Patent Publication Number: US-2007107938-A1

Title: Multiple receiver sub-array apparatus, systems, and methods

Description:
TECHNICAL FIELD  
      Various embodiments described herein relate to data acquisition and processing generally, including apparatus, systems, and methods to generate, acquire, and process sonic and seismic data in downhole environments.  
     BACKGROUND INFORMATION  
      Several mechanisms to obtain full waveform seismic and sonic data in the downhole environment are known to those of skill in the art. However, data generation and acquisition to support useful pre-emptive decision-making (e.g., ahead of the bit) can be prohibitively expensive or otherwise impractical to implement. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       FIGS. 1A, 1B , and  1 C illustrate several apparatus, including sub-arrays, according to various embodiments of the invention.  
       FIG. 2  is an illustration of apparatus and systems according to various embodiments of the invention.  
       FIG. 3  is a flow diagram illustrating several methods according to various embodiments of the invention.  
       FIG. 4  is a block diagram of an article according to various embodiments of the invention. 
    
    
     DETAILED DESCRIPTION  
      In some embodiments of the invention, the challenges described above may be addressed by combining one or more sub-arrays of seismic and sonic receivers with one or more seismic and sonic energy sources, configured to meet selected drilling objectives. Telemetry, in analog or digital formats, may be used to provide borehole waveform data to the surface in substantially real-time.  
       FIGS. 1A, 1B , and  1 C illustrate several apparatus  100 , including sub-arrays, according to various embodiments of the invention. For example, a relatively short section of drill pipe  112  may be designed to include a sub-array  110 , perhaps containing one or more sonic receivers  114 , one or more seismic receivers  116 , one or more seismic and/or sonic sources  118 , and one or more telemetry transmitters  120 , telemetry receivers  122 , and/or telemetry repeaters  124 . Thus, it should be apparent to the reader that the sub-array  110  instrumentation need not be limited to one kind of receiver or device. Such a sub-array  110  may serve as a receiver for Very-Long-Spaced Vertical Seismic Profile (VLSVSP) and/or Very-Large-Array Vertical Seismic Profile (VLAVSP) data acquisition and processing schemes.  
      In some embodiments, a number of sub-arrays  110  may be installed in a drill-string  108  to form arrays  126  of sub-arrays  110 , and super-arrays  128 , comprising a number of arrays  126  (in turn, comprising a number of sub-arrays  110 ). Not all sub-arrays  110  may include both receivers  114 ,  116  and repeaters  124 , but in some embodiments, a single, repeatable design (e.g., having a selected number of receivers  114 ,  116 , sources  118 , and telemetry devices  120 ,  122 ,  124 ) may be employed to reduce manufacturing cost. Some of the sub-arrays  110  may contain an active high-frequency source  118 , perhaps used for acoustic logging. Repeaters  124  may be included about every 1000 feet along the drill string  108 , and some sub-arrays  110  may serve as both a repeater (e.g., include one or more telemetry repeater  124  elements) and as a receiver (e.g., including one or more receivers  114 ,  116 ).  
      Receivers  114 ,  116  within the sub-arrays  110  may be spaced a selected distance apart (e.g., an inter-receiver spacing), and groups of receivers  114 ,  116  in sub-arrays may also be spaced at some selected distance apart (e.g., an inter-sub-array distance). Thus, as mentioned previously, two or more sub-arrays  110  may be formed into an array  126 , perhaps to facilitate the application of specific multi-channel algorithms and beam forming. The spacing between sub-arrays  110  within an array  126  may be less than a length or stand of pipe  112 , which may in turn serve to reduce or prevent aliasing of slower waves, including converted shear and coherent noise. The sub-array  110  receiver sections separated by an inter-sub-array distance may be separated by a distance substantially equivalent to the receiver spacing in wireline Vertical Seismic Profile (VSP) applications.  
      For example, one anti-aliasing relationship for maximum receiver (or maximum sub-array  110 ) spacing dz is shown in equation [1]: 
 
 dz=V   min /(2 F   max )  [1]
 
 where V min  is the minimum velocity and F max  is the maximum frequency of the waveform to be recorded. In some embodiments, the spacing of receivers  114 ,  116  within a sub-array  110  to meet the frequency-resolution characteristics of a drilling target  130  may be no larger than about dz, while the correct spatial sampling of the wave field  142  may relate dz to the maximum anticipated slowness of the formations to be encountered. 
