Seismic surveying using optical communication links

Abstract

Systems and methods for optical link communications of seismic data acquisition units are provided. The systems and methods can perform at least some portions of a seismic data acquisition survey. Multiple seismic data acquisition units can be deployed on the seabed. An optical communication link can be established between an extraction vehicle and at least one seismic data acquisition unit. The frequency of at least one seismic data acquisition unit can be resonated or synchronized via the optical communication link. At least one seismic data acquisition unit can be commanded to enter a low power state after resonating the frequency of at least one seismic data acquisition unit. The seismic data acquisition unit can exit the low power state and acquire seismic data in an operational state.

Description

[0001] This application is a divisional application of the invention patent application with application number 201780052733.1, application date June 19, 2017, applicant Fairfield Industries, and invention name “Seismic Survey Using Optical Communication Links”.

[0002] CROSS-REFERENCE TO RELATED APPLICATIONS

[0003] This application claims priority to U.S. Patent Application No. 15 / 625,708 filed on June 16, 2017, U.S. Patent Application No. 15 / 625,722 filed on June 16, 2017, U.S. Patent Application No. 15 / 625,730 filed on June 16, 2017, U.S. Provisional Patent Application No. 62 / 357,118 filed on June 30, 2016, U.S. Provisional Patent Application No. 62 / 357,145 filed on June 30, 2016, and U.S. Provisional Patent Application No. 62 / 357,136 filed on June 30, 2016, each of which is hereby incorporated by reference in its entirety. Technical Field

[0004] The present application relates to systems and methods for performing seismic surveys in marine environments. Background Art

[0005] Seismic data acquisition systems can acquire seismic data related to subsurface features, such as lithologic formations or fluid layers that can indicate the presence of hydrocarbons, minerals, or other elements. Acoustic signals can penetrate the earth's surface. Acoustic signals can reflect or refract off of subsurface lithologic formations. The reflected or refracted acoustic signals can be acquired, analyzed, and interpreted to indicate, for example, physical characteristics of lithologic formations, such as the presence of hydrocarbons. Summary of the invention

[0006] At least one aspect relates to a system for performing seismic surveys in a marine environment. The system may include a seismic data acquisition unit and an extraction vehicle. The seismic data acquisition unit may be placed or disposed on a seabed in a marine environment. The seismic data acquisition unit may include a first clock. The extraction vehicle may establish an optical communication link with the seismic data acquisition unit. The extraction vehicle may include a second clock and a data processing system. The data processing system may resonate or synchronize the first clock of the seismic data acquisition unit with the second clock. The data processing system may resonate the frequency of the first clock with the second clock via the optical communication link. The data processing system may synchronize the time of the first clock with the second clock via the optical communication link. The data processing system may command the seismic data acquisition unit to enter a low power state after the resonance or synchronization of the first clock. The seismic data acquisition unit may be configured to exit the low power state and acquire seismic data in an operating state.

[0007] At least one aspect may relate to a method for performing seismic surveys in a marine environment. The method may include positioning a seismic data acquisition unit on a seabed in the marine environment. The seismic data acquisition unit may include a first clock. The method may include an extraction vehicle establishing an optical communication link with the seismic data acquisition unit. The extraction vehicle may include a second clock and a data processing system. The method may include the data processing system resonating or synchronizing the first clock of the seismic data acquisition unit via the optical communication link to correspond to the second clock. The method may include the data processing system commanding the seismic data acquisition unit to enter a low power state after the resonance or synchronization of the first clock. The seismic data acquisition unit may be configured to exit the low power state and acquire seismic data in an operational state.

[0008] At least one aspect relates to a system for performing seismic surveys. The system may include a seismic data acquisition unit. The system may include a seismic data acquisition unit having a transmitter window. The transmitter window may be disposed in a first hole of a cover of the seismic data acquisition unit. The seismic data acquisition unit may include a receiver window disposed in a second hole of the cover. The system may include a first gasket located between the transmitter window and the first hole. The first gasket may provide a gap greater than a threshold between the transmitter window and the first hole. The gap may be greater than the threshold to allow the transmitter window to deform or move. For example, by allowing the transmitter window to deform, move, expand, or contract under pressure, the first gasket between the transmitter window and the first hole may reduce impact and breakage of the transmitter window. The system may also include a second gasket located between the receiver window and the second hole. The second gasket between the receiver window and the second hole may provide a gap greater than the threshold. By configuring the second gasket between the receiver window and the second hole to provide a gap greater than the threshold, the second gasket may allow the receiver window to move, deform, expand, or contract. For example, by allowing the receiver window to move under pressure, the second gasket between the receiver window and the second hole may reduce impact and breakage of the receiver window. The transmitter window, the receiver window, or both the transmitter window and the receiver window can be configured to transmit at least one of optical and electromagnetic communications to or from the extraction vehicle via at least one of the transmitter window and the receiver window of the extraction vehicle.

[0009] At least one aspect relates to a method of performing a seismic survey. The method may include providing a seismic data acquisition unit. The seismic data acquisition unit may include a transmitter window disposed in a first hole of a cover, and a receiver window disposed in a second hole of the cover. The method may include providing a first gasket between the transmitter window and the first hole. The first gasket between the transmitter window and the first hole may provide a gap greater than a threshold value to allow the transmitter window to move under pressure to reduce impact and cracking of the transmitter window. The method may include providing a second gasket between the receiver window and the second hole. The second gasket between the receiver window and the second hole may provide a gap greater than a threshold value. The gap provided by the second gasket between the receiver window and the second hole may allow the receiver window to move under pressure to reduce impact and cracking of the receiver window. The method may include transmitting optical or electromagnetic communications to or from an extraction vehicle via at least one of the transmitter window and the receiver window of the seismic data acquisition unit, via at least one of the transmitter window and the receiver window of the extraction vehicle.

[0010] At least one aspect relates to a system for performing seismic surveys in a marine environment. The system may include a seismic data acquisition unit disposed on a seabed in a marine environment. The seismic data acquisition unit may include a local pressure sensor, an optical transmitter, and an optical receiver to determine one or more pressure values. The system may include an extraction vehicle including a reference pressure sensor, an optical transmitter, and an optical receiver to establish an optical communication link with the seismic data acquisition unit. The extraction vehicle may generate reference pressure data. The local pressure sensor or one or more pressure values ​​may be calibrated based on the reference pressure data generated by the extraction vehicle.

[0011] At least one aspect relates to a method for performing seismic surveys in a marine environment. The method may include deploying a seismic data acquisition unit on a seabed in the marine environment. The seismic data acquisition unit may include a local pressure sensor, an optical transmitter, and an optical receiver. The method may include an extraction vehicle establishing an optical communication link with the seismic data acquisition unit. The extraction vehicle may include a reference pressure sensor, an optical transmitter, and an optical receiver. The method may include the extraction vehicle providing reference pressure data to the seismic data acquisition unit via the optical communication link. The method may include calibrating, by one or more processors, the local pressure sensor or one or more pressure values ​​measured by the local pressure sensor based on the reference pressure data.

[0012] These and other aspects and implementations are discussed in detail below. The foregoing information and the following detailed description include illustrative examples of various aspects and implementations, and provide an overview or framework for understanding the nature and characteristics of the claimed aspects and implementations. The accompanying drawings provide illustration and further understanding of the various aspects and implementations, and are incorporated into and constitute a part of this specification. BRIEF DESCRIPTION OF THE DRAWINGS

[0013] The drawings are not intended to be drawn to scale. Like reference numbers and names in the various drawings represent like elements. For clarity, not every component will be labeled in every drawing. In the drawings:

[0014] Figure 1 is a block diagram depicting an optical link timing and frequency synchronization and resonance system according to an illustrative embodiment;

[0015] Figure 2 is a block diagram depicting an optical link timing and frequency synchronization and resonance system according to an illustrative embodiment;

[0016] Figure 3 is a block diagram depicting a method of optical link timing and frequency synchronization and resonance according to an illustrative embodiment;

[0017] Figure 4 is a diagram depicting timing windows for synchronization and resonance according to an illustrative embodiment;

[0018] Figure 5 is a diagram depicting timing windows for synchronization and resonance according to an illustrative embodiment;

[0019] Figure 6 is a block diagram depicting a system for calibrating a sensor via an optical link according to an illustrative embodiment;

[0020] Figure 7 is a block diagram depicting a method for calibrating a sensor via an optical link according to an illustrative embodiment;

[0021] Figure 8 is a block diagram depicting a method for conditioning a sensor via an optical link according to an illustrative embodiment;

[0022] Fig. 9 is a diagram depicting timing windows for synchronization and resonance according to an illustrative embodiment;

[0023] Fig.10 is a diagram depicting a seismic survey apparatus including an optical window according to an illustrative embodiment;

[0024] Fig.11 is a diagram depicting a seismic survey apparatus including an optical window according to an illustrative embodiment;

[0025] Fig.12 is a seismic surveying device including an optical window according to an illustrative embodiment; and

[0026] Fig.13 is a method according to an illustrative embodiment.

[0027] Fig.14 An isometric schematic diagram depicting an example of seismic operations in deep water. DETAILED DESCRIPTION

[0028] The following is a more detailed description of various concepts and embodiments related to methods, apparatus, and systems for timing control and management of free-space optical links (or other electromagnetic signals, including optical and acoustic signals) to or from seismic data acquisition units. For example, an optical link can send timing data or other data to or from a seismic data acquisition unit that is deployed on the seabed or other surface of the earth. The timing data can synchronize the seismic data acquisition units so that the extracted seismic data can be properly interpreted to indicate the presence or absence of subsurface formations. The various concepts introduced above and discussed in more detail below can be implemented in any of a variety of ways, as the concepts described are not limited to any particular implementation.

[0029] In an underwater seismic data acquisition system, a series of seismic data acquisition units (e.g., nodes) can be deployed on the seabed or lakebed. Acoustic signals can propagate from a source through the water column and through the seabed and into (e.g., "down") the earth. The acoustic signals can be reflected or refracted from various lithologic formations back (e.g., "up") toward the earth's surface. The seismic data acquisition units deployed on the seabed can collect the reflected or refracted acoustic signals.

[0030] Extraction vehicles such as autonomous or remote underwater vehicles or other entities such as ships on the surface of a body of water can communicate wirelessly or optically with seismic data acquisition units deployed on the seabed or other surface of the earth to extract acquired seismic data. The systems and methods described herein relate to techniques used on optical links to control and manage data acquisition timing to ensure proper operation of the seismic data acquisition units. For example, there may be hundreds or thousands of seismic data acquisition units located on the seabed, in symmetrical array patterns, other patterns, or randomly deployed. Timing control and management of seismic data acquired by each seismic data acquisition unit is required to generate usable or quality seismic data. For example, if the seismic data acquisition units are not properly synchronized, there may be timing errors in the acquired seismic data, which may complicate or prevent the correct interpretation of the data.

[0031] The recording sensors of autonomous or separate seismic data acquisition units that collect seismic data are susceptible to timing offsets relative to each other. After data collection, these timing errors may need to be corrected in order to improve the analysis of the collected seismic data. The systems and methods described herein can control and minimize the sources of timing errors to provide a control system for resonating and synchronizing the local clocks of separate seismic data acquisition units deployed as part of a seismic survey. To achieve such control, the systems and methods provided herein can provide a reference signal to each deployed seismic data acquisition unit via an optical communication link. The systems and methods provided herein can use free space optical communication links or any electromagnetic transmission system (e.g., optical or acoustic) with appropriate bandwidth for other data communications.

[0032] In some cases, the systems and methods described herein relate to techniques used over optical links to control and manage pressure data or pressure measurements of seismic data acquisition units. For example, the systems and methods described herein can control and regulate pressure sensor data sensed by or for a seismic data acquisition unit deployed on the seabed or other location as part of a seismic survey. To achieve such control, the systems and methods provided herein can send or receive pressure sensor data or other reference signals to each deployed seismic data acquisition unit via an optical communication link. The systems and methods provided herein can use free space optical communication links or any electromagnetic transmission system (e.g., optical or acoustic) with appropriate bandwidth for seismic data communications.

