Key information

Title
Correction of sea surface state
Application number
20150190
Case type
National
Status
28.02.2022 P.g.a ikke betalt årsavgift
Filed
10.02.2015
Priority
18.02.2014 US 61/941,383 and others
Effective date
10.02.2015
Publicly available
19.08.2015
Applicant
PGS Geophysical AS (NO)
Inventor
Edwin Thomas Hodges (GB) et al.
Agent
ACAPO AS (NO)

Abstract and drawing

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A method for correction of a sea surface state can include receiving geophysical data from a seismic survey, wherein the seismic survey utilizes a plurality of receivers disposed in a body of water and at least one source in the body of water, actuated at a plurality of shot points. The method can include identifying, in the geophysical data, a wavefield based on the actuation of the at least one source, and determining, based on the identified wavefield, a sea surface state at the at least one source at one of the plurality of shot points.

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 19.09.2022 10-01 Saksbehandling 20150190 UT PT Endelig henlagt for ikke betalt årsavgift (3313)
16.08.2022 09-01 Saksbehandling 20150190 UT Henlagt manglede svar ENG ACAPO AS
 04.07.2022 08-01 Saksbehandling 20150190 UT PT Påminnelse om ikke betalt årsavgift (3329) (PT20150190)
16.12.2021 07-02 Saksbehandling 20150190 UT PT report 12:35:42
16.12.2021 07-01 Saksbehandling 20150190 UT Substantive examination ACAPO AS
 02.01.2017 06-01 Saksbehandling 20150190 UT PT Batch Varsel om betaling av første årsavgift (3317)
07.03.2016 05-02 Saksbehandling 20150190 INN Krav Acapo AS
 07.03.2016 05-01 Saksbehandling 20150190 INN Korrespondanse (Hovedbrev inn) Acapo AS
 17.06.2015 04-02 Saksbehandling 20150190 INN Hovedbrev Acapo AS
 17.06.2015 04-01 Saksbehandling 20150190 INN Korrespondanse (Hovedbrev inn) Acapo AS
 08.04.2015 03-02 Saksbehandling 20150190 INN Fullmakt Acapo AS
 08.04.2015 03-01 Saksbehandling 20150190 INN Korrespondanse (Hovedbrev inn) Acapo AS
 11.02.2015 02-01 Saksbehandling 20150190 UT Formalia 1 Acapo AS
 10.02.2015 01-04 Saksbehandling 20150190 INN Tegninger
10.02.2015 01-03 Saksbehandling 20150190 INN Overdragelsesdokument
10.02.2015 01-02 Saksbehandling 20150190 INN Beskrivelse
10.02.2015 01-01 Saksbehandling 20150190 INN Søknadsskjema Patent