 
      Inter-sub-array spacing can be made relatively large and/or variable along the drill string  108  to support an array  126  for a high-resolution, closely-spaced and limited investigation aperture relatively near to the target (e.g., closer to the drill bit  132 ). The inter-sub-array spacing may also support a lower resolution (but still comprise a relatively closely spaced non-aliased array  126 ), wide investigation aperture high in the drill string  108  above the target  130 , including use for VLSVSP operations.  
      For example, the maximum reflection point offset and hence the maximum aperture of investigation Ap on a target  130  may be related to the minimum depth of a buried receiver  114 ,  116  in a sub-array  110  approximately as shown in equation [2]: 
 
 Ap   max =2 X   off ( Dy−Dg )/(2 Dy−Dg ),  [2]
 
 where D r  is the depth of a target and D g     min    is the minimum depth of the receiver for a horizontal source-receiver offset X off , as may be apparent to those of skill in the art after reading the disclosure herein. The image spatial aperture Ap max  may be related to the relative positions of the surface source Xs and the downhole sub-array  110  (e.g., sometimes known in the art as receiver array Dr), and the entire volume  144  of earth material may be traversed by the wave field  142  as it propagates from each source Xs to a receiver  116 , and from various sources Xs, to a target  130 , to a receiver  116  in a sub-array  110 . Since the sources Xs may not be localized to the vicinity of the bottom hole assembly  146 , and since localized sonic tool velocity and control are not required, the sources Xs can be placed, by design, on the surface of the earth  148  to enhance the three-dimensional character of the results, perhaps being used to form a volumetric image of some volume  144  of the earth containing multiple targets  130 . 
 
      One or more surface Xs or sub-surface sources  118  may be employed. Thus, each setting or measurement opportunity may include a series of source activations taken at a level or station while drilling operations are suspended. In addition, one or more of these sources  118 , Xs may be moving in order to generate a horizontal or vertical profile of shot positions while continuously recording with one or more of the receiver arrays held stationary.  
      At a given time, sub-arrays  110  located higher in the drill string  108  may subsequently occupy stations or levels previously occupied by other sub-arrays  110  that are located lower in the drill sting  108 , after the drill string  108  has moved farther down hole (e.g., in direction Y). Redundancy may then be built into some embodiments. For example, depending on the depth interval between the stations or levels (which need not be taken at every stand but could well be over several stands of pipe  112  distant), a very large array VSP (VLAVSP) could include hundreds of levels of sub-array acquisition experiments. Indeed, the VLAVSP might be prohibitively expensive to acquire any other way, since the sub-arrays  110  may be located to move along the borehole with the drill string.  
      Even if single sub-arrays  110  are employed, and separated by relatively large distances (e.g., larger than an appropriate non-aliased receiver spacing), it may be possible to form a plurality of sub-arrays  110  into synthetic sub-arrays as data are accumulated. Certain additional processing to eliminate shot-to-shot variations might be required to formulate the synthetic arrays, perhaps similar to those processes used in vertical stacking operations. This approach may also require more time to execute, since multiple station acquisition may be needed before a synthetic array can be formed.  
      Receivers  114 ,  116  and repeaters  124  in a sub-array  110  may be combined with a high frequency source  118  for single well imaging (SWI) and steering applications. The sources  118  can be placed between sub-arrays  110 , or within sub-arrays  110 . Thus, single and multiple sources  118  can be placed between, within, or on either end of one or more sub-arrays  110 . Processing of acquired data may be similar to that which is employed for surface off-end and seismic split-spreads, as will become apparent to those of skill in the art after reading the material disclosed herein. Sources  118  transmitting sonic energy to sub-arrays  110  in the drill string  108  may also be placed near to, or at, the drill bit  132 , perhaps to implement a reverse VSP (RVSP) process.  
      In some embodiments, independent sub-arrays  110  may be placed along the entire length of a drill string  108  so that specific geophysical target objectives are met. Such objectives may include imaging ahead of the bit  132 , determining seismic travel time to depth, reconciliation of seismic targets with drilling results, AVO (amplitude versus incidence angle) studies, shear wave-particle motion studies, migration, and inversion for interval velocities ahead of the bit  132 .  
      Parameter determination may be conducted in a volumetric, three-dimensional framework where the independent variables (e.g., time and velocity) are a function of all three dimensions (e.g., f(x, y, z)). This framework may be influenced by the spacing of the receivers  114 ,  116  placed-by-design along the entire length of the drill string  108  (and the path of a borehole in three-dimensional space).  