[0033] Extraction vehicles such as autonomous or remote underwater vehicles or other entities such as ships on the surface of a body of water can communicate wirelessly or optically with seismic data acquisition units deployed on the seabed or other surfaces of the earth to extract the collected seismic data. The systems and methods described herein may involve one or more windows built into a seismic data acquisition unit that collects seismic data, and a window built into an extraction vehicle. The seismic data acquisition unit and the extraction vehicle can communicate with each other optically (or using another electromagnetic means). Optical (or other transmissions) can pass through the windows of the corresponding devices. For example, there may be hundreds or thousands of seismic data acquisition units located on the seabed, in a symmetrical array pattern, other patterns, or randomly deployed. One or more submersible extraction vehicles can pass within the range of a separate seismic data acquisition unit (e.g., 10 meters or some other distance), and an optical (or other type) communication link can be established with one of the seismic data acquisition units. Data such as seismic data, frequency calibration data, clock synchronization data, power state data, or other information can be transmitted between the extraction vehicle and the optically linked seismic data acquisition unit. The data transmission can be through at least one window of the seismic data acquisition unit and through at least one window of the extraction vehicle. The window, for example, enables the passage of optical data transmission to or from a transmitter, a receiver or other electronic or mechanical components disposed within the device.

[0034] Figure 1 1 is a block diagram depicting an optical link timing and frequency synchronization and resonance system. System 100 can perform seismic surveys in a marine environment. System 100 can facilitate performing seismic surveys in a marine environment. System 100 can be used to perform at least a portion of a seismic survey in a marine environment. For example, system 100 can synchronize or resonate one or more components of first device 102. System 100 can transmit, provide, or obtain seismic data, sensor data, status data, quality information, or other information.

[0035] System 100 may include a first device 102 and a second device 104. First device 102 may include a transmitter 114, a receiver 116, a data processing system 106, and a local master clock 120. Data processing system 106 may include: a field programmable gate array ("FPGA") 110 and a processor 108 and a memory. Second device 104 may include a transmitter 114, a receiver 116, a data processing system 106, and a global reference clock 112. Data processing system 106 of second device 104 may include a field programmable gate array ("FPGA") 110 and a processor 108 and a memory.

[0036] The first device 102 may include or refer to a seismic data acquisition unit, a seafloor sensor, an independent seafloor sensor, a node, or other unit that facilitates performing a seismic survey. The first device 102 may include a seismic detector contained within the first device or externally connected to the first device 102. The first device may be placed on the seabed in a marine environment.

[0037] The system 100 may include a second device 104. The second device 104 may include or be referred to as an extraction vehicle, a remotely operated vehicle, an underwater vehicle, an autonomous underwater vehicle, or other device that facilitates performing seismic surveys, which may interact with the first device 102. The second device 104 may communicate with the first device 102 to establish an optical communication link 118 with the first device 102. The second device 104 may establish an optical communication link 118 with the first device 102, or the first device 102 may establish an optical communication link 118 with the second device 104. Figure 1 As shown, the communication link 118 may form a loop around which signals may travel. Figure 6 The communication link 118 shown in FIG. 1 may be configured such that bidirectional signals travel back and forth between the first and second devices 102 and 104 , respectively.

[0038] Establishing the optical communication link 118 may include the receiver 116 of the second device 104 successfully receiving information from the transmitter 114 of the first device 102, and the receiver 116 of the first device 102 successfully receiving information from the transmitter 114 of the second device 104. Establishing the optical communication link 118 may refer to completing a handshake process, in which data optically sent and received between the first device 102 and the second device 104 are verified. In some cases, the first device 102 or the second device 104 may adjust the gain of the receiver or the power level of the transmitter until the data is successfully received through the optical communication link 118. The reception of information may include receiving data, a data packet, header information, payload data, bits, bytes, or signals. Successfully receiving information may refer to receiving data or a data stream with a satisfactory bit error rate at a satisfactory data rate. The bit error rate may be satisfactory based on a comparison with a bit error rate threshold. The bit error rate may be satisfactory if it is less than or equal to a threshold value, such as 0.5, 0.4, 0.3, 0.2, 0.1, or some other threshold value that facilitates performing seismic surveys. The data rate may be, for example, 100 kilobytes per second, 200 kilobytes per second, 500 kilobytes per second, 700 kilobytes per second, 1 megabyte per second, 1.5 megabytes per second, 5 megabytes per second, 10 megabytes per second, 20 megabytes per second, 30 megabytes per second, 50 megabytes per second, 100 megabytes per second, or more.

[0039] The second device 104 can resonate or synchronize the frequency of the first clock 120 (e.g., a local master clock) of the seismic data acquisition unit 102 to correspond to the second clock 112 (e.g., a global reference clock) via the optical communication link 118. The system 100 can resonate, synchronize, calibrate, tune, or otherwise adjust the first clock 120 or other sensor components or logic devices of the first device 102.

[0040] Resonance may refer to correcting a frequency error of the local master clock 120. Resonance may refer to adjusting an oscillation frequency of the local master clock 120 or an offset in oscillation, such as a phase shift. For example, the oscillation frequency or phase of the local master clock 120 may change or drift. The oscillation frequency or phase of the local master clock 120 may change or drift due to environmental variables, including, for example, time, temperature, gravity, tilt, pressure, shock, force, impact, low power, or power loss. Synchronization may refer to adjusting the time of the clock. For example, the local master clock 120 may indicate a first timestamp for a first time that is different from a second timestamp provided by the global reference clock 112 for the same first time. The system 100 may determine that the local master clock 120 is not synchronized with the global reference clock 112 because the first timestamp is different from the second timestamp.

[0041] In some cases, local master clock 120 may be out of synchronization with global reference clock 112 and have a frequency error relative to global reference clock 112. In some cases, local master clock 120 may only have a frequency error or a synchronization error relative to global reference clock 112.

[0042] The system 100 can determine a frequency error, whether it is the frequency of the oscillations or a phase shift of the oscillations, by comparing the oscillations of the local master clock 120 with the oscillations of the global reference clock 112. The system 100 can obtain a first signal generated by the local master clock 120 indicating the oscillations of the local master clock 120. The system 100 can obtain a second signal generated by the global reference clock 112. The system 100 can compare the first signal to the second signal to determine one or more differences.

[0043] The system 100 can calculate or determine a parameter or characteristic of the first signal or the second signal, and compare the parameters or characteristics of the first signal and the second signal. For example, the system 100 can determine an oscillation frequency of the first signal, and determine an oscillation frequency of the second signal. The system 100 can also determine that the oscillation frequency of the first signal is different from the oscillation frequency of the second signal. In response to determining that the oscillation frequency of the first signal is different from the oscillation frequency of the second signal, the system 100 can determine to adjust the oscillation frequency of the first signal to match or otherwise correspond to the oscillation frequency of the second signal.

[0044] The system 100 may use one or more techniques to determine the frequency of the first signal or the second signal. For example, the system 100 (e.g., FPGA 110) may be configured to perform a Fourier transform or a fast Fourier transform on the first signal or the second signal to determine the spectrum of the signal. The signal may contain a single frequency, in which case the spectrum may indicate pulses at a specific frequency. Another technique may include performing a peak detection or local peak detection technique on the signal. The number of peaks in one second may correspond to the frequency of the signal.

[0045] In some cases, the system 100 can determine a phase shift between the first signal and the second signal. The system 100 can determine the phase shift by determining an offset between peaks of the first signal and the second signal or other reference points in the signals.

[0046] The first device 102 may receive a reference signal from the global reference clock 112 of the second device 104 and then use the reference signal to resonate the local master clock 120. For example, the data processing system 106 of the second device 104 may send one or more reference pulses (e.g., one pulse per second or other pulse rate interval) generated based on the second clock 112 to the first device 102 via the transmitter 114 of the second device 104. The first device 102 may resonate the first clock 120 of the first device 102 using the one or more reference pulses received from the data processing system 106 of the second device 104 via the receiver 116 of the first device.

[0047] When resonating the local master clock 120, the first device 102 may provide an indication that the local master clock 120 has been resonated. The indication may include a status indicator. In some cases, the first device 102 may send a signal generated by the resonated local master clock 120 to the second device 104 via the optical communication link 118 for verification by the second device 104. The second device 104 may receive a signal from the resonated local master clock 120 via the optical communication link 118, compare the received signal with a reference signal generated by the global reference clock 112, and determine whether the local master clock 120 has been successfully resonated.

[0048] In some cases, the system 100 may determine that the local master clock 120 still contains a frequency error or a timing error, and continue the resonance or synchronization process until the local master clock 120 is resonated or synchronized. In response to resonating or synchronizing the local master clock 120, the system 100 may command the first device 102 to enter a low power state. The system 100 may command the first device 100 to enter a low power state after resonance of the frequency of the local master clock 120. The low power state may refer to a state or mode in which the first device 102 or one or more components of the first device 102 are in standby, passive operation, inactive, disabled, turned off, operated in an economy mode or low power mode, or otherwise save power or energy relative to an operating state. In some cases, the first device 102 may maintain the operation of the local master clock 120 so that the local master clock 120 remains synchronized and resonant, while disabling one or more other components of the first device 102 without affecting the accuracy of the local master clock 120. The first device 102 or one or more components thereof may exit the low power state and acquire seismic data in an operating state.

[0049] In some cases, the second device 104 may command the first device 102 to enter a low power state after resonance or synchronization of the local master clock 120. In some cases, the first device 102 may automatically enter a low power state in response to determining that the local master clock 120 is synchronized and resonant. In some cases, the first device 102 may receive an indication from the second device 104 indicating that the local master clock 120 is synchronized or resonant and also commanding the first device 102 to enter a low power mode.

[0050] The data processing system 106 of the second device 104 can send information to synchronize and resonate the first clock 120, and command the first device 102 to perform an action or enter a state. For example, the second device 104 can identify a data frame clock signal to provide through the optical communication link 118. The data frame clock signal can include or indicate one or more reference pulses, reference pulses per second, reference frequency, reference phase, reference timestamp or other reference signals. The data processing system 106 of the second device can send a data stream including the data frame clock signal via the optical communication link. The data processing system 106 can send one or more data frames to the first device 102 via the optical communication link 118, which includes payload data or transmits payload data to the first device 102 and tunes the first clock.

[0051] The first device 102 may receive a data stream or one or more data frames via the optical communication link 118. The first device 102 may parse the data stream to identify a data frame clock signal and payload data. The first device 102 may tune a local master clock 120 based on a data frame clock signal provided by a data processing system 106 of the second device 104. The first device 102 may further control the operation of the first device 102 (e.g., a mode or state of a component of the first device 102) in response to commands embedded in the payload data. For example, the payload data may include a command to enter a low power mode, exit a low power mode, acquire seismic data, acquire sensor data, perform a diagnostic procedure, or send data.

[0052] In some cases, the system 100 (e.g., one or both of the data processing systems 106 of the first device 102 and the second device 104) can measure, determine, or identify timing changes in seismic data collected by the first device 102. The timing changes can be determined after the seismic data is collected or after the second device 104 receives the seismic data from the first device 102. The system 100 can generate a time change function based on the timing changes. For example, the time change function can indicate a time offset or a frequency offset as a function of time, and can be used to remove timing errors from the collected seismic data. The time change function can be based on the historical performance of a seismic data reference clock associated with a seismic data acquisition unit. For example, the time change function can be based on historical performance corresponding to an environmental parameter (e.g., temperature, gravity, tilt, inclination, pressure, time, or other environmental parameter). For example, the frequency of the seismic data reference clock can vary based on temperature, which can be determined using historical performance information (e.g., a measurement of the clock frequency associated with the temperature of the clock, the first device, or the ambient temperature obtained when measuring the clock frequency). The system 100 (or other external system) can use the time change function to remove timing errors from the collected seismic data.

[0053] The system 100 can determine the distance between the first device 102 and the second device 104. For example, the system 100 can measure the time delay between signals sent from the extraction vehicle to the seismic data acquisition unit and returned to the extraction vehicle via the optical communication link. The system 100 can measure the time delay between the signals before or after the resonance or synchronization of the first clock 120 on the first device 102. The system 100 can determine the distance between the first device 102 and the second device 104 based on the time delay. For example, the system 100 can measure the time it takes for the signal to be sent from the second device 104 to the first device 102 and returned to the second device 104. The system 100 can account for circuit delays in the first device 102. The difference between the timestamps (accounting for any circuit or processing delays associated with recording or detecting the timestamps) can indicate the distance the signal traveled through the optical communication link 118 in the following manner: The speed of light in the water medium multiplied by the time difference can be equal to the distance between the first device 102 and the second device 104. The system 100 can determine the time delay based on the phase difference in the return signal. For example, the transmitter 114 of the first device 102 can send a signal to the second device 104. The second device 104 can generate a signal that is phase-locked with the signal received from the first device 102. The second device 104 can send the phase-locked signal to the first device 102. The first device 102 can determine the phase shift between its own signal and the second device 104 signal to determine the distance of the second device 104. For example, the distance can be determined as D = speed of light * phase shift / (4 * pi * frequency).

