Cross Reference to Related Applications

[0001] The present application claims priority to United States Patent Application No. 62/053,953 that was filed on September 23, 2014, which is hereby incorporated by reference in their entirety.

Background

[0002] In the oil and gas industry, geophysical prospecting techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon deposits. Generally, a seismic energy source is used to generate a seismic signal that propagates into the earth and is at least partially reflected by subsurface seismic reflectors (i.e., interfaces between underground formations having different acoustic impedances). The reflections may be recorded by seismic detectors located at or near the surface of the earth, in a body of water, or at known depths in boreholes, and the resulting seismic data may be processed to yield information relating to the location of the subsurface reflectors and the physical properties of the subsurface formations.

[0003] Some seismic surveys utilize point receiver acquisition, which may involve recording traces from individual receivers rather than summing the responses of a group or array of receivers before recording the summed trace. In a land seismic acquisition, receivers may be deployed on the ground surface. In this case the ground may be an uneven surface, which may cause signal arrival times to vary. Conventional acquisition may sum the responses of several receivers before recording. Arrival-time variations may be averaged and the resulting sum may be a broader signal than that of the originals. Point-receiver technology may record a trace from every receiver and apply corrections to each of the traces before they are summed, resulting in a compact signal with high signal-to-noise ratio. The seismic image created from point-receiver acquisition is usually of higher resolution than that obtained from grouped acquisition. Summary

[0004] In one embodiment, a cable assembly for use in land seismic data acquisition is provided. The cable assembly may include one or more receiver locations. The cable assembly may also include at least two geophones per receiver location, wherein the at least two geophones per receiver location include at least one in-phase sensor and at least one random polarity sensor. The cable assembly may further include one or more analog-to-digital converters ("ADC") that are in electrical communication with the at least two geophones per receiver location. The cable assembly may also include a first transmission line and a second transmission line configured as a single four-core cable, wherein each of the at least two geophones per receiver location are connected to one or more of the first transmission line and the second transmission line.

[0005] In some embodiments, the at least two geophones per receiver location may include one or more coil-based, passive geophones. The at least two geophones per receiver location may be mechanically coupled together. Each of the in-phase sensors may be connected to the first transmission line. Each of the random polarity sensor may be connected to the second transmission line.

[0006] In another embodiment, a method for acquiring point-receiver seismic data is provided. The method may include deploying one or more receiver locations. The method also may include providing at least two sensors per receiver location, wherein at least one of the at least two sensors per receiver location are in phase sensors and the remainder are random polarity sensors. The method may further include deploying at least one cable including a first transmission line and a second transmission line, wherein each of the in-phase sensors are associated with the first transmission line and each of the random polarity sensors are associated with the second transmission line. The method may also include receiving one or more signals at the at least two sensors per receiver location. [0007] In some embodiments, the at least two sensors per receiver location may be geophones. In some embodiments, the at least two sensors per receiver location may be hydrophones. The at least two sensors per receiver location may be mechanically coupled together. The at least one cable may be a single four-core cable. The method may further include providing one or more analog-to-digital converters ("ADC") that are in electrical communication with at least one of the at least two sensors. The at least one cable may include two two-core cables. The method may further include determining analog group formed data based upon, at least in part, the one or more received signals. The analog group formed data may include an approximation of digital signal data.

[0008] In another embodiment, a marine seismic cable assembly is provided. The marine seismic cable assembly may include one or more receiver locations. The assembly may also include at least two hydrophones per receiver location, wherein the at least two hydrophones per receiver location include at least one in-phase sensor and at least one random polarity sensor. The assembly may further include a first transmission line associated with each of the at least one in- phase sensors. The assembly may also include a second transmission line associated with each of the at least one random polarity sensors, wherein the first and the second transmission lines are configured as two two-core cables.

[0009] In some embodiments, the at least two hydrophones per receiver location may be mechanically coupled together. Each of the in phase sensors may be connected to the first transmission line. Each of the random polarity sensors may be connected to the second transmission line. The assembly may further include one or more analog-to-digital converters ("ADC") that are in electrical communication with the at least two hydrophones per receiver location. The one or more analog-to-digital converters may be included with a digital signal processor within an analog front end portion of the cable assembly.

