Patent Application
20240134079
In a typical towed streamer marine seismic survey, a vessel tows a set of elongate streamers along with one or more active seismic sources. Each streamer includes multiple seismic sensors disposed at spaced apart intervals along its length. The sources typically comprise air guns, or marine vibrators, or a combination of these. The sources are activated at intervals as the vessel follows a survey plan over a survey area. Acoustic energy generated by the source activations travels into the subsurface below the water bottom and is reflected by geological formations therein. The sensors in the streamers detect the reflected energy and, in response, generate signals that are recorded by equipment onboard the vessel. Such signals are processed and can be used to, among other things, generate an image of the subsurface geological formations in the survey area.
The term “offset” in a marine seismic survey generally refers to a distance between a source and a sensor or sensor group. The term “long offset” generally refers to an offset distance that is greater than the depth of a relevant subsurface target. For a variety of reasons, it is sometimes necessary or desirable to acquire long offset data to obtain sufficient information about subsurface features that are of interest.
Several problems are presented, however, when it is desired to gather long offset data in a marine seismic survey. Because all of the sensors in a typical towed streamer survey are disposed inside the towed streamers, the maximum offset recordable in such a survey is limited by the streamer length, L. While the streamers used in modern surveys can be very long—on the order of 8 km, for example—it is sometimes necessary to gather data at offsets greater than the length of the streamer spread. Accordingly, U.S. Pat. No. 5,761,152 (the “'152 patent”) teaches a method for using towed streamers to acquire data over a continuous range of offsets over which no offset coverage gaps exist. According to the method of the '152 patent, the largest offsets in the continuous range can reach an integer multiple of the streamer length or slightly less.
In alternative approaches, surveys employing sensors in ocean bottom nodes or in ocean bottom cables have also been used to acquire data over a continuous range of offsets over which no offset coverage gaps exist. In the latter approaches, the largest offsets in the continuous range acquired can also reach distances that are larger than the length of a modern seismic streamer. This is so because the sources and receivers are uncoupled in such surveys.
When using any of the aforementioned techniques to acquire data at offsets greater than 2L, either two or more source vessels must be used, or ocean bottom nodes or cables must be deployed. Either solution adds significant cost to the survey relative to the cost of a conventional towed streamer survey. In many cases, the additional cost is prohibitive, and therefore the data actually acquired are suboptimal.
This disclosure describes multiple embodiments by way of example and illustration. It is intended that characteristics and features of all described embodiments may be combined in any manner consistent with the teachings, suggestions and objectives contained herein. Thus, phrases such as “in an embodiment,” “in one embodiment,” and the like, when used to describe embodiments in a particular context, are not intended to limit the described characteristics or features only to the embodiments appearing in that context.
The phrases “based on” or “based at least in part on” refer to one or more inputs that can be used directly or indirectly in making some determination or in performing some computation. Use of those phrases herein is not intended to foreclose using additional or other inputs in making the described determination or in performing the described computation. Rather, determinations or computations so described may be based either solely on the referenced inputs or on those inputs as well as others. The phrase “configured to” as used herein means that the referenced item, when operated, can perform the described function. In this sense an item can be “configured to” perform a function even when the item is not operating and is therefore not currently performing the function. Use of the phrase “configured to” herein does not necessarily mean that the described item has been modified in some way relative to a previous state. “Coupled” as used herein refers to a connection between items. Such a connection can be direct or can be indirect through connections with other intermediate items. Terms used herein such as “including,” “comprising,” and their variants, mean “including but not limited to.” Articles of speech such as “a,” “an,” and “the” as used herein are intended to serve as singular as well as plural references except where the context clearly indicates otherwise.