[0054] The system 100 may include a plurality of devices, such as a plurality of first devices 102 and one or more second devices 104. For example, the system 100 may include a plurality of seismic data acquisition units 102. The system 100 may include a first seismic data acquisition unit 102 and a second seismic data acquisition unit 102. In some cases, the extraction vehicle 104 may establish a separate optical communication link with each of the plurality of seismic data acquisition units 102. The system 100 may resonate or synchronize a local master clock 120 of the first seismic data acquisition unit 102 with a local master clock 120 of the second seismic data acquisition unit 102. For example, the local master clock 120 of the first seismic data acquisition unit may be synchronized or resonated with a global reference clock 112. In order to increase the efficiency and speed at which the plurality of seismic data acquisition units are synchronized or resonated, if an optical communication link 118 may be established between the first and second seismic data acquisition units 102, the first seismic data acquisition unit 102 may facilitate synchronization or resonance of a local master clock 120 (e.g., a third clock) of the second seismic data acquisition unit 102. Therefore, the retrieval vehicle 104 may not establish an optical communication link 118 with each of the plurality of seismic data acquisition units 102 .

[0055] Figure 2 is a block diagram depicting an optical link timing and frequency synchronization and resonance system. Figure 2 A data processing system 106 is depicted representing one side of an optical communication link 118. The system 100 may be part of or reside in a seismic data acquisition unit 102 and an extraction vehicle 104, such as an autonomous or remote underwater vehicle, or other device that includes an optical system interface ("OZI"). The data processing system 106 may include at least one processor 108, and at least one field programmable gate array (FPGA) 110 (or other integrated circuit or logic device). The system 100 may include at least one global reference clock 112. For example, the global reference clock may be a part of the system 100 that resides in an extraction vehicle (e.g., an autonomous or remote underwater vehicle) that communicates with the seismic data acquisition unit via an optical transmission link. The system 100 may also include at least one local master clock 120. The local master clock 120 may reside in each seismic data acquisition unit that is part of a seismic survey. The system 100 may also include at least one optical transmitter 114 and at least one optical receiver 116. Optical transmitter 114 and optical receiver 116 may be part of an optical system interface that transmits and receives data between seismic data acquisition unit 102 and retrieval vehicle 104, such as via optical link 118. The data may include seismic data, clock frequency data and clock timing data, among other data.

[0056] The system 100 is capable of clock resonating (e.g., frequency tuning) and clock synchronizing (e.g., timing) the master clocks of the distributed seismic data acquisition units 102. For example, with respect to clock resonating, in order to manage the accumulation of time errors or drifts in the digitized acquired seismic data, it is desirable to set the master clocks located in the individual seismic data acquisition units 102 to the same known frequency value as accurately as possible. The system 100 resonates the master clocks 120 of the individual units with a global reference clock 112. The global reference clock 112 may be located on the extraction vehicle (as part of the OZI) and has been previously resonated with an onboard GPS controlled reference clock, which may be present on a vessel associated with the seismic survey.

[0057] The global reference clock 112 on the OZI can be used to generate a data stream associated with an optical link 118 between the extraction vehicle 104 and the individual seismic data acquisition units 102. A field programmable gate array (FPGA) 110 present on the seismic data acquisition unit can generate a local reference clock signal from a data frame clock signal received via the optical link. The FPGA 110 can also use the data frame clock signal to generate one or more reference pulses or reference pulses per second (PPS) signals, which are used to tune the local master clock of the remote seismic data acquisition unit to correct the frequency. For example, by selecting a data frame clock for an optical (or other) communication link that can be used directly by the seismic data acquisition unit, the system 100 can determine the correct clock frequency of the optical data stream to reduce the accumulated phase error and avoid the need for an additional phase-locked loop (PLL). In this way, the system 100 can transmit the global reference clock frequency to multiple seismic data acquisition units via the optical link data stream. During the time required to tune or resonate the master clock of the seismic data acquisition unit (e.g., a node or remote unit), the optical link can also be used for other communication purposes.

[0058] The frequency of the optical data link can be selected independently of the seismic data acquisition unit clock requirements. In this example, a phase-locked loop can be used to create a clock frequency used by the seismic data acquisition unit so that the portion of the data processing system 106 on the extraction vehicle can operate at a different clock or frame rate than the portion of the data processing system 106 on the seismic data acquisition unit. (For example, the frame rate of the portion of the data processing system 106 on the extraction vehicle can be higher than the frame rate of the portion of the data processing system 106 of the seismic data acquisition unit to facilitate higher speed data extraction without complicating the design of the optical receiver 116.) In addition, the data processing system 106 can use or select an optical data link frequency so that the frame clock from the optical receiver 116 meets the requirements of the seismic data acquisition unit, which can simplify the circuits and logic in the seismic data acquisition unit. The system 100 can select or use an optical link frequency that will produce a clock that can be used directly by the seismic data acquisition unit, or can select or use a different (e.g., not directly compatible) frequency for the optical link. When the frequencies are different, the system 100 can create the clock required by the seismic data acquisition unit from the optical link clock.

[0059] Clock synchronization (or its lack) between seismic data acquisition units can cause timing errors or differences between seismic data collected from each unit, and is another source of potential errors in seismic data acquisition. This timing error may occur when the sampling boundaries of the acquired seismic data are not synchronized with an absolute reference. In order to avoid or minimize these errors, the data processing system 106 can use an optical link to synchronize the pulse per second (PPS) signal of the global master clock located on the extraction vehicle or other equipment away from the individual seismic data acquisition unit. The processor 108 or FPGA 110 on the seismic data acquisition unit can derive the global master clock signal from the optical link data stream. If it is not aligned with the global reference PPS, the phase relationship of the locally derived PPS signal can be arbitrary. The data processing system 106 can achieve this alignment by sending a specified symbol, which is associated with a frame or packet transmitted by the optical data link, which is aligned with the occurrence of the PPS of the global reference clock.

[0060] The optical data link transmission may include idle symbols or characters that do not represent user data. The data processing system 106 may replace at least one of these idle symbols with a marker symbol that does not interfere with the transmission occurring via the optical link. The processor 108 or FGPA 110 on the seismic data acquisition unit receiving the optical link transmission may use the symbol to align the PPS of the optical link transmission with the locally generated PPS of the seismic data acquisition unit. This alignment phase locks the local clock PPS with the global reference clock PPS as long as the optical data link connects the seismic data acquisition unit to an extraction vehicle or other device.

[0061] The data processing system 106 can be part of the seismic data acquisition system 100 that manages the accumulation of timing errors. For example, the local master clock 120 of the seismic data acquisition unit 102 can be resonated and synchronized before acquiring seismic data. This can allow the performance of the local master clock to be verified to pre-derive sampling boundaries before the seismic data acquisition unit is operated to acquire seismic data, which typically sets the initial timing error to zero or substantially zero. In this example, at the end of seismic data acquisition, the local master clocks of the individual units can be measured again to determine the changes in the clocks over the seismic data acquisition period. These measurements can be used to derive a time variation function through which the seismic data is acquired. Using this function, the acquired seismic data can be resampled to remove timing errors that may remain in the acquired seismic data. A disadvantage of this example is that it takes time to zero the local clocks of the individual seismic data acquisition units with respect to the remote master clock of, for example, an extraction vehicle, an autonomous or remote underwater vehicle, or a vessel at or before the start of seismic data acquisition.

[0062] Another embodiment that can be used by the data processing system 106 to manage the accumulation of timing errors is to calibrate (e.g., to zero the error) the local clock 120 of each seismic data acquisition unit 102 before tuning the clock 120, and allow appropriate frequency re-tracking time to occur before the OZI (of the extraction vehicle 104) arrives in the vicinity of the seismic data acquisition unit 102 to extract seismic data from the unit via optical link transmission. The data processing system 106 (or other data processing system) can measure the timing changes at the end of the seismic data acquisition process, and can use the historical performance of the clock and additional calibration data of the clock to generate a time change function for eliminating the timing errors that may remain in the acquired seismic data. The seismic data can be corrected by the data processing system 106 or other data processing system using the time change function derived from the measured timing changes. In this example, the transmitted seismic data can be independent of the specific clock technology employed in the individual seismic data acquisition units.

[0063] In addition, the propagation delay between two transmitting devices (e.g., a seismic data acquisition unit and an extraction vehicle) can be measured using a precise timing control design of the optical data communication link. Figure 1 As shown in FIG. 1 , an optical data communication link transmission path 118 between the OZI of the extraction vehicle 104 and the remote seismic data acquisition unit 102 is extracted.

[0064] The data processing system 106 (or another vessel- or land-based data processing system) can use the optical link to measure the distance between the extraction vehicle 104 (or other OZI location) and the individual seismic data acquisition units 102. For example, the data processing system 106 can couple, synchronize, or resonate the global reference clock 112 with the local master clock 120, and can measure the time delay between a frame clock sent by the seismic data acquisition unit 102 via the transmission path 118 (e.g., from the optical transmitter 114 of the OZI on the extraction vehicle 104) and returned from the optical transmitter 114 of the seismic data acquisition unit 102 to the extraction vehicle 104. From this time delay, and accounting for propagation delays, circuit delays, and other geometric measurements or delay factors along the transmission path 118, the data processing system 106 (or other data processing system) can calculate the distance between the extraction vehicle 104 and the seismic data acquisition unit 118.

[0065] The processor 108 may include, provide, execute or be connected to a link manager agent 202, a main application 204 and a network stack 206. The link manager agent 202 may be designed and configured to initiate, establish or maintain an optical communication link 118 between the first device 102 and the second device 104. The link manager agent 202 may perform a wake-up process or a handshake process to establish a link and verify that the link is transmitting data. The network stack 206 may refer to a protocol stack, such as a computer protocol suite. The network stack 206 may include a software implementation of a protocol definition. The network stack 206 may be divided into different protocols (e.g., HTTP, TCP, IP, Ethernet or IEEE 802.eu) or different layers (e.g., application layer, transport layer, internet / network layer, data link / link layer, or physical layer). The network stack 206 may refer to a combination of hardware and software that implements an Ethernet network protocol (e.g., TCP, IP or UDP). The network stack 206 may implement the sending side of the network used on the link 118. The network stack 206 transforms and converts data from the link manager agent 202 into the requested packet type (e.g., UDP or TCP / IP) for transmission on the link 118. The network stack 206 can receive data packets in a standard form (e.g., UDP or TCP / IP) and pass them to the link manager agent 202.

[0066] The main application 204 is designed to provide functionality to support the operation of the seismic data acquisition device 102. The main application 204 can serve as a software bridge portion of the communication link between the recording system and the operating process of the seismic data acquisition unit. The main application 204 can provide the recording system with access to stored seismic data, self-test results, stored peripheral data (such as pressure, orientation, or battery logs). The main application 204 can respond to commands, such as entering a sleep state, starting seismic data acquisition, or tuning a local master clock. The main application 204 can respond to commands by executing the command or by connecting with one or more other components to facilitate the execution of the command.

[0067] FPGA 110 may include a link delay measurement component 208, a local reference clock generation component 210, a receive control component 212, an automatic negation and link status component 214, a transmit control component 216, a logic gate 218, an 8-bit to 10-bit (8B / 10B) decoder component 220, a frame synchronization component 222, a deserializer component 224, a clock recovery component 226, and an 8B / 10B encoder component 228, a serializer 230 and a transmit PLL 232.

[0068] The link delay measurement component 208 can determine the phase difference between the local master clock 120 and the recovered clock from the clock recovery component 226. This information can be used to determine the time delay between the first device 102 and the second device 104, thereby calculating the distance between them. The generate local reference clock component 210 can provide a clock for the link delay measurement component 208. If the link is running at the required rate, the clock can be a recovered frame clock, or the clock can be generated from the received frame clock. The generate local reference clock component 210 can provide a reference clock and a pulse per second (PPS) signal for resonating and synchronizing the local master clock 120.