[0010] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

Brief Description of the Drawings

[0011] Embodiments of the present disclosure are described with reference to the following figures.

[0012] FIG. 1A is a diagrammatic view of a system including an augmented analog seismic survey string in accordance with one or more embodiments of the present disclosure;

[0013] FIG. IB is a diagrammatic view of a system including a plurality of analog seismic survey strings in accordance with one or more embodiments of the present disclosure;

[0014] FIG. 2 is a diagrammatic view of two analog seismic survey strings in accordance with one or more embodiments of the present disclosure;

[0015] FIG. 3 is a flow diagram of a process in accordance with one or more embodiments of the present disclosure;

[0016] FIG. 4 A is a diagrammatic view of a vehicle that may deploy a plurality of analog seismic survey strings in a land seismic survey in accordance with one or more embodiments of the present disclosure;

[0017] FIG. 4B is a diagrammatic view of a sea vessel that may deploy one or more streamers in a marine seismic survey in accordance with one or more embodiments of the present disclosure; and

[0018] FIG. 5 illustrates an example of a data storage device in accordance with one or more embodiments of the present disclosure.

[0019] Like reference symbols in the various drawings may indicate like elements. Detailed Description

[0020] Various embodiments described herein are directed to a method, a system and an apparatus for acquiring seismic survey data using geophone receivers and/or hydrophone receivers. In some embodiments, various techniques described herein refer to the acquisition of point-receiver trace data using strings of geop hones. In a point-receiver survey the data from individual receivers may be demodulated, whereas a more conventional survey method may only allow for the collective demodulation of a group and/or an array of receivers that have been previously summed. Embodiments of the seismic acquisition process described herein may be used in any suitable application, including, but not limited to, land and marine seismic surveys.

[0021 ] Some conventional survey methods may attenuate coherent noise, but may do so at the expense of subsequent processing flexibility and/or resolution when compared to the point- receiver trace survey method. Further, the conventional survey method may only contain information pertaining to the lower frequency end of the original receiver trace. The point-receiver trace acquisition method may also allow individual processing of the receiver traces, and therefore correction of each receiver trace before summation. As such, the seismic image acquired by the point-receiver method may not only be of higher resolution, but may also include individual trace correction to account for seismic features such as near-surface heterogeneities etc. However, the ability to individually demodulate and/or record each point-receiver trace before summation may require addition transmission channels, which may be referred to as live channels, when compared to the conventional survey method.

[0022] There are therefore many reasons why it may be desirable to augment and/or complement the trace signals acquired by a conventional analogue string, with an approximation of the trace signals that would have been acquired by individual point-receivers. In some embodiments the seismic acquisition process described herein may obtain point-receiver like trace information using a conventional string that may be both cost and/or resource effective. Further, in some embodiments the acquisition process may use passive seismic sensors for the detection of seismic signals, and an augmented analogue string for the transmission of the detected seismic signals. Furthermore, the transmitted seismic signals may include seismic signals summed in- phase, and/or seismic signals summed with known, but random polarities. This approximation of point-receiver information may therefore enable high frequency trace information to be obtained, where intra-array perturbations are more significant, as well as individual trace correction etc.

[0023] Referring to FIG. 1 A there is shown a diagrammatic view of a system 100 including an augmented analog string 1 10 in accordance with various implementations described herein. In a first embodiment, the analog string 1 10 may comprise one or more conventional geophones 120. In some embodiments, a pair of geophones may be further located within the housing of one or more conventional geophones 120. The pair of geophones may be moving coil-based passive geophones 132 and 134. The pair of geophones may be mechanically coupled. Further, the geophones 132 and 134, may be selected and/or calibrated such that their sensitivities are substantially the same.