Description, claims and drawings

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content. Description
[0001] This application claims priority to U.S. Provisional Application 61/941,383, filed February 18, 2014, which is incorporated by reference.[0002] In the past few decades, the petroleum industry has invested heavily in the development of marine seismic survey techniques that yield knowledge of subterranean formations beneath a body of water in order to find and extract valuable mineral resources, such as oil. High-resolution seismic images of a subterranean formation are helpful for quantitative seismic interpretation and improved reservoir monitoring. For a typical marine seismic survey, a marine seismic survey vessel tows one or more seismic sources below the surface of the water and over a subterranean formation to be surveyed for mineral deposits. Seismic receivers may be located on or near the water bottom, on one or more streamers towed by the source vessel, or on one or more streamers towed by another vessel. The source vessel typically contains marine seismic survey equipment, such as navigation control, seismic source control, seismic receiver control, and recording equipment. The seismic source control may cause the one or more seismic sources, which are typically air guns or marine vibrators, to produce acoustic signals at selected times (often referred to as "firing a shot" or "shooting").[0003] Each acoustic signal is essentially a sound wave that travels down through the water and into the subterranean formation. At each interface between different types of rock, a portion of the sound wave may be refracted, a portion of the sound wave may be transmitted, and another portion may be reflected back toward the body of water to propagate toward the surface. The streamers towed behind the vessel are generally elongated cable-like structures. Each streamer includes a number of seismic receivers that detect pressure and/or particle motion changes in the water created by the sound waves reflected back into the water from the subterranean formation. The receivers thereby measure a wavefield that was ultimately initiated by the actuation of the seismic source. In this sense, the acoustic signals (or "shots") are actuated at the receivers, and the receivers measure a wavefield based on the actuation of the sources.[0004] Figures IA - ID illustrate coordinates and terminology associated with correction of sea surface state.[0005] Figure 2 illustrates a diagram including two shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure.[0006] Figure 3 illustrates a diagram including two shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure.[0007] Figure 4 illustrates a diagram including five shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure.[0008] Figure 5 illustrates a diagram including five shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure.[0009] Figure 6 illustrates a diagram including the use of sources, channels, and receivers, along with various cross-correlations according to one or more embodiments of the present disclosure.[0010] Figure 7 illustrates a diagram including the use of sources, channels, and receivers, along with various cross-correlations according to one or more embodiments of the present disclosure.[0011 ] Figure 8 illustrates a diagram relating to shot point direction, constant receiver direction, and constant channel direction according to one or more example embodiments of the present disclosure.[0012] Figure 9 illustrates an example shot point gather according to one or more embodiments of the present disclosure.[0013] Figure 10 illustrates an example shot point gather according to one or more embodiments of the present disclosure.[0014] Figure 11 illustrates an example shot point gather according to one or more embodiments of the present disclosure.[0015] Figure 12 illustrates an example two-dimensional (2D) receiver gather before correction of sea surface state according to one or more embodiments of the present disclosure.[0016] Figure 13 illustrates an example 2D receiver gather plus linear move out (LMO) before correction of sea surface state according to one or more embodiments of the present disclosure.[0017] Figure 14 illustrates an example 2D receiver gather plus LMO after correction of sea surface state according to one or more embodiments of the present disclosure.[0018] Figure 15 illustrates an example 2D receiver gather after correction of sea surface state according to one or more embodiments of the present disclosure.[0019] Figure 16 illustrates a diagram of a system for correction of sea surface state according to one or more embodiments of the present disclosure.[0020] Figure 17 illustrates a diagram of a machine for correction of sea surface state according to one or more embodiments of the present disclosure.[0021 ] Figure 18 illustrates an example method for correction of sea surface state according to one or more embodiments of the present disclosure.[0022] Figure 19 illustrates an example method for correction of sea surface state according to one or more embodiments of the present disclosure.[0023] The present disclosure is related to analyzing and correcting for the effects of sea surface state in marine seismic surveying. During marine seismic surveying, sea conditions may be uncontrollable. As a result, while a vessel is moving on the sea, shooting, and recording seismic data, waves and other sea surface factors may interrupt and/or interfere with seismic recording. Embodiments of the present disclosure allow for correction or compensation of these interruptions and interferences. For instance, embodiments of the present disclosure can reduce and/or remove effects of the sea surface state variations (e.g., due to waves, swells, etc.) on up-going survey data.[0024] It is to be understood the present disclosure is not limited to particular devices or methods, which may vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used herein, the singular forms "a", "an", and "the" include singular and plural referents unless the content clearly dictates otherwise. Furthermore, the words "can" and "may" are used throughout this application in a permissive sense (i.e., håving the potential to, being able to), not in a mandatory sense (i.e., must). The term "include," and derivations thereof, mean "including, but not limited to." The term "coupled" means directly or indirectly connected.[0025] The figures herein follow a numbering convention in which the first digit or digits correspond to the drawing figure number and the remaining digits identify an element or component in the drawing. Similar elements or components between different figures may be identified by the use of similar digits. As will be appreciated, elements shown in the various embodiments herein can be added, exchanged, and/or eliminated so as to provide a number of additional embodiments of the present disclosure. In addition, as will be appreciated, the proportion and the relative scale of the elements provided in the figures are intended to illustrate certain embodiments of the present invention, and should not be tåken in a limiting sense.[0026] This disclosure is related generally to the field of marine seismic surveying. For example, this disclosure may have applications in marine seismic surveying, in which one or more towed sources are used to generate wavefields, and receivers—either towed or ocean bottom—receive reflected seismic energy generated by the seismic sources. The disclosure may also have application to the analysis of the sea surface state in marine seismic surveying.[0027] Figures IA-ID illustrate coordinates and terminology associated with correction of a sea surface state. Figure IA illustrates an elevation or xz-plane view of an example marine seismic survey vessel 109 towing a source 103 (e.g., one or more airguns or marine vibrators) and a streamer 113 located beneath a free surface 115. In practice, source 103 and streamer 113 may be towed by the same or different vessels. Figure IA represents a snapshot, at an instant in time, of the undulating free surface 115 and corresponding smooth wave-like shape in the streamer 113. Figure IB includes xy-plane 117 and Figure IA includes an xz-plane 119 of the same Cartesian coordinate system used to specify coordinate locations within the fluid volume with respect to three orthogonal, spatial coordinate axes labeled x, y and z. The x coordinate uniquely specifies the position of a point in a direction parallel to the path of travel of the vessel 109 at a particular moment in time, and the y coordinate uniquely specifies the position of a point in a direction perpendicular to the x axis and substantially parallel to the free surface 115 at vessel 109 at a particular moment in time, and the z coordinate uniquely specifies the position of a point perpendicular to the xy-plane 117 at a particular moment in time. The geoid 123 is the hypothetical surface of the sea level at vessel 109 and is used to define zero elevation (i.e., z=0). Shaded disks, such as shaded disks 105-1 and 105-2, represent receivers spaced along streamer 113. Receivers 105 can include, for instance, seismic receivers and/or electromagnetic receivers, among others. Although illustrated on a towed streamer 113, receivers 105 may be located on ocean bottom cables or on nodes attached near or on the water bottom.[0028] Figure IA includes an illustration of a shot and wave paths 129-1, 129-2 from the source 103 at a corresponding number of receivers 105-1, 105-2. Also illustrated at the corresponding number of receivers 105-1, 105-2 is arrival of a corresponding number of signals 127-1, 127-2 from the source 103 reflected off the free surface 115. As used herein, "source-side" can refer to some action, item, or event associated with the source (not with the receiver), affecting a source, and/or positioned near or in the same location as the source, among others. "Receiver-side" can refer to the same association of actions, items, or events with a receiver. Figure IA illustrates up-going wavefield direction 133 and down-going wavefield direction 135, as will be further discussed herein.