[0069] The receive control component 212 may provide special symbol decode indications for aligning or synchronizing the local PPS generation and subsequently synchronizing the PPS of the local master clock 120. The receive control component 212 may provide receive status information and any necessary information for the auto-negotiation phase of link establishment.

[0070] The auto-negotiation and link state component 214 can provide low-level local receiver information used in establishing a link. This low-level link state information can be sent to a paired link manager agent as part of the link establishment protocol.

[0071] The transmit control component 216 can provide symbol encoding of local receiver information, transmission of reference PPS boundaries, and other network controls. Logic gates 218 can allow selection of a desired clock reference for the transmitted bit stream. This can be used for distance measurement mode of the link. The 8B / 10B decoder component 220 can convert the 10-bit received symbol back to the original 8-bit data value. The 8B / 10B encoding technique is one of several encodings that can be used to provide a controlled distribution of 1s and 0s on a digital transmission system that allows the clock to be recovered from the data pattern itself.

[0072] The frame synchronization component 222 can synchronize the local receiver frame boundaries with the boundaries of the transmitted data. This can allow correct symbol extraction and subsequent decoding of the symbols back to the original data. The deserializer component 224 can convert the digital bit stream from serial form to parallel form. For example, the deserializer component 224 can convert a series of 1s and 0s into a 10-bit wide symbol.

[0073] The clock recovery component 226 can extract the transmitted bit clock from the received data stream. The bit clock can be used to digitize the data stream for subsequent evaluation and decoding of the transmitted data. The 8B / 10B encoder component 228 can convert the user's 8-bit wide data values ​​into 10-bit wide symbols, which allows for controlled distribution of 1s and 0s in the transmitted data stream. The serialization component 230 can convert the 10-bit wide symbols into a stream of 1s and 0s for transmission on the link. The transmit PLL component 232 can provide appropriate frame and bit clocks for encoding and transmitting digital data on the link.

[0074] See also Figure 1 and Figure 2 , the link delay measurement component 208 may include controls required to drive the local optical transmitter 114 with a derived received frame clock (e.g., in place of the global reference clock 112 or the local master clock 120) and provide phase measurement functionality. The OZI of the extraction vehicle 104 (or another device) may command the seismic data acquisition unit 102 to switch its transmit frame clock (e.g., derived from the local master clock 120) to instead use its received frame clock (e.g., derived from received data and thus the global reference clock 112) for optical link data transmission via the transmission path 118. The data processing system 106 will then enable the local phase measurement logic and determine the two-way propagation delay. After applying compensation for data transmission speed through water, circuit delays, two-way trip delays, and the physical geometry of the optical communication link, the data processing system 106 may determine the distance between the seismic data acquisition unit 102 and the extraction vehicle 104. The data processing system 106 or another data processing system may refine the distance value using a smoothing function or statistical averaging techniques.

[0075] See also Figure 1 and Figure 2 In some examples, the system 100 may take longer (e.g., several minutes) to resonate or calibrate the clocks of the seismic data acquisition units than to synchronize the clocks (e.g., several seconds). In addition, the drift from the calibrated or resonant state may vary with the operation of the seismic data acquisition units, so that the seismic data acquisition units do not drift (or drift less) when they are in a shutdown, sleep, low power or off state. When the seismic data acquisition units are restarted, they can be restarted in a resonant state. Therefore, in some embodiments, the data processing system 106 resonates or calibrates the frequencies of the seismic data acquisition units after the seismic data acquisition units are deployed and before the seismic data acquisition units enter a low power, shutdown, shutdown or sleep state. The seismic data acquisition units can then be restarted to collect usable seismic data with their respective clocks fully resonated or calibrated prior to data acquisition. The clock frequencies of the respective clocks of the seismic data acquisition units can be synchronized by the data processing system 106 after the restart (or in some examples before shutdown). By resonating the seismic data acquisition unit frequencies before shutdown, the seismic data acquisition units do not need to re-resonate during the re-tracking time at startup. This saves time, as in this example, frequency synchronization at startup is faster than frequency resonance.

[0076] Figure 3 is a block diagram depicting a method for optical link timing and frequency synchronization and resonance. The method 300 may be performed by Figure 1 and 2106, including, for example, system 100, data processing system 106, transmitter 114, receiver 116, global reference clock 112, or local master clock 120. Method 300 may include, at 302, locating a first device. Method 300 may include, at 304, establishing a communication link between the first device and a second device. Method 300 may include, at 306, resonating a component of the first device. Method 300 may include, at 308, commanding the first device to enter a state.

[0077] At 302, method 300 may include positioning a first device. The first device, such as a seismic data acquisition unit, may be positioned on a seabed in a marine environment. In some cases, a second device, such as an extraction vehicle or ROV, may position the first device on the seabed. Method 300 may include positioning one or more devices on the seabed. The seismic data acquisition unit may include a first clock and a first data processing system.

[0078] At 304, method 300 may include establishing a communication link between the first device and the second device. For example, the extraction vehicle may establish an optical communication link with the seismic data acquisition unit. The extraction vehicle may include a second clock and a second data processing system. Establishing the optical communication link may include performing a wake-up procedure, an initialization procedure, a handshake procedure, or a link maintenance procedure.

[0079] The method 300 may include resonating a component of the first device at 306. For example, a data processing system of the first device or the second device may resonate a frequency of a first clock of a seismic data acquisition unit to correspond to a second clock via an optical communication link. The data processing system may synchronize the first clock with the second clock. To resonate or synchronize the first clock, the data processing system may send one or more reference pulses or reference pulses per second based on the second clock. The seismic data acquisition unit may resonate the first clock using the reference pulses per second.

[0080] At 308, method 300 may include commanding the first device to enter a state. For example, the data processing system of the first device may command the data processing system of the seismic data acquisition unit to enter a low power state after resonating the frequency of the first clock.

[0081] Figure 44 is an example chart depicting timing windows for synchronization and resonance. The timing windows may be used by the system 100. The chart 400 includes an x-axis corresponding to time and a y-axis corresponding to mode. Pulse 414 may indicate synchronization, pulse 416 may indicate resonance, and pulse 418 may indicate link data transmission (e.g., seismic or other sensor data transmission on a link). As shown in the chart 400, clock resonance 416 may start at time 402 and last until time 410, at which time resonance is complete. Clock synchronization 414 may start at time 404 and end at time 406, at which time clock synchronization is complete. Data transmission may start at time 408 and last until time 412, at which time data transmission is complete.

[0082] For example, the synchronization clock may take less time than the resonant clock. The resonant clock may take less time than the data transmission. For example, the duration of the synchronization pulse 414 may be less than one second, one second, 1.2 seconds, 1.5 seconds, 1.7 seconds, 2 seconds, 3 seconds, 4 seconds, 5 seconds, or longer. The duration of the resonant pulse 416 may be 15 seconds, 30 seconds, 45 seconds, 60 seconds, 90 seconds, 2 minutes, 3 minutes, 4 minutes, or longer. The duration of the data transmission pulse 418 may be 15 seconds, 30 seconds, 45 seconds, 60 seconds, 90 seconds, 2 minutes, 3 minutes, 4 minutes, or longer.

[0083] During the time window 420, the clock synchronization 414 may overlap with the clock resonance 416. For example, both the clock synchronization 414 and clock resonance 416 processes may be active. During the time window 422, the clock resonance 416 and the data transmission (or link use) 418 may be active. Thus, in some cases, the data transmission 418 may occur after the clock synchronization 414 is completed, but while the clock resonance 416 is still active.

[0084] Figure 5 5 is a diagram depicting timing for synchronization and resonance. Timing can be used by system 100. Graph 500 includes an x-axis corresponding to time and a y-axis corresponding to mode. Pulse 514 can indicate synchronization, pulse 516 can indicate resonance, and pulse 518 can indicate link data transmission (e.g., seismic or other sensor data transmission on the link). As shown in graph 500, clock resonance 516 can start at time 520 and continue until time 502, at which time resonance is completed. Clock synchronization 514 can start at time 504 and end at time 506, at which time clock synchronization is completed. Link data transmission can start at time 508 and continue through time 510 and until time 512, at which time data transmission is completed. Time 510 can indicate the midpoint of data transmission or the second acoustic emission (shot).

[0085] In the example shown in the diagram 500, none of the clock synchronization 514, clock resonance, and data transmission 518 may be active or overlapped during the same time. In this example, the clock synchronization 514 occurs after the clock resonance 516, and the data transmission 518 occurs after the clock synchronization 514.

[0086] In some cases, the system 100 may perform one or more of synchronization, resonance, or data transmission at different times, in different orders, or simultaneously. The synchronization, resonance, or data transmission may overlap, at least partially overlap, or be mutually exclusive.

[0087] Figure 6 is a block diagram depicting a system for calibrating a pressure sensor via an optical link. Figure 6 A system 100 is depicted, which may include at least one first device 102 (e.g., at least one seismic data acquisition unit) and at least one second device 104 (e.g., at least one extraction vehicle, such as an autonomous or remote underwater vehicle, or other device including an OZI). The data acquisition unit 102 and the extraction vehicle 104 may each include at least one processor 108, and at least one field programmable gate array (FPGA) 110 (or other integrated circuit or logic device). The extraction vehicle 104 may include at least one global reference clock 112. For example, the global reference clock 112 may be part of the extraction vehicle 104 (e.g., an autonomous or remote underwater vehicle) that communicates with the seismic data acquisition unit 102 via an optical (or other type of) transmission link 118. The seismic data acquisition unit 102 may include at least one local master clock 120. The local master clock 120 may be present in each seismic data acquisition unit 102 as part of a seismic survey. The seismic data acquisition unit 102 may include at least one local pressure transducer (or other pressure sensor) 140. The extraction vehicle 104 may include at least one reference pressure transducer (or other pressure sensor) 145 .

[0088] The data acquisition unit 102 and the extraction vehicle 104 may include at least one transmitter 114 (e.g., an optical transmitter) and at least one receiver 116 (e.g., an optical receiver). The optical transmitter 114 and the optical receiver 116 may be part of an optical system interface that transmits and receives data between, for example, the seismic data acquisition unit 102 and the extraction vehicle 104 via an optical link 118. The data may include pressure sensor data, pressure sensor data commands, seismic data, clock frequency data, and clock timing data, among other data. For example, the extraction vehicle 104 may transmit pressure data obtained from the reference pressure transducer 140 to the seismic data acquisition unit 102 to replace, calibrate, or adjust pressure data sensed by the local pressure transducer 145.

[0089] The system 100 is capable of synchronizing, calibrating or adjusting pressure sensor data. For example, the extraction vehicle 104 (via the processor 108, FPGA 110 and other components) can send pressure sensor data via the optical transmission link 118 to confirm, change, calibrate or adjust the determined pressure sensed by the local pressure transducer 145. The seismic data acquisition unit 102 can also transmit the pressure data (and other data) to the extraction vehicle 104 via the optical transmission link 118. The synchronized or adjusted pressure data can be used during the interpretation of seismic data to help refine the acoustic velocity model or can be used to help identify reservoir settlement or other purposes. Therefore, the improved pressure data or data collected via a calibrated pressure sensor can improve the quality or accuracy of the data by providing a more accurate sensor depth value, which can produce a relatively higher quality image formed by the seismic data compared to an uncalibrated pressure sensor that provides an inaccurate or less accurate depth measurement.

[0090] The system 100 can provide accurate pressure measurements of or from one or more seismic data acquisition units 102, which are deployed, for example, on the seabed or lakebed. The resolution can be accurate to meters, tens of centimeters, centimeters, or sub-centimeter levels. The local pressure transducer 145 and the reference pressure transducer 140 can operate at underwater depths of hundreds to thousands of meters. The system 100 compensates for pressure measurement drift of the individual local pressure transducers 145 over time by, for example, sending calibration or other pressure data via an optical transmission link 118. For example, to provide information that allows compensation for long-term drift associated with a local pressure transducer 145 that is present on the seabed for a period of time, pressure data from each local pressure transducer 145 (e.g., on a corresponding seismic data acquisition unit 102) can be compared to a known reference, such as pressure data from a reference pressure transducer 140 of the extraction vehicle 104, which can operate at the same or similar depth as the seismic data acquisition unit 102 (e.g., within tens of meters) and at a known or determined distance from the seismic data acquisition unit 102.