      While not being limited as such, various embodiments may be useful in the seismic bandwidth (e.g., about 10-1000 Hertz), as well as in the sonic bandwidth (e.g., about 2 kHz-20 kHz). It should be noted that velocity dispersion related to ranging seismically-defined targets  130  does not usually lend itself to sonic-defined velocities. This is because localized velocity measurements may neglect the three-dimensional character of the velocity field earth model through which surface-generated wave fields  142  can propagate. Thus, tool techniques using only sonic frequency wave fields tend to be essentially one-dimensional. Therefore, in many embodiments, the location of sub-arrays  110  along a drill string  108  are more likely to be subject to three-dimensional seismic (and not local sonic) velocities, the three-dimensional borehole path, and a planned surface source Xs distribution pattern.  
      In some embodiments, VLAVSP techniques may enable the construction of a multi-dimensional survey for more than one specific objective within a while-drilling environment. VLAVSP sensor distribution, via the use of sub-arrays  110 , may comprise a piecewise-continuous three-dimensional array, properly (e.g., according to sampling theory) and uniquely (e.g., in localized regions separated by relatively large gaps) distributed in space, so as to substantially simultaneously obtain measurements of a three-dimensional seismic wave field  142  during the drilling of a well.  
      It can now be seen that many embodiments may be realized. For example, an apparatus  100  may include one or more sub-arrays  110  of receivers  114 ,  116  included in a drill string  108 . The apparatus  100  may also include one or more sources  118  of sonic energy to be received by the sub-arrays  110  of receivers  114 ,  116 . The source  118  may be included in the drill string  108  and disposed between the two sub-arrays  110  of receivers  114 ,  116 , as well as within one or more sub-arrays  110 .  
      Sub-arrays  110  may include one or more sensor elements (e.g., receivers  114 ,  116 ) which are not considered to be co-located in relation to sonic sources  118  that may be used in conjunction with them. However, some embodiments of the apparatus  100  may include other types of reception devices  150 , such as groups of geophones, accelerometers, and hydrophones. These devices  150  may be separated linearly, but considered to be co-located with respect to the surface source Xs seismic frequencies. When sources  118  are located off each end of an array  110  and activated in succession, it may be possible to do geometric (environmental, borehole rugosity, tool tilt etc.) corrections and fore-aft looking application processing.  
      In some embodiments, the receivers  114 ,  116  in a sub-array  110  may be spaced apart from the receivers  114 ,  116  in another sub-array  110  of receivers by about a non-aliased receiver spacing distance (e.g., dz). One or more borehole clamping devices  152  (e.g., a clamping arm) may be attached to the sub-arrays  110 , perhaps to improve coupling between seismic receiver elements  116  and the borehole wall and to record impinging wavefields  142  with high fidelity.  
      As mentioned previously, one or more telemetry repeaters  124  may be included in the sub-arrays  110 . The telemetry repeaters  124  may comprise units similar to or identical to those used in the Novatek Engineering 2 Mbps drill pipe telemetry system and the Grant Prideco Inc. IntelliPipe telemetry system for borehole seismic applications. Such telemetry repeaters  124  may support transmission of waveforms to the surface  148  to enable practical realization of real-time borehole seismic data acquisition and predictive drilling operations.  
      In some embodiments, an apparatus  100  may have two or more sub-arrays  110  of receivers  114 ,  116  included in a drill string  108 . The sub-arrays  110  may be spaced apart by about a non-aliased receiver spacing distance, and the apparatus  100  may include a source Xs of surface seismic energy to be received by the sub-arrays  110 . In some cases, sub-arrays  110  may be spaced apart from other sub-arrays  110  by a distance associated with a selected aperture of investigation, or a distance associated with formation slowness.  
      Longer arrays  126  typically permit larger data acquisition apertures. Superarrays  128  of dissimilar design may also be combined within a single drill string  108 . For example, one superarray  128  may be located in a relatively shallow location (higher in the drill string  108 ) and another superarray  128  may be located fairly deep, perhaps at the imaging/information stage. The distal superarray  128  may have a larger aperture, since the numerator in equation [2] increases faster than the denominator and a distant viewpoint provides greater scope, and the proximal superarray  128  may have greater resolving power, since the distance Ap (and the rate of change of Ap) in equation [2] decreases as Dg approaches the target Dr to reveal greater detail, perhaps through a tighter concentration of reflection points. Additional superarrays  128  have not been shown in  FIG. 1B  to prevent obscuring other elements in the figure.  