[0029] Figure IB illustrates a top or xy-plane view of the marine seismic survey vessel 109 towing a source 103 with source units 103-1,103-2,103-3 and four separate streamers 113-1, 113-2,113-3, 113-4 located beneath a free surface. Embodiments are not limited to three source units in a source, as a source can include more or fewer source units. Some embodiments can include 35 source units in the source. Furthermore, the source can be one-dimensional (e.g., arranged in a line as shown), two-dimensional (e.g., arranged in a rectangular grid), or three-dimensional (e.g., arranged in a cube). Source 103 may be a number of types including, but not limited to a small explosive charge, an electric spark or are, a marine vibrator, and/or a seismic source gun, among others. Source 103 may comprise a number of source elements in a source configuration, and can, without limitation, generate a short-duration impulse. Embodiments are not limited to a particular number of streamers and can include more or fewer than are shown. Some embodiments can include 24 or more streamers. As illustrated, the streamers 113-1,113-2, 113-3, 113-4 can be modeled as a planar horizontal acquisition surface located beneath the free surface. However in practice, the acquisition surface can be smoothly varying due to active sea currents and weather conditions. In other words, the towed streamers may also undulate as a result of dynamic conditions of the fluid. The coordinates of a particular receiver are given by (x, y, z) taking into account both the xz-plane 119 and the xy-plane 117. In some embodiments, the receiver array may vary in the z direction (e.g., receivers disposed farther from the vessel may be deeper than those closer to the vessel). Likewise, in some embodiments, one or more of the streamers may be towed at a different depth than other streamers, thereby creating an acquisition volume.[0030] Various embodiments of the present disclosure provide methods to correct marine seismic data for sea surface state variations. The correction can occur, in some instances, at the source location, at the receiver location, or both. For instance, in marine seismic surveying, rough sea surfaces can cause amplitude and phase perturbations in acquired seismic data. Sea surface state correction in accordance with the present disclosure can compensate for at least some of these perturbations, resulting in smoothed time-varying sea surface states. In some instances, advantage may be tåken of a dual-receiver streamer (e.g., streamer receivers include both hydrophones and geophones), or any multi-sensor acquisition which allows a mathematical separation of the up-going wavefields and down-going wavefields. As used herein, "up-going wavefields" can include wavefields scattered upwards from the earth or formations therein, and "down-going wavefields" can include wavefields reflected downwards from the sea surface. For instance, a down-going wavefield typically contains a direct wave, typically contains receiver-side surface multiples and water-column reverberations, while an up-going wavefield typically contains primaries and source-side ghosts and internal multiples. Since the primary reflections are contained only in the up-going wavefield, wavefield separation can be used to isolate the signal from the primary reflections. [0031 ] Following the wavefield separation, up-going data may be considered as being free from any receiver-side sea surface effect. Therefore, any roughness observable on data reflected from shot point to shot point (the points at which a source is actuated) may be a side effect of the deviations in source datum caused by the sea surface state at the source location. In some examples, time-shifts associated with the source datum deviations may be identified and corrected for. Some embodiments of the present disclosure can generate a unique estimation of the sea surface state for each source location at the moment that source is actuated.[0032] The sea surface state (e.g., the wave height, time-derivative changes in wave height, wave frequency, and/or other sea conditions occurring at the sea surface) may vary from shot to shot in a marine seismic survey. As a consequence, source wavelet (wave-like oscillation used for signal processing) travel time may also vary from shot to shot. The effect of the sea surface state may be particularly noticeable in a receiver domain ensemble, where a single trace, which can include gathered information/data, may come from different shot points. It may manifest as a random jittery effect that could (perhaps wrongly) be qualified as "noise." In accordance with the present disclosure, assumptions can be made and a workflow may be devised that provides a surface-consistent static correction. Although Figures IA and 2A illustrate horizontal or straight-line towing, examples of the present disclosure may include circular towing and/or spiral towing, among others. Additionally, although Figures IA and IB illustrate a single vessel, a plurality of vessels may be present, with some or all of the vessels towing streamers and some or all of the vessels towing sources and actuating shots. The streamers may be towed in different directions, depths, and/or angles, among other differences. Receivers may be located on streamers, ocean bottom cables, or on nodes located on or near the water bottom.[0033] Figure 1C illustrates an example technique for acquiring seismic data that may be used in correction of sea surface state in one or more embodiments of the present disclosure. The example illustrated in Figure 1C is two-dimensional, meaning that the technique is related to data acquired using a single seismic streamer 113 or an ocean bottom cable 151. Examples of the present disclosure can also be used with three-dimensional acquisition techniques, in which more than one seismic source and/or laterally spaced streamers and/or ocean bottom cables are used to acquire seismic data. Examples of the present disclosure can also be used with receivers located on nodes near or on the water bottom 153.[0034] As illustrated in Figure 1C, vessel 109 can tow a source 103 that can be actuated at selected times. In some examples, a streamer 113 is also towed by the vessel 109. The streamer 113 includes receivers 105-1,..., 105-6 at spaced positions along the cable 113. Each receiver can be responsive, for example, to the pressure in the water or to changes in pressure, such as, for instance, changes in pressure with respect to time. Examples of the present disclosure can also be used with receivers that are sensitive to particle motion or changes in particle motion.[0035] In some embodiments, an ocean bottom cable (OBC) 151 can be deployed on the water bottom 153. The OBC 151 can include, for instance, receivers 155-1,..., 155-6 spaced along OBC 151. Signals generated by the receivers 155-1,..., 155-6 can be recorded by a recording unit 157 for later retrieval and processing. In some examples, both streamers and OBCs can be used to record signals to be processed according to the present disclosure. In some examples, in addition to or in place of, receivers located on nodes near or on the water bottom 153 may be used to record signals to be processed according to the present disclosure.[0036] When source 103, is actuated, acoustic energy travels downwardly, at 159. Some of the downwardly traveling energy 159 penetrates the water bottom 153 and reaches a subsurface layer boundary 199. Acoustic energy can be reflected from the layer boundary 199, whereupon the reflected energy travels upwardly, as shown generally at 163. Acoustic energy can also be reflected from the water bottom 153, whereupon the reflected energy travels upwardly, as shown generally at 161, The upwardly traveling acoustic energy 161, 163 can be detected by the receivers 105-1,..., 105-6 on the streamer 113 (or the receivers 155-1,..., 155-6 on the OBC 151 on the water bottom 153 if an OBC is used). The upwardly traveling energy 161, 163 can reflect from the water surface 115, whereupon the energy travels downwardly again, as shown at 101. The water surface reflected energy 101 can be detected by the receivers 105-1,..., 105-6, (and/or 155-1,..., 155-6) resulting in a ghost signal. The water surface reflected energy 101 also may be reflected from the water bottom 153, and becomes upwardly traveling energy, shown generally at 107. Further, acoustic energy can reflect from the water surface (down-going energy 101) and can again reflect from the water bottom (up-going energy 107) a plurality of times, resulting in water-layer multiple reflections.[0037] As a result of all the foregoing acoustic energy interactions with the water and the structures below the water, the acoustic energy detected by the receivers 105-1,..., 105-6, (and/or 155-1,..., 155-6) referred to as a "total wavefield", includes both upwardly traveling energy ("up-going wavefield") and downwardly traveling energy ("down-going wavefield"). The up-going and down-going wavefields include components resulting from subsurface reflectors, such as boundary 199, and from water surface and water bottom reflections.[0038] Figure ID illustrates an example nodal receiver geophysical survey system including a vessel 109 that moves along the surface of a body of water such as a lake or the sea. Data acquisition in accordance with one or more embodiments of the present disclosure can be performed via a nodal receiver geophysical survey system as illustrated in Figure ID. Sources 103-1 and 103-2 can be actuated, and the resultant wavefield can be detected with nodal receivers 116 positioned on the water bottom.[0039] As will be discussed further herein, a method for correction of a sea surface state can include receiving geophysical data from a seismic survey, wherein the seismic survey utilizes a plurality of receivers disposed in a body of water, and at least one source in the body of water, actuated at a plurality of shot points. The method can also include identifying, in the geophysical data, a wavefield based on the actuation of the at least one source, and determining, based on the identified wavefield, a sea surface state at the at least one source at one of the plurality of shot points. In some examples, determining the sea surface state can include separating up-going portions of the measured wavefield from down-going portions of the measured wavefield, determining source-side effects in the up-going wavefield, cross-correlating constant receiver and constant channel ensembles, and statistically filtering and extracting a surface consistent time correction to apply to the plurality of shot points based on the cross-correlation.