[0091] Through the optical transmission link 118, the system 100 can measure the precise distance between the extraction vehicle 104 and the seismic data acquisition unit 102. By incorporating a calibrated pressure reference into the logic device of the extraction vehicle 104, the extraction vehicle 104 can provide time and reference updates to the seismic data acquisition unit 102 via the optical transmission link 118, which can be used to compensate for drift in local pressure measurements made by the local pressure transducer 145. To achieve the reference update, the optical link data transmission provides the precise distance between the extraction vehicle 104 and the seismic data acquisition unit 102, as well as the precise position of the reference pressure transducer 140 and the local pressure transducer 145. The position can include, for example, the position of the reference pressure transducer 140 relative to the local pressure transducer 145. The position can include coordinates in one or more axes, such as x-axis, y-axis, and z-axis coordinates. The position can include position information relative to a point different from the seismic data acquisition unit, such as a fixed reference point or a moving reference point. Fixed or moving reference points may include, for example, points on the sea floor, seismic data acquisition units, underwater vehicles, ships, or other reference points. The position may include rotation information, such as pitch, yaw, or roll. In addition, multiple word readings may be performed to provide sufficient statistical measurements to compensate for the motion associated with the extraction vehicle 104. The distance measurement may be accurate to meters, tens of centimeters, centimeters, or sub-centimeter levels. The system 100 may compensate for angular errors in distance measurements caused by misalignment of the seismic data acquisition unit 102 and the extraction vehicle 104. For example, the system may use a camera to compensate for angular errors to determine the angular position of the seismic data acquisition unit 102 relative to the vehicle 104, such as how the vehicle 104 is centered above the unit 102 (e.g., how centered it is). The system 100 may use multiple receivers to measure the time delay between two received signals and use the time delay to calculate an angular correction for the distance measurement.

[0092] The extraction vehicle 104 may access one or more deployed seismic data acquisition units 102 on the sea floor and establish an optical transmission link 118. The reference pressure transducer 140 may determine the pressure of the extraction vehicle 104. The extraction vehicle 104 may also determine the distance between the extraction vehicle 104 and the seismic data acquisition unit 102. Based on the pressure (at the extraction vehicle 104, from the reference transducer 140) and the distance (e.g., vertical distance) between the extraction vehicle 104 and the seismic data acquisition unit 102, the extraction vehicle's processor 108 may determine what the pressure is at the location of the seismic data acquisition unit 102. The extraction vehicle 104 may provide this information to the seismic data acquisition unit 102 via the optical transmission link 118. The seismic data acquisition unit 102 may then use or record this received pressure information, e.g., as a replacement, alternative, or in addition to the pressure data obtained from the local pressure transducer 145. The seismic data acquisition unit 102 may also recalibrate the local pressure transducer 145 based on this information.

[0093] The extraction vehicle 104 may also obtain pressure data from the local pressure transducer 145 of the seismic data acquisition unit 102 and compare this information to the pressure information of the reference pressure transducer 140 to determine whether the local pressure transducer 145 reading has drifted. The drift may occur at least in part due to the presence of the seismic data acquisition unit 102 on the seabed for an extended period of time (e.g., weeks, months, or longer). This drift value from the true pressure reading may be used to recalibrate, reset, adjust the logic device of the seismic data acquisition unit 102 to replace the pressure data obtained by the local pressure transducer, or may be applied to the acquired seismic data to facilitate data interpretation, such as to make determinations in improving the acoustic velocity model or may be used to help identify reservoir subsidence or other uses.

[0094] With a large number (e.g., tens, hundreds, or thousands) of seismic data acquisition units 102 deployed on the seabed, accurate processing or interpretation of the acquired seismic data may rely on accurate measurements of the depth of the seismic data acquisition units 102. The system 100 may determine the depth of the seismic data acquisition unit based on calibrated one or more pressure values ​​and historical tidal conditions. For example, based on local or seasonal tidal conditions (e.g., low tide or high tide), water pressure, and ambient pressure or atmospheric pressure, the system 100 or another data processing system may determine the accurate depth of an individual local pressure transducer 145 of the seismic data acquisition unit 102. The depth measurement may be accurate to meters, tens of centimeters, centimeters, or sub-centimeter levels. For example, to improve gravity measurement data acquired from a marine environment, the system 100 or other data processing system may correct for the effects of hydrostatic pressure. The accurate pressure measurements obtained by the system 100 allow for such corrections.

[0095] In addition, oil, gas, hydrocarbon or other mineral extracts from reservoirs in the earth can cause sedimentation of the reservoir. For example, sedimentation can cause many different production and ecological problems associated with extraction infrastructure or enclosure structures. In marine environments, accurately measuring the sedimentation of, for example, the seabed may be challenging because the depth accuracy of the seismic data acquisition unit 102 may be required to determine the sedimentation. The system 100 can determine the depth based on the pressure measurements made by the local pressure transducer 145, and these depth measurements can be used to determine the sedimentation at meter, centimeter or sub-centimeter scales. Depth values ​​can also be determined from gravity measurement data.

[0096] Figure 7 is a block diagram depicting a method for calibrating a sensor via an optical link. The method 700 may be performed by Figure 1 , 2 6. The method 700 may include deploying a first device at act 702. At act 704, the method 700 may include establishing a communication link between the first device and the second device. At act 706, the method 700 may include providing reference data. At act 708, the method 700 may include calibrating the first device.

[0097] At act 702, method 700 may include deploying a first device. For example, a seismic data acquisition unit may be located on a sea floor in a marine environment. The seismic data acquisition unit may include a local pressure sensor, an optical transmitter, and an optical receiver. The seismic data acquisition unit may be deployed by an ROV.

[0098] At act 704, method 700 may include establishing a communication link between the first device and the second device. For example, the second device may include an extraction vehicle that includes a reference sensor, an optical transmitter, and an optical receiver. The reference sensor may include, for example, a reference pressure sensor, a reference clock, or a reference temperature sensor. The extraction vehicle may establish an optical communication link with the seismic data acquisition unit.

[0099] At act 706, method 700 may include providing reference data. For example, the extraction vehicle may provide or send reference pressure data to the seismic data acquisition unit via an optical communication link. The extraction vehicle may provide one or more reference pressure data to the seismic data acquisition unit via the optical communication link, including a pressure value, a timestamp corresponding to a pressure value detected by a reference pressure sensor, an indication of a distance between the extraction vehicle and the seismic data acquisition unit, and a position of the reference pressure sensor relative to a local pressure sensor of the seismic data acquisition unit.

[0100] At act 708, method 700 may include calibrating the first device. For example, one or more processors of system 100 may calibrate the local pressure sensor or one or more pressure values ​​measured by the local pressure sensor based on the reference pressure data. In some cases, the seismic data acquisition unit may calibrate the local pressure sensor based on the reference pressure data received from the extraction vehicle. The local pressure sensor may be calibrated based on the reference pressure data providing the one or more pressure values.

[0101] To calibrate the pressure data or pressure sensor, the first device or the second device may determine a plurality of reference pressure values ​​generated by a reference sensor of the second device. The first device or the second device may generate a reference pressure metric based on a statistical technique applied to the plurality of reference pressure values. For example, the reference pressure metric may be an average pressure, a weighted average pressure, a mode pressure value, a median pressure value, or a normalized pressure value. If the second device determines the reference pressure metric, the second device may send the generated reference pressure metric to the first device so that the first device calibrates the local pressure sensor.

[0102] In some cases, the seismic data acquisition unit may calibrate one or more pressure values ​​previously measured by the local pressure sensor to produce one or more calibrated pressure values. For example, the seismic data acquisition unit may record pressure values ​​prior to calibration. During calibration, the seismic data acquisition unit may update the recorded pressure values ​​to reflect the calibrated pressure values. One or more components of the system may calibrate previously recorded pressure values.

[0103] A second device (e.g., an extraction vehicle) can provide reference sensor data based on a distance between the second device and the first device (e.g., a seismic data acquisition unit). The second device can provide reference sensor data corresponding to sensor measurements obtained when the distance between the first device and the second device is within a threshold value (e.g., 3 inches, 6 inches, 12 inches, 2 feet, 3 feet, 6 feet, 8 feet, 10 feet, 15 feet, 20 feet or more). For example, the extraction vehicle can determine the distance between the extraction vehicle and the seismic data acquisition unit. The extraction vehicle can command the reference pressure sensor to obtain reference pressure data based on the distance between the extraction vehicle and the seismic data acquisition unit. For example, the extraction vehicle can command the reference pressure sensor to obtain reference pressure data in response to the distance between the extraction vehicle and the seismic data acquisition unit being less than a threshold value. Once the extraction vehicle is within a communicable distance from the seismic data acquisition unit or once a communication link is established with the seismic data acquisition unit, the extraction vehicle can periodically command the reference pressure sensor to obtain reference pressure data. The extraction vehicle can provide the reference pressure data measured when the distance is less than the threshold value to the seismic data acquisition unit for calibration. By measuring, identifying, detecting or obtaining reference data based on a distance threshold, the system can facilitate calibration of a local sensor of a seismic data acquisition unit. For example, if the distance is greater than the threshold, the reference data may not indicate pressure at the seismic data acquisition unit.

[0104] In some cases, the system may include other types of sensors. The system may be configured to calibrate one or more types of sensors. For example, the seismic data acquisition unit may include a gravity measurement sensor. The system may obtain one or more pressure values ​​calibrated based on reference pressure data determined by the extraction vehicle. The system may determine the depth of the seismic data acquisition unit based on one or more pressure values ​​and historical tidal conditions. The system may determine the depth by taking into account tidal conditions that may affect the pressure detected by the pressure data. Taking into account tidal conditions may include, for example, removing or adjusting the pressure value corresponding to the tidal condition, which may affect the pressure detected by the pressure sensor on the seabed. Then, the system may calibrate the gravity measurement data detected by the gravity measurement sensor based on one or more pressure values. In some cases, the system may determine a settlement value (e.g., collapse, sinking or compaction of the seabed or underground area on which the seismic data acquisition unit is placed) based on at least one of the determined depth or calibrated weight measurement data.

[0105] Figure 8 is a block diagram depicting a method for adjusting a clock or other sensor via an optical link. The method 800 may be performed by Figure 1 , 2or 6. The sensor may include a clock, a pressure sensor transducer, a gravity sensor, or other sensor. Adjusting the sensor may include calibration, synchronization, resonance, or other adjustments. The order in which the system calibrates, synchronizes, resonates, or otherwise adjusts the sensor may improve the efficiency of the adjustment process and the system. For example, method 800 may include turning on a first device (e.g., a seismic data acquisition unit) and preheating a first clock (or other first sensor) at 802. At 804, method 800 includes synchronizing the first clock (or other first sensor) with a second clock of a second device (e.g., an ROV) (or other second sensors of the same sensor type as the first sensor). At 806, method 800 includes the first device collecting or detecting data. At 808, method 800 includes the second device collecting the collected data from the first device, and adjusting the first clock. At 810, method 800 includes turning off the first clock.

[0106] The order in which the system synchronizes, resonates, or otherwise calibrates the clock can improve the efficiency of the calibration process. For example, calibrating (or resonating) a local clock may take on the order of a minute or several minutes, while synchronizing the clock may take less than 2 or 3 seconds. Since the drift from calibration is a function of operation, the clock may not drift as much when it is shut down compared to the amount of drift when the clock is running. After the clock is shut down, it may take a few seconds for the clock to warm up before the clock can operate normally and reliably. Based on this, the systems and methods of the present disclosure can improve the synchronization and calibration process to make it more efficient.

[0107] To improve the efficiency of the clock synchronization and calibration process, the first device may turn on and preheat the clock at 802. Preheating the clock may take a predetermined amount of time, such as 1 second, 2 seconds, 3 seconds, 10 seconds, 30 seconds, 1 minute, or more. In some cases, the system may detect when the clock is preheated based on the temperature of the clock or the performance of the clock (e.g., the oscillation frequency of the clock is stable within a tolerance of 2 cycles per second).

[0108] At 804, the first device may synchronize a clock with the second device and project a time drift for the clock based on the model. The projected time drift (e.g., a time variation function) may be a function of time, temperature, or other environmental parameters. For example, the time variation function may indicate a drift of one or more cycles per unit time (e.g., one or more cycles per minute, one or more cycles per 2 minutes, one or more cycles per 5 minutes, one or more cycles per hour, or one or more cycles per day) based on the current temperature.