During a typical marine seismic survey, one or more active seismic sources 108 are activated to produce acoustic energy 200 that propagates in body of water 106. Energy 200 penetrates various layers of sediment and rock 202, 204 underlying body of water 106. As it does so, it encounters interfaces 206, 208, 210 between materials having different physical characteristics, including different acoustic impedances. At each such interface, a portion of energy 200 is reflected upward while another portion of the energy is refracted downward and continues toward the next lower interface, as shown. Reflected energy 212, 214, 216 is detected by sensors 110 disposed at intervals along the lengths of streamers 104, along with a so-called direct wavefield that reaches the sensors via a path, such as path 222, that travels directly from the active sources 108 to the location of the sensors. In
Any number of active sources 108 may be used in a marine seismic survey. In the illustrated example, vessel 102 is shown towing two such sources. In other systems, different numbers of sources may be used, and the sources may be towed by other vessels, which vessels may or may not tow additional streamer arrays. Typically, an active source 108 includes one or more source subarrays 114, and each subarray 114 includes one or more acoustic emitters such as air guns or marine vibrators. Each subarray 114 may be suspended at a desired depth from a subarray float 116. Compressed air as well as electrical power and control signals may be communicated to each subarray via source umbilical cables 118. Data may be collected, also via source umbilical cables 118, from various sensors located on subarrays 114 and/or floats 116, such as acoustic transceivers and GPS units. Acoustic transceivers and GPS units so disposed help to accurately determine the positions of each subarray 114 during a survey. In some cases, subarrays 114 may be equipped with steering devices to better control their positions during the survey.
In the context of surveys related to hydrocarbon reservoirs, streamers 104 are often very long—on the order of 5 to 10 kilometers or longer—so usually are constructed by coupling numerous shorter streamer sections together. For surveys related to the installation of wind turbines, the streamers are typically much shorter—on the order of 100 to 500 meters, depending on the water depth. The target depth range in the latter types of surveys is often between 0 and 200 meters, whereas in hydrocarbon reservoir surveys the target depth is typically much deeper. In either case, each streamer 104 may be attached to a dilt float 120 at its proximal end (the end nearest vessel 102) and to a tail buoy 122 at its distal end (the end farthest from vessel 102). Dilt floats 120 and tail buoys 122 may be equipped with GPS units as well, to help determine the positions of each streamer 104 relative to an absolute frame of reference such as the earth. Each streamer 104 may in turn be equipped with acoustic transceivers and/or compass units to help determine their positions between GPS units and/or relative to one another. In many survey systems 100, streamers 104 include steering devices 124 attached at intervals, such as every 300 meters. Steering devices 124 typically provide one or more control surfaces to enable moving the streamer to a desired depth, or to a desired lateral position, or both. Paravanes 126 are shown coupled to vessel 102 via tow ropes 128. As the vessel tows the equipment, paravanes 126 provide opposing lateral forces that straighten a spreader rope 130, to which each of streamers 104 is attached at its proximal end. Spreader rope 130 helps to establish a desired crossline spacing between the proximal ends of the streamers. Power, control, and data communication pathways are housed within lead-in cables 132, which couple the sensors and control devices in each of streamers 104 to the control equipment 112 onboard vessel 102.
Collectively, the array of streamers 104 forms a sensor surface at which acoustic energy is received for recording by control equipment 112. In many instances, it is desirable for the streamers to be maintained in a straight and parallel configuration to provide a sensor surface that is generally flat, horizontal, and uniform. In other instances, an inclined and/or fan shaped receiving surface may be desired and may be implemented using control devices on the streamers such as those just described. Other array geometries may be implemented as well. Prevailing conditions in body of water 106 may cause the depths and lateral positions of streamers 104 to vary at times, of course. In various embodiments, streamers 104 need not all have the same length and need not all be towed at the same depth or with the same depth profile.
Sensors 110 within each streamer 104 may include one or more different sensor types such as pressure sensors (e.g., hydrophones) and/or motion sensors. Examples of motion sensors include velocity sensors (e.g., geophones) and acceleration sensors (e.g., accelerometers) such as micro-electromechanical system (“MEMS”) devices. In general, pressure sensors provide a magnitude-only, or scalar, measurement. This is because pressure is not associated with a direction and is, therefore, a scalar quantity. Motion sensors such as velocity sensors and acceleration sensors, however, each provide a vector measurement that includes both a magnitude and, at least implicitly, a direction, as velocity and acceleration are both vector quantities. Velocity sensors and acceleration sensors each may be referred to herein as “motion sensors.”
In the arrangement of
Techniques to be described herein may be employed in the context of any of the above or similar types of marine seismic surveys.