      There may be design tradeoffs involved between resolution and coverage. In some cases, aliasing limitations may involve the slowness of a converted wave or a tube wave (e.g., considered to be noise that is removed in processing), and additional sampling may be used to provide improved results.  
      Many other embodiments may be realized. For example, an apparatus  100  may include a telemetry repeater  124  to receive and re-transmit data, a sub-array of drill string receivers  114 ,  116  coupled to the telemetry repeater  124 , and a source  118  of sonic energy to be received by the sub-array  110  of drill string receivers  114 ,  116 . The source  118  may be located within the sub-array  110 , or external to the sub-array, somewhere along the length of the drill string  108 , perhaps in the same pipe stand. Some apparatus  100  may include a borehole clamping device  152  attached to the sub-array  110  of drill string receivers  114 ,  116 . Some apparatus  100  (e.g., an array  126 ) may also include a second telemetry repeater  124  to receive and re-transmit the data, a second sub-array  110  of drill string receivers coupled to the second telemetry repeater  124 , and a second source  118  of sonic energy to be received by the second sub-array  110  of drill string receivers  114 ,  116 .  
      Still further embodiments may be realized. For example, an apparatus  100  may have a first sub-array  110  of receivers  114 ,  116  included in a drill string  108 , as well as a first source  118  of sonic energy included in the drill string  108 , perhaps located proximate to and separated from one end of the first sub-array  110  of receivers  114 ,  116 . The apparatus  100  may also include a second source  118  of sonic energy included in the drill string  108  and located proximate to and separated from another end of the first sub-array  110  of receivers  114 ,  116 . In some embodiments, the apparatus  100  may include a second sub-array  110  of receivers  114 ,  116  spaced apart from the first sub-array  110  of receivers  114 ,  116  by about a non-aliased receiver spacing distance (e.g., dz). The receivers may  114 ,  116  be substantially linearly distributed along the length of the drill string  108 , and the apparatus  100  may include one or more devices  150 , such as geophones, hydrophones, and accelerometers. The apparatus  100  may also include one or more telemetry repeaters  124 .  
       FIG. 2  is an illustration of apparatus  200  and systems  264  according to various embodiments, perhaps used as part of a downhole drilling operation. The apparatus  200  may be similar to or identical to the apparatus  100  described above, and seen in  FIG. 1A . Thus, in some embodiments, a system  264  may form a portion of a drilling rig  202  located at the surface  204  of a well  206 . The drilling rig  202  may provide support for a drill string  208 , similar to or identical to the drill string  108  shown in  FIGS. 1A and 1B . The drill string  208  may operate to penetrate a rotary table  256  for drilling a borehole  280  through sub-surface formations  214 . The drill string  208  may include a Kelly  260 , drill pipe  212 , and a bottom hole assembly  246 , perhaps located at the lower portion of the drill pipe  212 . The drill string may include one or more super-arrays  228 .  
      The bottom hole assembly  246  may include drill collars  262 , a downhole tool  270 , and a drill bit  232 . The drill bit  232  may operate to create a borehole  280  by penetrating the surface  204  and sub-surface formations  214 . The downhole tool  270  may comprise any of a number of different types of tools including MWD (measurement while drilling) tools, LWD (logging while drilling) tools, and others.  
      During drilling operations, the drill string  208  (perhaps including the Kelly  260 , the drill pipe  212 , and the bottom hole assembly  246 ) may be rotated by the rotary table  256 . In addition to, or alternatively, the bottom hole assembly  246  may also be rotated by a motor (e.g., a mud motor) that is located downhole. The drill collars  262  may be used to add weight to the drill bit  232 . The drill collars  262  also may stiffen the bottom hole assembly  246  to allow the bottom hole assembly  246  to transfer the added weight to the drill bit  232 , and in turn, assist the drill bit  232  in penetrating the surface  204  and sub-surface formations  214 .  