[0109] At 806, the first device may then begin collecting seismic data. For example, an acoustic source may emit an acoustic signal that may be reflected from an underground lithologic formation. The first device may include a seismic detector to receive the reflected acoustic signal, which may be referred to as seismic data. Depending on the type of sensor, the first device may collect other types of data, such as pressure data. The first device may apply a model of the expected time drift of the clock to the collected data to correct the timestamps in the collected data. For example, the first clock may drift in frequency from the beginning of seismic data collection to the end of seismic data collection. The first device may apply the correction model to the collected data or apply it while the data is being collected and recorded. For example, when detecting and recording the sample, the first device may adjust or correct the timestamp corresponding to the seismic data sample.

[0110] At 808, the second device may collect data collected by the first device from the first device. At 808, the second device may also adjust the first clock of the first device. For example, the second device may include an ROV that is sent down to collect data from a seismic data acquisition unit (e.g., the first device). Since collecting seismic data may take several minutes, the ROV may adjust, synchronize, resonate, or otherwise calibrate the first clock while collecting seismic data to save resources (e.g., time, energy, battery power, or other resource utilization). The collection of data by the ROV from the seismic data acquisition unit may at least partially overlap with calibration or resonance. Since the resonance of the clock may take several seconds or minutes, the system may improve the efficiency of the overall clock calibration by performing the resonance while collecting data (which may also take several seconds or minutes).

[0111] At 810, the first device may shut down or turn off the first clock. For example, after the ROV collects data and calibrates the first clock on the seismic data acquisition unit, the seismic data acquisition unit may shut down, enter a standby mode, or enter a low power mode. One or more components of the seismic data acquisition unit may shut down, enter a standby mode, or enter a low power mode. For example, the clock may shut down or enter a standby mode to reduce or minimize the amount of frequency drift compared to the amount of frequency drift when the clock is running. The system may repeat the process of blocks 802-810 for one or more seismic data acquisition units on the seabed.

[0112] Fig. 9 It is based on the description Figure 8900. As shown in the graph 900, pulse 922 indicates when the clock (or other sensor) is warmed up. The warming up may start at time 902 and complete at time 904. Pulse 924 indicates the synchronization of the clock. The clock may start the synchronization process at time 906 and complete the synchronization at time 908. For example, the ROV may approach the clock to synchronize the clock during the time interval 906 to 908. After the synchronization 924 is completed at time 906, the ROV may move itself away from the clock, or return to the marine vessel.

[0113] During the time interval 910 to 912, a seismic data acquisition unit including a clock can acquire data 926, for example, a shot source can emit acoustic signals reflected from various underground features, and seismic data can record these reflected signals. After the seismic data acquisition is completed at time 912, the ROV can approach the seismic data acquisition unit to start collecting data at 930 or calibrating the clock at 928, or both. Calibration 928 can start first, or data collection 930 can start first. Calibration 928 can overlap with data collection 930. In some cases, clock calibration (e.g., synchronization or resonance) can start at time 914 and be completed at time 918. In some cases, data collection can start at time 916 and be completed at time 920. Data collection can end before or after calibration is completed. For example, by separating synchronization and resonance, the system can improve operational efficiency because the distance between the seismic data acquisition unit and the ROV can be used to perform synchronization.

[0114] Fig.10 A cross-section of a portion of an apparatus 1000 associated with a seismic survey is depicted. The apparatus 1000 may include a seismic data acquisition unit (e.g., Figure 1 102) or a pick-up vehicle (e.g., Figure 1104). For example, the device 1000 including the seismic data acquisition unit may have at least one receiver window 1005 disposed in the cover 1010 on the top surface 1015 of the seismic data acquisition unit. The top surface 1015 is generally the surface that faces upward toward the surface of the body of water when the seismic data acquisition unit is disposed on the seabed or other surface of the earth. The device 1000 may also include at least one transmitter window 1020 disposed in the cover 1010. The receiver window 1005 and the transmitter window 1020 may also be disposed in other areas of the device 1000, such as in the sidewalls, or in the case of an extraction vehicle, on the bottom surface, so that the windows face downward toward the seismic data acquisition unit disposed on the seabed during operation. The device 1000 may include at least one seal 1025 located at the transmitter window 1020. The at least one seal 1025 may include an O-ring (or other gasket, radial, backer, or mechanical seal). The device 1000 may include at least one seal 1027 at the receiver window. At least seal 1027 may include an O-ring (or other gasket, radial, liner or mechanical seal).

[0115] The device 1000 may include a first gasket 1045 between the transmitter window 1020 and the first hole 1070. The first gasket 1045 may provide a gap greater than a threshold between the transmitter window 1020 and the first hole 1070 to allow the transmitter window 1020 to move, deform, expand, or contract under pressure to reduce shock and cracking of the transmitter window 1020. The device 1000 may include a second gasket 1035 between the receiver window 1005 and the second hole 1060, which provides a gap greater than a threshold to allow the receiver window 1005 to move, deform, expand, or contract under pressure to reduce shock and cracking of the receiver window 1005.

[0116] At least a portion of the second pad 1035 located at the receiver window 1005 can be supported by the support 1040. At least a portion of the first pad 1045 located at the emitter window 1020 can be supported by the support 1050. The central area 1055 of the receiver window 1005 can be disposed above the hole 1060 or on top of the hole 1060. The central area 1065 of the emitter window 1020 can be disposed above the hole 1070 or on top of the hole 1070. At least one receiver 1075 (e.g., an optical receiver) can receive optical transmissions entering the device 1000 that pass through the central area 1055 of the receiver window 1005 and the hole 1060. At least one emitter (e.g., an optical emitter) 1080 can emit optical transmissions that pass through the hole 1070, through the central area 1065 of the emitter window 1020, and out of the device 1000 into a fluid medium such as water. The device 1000 can include a housing 1085. The housing may at least partially support the support 1040 or the support 1050 at a contact point 1090. The contact point 1090 may include a metal-to-metal (or other material) contact between the support 1040 (or the support 1050) and the housing 1085.

[0117] See especially Fig.10 , Fig.11 and Fig.12 , the contact point between the support 1040 (or support 1050) and the housing 1085 can be less than or reduced relative to the contact point between the second gasket 1035 and the receiver window 1005, or the contact point between the first gasket 1045 and the transmitter window 1020. For example, the gasket 1035 can avoid metal-to-metal contact. The gasket 1035 can include a nylon gasket or other material. The gasket 1035 can be disposed between the bottom or inner surface of the receiver window 1005 and the support 1040. The gasket 1035 can also be disposed between the bottom or inner surface of the transmitter window 1020 and the support 1050. Fig.12 1005, the outer surface 1092 of the cover 1010, and the outer surface 1093 of the emitter window 1020 can be flush or coplanar. The gasket 1035 can physically touch or contact the receiver window 1005 and the support 1040. Another gasket 1045 can physically touch or contact the emitter window 1020 and the support 1050.

[0118] Fig.12Receiver window 1005 is depicted sealed by seal 1025 (e.g., O-ring) and engaged or in contact with lid 1010. Transmitter window 1020 may have a similar construction with seal 1027. Lid 1010 (e.g., top of seismic data acquisition unit) may include at least one lip 1205. Receiver window 1005 may include chamfer 1210. Chamfer 1205 may be configured to avoid interference with a seal of receiver window 1005 (or transmitter window 1020) during installation of receiver window 1005 or transmitter window 1020 into lid 1010 or coupling of receiver window 1005 or transmitter window 1020 with lid 1010.

[0119] The device 1000 may include an optically transparent window that can transmit optical (or other) data transmission in a high-pressure environment, such as on the seabed or at or near the bottom of the water column. The systems and methods described herein provide optically transparent windows 1005, 1020 in the device 1000 for, for example, optical (or other) data communication link transmission between a seismic data acquisition unit and an extraction vehicle. In this example, each of these devices may include windows 1005, 1020. The device 1000 may be subjected to high-pressure conditions, such as on the seabed hundreds, thousands or more feet below the water surface. The windows 1005, 1020 may provide transmittance at an appropriate wavelength (e.g., 400-550nm or another range) for light transmission. For example, light transmission may occur at a wavelength of substantially (e.g., + / -10%) 405nm or substantially (e.g., + / -10%) 450nm. The windows 1005, 1020 may also provide the necessary mechanical strength to maintain their integrity under high-pressure conditions. The windows 1005, 1020 may be made of, for example, industrial sapphire. The windows 1005, 1020 may be back mounted into the cover 1010 and sealed with an O-ring 1025 during assembly of the device 1000, sufficient to handle seabed pressure conditions. This mechanical mounting solution takes into account the brittleness of sapphire (or other material) relative to the material of the cover and housing, such as aluminum (or other material).

[0120] The structural arrangement of the windows 1005, 1020 in the cover 1010 can result in a flush or coplanar outer surface of the device 1000 (e.g., the top of a seismic data acquisition unit or the bottom of an extraction vehicle). Such flush or coplanar surfaces can minimize cracks or protrusions on the device 1000 and can prevent the accumulation of particles and marine growth. On the seismic data acquisition unit or other device 1000, the flushness between the outer surface 1091 of the receiver window 1005, the outer surface 1092 of the cover 1010, and the outer surface 1093 of the transmitter window 1020 can allow for a suction-based system for deployment of the seismic data acquisition unit. For example, a suction device can be attached to the top surface of the seismic data acquisition unit to move the unit, for example, from a first position to a second position on a ship, or from a storage basket or tray to the seabed in the water column. The flushness of the top surface can prevent suction-based seals from slipping, not sealing, or loosening.

[0121] The cover 1010 may include at least one pocket or open area into which the window 1005, 1020 may be inserted during assembly of the device 1000. The combination of the lip 1205 and the mating features (e.g., protrusions) of the window 1005, 1020 may retain the window 1005, 1020 in the pocket of the cover 1010 and allow installation from the rear (e.g., back or interior) of the cover 1010. A seal 1025 or 1027, such as a radial seal or an O-ring, may seal the window 1005, 1020, respectively, about the cover 1010 without requiring mounting hardware and may create friction sufficient to inhibit the window 1005, 1020 from moving out of position during installation. A chamfer 1210 at the edge of the window 1005, 1020 below the lip 1205 accommodates the use of the O-ring 1025. Chamfer 1210 allows windows 1005 , 1020 to be installed without rolling or interfering with seal 1025 or 1027 .

[0122] The gasket between the window 1005, 1020 and the lid 1010 (or similar element on the extraction vehicle) can accommodate external high pressures while eliminating aluminum (or other material) impacts that may cause cracking or shattering of the window 1005, 1020. For example, the gap can be greater than normal manufacturing tolerances, such as 0.001 inches, 0.002 inches, 0.003 inches, 0.004 inches, 0.005 inches, 0.007 inches, 0.008 inches, or 0.009 inches or more. This allows the lid 1010 and surrounding structures to move or float under high pressures such as those found at ocean depths without compromising the seal formed by the windows 1005, 1020, gaskets 1035 or 1045, or O-rings 1025. This also allows the ocean pressure to be equalized around the lid lip 1205, which can minimize movement of the lip 1205.

[0123] Thus, the gaskets 1035 and 1045 between the windows 1005, 1020 and the cover 1010, respectively, can provide a floating feature for the cover 1010 and the surrounding structure. For example, the floating feature can refer to an internal structure (e.g., a window or sapphire window) that is not rigidly or firmly fixed in a surrounding structure (e.g., a frame or metal frame). Instead, the window can be held in place with a gasket assembly. The gasket 1035 or 1045 may include a mechanical seal that fills a space between two or more mating surfaces or structures (e.g., an internal structure and a surrounding structure). The gaskets 1035 and 1045 can be compressible or subject to deformation. The gaskets 1035 and 1045 can be compressed or deformed at a rate or amount different from the surrounding structure or at different pressures or at different temperatures. The rate of deformation can refer to the amount of deformation based on a specific pressure or temperature. The gaskets 1035 and 1045 can be more compressible than structures such as the window itself or a metal frame surrounding the window. The surrounding structures such as window 1005 or 1020 and the metal frame forming the cover 1010 can be less compressible than the gasket, although they may experience some compression or deformation at certain depths due to pressure or temperature. Different structures can be compressed at different rates relative to each structure. For example, if the cover 1010, the window 1005 or 1020 can be compressed or deformed at a different rate or by a different amount than the metal frame. Since this difference in compressibility may cause the surrounding structure (e.g., the metal frame of the cover 1010) to compress faster than the internal structure (e.g., sapphire window 1005 or 1020), the combined force applied by the surrounding structure to the internal structure may cause the internal structure to rupture. By floating the internal structure with the gasket 1035 or 1045, when the gasket is compressed, the gasket 1035 or 1045 can absorb the increased compression of the surrounding structure without applying excessive force on the internal structure, thereby preventing the internal structure from rupturing. Therefore, floating the window can prevent the impact of the surrounding materials.