The distance between a source and any one sensor or sensor group constitutes an offset. Such an offset may be measured from the source to a single sensor, or to any one of the sensors within a sensor group, or to the center of a sensor group. Three different example offsets are illustrated in the drawing, ranging in length from a smallest offset 812, to an intermediate length offset 814, to a largest offset 816. A distance along the straight line path between a source and a given sensor or sensor group, as depicted by arrows 812-816, is commonly referred to as a “seismic offset” or simply an “offset.” A distance along direction 808 between a source and the inline projection of a sensor or sensor group is commonly referred to as an “inline offset.” Thus, sensor or sensor group 802 defines a smallest inline offset 818 with respect to source 800, sensor or sensor group 804 defines an intermediate length inline offset 820 with respect to the source, and sensor or sensor group 806 defines a largest inline offset 822 with respect to the source. Similarly, a distance along direction 810 between a sensor or sensor group and the crossline projection of the source is commonly referred to as a “crossline offset.” In the illustrated example, each of sensors or sensor groups 802-806 defines the same crossline offset 824 with respect to source 800.
The unqualified term “offset” when used herein refers to any of the above-described distances.
Computer system 900 includes one or more central processor unit (“CPU”) cores 902 coupled to a system memory 904 by a high-speed memory controller 906 and an associated high-speed memory bus 907. System memory 904 typically comprises a large array of random-access memory locations, often housed in multiple dynamic random-access memory (“DRAM”) devices, which in turn are housed in one or more dual inline memory module (“DIMM”) packages. Each CPU core 902 is associated with one or more levels of high-speed cache memory 908, as shown. Each core 902 can execute computer-readable instructions 910 stored in system memory 904, and can thereby perform operations on data 912, also stored in system memory 904.
Memory controller 906 is coupled, via input/output bus 913, to one or more input/output controllers such as input/output controller 914. Input/output controller 914 is in turn coupled to one or more non-transitory computer readable media such as computer-readable medium 916 and computer-readable medium 918. Non-limiting examples of such computer-readable media include so called solid-state disks (“SSDs”), spinning media magnetic disks, optical disks, flash drives, magnetic tape, and the like. Media 916, 918 may be permanently attached to computer system 900 or may be removable and portable. In the example shown, medium 916 has instructions 917 (software) stored therein, while medium 918 has data 919 stored therein. Operating system software executing on computer system 900 may be employed to enable a variety of functions, including transfer of instructions 910, 917 and data 912, 919 back and forth between media 916, 918 and system memory 904.
Computer system 900 may represent a single, stand-alone computer workstation that is coupled to input/output devices such as a keyboard, pointing device and display. It may also represent one node in a larger, multi-node or multi-computer system such as a cluster, in which case access to its computing capabilities may be provided by software that interacts with and/or controls the cluster. Nodes in such a cluster may be collocated in a single data center or may be distributed across multiple locations or data centers in distinct geographic regions. Further still, computer system 900 may represent an access point from which such a cluster or multi-computer system may be accessed and/or controlled. Any of these or their components or variants may be referred to herein as “computing apparatus” or a “computing device.”
In example embodiments, data 919 may correspond to sensor measurements or other data recorded during a marine geophysical survey, or may correspond to a survey plan for implementing any of the methods described herein. Instructions 917 may correspond to algorithms for performing any of the methods described herein, or for producing a computer-readable survey plan for implementing one or more of such methods. In such embodiments, instructions 917, when executed by one or more computing devices such as one or more of CPU cores 902, cause the computing device to perform operations described herein on the data, producing results that may be stored in one or more non-transitory computer-readable media such as medium 918. In such embodiments, medium 918 constitutes a geophysical data product that is manufactured by using the computing device (and in come cases vessels, sources, and sensors) to perform methods described herein and by storing the results in the medium. Geophysical data product 918 may be stored locally or may be transported to other locations where further processing and analysis of its contents may be performed. If desired, a computer system such as computer system 900 may be employed to transmit the geophysical data product electronically to other locations via a network interface 920 and a network 922 (e.g. the Internet). Upon receipt of the transmission, another geophysical data product may be manufactured at the receiving location by storing contents of the transmission, or processed versions thereof, in another non-transitory computer readable medium. Similarly, geophysical data product 918 may be manufactured by using a local computer system 900 to access one or more remotely-located computing devices in order to execute instructions 917 remotely, and then to store results from the computations on a medium 918 that is attached either to the local computer or to one of the remote computers. The word “medium” as used herein should be construed to include one or more of such media.