[0024] Referring to FIG. IB there is shown a diagrammatic view of a system 105 including a plurality of augmented analog seismic survey strings 110 in accordance with various implementations described herein. While the illustrative embodiment of FIG. IB has three seismic survey strings 110, and each seismic survey string 110 has 6 representative receiver locations, it will be apparent to those of ordinary skill in the art that there are many modifications and variations on this illustrative embodiment that are within the scope and spirit of this disclosure.

[0025] Referring again to FIG. 1 A in some embodiments, a seismic data signal from each of the geophones 132 and 134 may be transmitted to a processing unit 140 via individual transmission (live channels) lines, wherein there may be a first transmission line and second transmission line. Further, at least one of the two geophones may be connected with the same phase as other geophones in the seismic survey string 110 to the first transmission line, and remainder may be connected with a random, but known polarity, to the second transmission line. The seismic data signal may be transmitted to processing unit 140 wirelessly and/or by utilizing a cable . The cable may be common to one or more pairs of geophones. The cable may be fiber and/or multi-core. In the illustrative embodiment the cable is a four-core cable.

[0026] In some embodiments, processing unit 140 may be configured to have two or more analogue front-ends 160, and may be composed of only passive electronic components. The processing unit 140 may further include an analogue-to-digital converter (ADC) 162. There may be an ADC 162 for each transmission channel, therefore geophone 132 may be connected to one transmission channel and geophone 134 to another. Alternatively, the channels may be multiplexed and/or sampled such that there is only a single ADC 162. The processing unit 140 may further comprise one or more digital signal processors (DSP) 164 to measure, filter, compress, correct, sum etc. the analog seismic data signal for each transmission channel.

[0027] In some embodiments, it may be possible to utilize existing analogue front-ends 160, ADC's 162 and/or DSP's 164 that are currently used to acquire and process the seismic data signal from the conventional analogue string 110. By utilizing existing hardware and/or processing capabilities it may be possible to mitigate the system cost of digitizing the analogue complementary approximation of a point-receiver system, especially in existing systems that may have one or more surplus analog input channels and/or surplus DSP processing power.

[0028] Referring again to FIG. 1A, the process of demodulating an approximation of point- receiver trace data using strings of moving coil-based passive geophones 132 and 134 may consist of randomly reversing the polarity of one or more of the moving coil-based passive geophones. For example, one of the two geophones, such as geophone 132, may be referred to as an in-phase geophone sensor 132. The in-phase geophone sensor 132 may be connected with normal polarity to a first transmission channel. The other geophone 134, may be referred to as the random polarity geophone sensor 134. The random polarity geophone sensor 134 may be connected to a second transmission channel.

[0029] In some embodiments, demodulation may consist of selectively reversing the polarities of the electrical connections to geophone 134. The selective reversing may be based on a random or pseudorandom sequence. The demodulating process may further assume that the signals recorded by the geophones have a sparse representation in the wavenumber domain. As such, the demodulating process may utilize compressive sensing (sparse sampling) theory to effectively demodulate (separate) the summed signals, and thereby reconstruct the individual hydrophone (geophone) waveforms. The process may thereby exploit the sparsity of the waveform in one domain, for example the wave-number domain, to recover the waveform, by solving an under- determined system of equations. The demodulation process may thereby obtain an approximation of the signals that would have been recorded by individual point-receivers using a conventional analogue string, without requiring the digitalization of each hydrophone receiver, and also with a reduced number of channels.

[0030] In some embodiments, as described herein, the two transmission channels may be assembled within the four-core cable, and may consist of one or more in-phase geophone sensors 132, and one or more random polarity geophone sensors 134. The one or more in-phase geophone sensors may be configured such that low frequency seismic data is preserved. Further, their configuration, and presence, may improve the performance of the separation algorithm, and the estimation of the point-receiver data, since the data recorded by individual geophones maybe more determinable.