[0040] Figure 2 illustrates a diagram 200 including two shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure. Figure 2 illustrates an example in which a source 203 is actuated at a set of receivers Rn 205 at different times ti and t2, for instance at 202 and 204, respectively. The two shots are actuated from the same source 203, but at different times ti and t2. Source 203 moves from shot point Sl at time ti (at 202) to shot point S2 at time t2 (at 204). As illustrated in Figure 2, the shift in the position of the receivers 205 from right to left and from time ti (at 202) to time t2 (at 204) can indicate the passage of the streamer 213 through the water from right to left as time advances from ti to t2. Seismic source 203 can represent an appropriate submerged seismic source, which may be activated to generate an acoustic wavefield. Source 203 may be towed by a vessel or otherwise disposed in the marine environment.[0041 ] Because of simultaneous recording of the plurality of receivers Rn, whatever the sea condition, there may be some continuity between traces within a given shot point (e.g., shot point Sl or S2). Reciprocally, for a given receiver position, traces may be coming from different shot points shot at different times, which therefore may express sea surface state variation at each shooting time. In the example illustrated in Figure 2, source 203 may be approximately 7 meters from sea surface 215 at each shot point Sl and S2, though embodiments are not limited to this distance or to identical depths at shot point Sl and S2.[0042] At 206, the plurality of receivers Rn 205 simultaneously record the wavefield resulting from source 203 actuating at shot point Sl at time ti. In the example illustrated in Figure 2, the distance between the receivers Rn 205 and the sea surface 215 is approximately 15 meters at the distal end of streamer 213, though embodiments are not limited to this distance or to each of the receivers Rn 205 being at identical depths. At 208, the plurality of receivers Rn 205 simultaneously record the wavefield resulting from source 203 actuation at shot point S2 at time t2 with a distance of 15 m between the distal end of streamer 213 and the sea surface 215, however, embodiments are not limited to this distance, to each of the receivers Rn 205 being at identical depths, or to the same depth of the distal end of streamer 213 when recording wavefields from actuations of the source 203 at times ti and t2.[0043] The measured wavefield may include both up-going and down-going portions. These portions can be separated, and source-side effects in the up-going portion can be determined. An example of wave separation, also known as decomposition, is described in United States Patent Application Publication Number 2014/0016436, which is hereby incorporated by reference. For instance, a sea surface state variation as it relates to the source side can be determined. Cross-correlations, as will be discussed further herein, can be performed between constant receiver and constant channel ensembles. A surface time correction to apply to the plurality of shot points can be statistically filtered and extracted based on the source-side effects and cross-correlations. For example, this surface time correction can correct for sea surface state variations, making for more accurate, smoother sea surface state data.[0044] Figure 3 illustrates a diagram 300 including two shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure. In the example the actuated shots can include a series of shots actuated at different times from a single source. For instance, the shots can be actuated at nearly the same time and/or within a particular time interval. Figure 3 illustrates an example in which two shots, occurring at shot points Sl and S2, are actuated from source units 303-1 and 303-2, respectively, at a plurality of receivers Rn 305. While only one receiver is shown in Figure 3, Rn 305 can represent a plurality of receivers, and the plurality of receivers may be disposed on one or more streamers, one or more ocean bottom cables, a plurality of nodes near or on the water bottom, or any combination thereof. As noted with respect to Figure 2, because of the simultaneous recording of the plurality of receivers Rn 305, whatever the sea condition, there may be some continuity between traces within a given shot point (e.g., shot point Sl or S2). Reciprocally, for a given receiver position, all the traces may be coming from different shot points shot at different times, which therefore may express sea surface state variation at each shooting time. The arrows as illustrated in Figures 3-5 are not meant to be directional. Rather Figures 3-5 illustrate that a given receiver location Rn 305 can record data initiated from consecutive source locations (e.g., at shot points Sl,..., Sn) for which the sea surface state may be unpredictable. In the example illustrated in Figure 3, each source unit 303-1, 303-2 may be a particular distance 312-1, 312-2 away from a sea surface 315. In some examples, these distances 312-1- and 312-2 can be the same, however, they are not required to be the same.[0045] Figure 4 illustrates a diagram 400 including five shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure. In the example the actuated shots can include a series of shots actuated at different times from a single source. For instance, the shots can be actuated at nearly the same time and/or within a particular time interval. Figure 4 illustrates an example in which five shots, occurring at shot points Sl, S2, S3, S4 and S5 are actuated from source units 403-1, 403-2, 403-3, 403-4, and 403-5, respectively at a plurality of receivers Rn 405. While only one receiver is shown in Figure 4, Rn 405 can represent a plurality of receivers, and the plurality of receivers may be disposed on one or more streamers, one or more ocean bottom cables, a plurality of nodes near or on the water bottom, or any combination thereof. The plurality of receivers Rn 405 may simultaneously record a wavefield based on the five shots at a particular time. Similar to Figures 2 and 3, because of simultaneous recording of the plurality of receivers Rn 405, whatever the sea condition, there may be some continuity between traces at different receivers from a given shot point. Reciprocally, for a given receiver position, traces may be coming from different shot points shot at different times, which therefore may express sea surface state variation at each shooting time.[0046] As illustrated in Figure 4, consecutive shot points Sl, S2, S3, S4, and S5 are shot at a regular time interval during which a vessel has moved up and down on the sea surface 415; the state of sea surface 415 is illustrated for each of the shot points Sl, S2, S3, S4, and S5 by sea surface 415 shown as multiple wavy lines. In the example illustrated in Figure 4, an assumption can be made that a distance 412-1, 412-2, 412-3, 412-3, 412-4, 412-5 of a source unit 403-1, 403-2, 403-4, 403-4, 403-5 away from a sea surface 415 remains stable, an absolute height of the source unit may differ from shot to shot. In the example illustrated in Figure 4, each source unit may be approximately 7 meters from sea surface 415, though embodiments are not limited to this distance or that each source unit is at the same depth.[0047] Figure 5 illustrates a diagram 500 including five shots actuated at a plurality of receivers according to one or more embodiments of the present disclosure. In the example the actuated shots can include a series of shots actuated at different times from a single source. For instance, the shots can be actuated at nearly the same time and/or within a particular time interval. Diagram 500 includes five shots occurring at shot points Sl, S2, S3, S4, and S5 actuated at a plurality of receivers Rn 505 from source units503-l, 503-2, 503-4, and503-5, respectively. While only one receiver is shown in Figure 5, Rn 505 can represent a plurality of receivers, and the plurality of receivers may be disposed on one or more streamers, one or more ocean bottom cables, a plurality of nodes near or on the water bottom, or any combination thereof. The plurality of receivers Rn 505 can be simultaneously recording wavefields resulting from shots at shot points Sl,..., S5 at a particular time. Similar to Figures 2-4, because of the simultaneous recording, whatever the sea condition, there may be some continuity between traces within a given shot point. Reciprocally, for a given receiver position, traces may be coming from different shot points shot at different times, which therefore may express sea surface state variation at each shooting time. However, in contrast to Figure 4, Figure 5 illustrates a culmination of the sea surface 515 and its state above the consecutive shot points Sl, S2, S3, S4, and S5. For instance, as illustrated in Figure 5, if the sea surface 515 is not flat, shot points Sl, S2, S3, S4, and S5 are not aligned on a horizontal line. This may result in a vessel travel time difference from shot point to shot point as the sea surface state is always changing.[0048] Assuming the distance from a source to the sea surface remains relatively stable (within about a 10% variation), the variations in the sea surface state at the source may cause the absolute height of a source to differ from shot to shot. Within a shot point, all traces may express a continuous sea surface state. Within a receiver gather, all the traces may come from different source positions shot at different times and sea surface state variation. The demonstrated effect may be expressed as a random time delay between traces.