As can be seen from the illustration, sensors disposed within 12 km from the source could register all of refracted energy 1110 but none of refracted energy 1112. Similarly, sensors disposed between 20 km and 30 km from the source could register all of refracted energy 1112 but none of refracted energy 1110. Notably, sensors disposed between 12 km and 20 km would not register any reflected source energy or refracted source energy that would be relevant for gaining useful information about targets in the subsurface. Accordingly, the region indicated by bracket 1120 in
Marine seismic surveying configurations and techniques will now be described that are well suited for survey areas that exhibit one or more shadow zones.
Streamer spread 1204, as well as the streamer spreads in any of the embodiments described herein, may comprise one or more elongate streamers in which seismic sensors are disposed at spaced apart intervals along the length of each streamer—for example according to any of the arrangements described above. Active seismic source 1206, as well as the active seismic sources in any of the embodiments described herein, may comprise one or more source elements—also according to any of the arrangements described above. The source elements may be of the same type or may be of different types. For example, the source elements may comprise air guns, or marine vibrators, or both. In some embodiments, all of the streamers in the streamer spread may have the same length. In other embodiments, the lengths of the streamers in the spread may differ. In either case, the length of a longest streamer in the streamer spread will be denoted L in the following discussion.
In the embodiment of
Vessel 1212 in
As the marine seismic survey proceeds, sources 1206, 1214 are activated, and sensors in the streamers record energy from both sources. In various embodiments, the sources may be activated in a manner that will facilitate de-blending of the energy emitted by the sources. “De-blending” refers to any of several known techniques by which mixed energy from two or more sources used during a seismic survey is separated such that energy attributable to each individual source is isolated from energy attributable to the other sources. In various embodiments, sources 1206, 1214 may be activated simultaneously, near-simultaneously, or at separate times. In either case, the de-blending process may make use of dithering of the source activation times or locations, where dithering refers to random or pseudo-random differences in source activation times or locations from one shot point to a next shot point for a given source. Because sources 1206, 1214 are spatially separated by a significant distance, the de-blending process may also make use of angles of incidence in the source energy recorded by the sensors in the streamers. Other source activation and de-blending techniques may also be employed.
Sensors in the streamers record energy from the sources over two different offset ranges.
The minimum offset distance recorded for source 1206 is measured from source 1206 to a nearest sensor in the streamer spread (in this case, the sensor or sensor group nearest to the front end of the streamer spread), which distance is equal to X. The maximum offset distance recorded for source 1206 is measured from source 1206 to a farthest sensor in the streamer spread (in this case, the sensor or sensor group nearest to the tail end of the streamer spread), which distance is equal to X+L. Thus, for source 1206, sensors in the streamers record offsets over a range of distances from X to X+L. Example ray paths for reflected energy corresponding to the minimum and maximum offset distances in this offset range are indicated in the drawing with dashed arrows 1216 (minimum offset) and 1218 (maximum offset).
The minimum offset distance recorded for source 1214 is measured from source 1214 to a nearest sensor in the streamer spread (in this case, the sensor or sensor group nearest to the front end of the streamer spread), which distance is equal to A+L. The maximum offset distance recorded for source 1214 is measured from source 1214 to a farthest sensor in the streamer spread (in this case, the sensor or sensor group nearest to the tail end of the streamer spread), which distance is equal to A+2L. Thus, for source 1214, sensors in the streamers record offsets over a range of distances from A+L to A+2L. Example ray paths for reflected energy corresponding to the minimum and maximum offset distances in this offset range are indicated in the drawing with dashed arrows 1220 (minimum offset) and 1222 (maximum offset).
Vessel 1412 tows an active seismic source 1414 but does not tow streamers. In the illustrated embodiment, vessel 1412 sails behind vessel 1402 such that source 1414 is disposed behind the tail end of the streamer spread by a distance A+L. As the survey progresses, sources 1406, 1412 are activated, and sensors in the streamers recorded energy from both sources.
As was the case in the configuration of
As in configurations 1300 and 1400, source 1506 may be towed relative to the front of streamer spread 1504 by a distance X, which distance may vary as described above. Distance X is not specifically illustrated in
In configuration 1500, the minimum offset distance recorded for source 1506 corresponds to example ray path 1516, leading from source 1506 to the front end of streamer spread 1504, which distance is equal to X. The maximum offset distance recorded for source 1506 corresponds to example ray path 1518, leading from source 1506 to the tail end of streamer spread 1526, which distance is equal to X+2L. The minimum offset distance recorded for source 1514 corresponds to example ray path 1520, leading from source 1514 to the front end of streamer spread 1504, which distance is equal to A+2L. The maximum offset distance recorded for source 1514 corresponds to example ray path 1522, leading from source 1514 to the tail end of streamer spread 1526, which distance is equal to A+4L.