[0031] As stated herein, compression sensing theory enables the reconstruction of a signal, by finding solutions to an undermined system of liner equations at each instant of time. In the case of the disclosed process the augmented analogue string delivers both conventional analogue group formed data, and data from an approximation of the signals that would have been recorded by digital sensors located where the moving coil-based passive geophones (132 and 134) are situated. In such a situation an approximation is possible, where the number of sensor packages connected to the augmented string is greater than number of internal sensors, in which case the system of linear equations that may be built at each instant in time is underdetermined. [0032] For example, in the scenario of a four-core cable, with six sensor packages 120 connected, wherein there are two geophones 132 and 134 in each package 120, there may be two channels. These two channels may either be a nodal (wireless) based system or the cabled based system described herein. In this scenario the recording system may be mathematically described by the following undetermined system of linear equations at each instant in time. (See equation

(1))

[0033] Referring to equation (1), ri through re are individual digitized ground particle velocities at six considered receiver locations. For example, in an acquisition with a single seismic survey string 110, such as that depicted in FIG. 1A, ri through r<imay correspond to the individual ground particle velocities, which may have been recorded, if the ground particle velocities at ri through re had been acquired and digitized individually. Further, dl and d2 are the corresponding digitized signals, which may be obtained after demodulation of the signals transmitted by seismic survey string 110, by the processing unit 140, in accordance with the one or more embodiments described herein.

[0034] Further, in an acquisition with a plurality of seismic survey strings 1 10, such as that depicted in FIG IB, equation (1) may be modified. For example:

(2)

[0035] Equation (2) represents an acquisition with three seismic survey strings 1 10, wherein ry is the signal sensed by the i ^th sensor of the f ^h string, and du is the digitized signal by the tf ^h string for the I ^th string transmission line. Furthermore, the methods employed to solve this undetermined system for ry may be similar to the methods used by a person of ordinary skill in the art for the separation of data acquired with simultaneous source methods.

[0036] In some embodiments, the entries (weighting) of the first row of the matrix in equation 1 may be other than unity. Further in some instances, different (but known) polarity encoding schemes may be used for each augmented string.

[0037] Referring to FIG. 2, there is shown a diagrammatic view of two analog seismic survey strings in accordance with one or more embodiments of the present disclosure. In some embodiments, the alternative embodiment depicted in FIG. 2 may be used. The two analog seismic survey strings may be two-core (single channel) strings 210 and 220, and may be deployed in close proximity, i.e. their separation is far smaller than the minimum wavelength of interest. The sensors 212 and 214 connected to one of the two strings 210 may have normal polarity described herein. The sensors 216 and 218 connected to the other string 220 may have their polarity randomly reversed as described herein. Each sensor package 212-218 may be a standard single geophone.

[0038] Referring now to FIG. 3, an embodiment depicting operations consistent with implementations of seismic acquisition process described herein. Embodiments may include deploying (302) one or more receiver locations. Embodiments may also include providing (304) at least two sensors , 132 and 134, per receiver location, wherein at least one of the at least two sensors per receiver location are in-phase sensors 132 and the remainder are random polarity sensors 134. Embodiments may further include deploying (306) at least one cable including a first transmission line and a second transmission line, wherein each of the in-phase sensors 132 are associated with the first transmission line and each of the random polarity sensors are associated with the second transmission line. Embodiments may also include receiving (308) one or more signals at the at least two sensors per receiver location.

[0039] Although the various embodiments and examples described above are directed to a method, a system, and an apparatus for acquiring point-receiver seismic survey trace data using geophones within the context of land seismic, the various embodiments are equally valid for marine seismic survey.

[0040] Referring now to FIG. 4 A there is shown a diagrammatic view of vehicle 420 that may deploy a plurality of analog seismic survey strings 110 in a land seismic survey in accordance with one or more embodiments of the present disclosure. The one or more seismic survey strings may include an augmented analog survey string 110 in accordance with the various implementations described herein with respect to the seismic survey string 110 of FIG. 1. The one or more augmented analog survey strings 110 may include a pair of geophones 132 and 134, which may be located within the housing of a conventional hydrophone receiver 120. The pair of geophone receivers may be passive geophone receivers, and may be mechanically coupled. Further, the pair of geophone receivers may be selected and/or calibrated such that their sensitivities are substantially the same.

[0041 ] In some embodiments, the alternative embodiment depicted in FIG. 2 may be employed in a land seismic survey setting, whereby there may be two analog survey strings 110 deployed in close proximity.