[0049] Figure 6 illustrates a diagram 600 including the use of sources, channels, and receivers, along with various cross-correlations according to one or more embodiments of the present disclosure, as they are associated with sea surface state correction. The embodiment illustrated in Figure 6 can, in some examples, be applied only to up-going data, and may be applied after de-noise and wavefield separation of up-going and down-going data processes have been applied in a shot point domain. As a vessel moves in a particular direction, for instance channel direction 630, over time 632, data can be collected. Choosing where and when to collect this data can aid in correction and/or compensation for sea surface state variations. For instance, a same number of nearest channels can be chosen for all sequential shot points. In some examples of the present disclosure, a channel can include data recorded from a receiver at one location on a streamer. A channel can also refer to, for instance, the actual recording device inserted into a streamer at a regular distance interval (e.g., 12.5 meters). For example, a streamer may contain hundreds of channels. A time window 638 can be designed starting just above the water bottom (e.g., just above first order multiple 636, taking into account water-bottom reflection 634) and finishing at twice the water bottom period. In the example illustrated in Figure 6, this bottom period may include, for instance, a maximum of 500 ms. As will be discussed further herein, after the time window design to correct for the sea surface effect on the receiver side and the source side, the constant receiver and constant channel ensembles can be cross-correlated, gathered, and surface consistent time correction can be statistically filtered and extracted to apply to every shot point.[0050] As used herein, "constant receiver" can refer to data recorded from a particular location in the water. A constant receiver can include data that would have been recorded from the particular location if there was a stationary receiver placed at that particular location; however, a stationary receiver may not be possible in streamer-based acquisition due to the streamer constantly moving. In response, in accordance with the present disclosure, a constant receiver can be constructed by taking data recorded from one channel when it was in a first location, and combining it with data recorded from the next channel, for instance, when it had moved to the particular, desired location. This can be performed for all channels on the streamer.[0051 ] In some examples, a constant receiver can be considered a fixed point in space. On a constant receiver record, data collected can include all data that has been recorded from one location. A "constant channel", as used herein, can represent that data being recorded from the same physical receiver, i.e., a fixed position on the streamer. Because the streamer is constantly moving through the water, this can represent data from a number of different locations. Figure 7 illustrates a diagram 700 including the use of sources, channels, and receivers, along with various cross-correlations according to one or more embodiments of the present disclosure. Diagram 700 includes the use of sources at shot points Sl to Sn, channels cl to cn, and receivers ri to rn, along with various cross-correlations. In the example illustrated in Figure 7, a vessel towing a source may be thought of as moving toward the right side of Figure 7 in shot point direction 748, such that each horizontal line represents a shot point Sl, S2, ..., Sn (e.g., the vessel is shooting at regular increments). In the illustrated embodiment, the vessel also tows a streamer on which a plurality of receivers is located. A constant receiver direction is illustrated at 744, and the constant channel direction (assuming a given receiver is located at constant location along the streamer) is illustrated at 750. In some examples, the constant channel may change from source-to-source based on how far the vessel has moved.[0052] In the example illustrated in Figure 7, each line labeled ri, r2,..., rn can represent a receiver position, and each vertical dash labeled cl, c2,..., cn can represent a channel position (e.g., first channel, second channel, etc). As illustrated in Figure 7, constant receiver direction 744 and constant channel direction 750 are used as an explanation of diagram 700. For instance, diagram 700 can represent recording of data from shots at a plurality of shot points Sl, S2,..., Sn and a plurality of channels cl,..., cn for a plurality of different receiver positions ri, r2,..., rn. Diagram 700 can be used to aid in understanding a layout of an acquisition, for instance. However, diagram 700 is schematized to represent acquisition of the data, but is not a drawn picture of the acquisition. Shot point direction 748 can indicate a progression of data acquisition from shot point Sl through shot point S2, through shot point S3, and so on through shot point Sn. Shot point direction 748 can be used to indicate the direction in which to read diagram 700, for instance.[0053] Information/data regarding consecutive shot points Sl,S2,...,Sn can be gathered at each receiver and channel position. Each trace can be embedded, as illustrated in Figure 11, and each trace can include information/data about the sea surface state at sources associated with consecutive shot points Sl, S2,..., Sn. Using cross-correlation of the data, the effect of the sea above a source can be reduced or eliminated. For instance, because there may not be a large distance between each source unit (e.g., between shot points Sl and S2), a large difference in a wavefield may not be observed or expected; however, using cross-correlation among all the data (receivers, shot points/sources, channels), sea surface state correction is possible. In some examples, as a result of this cross-correlation, a sea surface state may appear flat, even though the vessel and sources are moving up and down.[0054] For instance, up-going wavefield data and source-side data can be collected, and used to calculate a cross-correlation within an ensemble of source units (shot points), channels, and receivers. These cross-correlations can be used to correct the sea surface state. Examples of the present disclosure can decompose the sea surface effect on a receiver side and a source side of a towed streamer and correct for the sea surface effect on the receiver side and the source side based on the decomposition.[0055] For instance, cross-correlation AS at a constant channel between consecutive shot points (S1*S2), (S2*S3),..., (Sn-l*Sn) can be determined. In some instances, AS may refer to a change in sea surface state relative to a constant channel. For example, channel 1 of source unit 1 can be cross-correlated with channel 1 of source unit 2, etc. The resulting change in time values may be normal move out (NMO) independent, in other words, independent of an effect that the offset distance between a seismic source and a receiver has on the arrival time of a reflection in the form of an increase of time with offset. The resulting change in time values may characterize two terms and be determined as a function of: G, which varies smoothly (indicative of the geology of the area from which the data was collector); and Rd which is random (indicative of the sea surface state variation). Accordingly:[0056] A cross-correlation at a constant channel within a shot point between consecutive channels (cl*c2), (c2*c3),..., (cn-l*cn) can be determined. The resulting change in time values may be characterized by two terms and be determined as a function of: V, which varies smoothly with increasing offset (indicative of the velocity); and G, which varies smoothly (indicative of the geology). Accordingly:[0057] A cross-correlation at a constant receiver between consecutive shot points, (cl*c3), (c3*c5),..., (cn-3*cn-l) and (c2*c4), (c4*c6),..., (cn-2*cn) can also be performed. The resulting change in time values may be characterized by three terms and be determined as a function of: V, which varies smoothly with increasing offset (indicative of the velocity); G, which varies smoothly (indicative of the geology); and Rd that is random (indicative of the sea surface state variation). Accordingly:[0058] There may a certain amount of redundancy between the cross-correlations. This redundancy can be used to reduce uncertainty in sea surface state variation and separate the effects of the geology and NMO from the randomness that characterizes the sea surface state variation.[0059] For instance, in order to compute surface consistent statics at source locations with a-priori knowledge that the static values at receiver locations equal zero, the following can be performed:[0060] Figure 8 illustrates a diagram 854 relating to shot point direction, constant receiver direction, and constant channel direction according to one or more example embodiments of the present disclosure. Figure 8 is an example of elaboration of shot point direction, constant channel direction, and constant receiver direction as described with reference to Figure 7. For instance, by reordering acquired data, the data can be placed into a particular order, which can include what would have been obtained had the receivers been fixed in space, rather than being towed behind a vessel. Diagram 854 includes an example relating to shot point direction 856, constant receiver direction 860, and constant channel direction 858. In the example illustrated in Figure 8, as discussed with reference to Figure 6, AS can include a cross-correlation at a constant channel between consecutive shot points. Also as discussed with reference to Figure 6, AC can include a cross-correlation at a constant channel within a shot point between consecutive channels. Finally, as discussed with reference to Figure 6, AR2n can include a cross-correlation within a constant receiver between consecutive shot points. Figure 8 illustrates the constant receiver direction 860, constant channel direction 858, and shot point direction 856, as used in example embodiments. Cross-correlations between these constant receiver and constant channel ensembles can aid in correction of sea surface state. As noted above with respect to Figure 6, redundancy between the cross-correlations can be used to reduce variations and separate the effects of the geology and NMO from the randomness that characterizes the sea surface state variation.