As was the case with configurations 1300 and 1400, configuration 1500 may be varied by sailing vessel 1512 behind the composite streamer spread such that source 1514 follows the tail end of the composite streamer spread by a distance A+2L. The resulting offset ranges recorded in such a configuration will correspond exactly to those illustrated in
The distance A used in any of the above survey configurations may correspond to the size(s) of one or more shadow zones in the survey area. The distance can be pre-determined during survey planning—for example by seismic modeling—or can be estimated and/or optimized by data analysis that is performed while the survey is progress. In any such surveys, the distance A can be either a fixed or a variable parameter. For example, in survey areas that exhibit changes in geology (e.g., changes in target depths, thickness of geological structures, acoustic parameters, or water depth), the parameter A can be dynamically adjusted in a manner that corresponds to the changes in geology as the survey progresses over the survey area. Thus, the distance A used during a survey can be adjusted dynamically on demand.
In many scenarios, it will be advantageous to use a distance A that is substantially larger than, for example, the distance X in configurations 1300, 1400, 1500, and substantially larger than the following distance observed by vessel 1524 in configuration 1500. In such scenarios, using a distance A that is greater than or equal to 2 km may prove beneficial in order to acquire signals at offsets that are sufficiently long to accommodate commensurately large shadow zones. As was mentioned above, in any embodiments the distance X can be zero or can be a small distance—for example on the order of 100 meters—such that only the distances A and L and the various multiples and sums thereof described herein are relevant to the survey design.
In some embodiments, the parameter A may be determined by performing a pilot survey prior to performing the marine seismic survey in which the parameter A is to be used.
A shadow zone identified by the pilot survey would correspond to a range offset distances between the pilot source and the pilot sensor over which substantially no reflected energy and substantially no refracted energy from the pilot source was received by the pilot sensor from target depths associated with the survey. For each shadow zone so identified, the size of this range of offset distances would correspond to the shadow zone length.
During the actual marine seismic survey, the distance A may be chosen so that it corresponds to the shadow zone length as determined during the pilot survey. For survey areas that exhibit multiple shadow zones having different lengths as determined by the pilot survey, the distance A used during the actual marine seismic survey may be varied accordingly as the actual marine seismic survey progresses over the survey area.
In other embodiments, the distance A used during the actual marine seismic survey may be varied based on real-time analysis of signals recorded by the sensors in the towed streamer spread(s). For instance, guided by pre-survey modeling and/or pilot survey results, if refraction energy from the target depths decreases or becomes absent on some or all of the receivers at some point during the survey, then the distance A can be adjusted (increased or decreased as indicated given the circumstances leading up to the change and the nature of the change observed), to better record the refraction energy that is of interest to the survey. Such real-time analysis can include careful tracking and analysis of refraction energy in the seismic data being recorded so that distance A can be adjusted to optimize the recording of refraction energy of interest as the survey progresses.
In further embodiments, the distance A used during the actual marine seismic survey may be varied based on one or more of: changes in depth of geological features that are of interest to the survey (i.e., “targets”), thicknesses of geological features in the subsurface, differences in acoustic parameters in different parts of the survey area or at different depths, and differences in water depth over the survey area.
In some embodiments, the source types towed by the source-only vessel in configurations 1300, 1400, 1500 may differ from the source types towed by the streamer vessel. In such embodiments, the sources towed by the streamer vessel may comprise conventional or broadband seismic sources, while the source types towed by the source-only vessels may comprise lower-frequency seismic sources. In this context, the term “conventional or broadband” refers to sources that emit usable energy at frequencies in a range from about 8 Hz to about 200 Hz. The term “lower frequency” refers to sources that emit usable energy at frequencies below 8 Hz—for example, extending as low as about 1.5 Hz or lower. In one non-limiting example, the streamer vessel may tow an air gun source having a volume of 3,280 cubic inches, while the source-only vessel may tow higher-volume air gun source such as a source having a volume of 4,000 to 8,000 cubic inches. Other non-limiting examples of lower frequency sources include the low-frequency vibrational source called WOLFSPAR, which was designed and was built by British Petroleum, P.L.C, and the TPS source manufactured by Sercel, which has a volume of 28,000 cubic inches. In other embodiments, other source types and source volumes may be used by either vessel as appropriate given the characteristics of the area being surveyed and the design of the survey itself.