      During drilling operations, a mud pump  272  may pump drilling fluid (sometimes known by those of skill in the art as “drilling mud”) from a mud pit  274  through a hose  236  into the drill pipe  212  and down to the drill bit  232 . The drilling fluid can flow out from the drill bit  232  and be returned to the surface  204  through an annular area  240  between the drill pipe  212  and the sides of the borehole  280 . The drilling fluid may then be returned to the mud pit  274 , where such fluid is filtered. In some embodiments, the drilling fluid can be used to cool the drill bit  232 , as well as to provide lubrication for the drill bit  232  during drilling operations. Additionally, the drilling fluid may be used to remove sub-surface formation  214  cuttings created by operating the drill bit  232 .  
      Thus, referring now to  FIGS. 1A-1C  and  2 , it may be seen that in some embodiments, the system  264  may include a drill string  108 ,  208 ; a first sub-array  110  of receivers  114 ,  116  included in the drill string  108 ,  208 ; a second sub-array  110  of receivers  114 ,  116  included in the drill string  108 ,  208 ; and one or more sources  118  of sonic energy to be received by the first and second sub-arrays  110  of receivers  114 ,  116 . The sources  118  may be included in the drill string  108 ,  208 , and be disposed between the two sub-arrays  110  of receivers  114 ,  116 . The sub-arrays  110  may be spaced apart by about a non-aliased receiver spacing distance.  
      In some embodiments, the system  264  may include a first telemetry repeater  124  included in the first sub-array  110  of receivers  114 ,  116 ; and a second telemetry repeater  124  included in the second sub-array  100  of receivers  114 ,  116 . The system  264  may also include a telemetry receiver  122  to receive data from the first telemetry repeater  124 , and/or a telemetry transmitter  120  to transmit the data to another telemetry receiver  122  or repeater  124 .  
      Other embodiments may be realized. For example, a system  264  may include a drill string  108 ,  208 ; a first sub-array  110  of receivers  114 ,  116  included in the drill string  108 ,  208 ; a second sub-array  110  of receivers  114 ,  116  included in the drill string  108 ,  208  and spaced apart from the first sub-array  110  of receivers  114 ,  116  by no more than a non-aliased receiver spacing distance; and a source Xs of surface seismic energy to be received by the first sub-array  110  of receivers  114 ,  116  and the second sub-array  110  of receivers  114 ,  116 .  
      The system  264  may include a first telemetry repeater  124  included in the first sub-array  110  of receivers  114 ,  116 ; and a second telemetry repeater  124  included in the second sub-array  110  of receivers  114 ,  116 . The system  264  may also include other sub-arrays  110 , perhaps spaced apart from the first and/or second sub-arrays  110  by no more than the non-aliased receiver spacing distance, or a selected aperture of investigation, or a formation slowness, for example.  
      Any of the components previously described can be implemented in a number of ways, including software embodiments. Thus, the surface sources Xs; apparatus  100 ,  200 ; drill-strings  108 ,  208 ; drill pipe  112 ; sub-array  110 ; sonic receivers  114 ; seismic receivers  116 ; sub-surface sources  118 ; telemetry transmitters  120 ; telemetry receivers  122 ; telemetry repeaters  124 ; arrays  126 ; super-arrays  128 ,  228 ; targets  130 ; drill bits  132 ,  232 ; wave fields  142 ; volume  144 ; bottom hole assemblies  146 ,  246 ; surface of the earth  148 ; reception devices  150 ; clamping devices  152 ; drilling rig  202 ; well surface  204 ; well  206 ; borehole  280 ; sub-surface formations  214 ; hose  236 ; annular area  240 ; rotary table  256 ; Kelly  260 ; drill collars  262 ; systems  264 ; downhole tool  270 ; mud pump  272 ; and mud pit  274  may all be characterized as “modules” herein. Such modules may include hardware circuitry, and/or a processor and/or memory circuits, software program modules and objects, and/or firmware, and combinations thereof, as desired by the architect of the apparatus  100 ,  200  and systems  264 , and as appropriate for particular implementations of various embodiments. For example, in some embodiments, such modules may be included in an apparatus and/or system operation simulation package, such as a software electrical signal simulation package, a power usage and distribution simulation package, a real-time telemetry simulation package, a power/heat dissipation simulation package, and/or a combination of software and hardware used to simulate the operation of various potential embodiments.  
      It should also be understood that the apparatus and systems of various embodiments can be used in applications other than for drilling operations, and thus, various embodiments are not to be so limited. The illustrations of apparatus  100 ,  200  and systems  264  are intended to provide a general understanding of the structure of various embodiments, and they are not intended to serve as a complete description of all the elements and features of apparatus and systems that might make use of the structures described herein.  