[0061 ] In a number of embodiments, sea surface state correction can be applied to a data set in order to demonstrate the feasibility of computing and correcting for sea statics on the source side. For example, the data examples presented in Figures 9-14 can include hydrophone, up-going, and down-going at 0 m in both shot and 2D receiver domains. The 2D receiver gathers are presented with and without linear move out (LMO) to determine the effect of the applied statics on the data. Hydrophone-only streamers record the combination of the up-going and down-going wavefields, and may be thus contaminated with unwanted "ghost" reflections from all target depths.[0062] Figure 9 illustrates an example shot point gather 964 according to one or more embodiments of the present disclosure. In some examples, example shot point gather 964 includes data collected via hydrophone-only streamers. As illustrated at 965, receiver-side ghosts are instable on the shot point data.[0063] Figure 10 illustrates an example shot point gather 1064 according to one or more embodiments of the present disclosure, and can, for example include down-going data. As illustrated at 1071, the down-going data contains information related to the sea surface state over the recording streamer.[0064] Figure 11 illustrates an example shot point gather 1164 according to one or more embodiments of the present disclosure. As illustrated at 1177, the sea surface state over the recording streamer does not affect the quality of the up-going on the shot point data. As such, in a number of embodiments, only up-going data is utilized, along with only data on the source side, resulting in a compensation, also known as smoothing out of data, for sea surface state variation.[0065] Figure 12 illustrates an example two-dimensional (2D) receiver gather 1280 before correction of sea surface state according to one or more embodiments of the present disclosure. In the example illustrated in Figure 12, the x-axis can represent a vessel's travel, and the y-axis can represent a change in data gathered. Figure 12 can illustrate data points collected over some time period, also known as a "snapshot". For instance, each trace can be collected at a different shot point such that the trace changes from one shot point to another. Looking at the up-going data at 0 m, the interface data 1281 at the sea bed indicates a first surface status before a correction or compensation for sea surface state variation. This may be smoothed (as will be discussed with respect to Figure 15) in accordance with the present disclosure. As used herein, an "interface" can include a common surface separating two media. For instance, different properties of the media can result in partial reflection of source energy back towards the receivers.[0066] Figure 13 illustrates an example 2D receiver gather 1386 plus LMO before correction of sea surface state according to one or more embodiments of the present disclosure. In the example illustrated in Figure 13, the x-axis can represent a vessel's travel, and the y-axis can represent a change in data gathered. Figure 13 can illustrate data points collected over some time period, and each trace can be collected at a different shot point (e.g., changes from one shot point to another). Looking at the up-going data at 0 m, the interface data 1387 indicates an interface status before a correction or compensation for sea surface state variation. This may be smoothed (as will be discussed with respect to Figure 14) in accordance with the present disclosure.[0067] Figure 14 illustrates an example 2D receiver gather 1490 plus LMO after correction of sea surface state according to one or more embodiments of the present disclosure. The x-axis can represent a vessel's travel, and the y-axis can represent a change in data gathered. Figure 14 can illustrate data points collected over some time period. In the example illustrated in Figure 14, each trace is collected at a different shot point. The up-going interface data 1491 is smoother as compared to the interface data 1387 of Figure 13, in response to a correction or compensation for sea surface state variation in accordance with the present disclosure.[0068] Figure 15 illustrates an example 2D receiver gather 1596 after correction of sea surface state in according to one or more embodiments of the present disclosure. In the example illustrated in Figure 15, the x-axis can represent a vessel's travel, and the y-axis can represent a change in data gathered. Figure 15 can illustrate data points collected over some time period. In the example illustrated in Figure 15, each trace is collected at a different shot point. The up-going interface data 1597 is smoother as compared to the interface data 1281 of Figure 12, in response to a correction or compensation for sea surface state variation in accordance with the present disclosure.[0069] In some embodiments, in order to model a realistic sea surface, a number of models, algorithms, and functions may be used. For instance, a Pierson-Moskowitz spectrum and Hasselmann's directivity correction may be used to model a realistic sea surface. Sea surface parameters may be obtained employing spectral analysis. A Kirchhoff-Helmholtz integral can be used to model scattered data from a time-varying 2D sea surface. Sea surface imaging technology may recover 2D time-varying sea surfaces from 3D dual-receiver data (or any multi-sensor acquisition which allows a mathematical separation of the up-going wavefields and down-going wavefields). Accordingly, applying streamer-wise imaging to 3D data may be a possible way of recovering some of the main features of a 2D time-varying sea surface in a number of embodiments. For example, according to a 3D processing embodiment of this disclosure, the sea surface may be imaged by all streamers for a given instant of time. According to a 2D processing embodiment, the sea surface may be imaged by one streamer for a given instant of time. This may then be repeated, for instance, for all streamers. The sea surface profiles corresponding to the same times may then be juxtaposed and interpolated.[0070] Figure 16 illustrates a diagram of a system 1692 for correction of sea surface state in accordance with one or more example embodiments of the present disclosure. The system 1692 can include a data store 1698, a subsystem 1694, and/or a number of engines 1666, 1667, 1668, and 1669. The subsystem can include the number of engines, such as measurement engine 1666, determination engine 1667, decomposition engine 1668, and/or correction engine 1669, and can be in communication with the data store 1698 via a communication link. The system 1692 can include additional or fewer engines than illustrated to perform the various functions described herein. The system can represent software and/or hardware of a machine (e.g., machine 1782 as referenced in Figure 17, etc). [0071 ] The number of engines can include a combination of hardware and programming that is configured to perform a number of functions described herein. The programming can include program instructions (e.g., software, firmware, etc.) stored in a memory resource (e.g., computer readable medium, computer readable medium, etc.) as well as hard-wired program.[0072] For example, the measurement engine 1666 can include a combination of hardware and programming that is configured to measure an up-going portion of a wavefield based on an actuation of a source. The measured up-going portion of the wavefield, in some examples, may have been collected by a plurality of receivers. In some embodiments, the determination engine 1667 can include a combination of hardware and programming that is configured to determine, based on the measured up-going portion of the wavefield, a sea surface state at the source.[0073] In a number of embodiments, the decomposition engine 1668 can include a combination of hardware and programming that is configured to decompose the sea surface state at the source and at at least one of the plurality of receivers. In some examples, the decomposition can be configured to decompose the sea surface effect using cross-correlations of an ensemble of source units, channels, and receivers, in various combinations associated with the source and the streamer. The ensemble of source units, channels, and receivers can include, for instance, a constant distance from the source to the sea surface, a constant channel direction, and a constant receiver direction.[0074] In some embodiments, the correction engine 1669 can include a combination of hardware and programming that is configured to correct for the sea surface state at the source and at the at least one of the plurality of receivers based on the decomposition. The sea surface state can include, for example, a sea surface state variation on the up-going portion(s) of the wavefield at particular receiver locations on the source side of a towed streamer and/or at the at least one of the plurality of receivers.[0075] In a number of examples, system 1692 can include a record engine including a combination of hardware and programming configured to simultaneously record traces received from the source and display the traces as a random time delay between traces via a graphical user interface. System 1692 can further comprise a design engine including a combination of hardware and programming configured to design a time window in which to correct for the sea surface state at the source and at the at least one of the plurality of receivers.[0076] Each of the number of engines 1666, 1667, 1668, 1669 can include hardware and/or a combination of hardware and programming that can function as a corresponding module as described with respect to Figure 17. For example, the measurement engine 1666 can include hardware and/or a combination of hardware and programming that can function as the measurement module 1772, the determination engine 1667 can include hardware and/or a combination of hardware and programming that can function as the determination module 1774, the decomposition engine 1668 can include hardware and/or a combination of hardware and programming that can function as the decomposition module 1776, and/or the correction engine 1669 can include hardware and/or a combination of hardware and programming that can function as the correction module 1778.