Patent Application
20070107938
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.
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.
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.
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=Vmin/(2Fmax) [1]
where Vmin is the minimum velocity and Fmax 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]:
Apmax=2Xoff(Dy−Dg)/(2Dy−Dg), [2]
where Dr is the depth of a target and Dg
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
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.
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
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,
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.
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.