      Applications that may include the novel apparatus and systems of various embodiments include electronic circuitry used in high-speed computers, communication and signal processing circuitry, modems, processor modules, embedded processors, data switches, and application-specific modules, including multilayer, multi-chip modules. Such apparatus and systems may further be included as sub-components within a variety of electronic systems, such as televisions, cellular telephones, personal computers, workstations, radios, video players, vehicles, and borehole data acquisition and data transmission systems, among others. Some embodiments include a number of methods.  
      For example,  FIG. 3  is a flow diagram illustrating several methods  311 ,  361  according to various embodiments. In some embodiments of the invention, a method  311  may (optionally) begin at block  321  with moving a drill string through a borehole while acquiring data generated by a plurality of receiver sub-arrays included in the drill string. The sub-arrays may be separated by one or more sources of sonic energy, and the sonic energy may be received by the sub-arrays at a plurality of stations. The method  311  may continue with sending the data via telemetry through one or more telemetry repeaters co-located with the sub-arrays at block  325 , as well as collecting the data at a receiver, including a telemetry receiver, at block  329 . The method  311  may also include redundantly collecting the data using one of the sub-arrays to acquire a portion of the data previously acquired by another one of the plurality of receiver sub-arrays at block  333 .  
      Those of ordinary skill in the art are familiar with several methods for the construction of synthetic sub-arrays. For example, a method of sub-array construction termed “beam-steering” is described in “A Geophone Subarray Beam-Steering Process” by Dale E. Biswell, Larry F. Konty, and Alfred L. Liaw; Geophysics, Vol. 49, No. 11; 1984. A similar mechanism is described in U.S. Pat. No. 4,319,347, issued to Savit. Thus, in some embodiments, the method  311  may include forming a synthetic sub-array at block  337  by collecting the data from two or more of the plurality of receiver sub-arrays, perhaps spaced farther apart from each other than a non-aliased receiver spacing distance.  
      The method  311  may also include predicting pressure-related phenomena (and other phenomena known to those of skill in the art) based on the data at block  341 , as well as steering the drill string in response to the data at block  345 . The data collected may include any type of information, such as pressure, sound velocity, slowness, and sound reflection data (e.g., from targets and formations), among others.  
      Given the wide range of elements that can be included in the sub-arrays, within a drill string, and within the systems described to this point, many variations may be realized. For example, the method  311  may include moving one or more sources at block  349  to generate a horizontal profile or a vertical profile of shot positions while substantially continuously recording data (e.g., this means that data can be recorded in a substantially continuous manner except during the operation of moving the drill string).  
      Those of ordinary skill in the art are familiar with combining multiple source activations to form source arrays (e.g., multiple shots into a receiver, known in the art as a “common receiver gather”) or receiver arrays (e.g., single shot, multiple receivers, known in the art as a “common shot gather”) in order to take advantage of the geometric moveout and redundancy characteristics of these gathers to enhance slowness estimation or imaging. For more information on this subject, one may refer to “Multiple-Shot Processing of Array Sonic Waveforms” by Hsu, Kai, Shu-Kong Chang; Geophysics, Vol. 52, No. 10; 1987. Thus, in some embodiments, the method  311  may include substantially successively activating a first and a second source of sonic energy, and then executing a geometric correction, or a fore-aft looking application at block  353 , among others.  
      Still other embodiments may be realized. For example, a method  361  may include activating a surface source of seismic energy, and receiving the seismic energy at a first sub-array of drill string receivers at block  371 .  
      The method  361  may also include collecting data at a plurality of stations in a borehole using a telemetry receiver at block  375 , wherein a first portion of the data is generated by a first drill string sub-assembly including: a first telemetry repeater (to receive and re-transmit the first portion of the data), a first sub-array of drill string receivers coupled to the first telemetry repeater, and a first source of sonic energy to be received by the first sub-array of drill string receivers.  
      The method  361  may also include, at block  379 , collecting a second portion of the data in the borehole using the telemetry receiver, wherein the second portion of the data is generated by a second drill string sub-assembly including: a second telemetry repeater to receive and re-transmit the second portion of the data, a second sub-array of drill string receivers coupled to the second telemetry repeater, and a second source of sonic energy to be received by the second sub-array of drill string receivers. Activities occurring at block  379  may also include redundantly collecting the first portion of the data as the second portion of the data.  
