respect to the imaging activation pattern and the velocity activation pattern. For example, in certain embodiments, the imaging activation pattern may be located directly above the node patch positioned on the seabed. In some embodiments, the velocity activation pattern comprises a plurality of separate velocity activation lines (e.g., velocity activation lines <NUM> shown in <FIG>) separated by gaps (e.g., gaps <NUM> shown in <FIG>). In certain embodiments, method <NUM> comprises correcting a seismic velocity model associated with the subterranean formation based on seismic data collected from the velocity activation pattern, and creating a seismic image of the subterranean formation based on seismic data collected from the imaging activation pattern and the corrected seismic velocity model. A technique for processing recorded seismic data into an image may begin with organizing and sorting the data, removing bad or excessively noisy traces, correcting timing and position errors, etc. An initial velocity model may be created using pre-existing data. In a virgin area the initial velocity model may be very simplistic. For example, it may be based on regional geological trends. In an area with existing seismic data quite detailed velocity models may already exist. The recorded data may then be used to improve the initial velocity model, where the initial velocity model serves as the starting point for an iterative inversion process (e.g. "FWI", Full-waveform inversion) that adjusts the model to better fit the recorded data. The velocity survey data is typically most important in the early stages of the inversion, which correct gross errors in the velocity model. However, the imaging survey data may become more important at later stages of the inversion. The improved velocity model may then used to "migrate" the seismic data to produce an image using, for example, an algorithm like RTM (reverse-time migration).

Referring to <FIG>, a method <NUM> for performing a seismic survey of an earthen subterranean formation is shown. Beginning at block <NUM>, method <NUM> comprises deploying a node patch (e.g., node patch <NUM> shown in <FIG>) comprising a plurality of seismic receivers (e.g., seismic receivers <NUM> shown in <FIG>) to an offshore seabed in a survey area (e.g., survey area <NUM> shown in <FIG>). At block <NUM>, method <NUM> comprises deploying a surface vessel (e.g., surface vessel <NUM> shown in <FIG>) towing an array of seismic sources (e.g., seismic sources <NUM> shown in <FIG>) to the survey area located.

At block <NUM>, method <NUM> comprises activating the array of seismic sources to generate seismic waves as the array of seismic sources are transported in an inline direction (e.g., inline direction <NUM> shown in <FIG>) through the survey area whereby an imaging activation pattern (e.g., imaging activation pattern <NUM> shown in <FIG>) and a velocity activation pattern (e.g., velocity activation pattern <NUM> shown in <FIG>) are formed, wherein a lateral offset between the velocity activation pattern and the node patch is greater than a lateral offset between the imaging activation pattern and the node patch. In some embodiments, the node patch may be centrally positioned with respect to the imaging activation pattern and the velocity activation pattern. For example, in certain embodiments, the imaging activation pattern may be located directly above the node patch positioned on the seabed. In some embodiments, the velocity activation pattern comprises a plurality of separate velocity activation lines (e.g., velocity activation lines <NUM> shown in <FIG>) separated by gaps (e.g., gaps <NUM> shown in <FIG>), and wherein each of the plurality of velocity activation lines has a minimum width in a crossline direction, orthogonal to the inline direction, of at least <NUM> meters. In certain embodiments, method <NUM> comprises correcting a seismic velocity model associated with the subterranean formation based on seismic data collected from the velocity activation pattern, and creating a seismic image of the subterranean formation based on seismic data collected from the imaging activation pattern and the corrected seismic velocity model.

Referring to <FIG>, a method <NUM> for performing a seismic survey of an earthen subterranean formation is shown. Beginning at block <NUM>, method <NUM> comprises deploying a node patch (e.g., node patch <NUM> shown in <FIG>) comprising a plurality of seismic receivers (e.g., seismic receivers <NUM> shown in <FIG>) to an offshore seabed in a survey area (e.g., survey area <NUM> shown in <FIG>). At block <NUM>, method <NUM> comprises deploying a surface vessel (e.g., surface vessel <NUM> shown in <FIG>) towing an array of seismic sources (e.g., seismic sources <NUM> shown in <FIG>) to the survey area located, wherein each of the seismic source arrays <NUM>, upon activation, is configured to produce a combined average amplitude of less than <NUM> dB, integrated over about <NUM> seconds, at frequencies less than <NUM>.

At block <NUM>, method <NUM> comprises activating the array of seismic sources to generate seismic waves as the array of seismic sources are transported in an inline direction (e.g., inline direction <NUM> shown in <FIG>) through the survey area whereby an imaging activation pattern (e.g., imaging activation pattern <NUM> shown in <FIG>) and a velocity activation pattern (e.g., velocity activation pattern <NUM> shown in <FIG>) are formed, wherein a lateral offset between the velocity activation pattern and the node patch is greater than a lateral offset between the imaging activation pattern and the node patch. In some embodiments, the node patch may be centrally positioned with respect to the imaging activation pattern and the velocity activation pattern. For example, in certain embodiments, the imaging activation pattern may be located directly above the node patch positioned on the seabed. In some embodiments, the velocity activation pattern comprises a plurality of separate velocity activation lines (e.g., velocity activation lines <NUM> shown in <FIG>) separated by gaps (e.g., gaps <NUM> shown in <FIG>). In certain embodiments, method <NUM> comprises correcting a seismic velocity model associated with the subterranean formation based on seismic data collected from the velocity activation pattern, and creating a seismic image of the subterranean formation based on seismic data collected from the imaging activation pattern and the corrected seismic velocity model.

Claim 1:
A method for performing a seismic survey of an earthen subterranean formation (<NUM>), comprising:
(a) deploying a node patch (<NUM>) comprising a plurality of seismic receivers (<NUM>) to an offshore seabed (<NUM>) in a survey area (<NUM>);
(b) deploying a surface vessel (<NUM>) towing an array of seismic sources (<NUM>) to the survey area (<NUM>); and
(c) activating the array of seismic sources (<NUM>) to generate seismic waves as the array of seismic sources (<NUM>) are transported in an inline direction (<NUM>, <NUM>) through the survey area (<NUM>) whereby an imaging activation pattern (<NUM>, <NUM>) and a velocity activation pattern (<NUM>, <NUM>, <NUM>) are formed, wherein a lateral offset between the velocity activation pattern (<NUM>, <NUM>, <NUM>) and the node patch (<NUM>) is greater than a lateral offset between the imaging activation pattern (<NUM>, <NUM>) and the node patch (<NUM>);
wherein the velocity activation pattern (<NUM>, <NUM>, <NUM>) comprises a plurality of separate velocity activation lines (<NUM>, <NUM>, <NUM>) separated by gaps (<NUM>, <NUM>), and wherein each of the plurality of velocity activation lines (<NUM>, <NUM>, <NUM>) has a minimum width in a crossline direction (<NUM>, <NUM>), orthogonal to the inline direction(<NUM>, <NUM>), of at least <NUM> meters.