[0042] FIG. 4A illustrates a vehicle 420 that may include a reel or spool (not shown) for deploying a one or more augmented analog survey strings 110, which may be a cable-like structure having a number of geophone receivers 120 for performing a land seismic survey of a subterranean structure below the surface of the earth. [0043] In some embodiments, there may be a seismic vibrator vehicle 430, which may include a vibrating element 432, and a baseplate 434. There may also be a signal measuring apparatus element 436, for example, one or more accelerometers, whose signals maybe combined to measure the actual ground signal applied to the earth by the seismic vibrator vehicle baseplate 434. In the illustrative embodiment of FIG. 4A, the vibrating element 432 is coupled with the baseplate 434 to provide for the transmission of vibrations from the vibrating element 432 to the baseplate 434. The baseplate 434 may be positioned in contact with a surface of the earth, thereby communicating vibrations of the vibrator 1 1 into the earth.

[0044] The seismic signal 440 that is generated by the seismic vibrator vehicle 430 may be reflected off of the interfaces between subsurface impedances. This reflected signal 450 may be detected by the pairs of geophones of the one or more augmented analog survey strings 110. The detected signals ry may then be processed in accordance with one or more embodiments of the present disclosure.

[0045] Referring now to FIG. 4B there is shown a diagrammatic view of sea vessel 400 that may deploy one or more streamers in accordance with one or more embodiments of the present disclosure. The one or more streamers may include an augmented analog streamer string 402 in accordance with the various implementations described herein with respect to the seismic survey string 1 10 of FIG. 1. In a marine seismic survey the geophones 132 and 134, of the land seismic survey string 1 10 may be replaced with a pair of hydrophone receivers, sensors (not shown), which may be located within the housing of a conventional hydrophone receiver 403. The pair hydrophone receivers may be passive hydrophone receivers, and may be mechanically coupled. Further, the pair of hydrophone receivers may be selected and/or calibrated such that their sensitivities are substantially the same.

[0046] In some embodiments, the alternative embodiment depicted in FIG. 2 may be employed in a marine setting, whereby there may be two analog streamers strings 402 deployed in close proximity. [0047] FIG. 4B illustrates a sea vessel 400 that may include a reel or spool 404 for deploying a one or more streamers 402, which may be a cable-like structure having a number of hydrophone receivers 403 for performing a subterranean survey of a subterranean structure 414 below a sea floor 412. A portion of streamer 402, and more particularly, hydrophone receivers 403, may be deployed in a body of water 408 underneath a sea surface 410. Streamer 402 may be towed by the sea vessel 400 during a marine seismic survey.

[0048] In some embodiments, instead of using a streamer 402 that is towed in the water 408 by sea vessel 400, a seabed cable may be used instead, where the seabed cable may be, for example deployed from the reel 404 on the sea vessel 400 and laid on the sea floor 412.

[0049] In yet another embodiment, a vertical streamer that may be deployed from either a buoy, stationary underwater or surface autonomous vehicle, and/or a structure rising up from the sea floor. This type of arrangement may be referred to as a vertical cable survey. Accordingly, this type of arrangement may render recording buoys and surface connections unnecessary.

[0050] In the following, the term "streamer" is intended to cover either a streamer that is towed by a sub-sea or sea surface vessel or non-towable streamers such as a seabed cable laid on the sea floor 112 or those that may be deployed vertically in the water column.

[0051] Also depicted in FIG. 4B are a number of signal sources 405 that may produce signals which propagated into the body of water 408 and into subterranean structure 414. The signals may be reflected from layers in subterranean structure 414, including a geological formation 416 that can be any one of a hydrocarbon-containing reservoir, a fresh water aquifer, an injection zone, and so forth. Signals reflected from 416 may be propagated upwardly toward sensors 403 for detection by the sensors. Measurement data may be collected by sensors 403, which may store the measurement data and/or transmit the measurement data back to data storage device 406. In some embodiments the storage device may be situated on the sea vessel 400, and may be functionally equivalent to the processing unit 140 described herein. [0052] In some embodiments, sensors 403 may be seismic sensors, which may be implemented with acoustic sensors such as hydrophones, geophones, and/or fiber optic based sensor systems. The signal sources 405 may be seismic sources, such as air guns, marine vibrators and/or explosives. In an alternative embodiment, the sensors 403 may be electromagnetic (EM) sensors 403, and signal sources 405 may be EM sources that generate EM waves that are propagated into subterranean structure 414.