[0077] Figure 17 illustrates a diagram of a machine 1782 for correction of sea surface state in accordance with one or more example embodiments of the present disclosure. The machine 1782 can utilize software, hardware, firmware, and/or logic to perform a number of functions. The machine 1782 can be a combination of hardware and program instructions configured to perform a number of functions. The hardware, for example, can include a number of processing resources 1784 and a number of memory resources 1788, such as a machine-readable medium (MRM) or other memory resources 1788. The memory resources 1788 can be internal and/or external to the machine 1782. The program instructions may be machine-readable instructions (MRI) and can include instructions stored on the MRM to implement a particular function (e.g., sea surface state correction). The set of MRI can be executable by one or more of the processing resources 1784. The memory resources 1788 can be coupled to the machine 1782 in a wired and/or wireless manner. For example, the memory resources 1788 can be an internal memory, a portable memory, a portable disk, and/or a memory associated with another resource, enabling MRI to be transferred and/or executed across a network such as the Internet.[0078] Memory resources 1788 can be non-transitory and can include volatile and/or non-volatile memory. Volatile memory can include memory that depends upon power to store information, such as various types of dynamic random access memory (DRAM) among others. Non-volatile memory can include memory that does not depend upon power to store information. Examples of non-volatile memory can include solid state media such as flash memory, electrically erasable programmable read-only memory (EEPROM), phase change random access memory (PCRAM), magnetic memory such as a hard disk, tape drives, floppy disk, and/or tape memory, optical discs, digital versatile discs (DVD), Blu-ray discs (BD), compact discs (CD), and/or a solid state drive (SSD), etc, as well as other types of computer-readable media.[0079] The processing resources 1784 can be coupled to the memory resources 1788 via a communication path 1793. The communication path 1793 can be local or remote to the machine 1782. Examples of a local communication path 1793 can include an electronic bus internal to a machine, where the memory resources 1788 are in communication with the processing resources 1784 via the electronic bus. Examples of such electronic buses can include Industry Standard Architecture (ISA), Peripheral Component Interconnect (PCI), Advanced Technology Attachment (ATA), Small Computer System Interface (SCSI), Universal Serial Bus (USB), among other types of electronic buses and variants thereof. The communication path 1793 can be such that the memory resources 1788 are remote from the processing resources 1784, such as in a network connection between the memory resources 1788 and the processing resources 1784. That is, the communication path 1793 can be a network connection. Examples of such a network connection can include LAN, wide area network (WAN), PAN, and the Internet, among others.[0080] As shown in Figure 17, the MRI stored in the memory resources 1788 can be segmented into a number of modules 1772, 1774, 1776, 1778 that when executed by the processing resources 1784 can perform a number of functions. As used herein, a "module" includes a set of instructions included to perform a particular task or action. The number of modules 1772, 1774, 1776,1778 can be sub-modules of other modules. For example, the measurement module 1772 can be a sub-module of the determination module 1774 and/or the measurement module 1772 and the determination module 1774 can be contained within a single module. Furthermore, the number of modules 1772, 1774, 1776,1778 can comprise individual modules separate and distinct from one another. Examples are not limited to the specific modules 1772, 1774, 1776, 1778 illustrated in Figure 17.[0081] The machine 1782 can include a measurement module 1772, which can include instructions to receive up-going wavefield data and source-side data collected from receivers (or any multi-sensor acquisition which allows a mathematical separation of the up-going wavefields and down-going wavefields). The source-side data, in some examples, may be associated with a sea surface state. Measurement module 1772 can include instructions to collect down-going wavefield data in conjunction with the up-going wavefield data from the receiver (or any multi-sensor acquisition which allows a mathematical separation of the up-going wavefields and down-going wavefields) associated with the sea surface state. The machine 1782 can also include a determination module 1774, which can include instructions to calculate a cross-correlation at a constant channel between consecutive shot points using the collected data, calculate a cross-correlation at a constant channel within a constant receiver between consecutive shot points using the collected data, and calculate a cross-correlation within a constant receiver between consecutive shot points using the collected data.[0082] In some examples, measurement module 1772 can include instructions to calculate the cross-correlation at the constant channel between consecutive shot points as a function of a geology of the area from which the data was collected and a sea surface state variation. Measurement module 1772 can also include instructions to calculate the cross-correlation at the constant channel within a shot point between consecutive channels as a function of source and receiver velocity and a geology of the area from which the data was collected. In some instances, measurement module 1772 can include instructions to calculate the cross-correlation within the constant receiver.[0083] In addition, the machine 1782 can include a decomposition module 1776, which can include instructions to separate the down-going wavefield data and the up-going wavefield collected via the measurement module 1772 prior to the cross-correlation calculations performed via the determination module 1774. The machine 1782 can also include a correction module 1778, which can include instructions to correct the sea surface state based on the calculated cross-correlations.[0084] Figure 18 illustrates an example method 1831 for correction of sea surface state according to one or more embodiments of the present disclosure. At 1837, method 1831 can include receiving geophysical data from a seismic survey. The seismic survey can utilize a plurality of receivers disposed in a body of water and at least one source in the body of water, actuated at a plurality of shot points. In some examples, the disposed receivers can be associated with a towed streamer, and the towed streamer can comprise a dual-receiver streamer or any multi-sensor acquisition which can allow for mathematical separation of up-going and down-going wavefields. At 1843, method 1831 can include identifying, in the geophysical data, a wavefield based on the actuation of the at least one source. A unique estimation of a sea surface state for a location of the at least one source at the moment that source is actuated in some instances.[0085] At 1845, method 1831 can include determining, based on the identified wavefield, a sea surface state at the at least one source at one of the plurality of shot points. Determining the sea surface state can include, in some examples, separating up-going portions of the identified wavefield from down-going portions of the identified wavefield and determining source-side effects in the up-going wavefield. Determining the sea surface state can also include cross-correlating constant receiver and constant channel ensembles and statistically filtering and extracting a surface consistent time correction to apply to the plurality of shot points based on the cross-correlation. As used herein, "cross-correlating a constant channel ensemble" can include cross-correlating a constant channel between consecutive shot points and/or within a shot point between consecutive channels. "Cross-correlating a constant receiver ensemble", as used herein, can include cross-correlating within a constant receiver between consecutive shot points.[0086] Determining the sea surface state can include, in some examples, comparing an up-going portion of the identified wavefield to an up-going portion of a different identified wavefield and determining the sea surface state based on the comparison.[0087] In accordance with a number of embodiments of the present disclosure, a geophysical data product may be produced. The geophysical data product may include, for example, estimations of sea surface state and/or seismic data with correction of sea surface state. Geophysical data may be obtained and stored on a non-transitory, tangible machine-readable medium. The geophysical data product may be produced by processing the geophysical data offshore (i.e. by equipment on a vessel) or onshore (i.e. at a facility on land) either within the United States or in another country. If the geophysical data product is produced offshore or in another country, it may be imported onshore to a facility in the United States. In some instances, once onshore in the United States, geophysical analysis may be performed on the geophysical data product. In some instances, geophysical analysis may be performed on the geophysical data product offshore. For example, estimation of sea surface state can be performed on seismic data offshore to facilitate other processing of the measured data either offshore or onshore. As another example, the correction of sea surface state in seismic data can be performed on seismic data offshore or onshore to facilitate other processing of data either offshore or onshore.[0088] Figure 19 illustrates an example method 1911 for correction of sea surface state according to one or more embodiments of the present disclosure. For instance, method 1911 can include generating a geophysical data product associated with correction of sea surface state. At 1947, method 1911 can include receiving geophysical data and at 1949, method 1911 can include processing the geophysical data to generate the geophysical data product. Processing the geophysical data can include, in some examples, identifying, in the geophysical data, a wavefield based on the actuation of the at least one source and determining, based on the identified wavefield, a sea surface state at the at least one source actuated at a plurality of shot points.