      It should be noted that the methods described herein do not have to be executed in the order described, or in any particular order. Moreover, various activities described with respect to the methods identified herein can be executed in iterative, serial, or parallel fashion. Information, including parameters, commands, operands, and other data, can be sent and received in the form of one or more carrier waves.  
      Upon reading and comprehending the content of this disclosure, one of ordinary skill in the art will understand the manner in which a software program can be launched from a computer-readable medium in a computer-based system to execute the functions defined in the software program. One of ordinary skill in the art will further understand the various programming languages that may be employed to create one or more software programs designed to implement and perform the methods disclosed herein. The programs may be structured in an object-orientated format using an object-oriented language such as Java or C++. Alternatively, the programs can be structured in a procedure-orientated format using a procedural language, such as assembly or C. The software components may communicate using any of a number of mechanisms well known to those skilled in the art, such as application program interfaces or interprocess communication techniques, including remote procedure calls. The teachings of various embodiments are not limited to any particular programming language or environment. Thus, other embodiments may be realized.  
       FIG. 4  is a block diagram of an article  485  according to various embodiments, such as a computer, a memory system, a magnetic or optical disk, some other storage device, and/or any type of electronic device or system. The article  485  may include a processor  487  coupled to a machine-accessible medium such as a memory  489  (e.g., removable storage media, as well as any memory including an electrical, optical, or electromagnetic conductor) having associated information  491  (e.g., computer program instructions and/or data), which when accessed, results in a machine (e.g., the processor  487 ) performing such actions as collecting data at a plurality of stations in a borehole using a telemetry receiver, wherein a first portion of the data is generated by a first drill string sub-assembly including a first telemetry repeater to receive and re-transmit the first portion of the data, a first sub-array of drill string receivers coupled to the first telemetry repeater, and a first source of sonic energy to be received by the first sub-array of drill string receivers.  
      Additional activities may include collecting a second portion of the data in the borehole using the telemetry receiver, wherein the second portion of the data is generated by a second drill string sub-assembly including a second telemetry repeater to receive and re-transmit the second portion of the data, a second sub-array of drill string receivers coupled to the second telemetry repeater, and a second source of sonic energy to be received by the second sub-array of drill string receivers. Further activities may include redundantly collecting the first portion of the data as the second portion of the data, as well as activating a surface source of seismic energy; and receiving the seismic energy at the first sub-array of drill string receivers. Other embodiments may be derived by reviewing the descriptions of various methods given above.  
      Implementing the apparatus, systems, and methods of various embodiments may enable the provision of high-fidelity seismic waveform data in substantially real-time, perhaps via broad-band telemetry. The uses of these data include but are not limited to real-time applications such as: drill bit location with respect to a sub-array surface target in depth or in surface seismic time, pressure prediction, stress prediction, prediction of seismic-petrophysical parameters ahead of the bit, sub-surface imaging, locating casing points, and the identification of drilling hazards. Providing these data in real-time while drilling, and the look-ahead character of the data collected, make pre-emptive (e.g., ahead of the bit) real-time drilling decisions feasible.  
      The accompanying drawings that form a part hereof, show by way of illustration, and not of limitation, specific embodiments in which the subject matter may be practiced. The embodiments illustrated are described in sufficient detail to enable those skilled in the art to practice the teachings disclosed herein. Other embodiments may be utilized and derived therefrom, such that structural and logical substitutions and changes may be made without departing from the scope of this disclosure. This Detailed Description, therefore, is not to be taken in a limiting sense, and the scope of various embodiments is defined only by the appended claims, along with the full range of equivalents to which such claims are entitled.  
      Such embodiments of the inventive subject matter may be referred to herein, individually and/or collectively, by the term “invention” merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed. Thus, although specific embodiments have been illustrated and described herein, it should be appreciated that any arrangement calculated to achieve the same purpose may be substituted for the specific embodiments shown. This disclosure is intended to cover any and all adaptations or variations of various embodiments. Combinations of the above embodiments, and other embodiments not specifically described herein, will be apparent to those of skill in the art upon reviewing the above description.  
      The Abstract of the Disclosure is provided to comply with 37 C.F.R. § 1.72(b), requiring an abstract that will allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. In addition, in the foregoing Detailed Description, it can be seen that various features are grouped together in a single embodiment for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed embodiments require more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive subject matter lies in less than all features of a single disclosed embodiment. Thus the following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separate embodiment.