[0053] Although not shown in FIG. 4B, streamer 402 may further include additional sensors (e.g., depth sensors), which may be used to detect a position of respective sections of streamer 402. In accordance with some embodiments, data from these additional sensors may be sent back to data storage device 406 to update information regarding which sections of streamer 402 are in body of water 408, and which sections of streamer 402 are outside the body of water 408.

[0054] In some embodiments, streamer 402 may include any number, type and configuration of sensors. Some of these may include, but are not limited to, hydrophones, geophones, particle displacement sensors, particle velocity sensors, accelerometers, pressure gradient sensors, or combinations thereof.

[0055] In some embodiments, streamer 402 may include a multi-component streamer, which means that streamer 402 may contain particle motion sensors and pressure sensors. The pressure and particle motion sensors may be part of a multi-component sensor unit. Each pressure sensor may be configured to detect a pressure wavefield, and each particle motion sensor may be configured to detect at least one component of particle motion that is associated with acoustic signals that are proximate to the sensor. Examples of particle motions include one or more components of a particle displacement, one or more components (inline (x), crossline (y) and vertical (z) components of a particle velocity, and one or more components of a particle acceleration. In this embodiment, each transmission line connects sensors of the same type (hydrophones or geophones) whose signals are transmitted with the polarity reversal schemes disclosed herein. [0056] Referring now to FIG. 5, an example of a computing device that may be associated with certain embodiments of the seismic acquisition techniques described above is provided. In some embodiments, the computing device may include and/or may be in communication with some or all of the components shown in FIGS. 1-4, for example, geophones, hydrophones, DSPs, ADCs, etc. Computing device 550 may include a processor 552, memory 564, an input/output device such as a display 554, a communication interface 566, and a transceiver 568, among other components. The device 550 may also be provided with a storage device, such as a microdrive or other device, to provide additional storage. Each of the components 550, 552, 564, 554, 566, and 568, may be interconnected using various buses, and several of the components may be mounted on a common motherboard or in other manners as appropriate.

[0057] Processor 552 may execute instructions within the computing device 550, including instructions stored in the memory 564. The processor may be implemented as a chipset of chips that include separate and multiple analog and digital processors. The processor may provide, for example, for coordination of the other components of the device 550, such as control of user interfaces, applications run by device 550, and wireless communication by device 550.

[0058] In some embodiments, processor 552 may communicate with a user through control interface 558 and display interface 556 coupled to a display 554. The display 554 may be, for example, a TFT LCD (Thin-Film-Transistor Liquid Crystal Display) or an OLED (Organic Light Emitting Diode) display, or other appropriate display technology. The display interface 556 may comprise appropriate circuitry for driving the display 554 to present graphical and other information to a user. The control interface 558 may receive commands from a user and convert them for submission to the processor 552. In addition, an external interface 562 may be provide in communication with processor 552, so as to enable near area communication of device 550 with other devices. External interface 562 may provide, for example, for wired communication in some embodiments, or for wireless communication in other embodiments, and multiple interfaces may also be used. [0059] In some embodiments, memory 564 may store information within the computing device 550. The memory 564 can be implemented as one or more of a computer-readable medium or media, a volatile memory unit or units, or a non-volatile memory unit or units. Expansion memory 574 may also be provided and connected to device 550 through expansion interface 572, which may include, for example, a SIMM (Single In Line Memory Module) card interface. Such expansion memory 574 may provide extra storage space for device 550, or may also store applications or other information for device 550. Specifically, expansion memory 574 may include instructions to carry out or supplement the processes described above, and may include secure information also. Thus, for example, expansion memory 574 may be provide as a security module for device 550, and may be programmed with instructions that permit secure use of device 550. In addition, secure applications may be provided via the SIMM cards, along with additional information, such as placing identifying information on the SIMM card in a non-hackable manner.