[0089] In some instances, processing the geophysical data can further include separating up-going portions of the measured wavefield from down-going portions of the identified wavefield and determining source-side effects in the up-going wavefield. Processing the geophysical data can also include cross-correlating constant receiver and constant channel ensembles and statistically filtering and extracting a surface consistent time correction to apply to the plurality of shot points based on the cross-correlation.[0090] Though not illustrated in Figure 19, method 1911 can include, in some examples, recording the geophysical data product on a non-transitory machine-readable medium suitable for importing onshore. Method 1911 can also include performing geophysical analysis on the geophysical data product onshore and/or offshore.[0091 ] Although specific embodiments have been described above, these embodiments are not intended to limit the scope of the present disclosure, even where only a single embodiment is described with respect to a particular feature. Examples of features provided in the disclosure are intended to be illustrative rather than restrictive unless stated otherwise. The above description is intended to cover such alternatives, modifications, and equivalents as would be apparent to a person skilled in the art håving the benefit of this disclosure.[0092] The scope of the present disclosure includes any feature or combination of features disclosed herein (either explicitly or implicitly), or any generalization thereof, whether or not it mitigates any or all of the problems addressed herein. Various advantages of the present disclosure have been described herein, but embodiments may provide some, all, or none of such advantages, or may provide other advantages.[0093] In the foregoing Detail ed Description, some features are grouped together in a single embodiment for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the disclosed embodiments of the present disclosure have to use more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive subject matter lies in less than all features of a single disclosed embodiment. Thus, the following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separate embodiment.
Claims
1. A method, comprising: receiving geophysical data from a seismic survey, wherein the seismic survey utilizes a plurality of receivers disposed in a body of water, and at least one source in the body of water, actuated at a plurality of shot points; identifying in the geophysical data, a wavefield based on the actuation of the at least one source; and determining, based on the identified wavefield, a sea surface state at the at least one source at one of the plurality of shot points.2. The method of claim 1, wherein the plurality of receivers comprise receivers allowing for mathematical separation of up-going and down-going wavefields.3. The method of claim 1, wherein determining the sea surface state comprises: separating up-going portions of the measured wavefield from down-going portions of the measured wavefield; determining source-side effects in the up-going wavefield; cross-correlating constant receiver and constant channel ensembles; and statistically filtering and extracting a surface consistent time correction to apply to the plurality of shot points based on the cross-correlation.4. The method of claim 3, wherein cross-correlating a constant channel ensemble comprises cross-correlating a constant channel between consecutive shot points.5. The method of claim 3, wherein cross-correlating a constant channel ensemble comprises cross-correlating a constant channel within a shot point between consecutive channels.6. The method of claim 3, wherein cross-correlating a constant receiver ensemble comprises cross-correlating within a constant receiver between consecutive shot points.7. The method of claim 1, wherein the determining the sea surface state comprises: comparing an up-going portion of the measured wavefield to an up-going portion of a different measured wavefield; and determining the sea surface state based on the comparison.8. The method of claim 1, further comprising generating a unique estimation of a sea surface state for a location of the at least one source at the moment that source is actuated.9. A non-transitory machine-readable medium storing instructions executable by a processing resource to cause a computing system to: receive up-going wavefield data and source-side data collected from receivers,wherein the source-side data is associated with a sea surface state; calculate a cross-correlation at a constant channel between consecutive shot points using the collected data; calculate a cross-correlation at a constant channel within a shot point between consecutive channels using the collected data; calculate a cross-correlation within a constant receiver between consecutive shot points using the collected data; and correct the sea surface state based on the calculated cross-correlations.10. The non-transitory machine-readable medium of claim 9, further comprising instructions executable to calculate the cross-correlation at the constant channel between consecutive shot points as a function of a geology of the area from which the data was collected and a sea surface state variation.11. The non-transitory machine-readable medium of claim 9, further comprising instructions executable to calculate the cross-correlation at the constant channel within a shot point between consecutive channels as a function of source and receiver velocity and a geology of the area from which the data was collected.12. The non-transitory machine-readable medium of claim 9, further comprising instructions executable to calculate the cross-correlation within the constant receiver between consecutive shot points as a function of source and receiver velocity, a geology of the area from which the data was collected, and sea surface state variation.13. The non-transitory machine-readable medium of claim 9, further comprising instructions executable to: collect down-going wavefield data in conjunction with the up-going wavefield data from the receivers associated with a sea surface state; and separate the down-going wavefield data and the up-going wavefield data prior to calculating the cross-correlations.14. A system, comprising: a measurement engine to measure an up-going portion of a wavefield based on an actuation of a source,wherein the measured up-going portion of the wavefield has been collected by a plurality of receivers; a determination engine to determine, based on the measured up-going portion of the wavefield, a sea surface state at the source; a decomposition engine to decompose the sea surface state at the source and at at least one of the plurality of receivers and a correction engine to correct for the sea surface state at the source and at the at least one of the plurality of receivers based on the decomposition.15. The system of claim 14, including the decomposition engine to decompose the sea surface state using cross-correlations of an ensemble of source units, channels, and receivers, in various combinations associated with the source and the at least one receiver.16. The system of claim 15, wherein the ensemble of source units, channels, and receivers include a constant distance from the source to a sea surface, a constant channel direction, and a constant receiver direction.17. The system of claim 14, wherein the sea surface state includes a sea surface state variation on the up-going portion of the wavefield at the at least one of the plurality of receivers.18. The system of claim 14, further comprising a record engine to: simultaneously record traces received from the source; and display the traces as a random time delay between traces via a graphical user interface.19. The system of claim 14, further comprising a design engine to design a time window in which to correct for the sea surface state at the source and at the at least one of the plurality of receivers.20. A method comprising: receiving geophysical data from a seismic survey; and processing the geophysical data to generate the geophysical data product, wherein processing the geophysical data comprises: identifying in the geophysical data a wavefield based on the actuation of the at least one source; and determining, based on the identified wavefield, a sea surface state at the at least one source actuated at a plurality of shot points.21. The method of claim 20, processing the geophysical data further comprises: separating up-going portions of the identified wavefield from down-going portions of the measured wavefield; determining source-side effects in the up-going wavefield; cross-correlating constant receiver and constant channel ensembles; and statistically filtering and extracting a surface consistent time correction to apply to the plurality of shot points based on the cross-correlation.22. The method of claim 20, further comprising recording the geophysical data product on a non-transitory machine-readable medium suitable for importing onshore.
Drawings

Priority

18.02.2014 US 61/941,38323.07.2014 US 14/338,516

Patent classes

IPC classesG01V 1/38

Citations

US 7872942 B2 (B2)US 7872942 B2 (B2)US 2008159074 A1 (A1)GB 2405473 A (A)GB 2405473 A (A)US 2011044127 A1 (A1)US 7426438 B1 (B1)

Applicants, owners and inventors

Applicants
PGS Geophysical AS
Postboks 251 Lilleaker 0216 OSLO NO (OSLO Municipality, Oslo county)Org. number: 960563085Inventors
Edwin Thomas Hodges
24 Hawthorn Road GU236LH WOKING GB
Magdy Attia Sedhom
Flat 6, Egment House, Cromwell Road KT123NJ SURREY GB
Paul Lecocq
37 Drayton Gardens W13OLG WEST EALING GB

Agent

ACAPO AS
ACAPO AS

Org. number: 915113737

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Edvard Griegs vei 1 5059 BERGEN NO (BERGEN Municipality, Vestland county)
Org. number: 915113737
Reference: P16429NO00

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