In further embodiments, signals recorded by the streamer sensors from the source towed by the streamer vessel (the signals recorded in the shorter of the two offset ranges acquired during the survey) may be used, in accordance with known techniques, for generating an image of the geological features of the subsurface under the survey area. To support the imaging, signals recorded by the streamer sensors from the sources towed by the source-only vessel (the signals recorded in the longer of the two offset rages acquired during the survey) may be used, also in accordance with known techniques, to develop a velocity model of the subsurface. For example, the latter signals may be used in a full waveform inversion (“FWI”) process to develop the velocity model.
In step 1812, the sources are activated, and the sensors in the streamers generate signals responsive to energy received from both sources. The generated signals may be recorded. In step 1814, the recorded signals are processed to separate (i.e., to isolate) the energy attributable to each source from the recorded signals. In step 1816, the energy attributed to the second source (the source associated with the longer of the two offset ranges) is used for building a velocity model of the subsurface. For example, the energy may be used in an FWI process to develop the velocity model. In step 1818, the velocity model is used in conjunction with the energy attributed to the first source (the source associated with the shorter of the two offset ranges) to generate an image of geological features in the subsurface.
In some embodiments (see step 1802), the offset coverage gap is determined based on results from a prior two-dimensional (“2D”) pilot survey over the survey area, where the pilot survey employed one or more node sensors. In further embodiments (see step 1808), the distance between the source-only vessel and the streamer vessel used during the three-dimensional (“3D”) survey of steps 1804 to 1812 may vary as the 3D survey progresses. The variation may be based on the results of the 2D pilot survey, or may be based on real-time analysis of data recorded during the 3D survey, or may be based on a combination of the two. In still further embodiments (see step 1810), a third vessel may be employed to tow a second streamer spread behind the first streamer spread to create a longer, composite streamer spread, in which case the distance between the source-only vessel and the composite streamer spread is adjusted accordingly to preserve the offset coverage gap.
In any embodiments, the source-only vessels need not sail directly inline with the vessel or vessels that tow the streamer spread. Rather, if desired, the source-only vessels may sail at various crossline offsets to the streamer vessel(s). Moreover, any of the offset types discussed above with reference to
In any embodiments, signals generated by sensors in the streamer spread, or data representative thereof, may be recorded in one or more non-transitory computer readable media. In this manner, the performance of a marine seismic survey according to the embodiments described herein, coupled with the recording of the signals generated thereby, constitutes the manufacture of a geophysical data product that comprises the non-transitory computer readable medium.
Embodiments such as those described above may provide numerous advantages. For example, they enable the acquisition of extended long offset data to support superior velocity model building in geologies that exhibit shadow zones, and they enable doing so by using only towed streamer marine seismic surveys, which are significantly less costly than surveys that employ ocean bottom nodes or ocean bottom cables.
The following is a non-limiting list of further example embodiments.
Multiple specific embodiments have been described above and in the appended claims. Such embodiments have been provided by way of example and illustration. Persons having skill in the art and having reference to this disclosure will perceive various utilitarian combinations, modifications and generalizations of the features and characteristics of the embodiments so described. For example, steps in methods described herein may generally be performed in any order, and some steps may be omitted, while other steps may be added, except where the context clearly indicates otherwise. Similarly, components in structures described herein may be arranged in different positions or locations, and some components may be omitted, while other components may be added, except where the context clearly indicates otherwise. The scope of the disclosure is intended to include all such combinations, modifications, and generalizations as well as their equivalents.
This application claims benefit to the filing date of co-pending U.S. Provisional Patent Application 63/417,816, filed on Oct. 20, 2022, titled “Extended Long Offset Acquisition with Constant or Dynamically Adjusted Offset Gap” (the “Provisional Application”), the contents of which are hereby incorporated by reference as if fully set forth herein. In the event of a conflict between the meaning of a term as used in the Provisional Application and the same or a similar term as used herein, the meaning and usage provided herein shall control.
| Number | Date | Country | |
|---|---|---|---|
| 63417816 | Oct 2022 | US |