[0124] The device 1000 can provide structural support for the windows 1005, 1020 over an opening in the housing 1085 that is larger than the diameter of the windows. The supports 1040, 1050 below the windows can be sized to reduce contact stresses on the windows 1005, 1020 and transfer those stresses to the smaller metal frame (e.g., at the contact point 1090). A pad 1035 (e.g., a nylon pad) can be placed below the bottom surface of the windows 1005, 1020 to provide a thin layer of ductile material (e.g., on top of the supports 1040, 1050) that can mask the surface roughness of the metal and make the contact stresses more uniform over the area between the windows 1005, 1020 (e.g., at the pads 1035, 1045).

[0125] The windows 1005, 1020 and the cover 1010 can be substantially (e.g., + / - 10%) 0.5 inches thick. In some embodiments, the cover 1010 is thicker than the windows 1005, 1020. For example, the cover 1010 can be 0.5 inches thick and the windows 1005, 1020 can be 0.48 inches thick. The receiver window 1005 can have a larger diameter than the transmitter window. For example, the receiver window 1005 can have a diameter of substantially (+ / - 10%) 3 inches, and the transmitter window 1020 can have a diameter of substantially (+ / - 10%) 1 1 / 8 inches. For example, the diameter of the receiver window 1005 can be 3 inches, with the two center inches (e.g., a one inch radius from the center point) forming the center region 1055, and the outer 1 / 2 inch of the receiver window 1005 forming the peripheral region 1035. The transmitter window 1020 can be similarly arranged in proportion. In some examples, at their closest points on device 1000, receiver window 1005 and transmitter window 1020 may be separated by 1 inch, + / - 10%, with a portion of cover 1010 separating windows 1005, 1020. Cover 1010 may have a diameter of 19 inches (+ / - 10%) or another diameter greater or less than 10 inches. These dimensions are all examples, and other dimensions greater or less than these dimensions are possible.

[0126] Fig.13Method 1300 is shown. Method 1300 can be part of a seismic data acquisition method associated with seismic surveying. Method 1300 can include providing a seismic data acquisition unit (action 1305). The seismic data acquisition unit can include the device 1000 described herein, and can have a transmitter window disposed in a first hole of a cover, and a receiver window disposed in a second hole of the cover. Method 1300 can also include providing an extraction vehicle (action 1310). The extraction vehicle can include the device 1000 described herein, and can have at least one of a transmitter window and a receiver window. Method 1300 can include transmitting optical or electromagnetic communications between the seismic data acquisition unit and the extraction vehicle via at least one of a transmitter window and a receiver window of the seismic data acquisition unit and a transmitter window and a receiver window of the extraction vehicle (action 1315). For example, the seismic data acquisition unit and the extraction vehicle can establish an optical (or other) data communication link. Data sent via the link can pass through windows 1005, 1020 of the respective devices 1000. Method 1300 may include transmitting optical or electromagnetic communications to or from the extraction vehicle via at least one of a transmitter window and a receiver window of the extraction vehicle, via at least one of a transmitter window and a receiver window of a seismic data acquisition unit.

[0127] In some cases, at act 1305, method 1300 may include providing a seismic data acquisition unit having a transmitter window disposed in a first hole of the cover, and a receiver window disposed in a second hole of the cover. Method 1300 may include providing an interface between the transmitter window and the first hole, the interface including a gasket configured to seal the transmitter window and provide a gap greater than a threshold value to allow the transmitter window to move under pressure to reduce shock and cracking of the transmitter window. The method 1300 may include providing an interface between the receiver window and the second hole, the interface including a gasket configured to seal the receiver window and provide a gap greater than a threshold value to allow the receiver window to move under pressure to reduce shock and cracking of the receiver window.

[0128] Fig.14 is an isometric schematic diagram of an example of seismic operations in deep water facilitated by a first marine vessel 5 . Fig.14 is a non-limiting illustrative example of a marine environment in which the systems and methods of the present disclosure may perform seismic surveys or calibrate geophone and hydrophone pairs.

[0129] As an example, Fig.14A first vessel 5 is shown positioned on the surface 10 of a water column 15 and includes a platform 20 supporting operational equipment. At least a portion of the platform 20 includes space for a plurality of sensor equipment racks 90 in which seismic sensor equipment (e.g., first equipment 102) is stored. The sensor equipment racks 90 may also include data acquisition equipment or sensor recharging equipment.

[0130] The platform 20 also includes one or more cranes 25A, 25B attached thereto to facilitate the transfer of at least a portion of operating equipment, such as ROV (e.g., second equipment 104) or seismic sensor equipment to the water column 15 from the platform 20. For example, the crane 25A connected to the platform 20 is configured to lower and raise the ROV 35A, which transmits and positions one or more sensor equipment 30 on the seabed 55. The seabed 55 may include a lakebed 55, a seabed 55, or a ground 55. The ROV 35A is connected to the first ship 5 by a tether 46A and an umbilical cable 44A, and the umbilical cable 44A provides power, communication, and control to the ROV 35A. A tether management system (TMS) 50A is also connected between the umbilical cable 44A and the tether 46A. The TMS 50A can be used as an intermediate underground platform from which the ROV 35A is operated. For most ROV 35A operations at or near seafloor 55, TMS 50A may be positioned approximately 50 feet above seafloor 55 and tether 46A may be paid out as needed to allow ROV 35A to move freely above seafloor 55 to position and transport seismic sensor devices 30 thereon.

[0131] The crane 25B may be coupled to the stern of the first vessel 5 or other location on the first vessel 5 (e.g., by latches, anchors, nuts and bolts, screws, suction cups, magnets, or other fasteners). Each of the cranes 25A, 25B may be any lifting device or launch and recovery system (LARS) suitable for operation in a marine environment. The crane 25B may be coupled to the seismic sensor delivery device 100 by a cable 70. The delivery device 100 may be a drone, a skid structure, a basket, or any device capable of accommodating one or more sensor devices 30 therein. The delivery device 100 may be a structure configured as a warehouse suitable for accommodating and transporting one or more sensor devices 30. The delivery device 100 may include an onboard power supply, a motor or gearbox, or a propulsion system 105. The delivery device 100 may be configured as a sensor device storage rack for transferring the sensor device 30 from the first vessel 5 to the ROV 35A, and transferring it from the ROV 35A to the first vessel 5. The delivery device 100 may include an onboard power supply, a motor or gearbox, or a propulsion system 105. Alternatively, the conveyor 100 may not include any integrated power plant, or may not require any external or internal power source. The cable 70 may provide power or control for the conveyor 100. Alternatively, the cable 70 may be an umbilical cord, tether, rope, line, rope, etc. that is only configured to support the conveyor 100.

[0132] ROV 35A may include a seismic sensor device storage compartment 40 configured to store one or more seismic sensor devices 30 (e.g., first device 102) therein for deployment or retrieval operations. Storage compartment 40 may include a warehouse, a rack, or a container configured to store seismic sensor devices. Storage compartment 40 may also include a conveyor, such as a movable platform with seismic sensor devices thereon, such as a turntable or a linear platform, which is configured to support and move seismic sensor devices 30 therein. Seismic sensor devices 30 may be deployed on seabed 55 and retrieved therefrom by operation of the movable platform. ROV 35A may be positioned at a predetermined position above or on seabed 55, and seismic sensor devices 30 may be rolled, conveyed, or otherwise moved out of storage compartment 40 at a predetermined position. Seismic sensor devices 30 may be deployed and retrieved from storage compartment 40 by a robotic device 60 (e.g., a robotic arm, an end effector, or a manipulator) disposed on ROV 35A.

[0133] The seismic sensor device 30 may be referred to as a seismic data acquisition unit 30 or a node 30 or a first device 102. The seismic data acquisition unit 30 may record seismic data. The seismic data acquisition unit 30 may include one or more of at least one seismic detector, at least one hydrophone, at least one power source (e.g., battery, external solar panel), at least one clock, at least one inclinometer, at least one environmental sensor, at least one seismic data recorder, at least one global positioning system sensor, at least one wireless or wired transmitter, at least one wireless or wired receiver, at least one wireless or wired transceiver, or at least one processor. The seismic sensor device 30 may be a stand-alone unit such that all electronic connections are within the unit, or one or more components may be external to the seismic sensor device 30. During recording, the seismic sensor device 30 may operate in an independent manner such that the node does not require external communication or control. The seismic sensor device 30 may include a plurality of seismic detectors and hydrophones configured to detect acoustic waves reflected by underground lithologic formations or hydrocarbon deposits. The seismic sensor device 30 may also include one or more seismic detectors configured to vibrate the seismic sensor device 30 or a portion of the seismic sensor device 30 to detect the degree of coupling between the surface of the seismic sensor device 30 and the ground surface. One or more components of the seismic sensor device 30 may be attached to a gimbaled platform having multiple degrees of freedom. For example, a clock may be attached to a gimbaled platform to minimize the effects of gravity on the clock.

[0134] For example, in a deployment operation, a first plurality of seismic sensor devices including one or more sensor devices 30 may be loaded into the storage compartment 40 while on the first vessel 5 in a pre-loading operation. The ROV 35A with the storage compartment connected thereto is then lowered to a subsurface location in the water column 15. The ROV 35A is operated along a route using commands from personnel on the first vessel 5 to transfer the first plurality of seismic sensor devices 30 from the storage compartment 40 and deploy the individual sensor devices 30 at selected locations on the seabed 55. Once the storage compartment 40 is depleted of the first plurality of seismic sensor devices 30, the transfer device 100 is used to deliver a second plurality of seismic sensor devices 30 as a payload from the first vessel 5 to the ROV 35A.

[0135] The transfer system 100 may be preloaded with a second plurality of seismic sensor devices 30 while on or near the first vessel 5. When the appropriate number of seismic sensor devices 30 are loaded onto the transfer device 100, the transfer device 100 may be lowered by the crane 25B to a selected depth in the water column 15. The ROV 35A and the transfer device 100 cooperate at an underground location to allow the second plurality of seismic sensor devices 30 to be transferred from the transfer device 100 to the storage compartment 40. When the transfer device 100 and the ROV 35A cooperate, the second plurality of seismic sensor devices 30 contained in the transfer device 100 are transferred to the storage compartment 40 of the ROV 35A. Once the storage compartment 40 is reloaded, the ROV 35A and the transfer device 100 are disassembled or uncoupled, and the seismic sensor device arrangement performed by the ROV 35A may be resumed. Reloading of the storage compartment 40 may be provided while the first vessel 5 is in motion. If transport apparatus 100 is empty after transporting the second plurality of seismic sensor devices 30, transport apparatus 100 may be raised to vehicle 5 by crane 25B, wherein a reloading operation replenishes transport apparatus 100 with a third plurality of seismic sensor devices 30. Transport apparatus 100 may then be lowered to a selected depth while reloading storage compartment 40. This process may be repeated until the desired number of seismic sensor devices 30 have been deployed.

[0136] Reloading the ROV 35A at the underground location using the transfer device 100 reduces the time or "planting" time required to place the seismic sensor device 30 on the seabed 55, because the ROV 35A is not raised and lowered to the surface 10 for reloading the seismic sensor device. The ROV 35A can synchronize the clock of the node 30 at the planting time. In addition, since the ROV 35A can run for a longer period of time below the surface 10, the mechanical stress set on the equipment used to lift and lower the ROV 35A is minimized. The reduced lifting of the ROV 35A may be particularly advantageous in bad weather or bad sea conditions. Therefore, the life of the equipment can be enhanced because the ROV 35A and related equipment are not raised above the surface 10, which may cause the ROV 35A and related equipment to be damaged, or cause the risk of injury to the vehicle personnel.