[0060] The memory may include, for example, flash memory and/or NVRAM memory, as discussed below. In one embodiment, a computer program product is tangibly embodied in an information carrier. The computer program product may contain instructions that, when executed, perform one or more methods, such as those described above. The information carrier may be a computer- or machine-readable medium, such as the memory 564, expansion memory 574, memory on processor 552, or a propagated signal that may be received, for example, over transceiver 568 or external interface 562.

[0061 ] Device 550 may communicate wirelessly through communication interface 566, which may include digital signal processing circuitry. Communication interface 566 may provide for communications under various modes or protocols, such as GSM voice calls, SMS, EMS, or MMS speech recognition, CDMA, TDMA, PDC, WCDMA, CDMA2000, Bluecomm, or GPRS, among others. Such communication may occur, for example, through radio-frequency transceiver 568. In addition, short-range communication may occur, such as using a Bluetooth, WiFi, or other such transceiver (not shown). In addition, GPS (Global Positioning System) and/or GNSS (Global Navigation Satellite System) receiver module 570 may provide additional navigation and location- related wireless data to device 550, which may be used as appropriate by applications running on device 550.

[0062] Device 550 may also communicate audibly using audio codec 560, which may receive spoken information from a user and convert it to usable digital information. Audio codec 560 may likewise generate audible sound for a user, such as through a speaker, e.g., in a handset of device 550. Such sound may include sound from voice telephone calls, may include recorded sound (e.g., voice messages, music files, etc.) and may also include sound generated by applications operating on device 550. Various additional and/or alternative components may also be included, such as those involved in enabling undersea communications.

[0063] The flowchart and block diagrams in the figures illustrate the architecture, functionality, and operation of possible implementations of systems, methods and computer program products according to various embodiments of the present disclosure. In this regard, each block in the flowchart or block diagrams may represent a module, segment, or portion of code, which comprises one or more executable instructions for implementing the specified logical function(s). It should also be noted that, in some embodiments, the functions noted in the block may occur out of the order noted in the figures. For example, two blocks shown in succession may, in fact, be executed substantially concurrently, or the blocks may sometimes be executed in the reverse order, depending upon the functionality involved. It will also be noted that each block of the block diagrams and/or flowchart illustration, and combinations of blocks in the block diagrams and/or flowchart illustration, can be implemented by special purpose hardware-based systems that perform the specified functions or acts, or combinations of special purpose hardware and computer instructions.

[0064] As used in any embodiment described herein, the term "circuitry" may comprise, for example, singly or in any combination, hardwired circuitry, programmable circuitry, state machine circuitry, and/or firmware that stores instructions executed by programmable circuitry. It should be understood at the outset that any of the operations and/or operative components described in any embodiment or embodiment herein may be implemented in software, firmware, hardwired circuitry and/or any combination thereof.

[0065] The terminology used herein is for the purpose of describing particular embodiments and is not intended to be limiting of the disclosure. As used herein, the singular forms "a", "an" and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms "comprises" and/or "comprising," when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

[0066] The corresponding structures, materials, acts, and equivalents of means or step plus function elements in the claims below are intended to include any structure, material, or act for performing the function in combination with other claimed elements as specifically claimed. The description of the present disclosure has been presented for purposes of illustration and description, but is not intended to be exhaustive or limited to the disclosure in the form disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure. The embodiment was chosen and described in order to best explain the principles of the disclosure and the practical application, and to enable others of ordinary skill in the art to understand the disclosure for various embodiments with various modifications as are suited to the particular use contemplated.

[0067] Although a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the system described herein. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words 'means for' together with an associated function.

[0068] Having thus described the disclosure of the present application in detail and by reference to embodiments thereof, it will be apparent that modifications and variations are possible without departing from the scope of the disclosure defined in the appended claims.