[0137] Likewise, in a retrieval operation, the ROV 35A can collect each seismic sensor device 30 previously placed on the seabed 55 using commands from personnel on the first vessel 5, or collect data from the seismic sensor device 30 without retrieving the device 30. The ROV 35A can adjust the clock of the device 30 while collecting seismic data. The retrieved seismic sensor device 30 is placed in the storage compartment 40 of the ROV 35A. In some embodiments, the ROV 35A can be sequentially positioned near each seismic sensor device 30 on the seabed 55, and the seismic sensor device 30 is rolled, transported, or otherwise moved from the seabed 55 to the storage compartment 40. The seismic sensor device 30 can be retrieved from the seabed 55 by a robotic device 60 disposed on the ROV 35A.

[0138] Once the storage compartment 40 is filled or contains a predetermined number of seismic sensor devices 30, the transfer device 100 is lowered to a position below the surface 10 and engaged with the ROV 35A. The transfer device 100 can be lowered to a selected depth in the water column 15 by the crane 25B, and the ROV 35A and the transfer device 100 are engaged at the underground location. Once engaged, the retrieved seismic sensor devices 30 contained in the storage compartment 40 are transferred to the transfer device 100. Once the storage compartment 40 is exhausted of retrieved sensor devices, the ROV 35A and the transfer device 100 are disassembled and the sensor device retrieval by the ROV 35A can be resumed. Thus, the transfer device 100 is used to transport the retrieved seismic sensor devices 30 as a payload to the first vessel 5, allowing the ROV 35A to continue collecting seismic sensor devices 30 from the seabed 55. In this way, the sensor device retrieval time is significantly reduced due to the ROV 35A not being raised and lowered for sensor device unloading. Furthermore, because the ROV 35A may be underground for extended periods of time, safety issues and mechanical stress on equipment associated with the ROV 35A are minimized.

[0139] For example, the first vessel 5 may travel in a first direction 75, such as in a +X direction, which may be a compass direction or other linear or predetermined direction. The first direction 75 may also take into account or include drift caused by waves, current (one or more), or wind speed and direction. The plurality of seismic sensor devices 30 may be placed on the seabed 55 at selected locations, such as a plurality of rows Rn (R1 and R2 are shown) in the X direction or columns Cn (C1-Cn are shown) in the Y direction, where n is equal to an integer. The rows Rn and columns Cn may define a grid or array, where each row Rn (e.g., R1-R2) includes a receiver line for the width of the sensor array (X direction), or each column Cn includes a receiver line for the length of the sensor array (Y direction). The distance between adjacent sensor devices 30 in a row is shown as a distance LR, and the distance between adjacent sensor devices 30 in a column is shown as a distance LC. Although a substantially square pattern is shown, other patterns may be formed on the seabed 55. Other patterns include non-linear receiver lines or non-square patterns. The pattern(s) may be predetermined or result from other factors, such as the topography of the seabed 55. The distances LR and LC may be substantially equal and may include dimensions between about 60 meters and about 400 meters, or greater. As described above, the distance between adjacent seismic sensor devices 30 may be predetermined or result from the topography of the seabed 55.

[0140] The first vessel 5 operates at a certain speed, such as an allowable or safe speed, to operate the first vessel 5 and any equipment towed by the first vessel 5. The speed may take into account any weather conditions, such as wind speed and wave action, and currents in the water column 15. The speed of the vehicle may also be determined by any operating equipment suspended from, attached to, or otherwise towed by the first vessel 5. For example, the speed may be limited by the drag coefficient of the components of the ROV 35A, such as the TMS 50A and the umbilical line 44A, and any weather conditions or currents in the water column 15. Since the components of the ROV 35A are subject to resistance according to the depth of the components in the water column 15, the first vehicle speed may be operated in a range of less than about 1 knot. In an example where two receiver lines (rows R1 and R2) are laid, the first vehicle includes a first speed between about 0.2 knots and about 0.6 knots. In some embodiments, the first speed includes an average speed of about 0.25 knots (including intermittent speeds less than 0.25 knots) and a speed greater than about 1 knot, depending on weather conditions such as wave action, wind speed, or current in the water column 15.

[0141] During a seismic survey, a receiver line, such as row R1, can be deployed. When a single receiver line is completed, a second ship 80 can be used to provide a source signal. In some cases, a first vehicle or other device can provide a source signal. The second ship 80 is provided with a source device or an acoustic source device 85, which can be a device capable of generating an acoustic signal or a vibration signal suitable for obtaining survey data. The source signal propagates to the seabed 55, and a portion of the signal is reflected back to the seismic sensor device 30. The second ship 80 may be required to pass through each single receiver line (row R1 in this example) multiple times, such as at least four times. During the time when the second ship 80 passes through, the first ship 5 continues the deployment of the second receiver line. However, the time involved in passing by the second ship 80 is much shorter than the deployment time of the second receiver line. When the second ship 80 remains idle while the first ship 5 completes the second receiver line, this results in a lag time in the seismic survey.

[0142] The first vessel 5 can use one ROV 35A to lay down the sensor equipment to form the first set of two receiver lines (rows R1 and R2) in any number of columns, which can produce up to and including several miles of length for each receiver line. The two receiver lines (rows R1 and R2) can be substantially parallel (e.g., within + / - 10 degrees). When the one-way pass of the first vessel 5 is completed and the first set of seismic sensor equipment 30 (rows R1, R2) is laid down to a predetermined length, a second vessel 80 provided with a source device 85 is used to provide a source signal. The second vessel 80 can make eight or more passes along the two receiver lines to complete the seismic survey of the two rows R1 and R2.

[0143] As the second vessel 80 reflects along the two rows R1 and R2, the first vessel 5 can turn 180 degrees and travel in the X direction to place the seismic sensor devices 30 in two additional rows adjacent to the rows R1 and R2. A second set of two receiver lines is thereby formed. The second vessel 80 can then make another series of passes along the second set of receiver lines while the first vessel 5 turns 180 degrees to travel in the +X direction to lay another set of receiver lines. This process can be repeated until a designated area of ​​the seabed 55 has been surveyed. Thus, the idle time of the second vessel 80 is minimized because the deployment time for laying receiver lines is reduced to approximately half by deploying two rows in one pass of the vehicle 5.

[0144] Although only two rows R1 and R2 are shown, the sensor device 30 layout is not limited to this configuration, as the ROV 35A can be adapted to arrange more than two rows of sensor devices in a unidirectional tow. For example, the ROV 35A can be controlled to arrange between three and six rows of sensor devices 30, or to arrange a greater number of rows in a unidirectional tow. The width of the "one-pass" travel of the first vessel 5 to arrange the width of the sensor array can be limited by the length of the tether 46A or the spacing (distance LR) between the sensor devices 30.

[0145] Any reference to an embodiment or element or action of the systems and methods herein mentioned in the singular may include embodiments including a plurality of such elements, and any reference to any embodiment or element or action herein in the plural may include embodiments including only a single element. References in the singular or plural are not intended to limit the currently disclosed systems or methods, their components, actions or elements to a single or multiple configuration. References to any action or element based on any information, action or element may include embodiments in which the action or element is based at least in part on any information, action or element.

[0146] Any embodiment disclosed herein may be combined with any other embodiment, and references to "an embodiment," "some embodiments," "alternative embodiments," "various embodiments," "one embodiment," etc. are not necessarily mutually exclusive and are intended to indicate that a particular feature, structure, or characteristic described in connection with an embodiment may be included in at least one embodiment. These terms as used herein do not necessarily all refer to the same embodiment. Any embodiment may include or be exclusively combined with any other embodiment in any manner consistent with the aspects and embodiments disclosed herein.

[0147] References to "or" may be interpreted as inclusive, such that any term described using "or" may indicate any occurrence of a single, more than one, and all of the described terms. References to at least one of a joint list of terms may be interpreted as inclusive OR to indicate any occurrence of a single, more than one, and all of the described terms. For example, references to "at least one of 'A' and 'B'" may include only "A," only "B," and both "A" and "B." Elements other than "A" and "B" may also be included.

[0148] Where technical features in the drawings, detailed description or any claims are followed by reference signs, the reference signs are included to increase the intelligibility of the drawings, detailed description and claims. Therefore, neither the reference signs nor their absence will have any limiting effect on the scope of any claim element.

[0149] The systems and methods described herein may be embodied in other specific forms without departing from their characteristics. The foregoing embodiments are illustrative rather than limiting of the described systems and methods. Accordingly, the scope of the systems and methods described herein is indicated by the appended claims rather than the preceding description, and changes that fall within the meaning and range of equivalents of the claims are included therein.

Claims

1. A system for performing seismic survey, comprising: a seismic data acquisition unit having a transmitter window disposed in the first aperture of the cover and having a receiver window disposed in the second aperture of the cover; a first gasket positioned between the emitter window and the first aperture to provide a gap greater than a threshold value to allow deformation of the emitter window; a second gasket positioned between the receiver window and the second aperture to provide a gap greater than a threshold value to allow deformation of the receiver window; and At least one of the transmitter window and the receiver window of the seismic data acquisition unit is configured to transmit at least one of optical and electromagnetic communications to or from the extraction vehicle via at least one of the transmitter window and the receiver window of the extraction vehicle.

2. The system of claim 1, comprising: The extraction vehicle has a transmitter window disposed in a first aperture of the extraction vehicle and has a receiver window disposed in a second aperture of the extraction vehicle; a third gasket positioned between the extraction vehicle launcher window and the extraction vehicle first aperture to provide a gap greater than a threshold value to allow the extraction vehicle launcher window to deform under pressure to reduce impact and fracture of the extraction vehicle launcher window; and and a fourth gasket positioned between the extraction vehicle's receiver window and the extraction vehicle's second aperture to provide a gap greater than the threshold value, thereby allowing the extraction vehicle's receiver window to deform under pressure to reduce impact and fracture of the extraction vehicle's receiver window.

3. The system of claim 1, wherein: The first gasket between the emitter window and the first hole includes an O-ring.

4. The system of claim 1, wherein: At least one of the transmitter window and the receiver window is formed of a material including sapphire.

5. The system of claim 1, wherein: The diameter of the receiver window of the seismic data acquisition unit is greater than the diameter of the transmitter window of the seismic data acquisition unit.

6. The system of claim 1, wherein: The thickness of the cover is different from the thickness of the emitter window.

7. The system of claim 1, comprising: The extraction vehicle is deployed in the water column, Wherein, the seismic data acquisition unit is deployed on the seabed.

8. The system of claim 1, comprising: An outer surface of the transmitter window or the receiver window is flush with an outer surface of the cover.

9. The system of claim 1, wherein: The first liner includes nylon.

10. The system of claim 1, wherein: The first liner is at least partially formed from a first material that deforms at a different rate than a second material forming at least a portion of the cover.

11. The system of claim 1, wherein: A first material forming the first liner deforms at a different rate in response to temperature or pressure than a second material forming the cover.

12. The system of claim 1, comprising: The first gasket is disposed between a bottom portion of the emitter window and a support.

13. The system of claim 1, comprising: The first gasket is located between the emitter window and the first hole to float the emitter window; and The second gasket is located between the receiver window and the second hole to float the receiver window.

14. The system of claim 1, wherein: The receiver window includes a chamfer configured to avoid interference with the second gasket to facilitate installation of the receiver window.

15. A method of performing seismic surveying, comprising: providing a seismic data acquisition unit having a transmitter window disposed in a first aperture of the cover and having a receiver window disposed in a second aperture of the cover; providing a first gasket between the emitter window and the first aperture to provide a gap greater than a threshold value to allow the emitter window to move under pressure to reduce shock and cracking of the emitter window; providing a second gasket between the receiver window and the second aperture to seal the receiver window and provide a gap greater than the threshold to allow the receiver window to move under pressure to reduce shock and cracking of the receiver window; and Optical or electromagnetic communications are transmitted to or from the extraction vehicle via at least one of a transmitter window and a receiver window of the seismic data acquisition unit, via at least one of a transmitter window and a receiver window of the extraction vehicle.

16. The method of claim 15, wherein: The first gasket between the emitter window and the first hole includes an O-ring.

17. The method of claim 15, wherein: The emitter window is formed from a material including sapphire.

18. The method of claim 15, comprising: deploying the extraction vehicle in the water column; and The seismic data acquisition unit is deployed on the seabed.

19. The method of claim 15, wherein: An outer surface of the transmitter window or the receiver window is flush with an outer surface of the cover.

20. The method of claim 15, comprising: The first liner is deformed at a different rate than the cover is deformed.

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