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WO2008150253A1 - Systèmes et procédés de diagraphie avec compensation d'inclinaison pour des outils acoustiques spécifiques à un secteur - Google Patents

Systèmes et procédés de diagraphie avec compensation d'inclinaison pour des outils acoustiques spécifiques à un secteur Download PDF

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Publication number
WO2008150253A1
WO2008150253A1 PCT/US2007/012087 US2007012087W WO2008150253A1 WO 2008150253 A1 WO2008150253 A1 WO 2008150253A1 US 2007012087 W US2007012087 W US 2007012087W WO 2008150253 A1 WO2008150253 A1 WO 2008150253A1
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WIPO (PCT)
Prior art keywords
tool
acoustic
logging
borehole
tilt
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2007/012087
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English (en)
Inventor
Don Crawford
Batakrishna Mandal
Clovis F. Bonavides
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Filing date
Publication date
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Priority to CA2673243A priority Critical patent/CA2673243C/fr
Priority to PCT/US2007/012087 priority patent/WO2008150253A1/fr
Publication of WO2008150253A1 publication Critical patent/WO2008150253A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/46—Data acquisition

Definitions

  • the collection of information relating to conditions down- hole which commonly is referred to as "logging”, can be performed by several methods including wireline logging and "logging while drilling” (LWD).
  • a probe or "sonde” In wireline logging, a probe or "sonde” is lowered into the borehole after some or all of a well has been drilled.
  • the sonde hangs at the end of a long cable or “wireline” that provides mechanical support to the sonde and also provides an electrical connection between the sonde and electrical equipment located at the surface of the well.
  • various parameters of the earth's formations are measured and correlated with the position of the sonde in the borehole as the sonde is pulled uphole.
  • the drilling assembly includes sensing instruments that measure various pa- rameters as the formation is being penetrated, thereby enabling measurements of the formation while it is less affected by fluid invasion. While LWD measurements are desirable, drilling operations create an environment that is generally hostile to electronic instrumentation, telemetry, and sensor operations.
  • Acoustic logging tools can be employed in both wireline logging and LWD environ- ments.
  • Acoustic well logging is a well-developed art, and details of acoustic logging tools and techniques are set forth in A. Kurkjian, et al., "Slowness Estimation from Sonic Logging Waveforms", Geoexploration, Vol. 277, pp. 215-256 (1991); C. F. Morris et al., "A New Sonic Array Tool for Full Waveform Logging," SPE- 13285, Society of Petroleum Engineers (1984); A. R. Harrison et al., "Acquisition and Analysis of Sonic Waveforms From a Borehole Monopole and Dipole Source . . . " SPE 20557, pp.
  • An acoustic logging tool typically includes an acoustic source (transmitter), and a set of receivers that are spaced several inches or feet apart. An acoustic signal is transmitted by the acoustic source and received at the receivers which are spaced apart from the acoustic source. Measurements are repeated every few inches as the tool passes along the borehole.
  • the acoustic signal from source travels through the formation adjacent the borehole to the receiver array, and the arrival times and perhaps other characteristics of the receiver responses are recorded.
  • compressional wave (P-wave), shear wave (S-wave), and Stoneley wave arrivals and waveforms are detected by the receivers and are processed.
  • the processing of the data is often accomplished by an uphole computer system or may be processed real time by a processor in the tool itself. Regardless, the information that is recorded is typically used to find formation characteristics such as formation slowness (the inverse of acoustic speed), from which pore pressure, porosity, and other formation property determinations can be made. In some tools, the acoustic signals may even be used to image the formation.
  • Fig. 1 shows an illustrative logging while drilling environment
  • Fig. 2 shows an illustrative wireline logging environment
  • Fig. 3 shows an illustrative acoustic logging tool
  • Fig. 4 shows the sectorization of an illustrative acoustic receiver
  • Fig. 5 illustrates an off-center and tilted acoustic logging tool
  • Figs. 6A and 6B show illustrative waveforms received in opposing sectors of the tool of Fig. 5;
  • Fig. 7 A and 7B are slowness-time semblance graphs illustrating the effects of tool tilt;
  • Fig. 8 is a flow diagram of an illustrative acoustic logging method with tilt compensation
  • Fig. 9 is a block diagram of an illustrative computer system suitable for implementing aspects of the disclosed methods. While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.
  • Some method embodiments include: generating an acoustic signal that propagates along a borehole in a formation; receiving a signal from each of a set of azimuthally-arranged acoustic transducers; processing the signals to compensate for logging tool tilt; and determining a property of the formation based at least in part on the compensated signals.
  • Some tool embodiments include an internal controller that processes signals from different directions to determine and correct time offsets that are attributable to logging tool tilt. Thereafter, the tilt-compensated signals can be used to measure formation and borehole parameters which may be associated with position and displayed in the form of borehole logs and/or images.
  • Fig. 1 shows an illustrative logging while drilling (LWD) environment.
  • a drilling platform 2 supports a derrick 4 having a traveling block 6 for raising and lowering a drill string 8.
  • a kelly 10 supports the drill string 8 as it is lowered through a rotary table 12.
  • a drill bit 14 is driven by a downhole motor and/or rotation of the drill string 8. As bit 14 rotates, it creates a borehole 16 that passes through various formations 18.
  • a pump 20 circulates drilling fluid through a feed pipe 22 to kelly 10, downhole through the interior of drill string 8, through orifices in drill bit 14, back to the surface via the annulus around drill string 8, and into a reten- tion pit 24.
  • the drilling fluid transports cuttings from the borehole into the pit 24 and aids in maintaining the borehole integrity.
  • An acoustic LWD tool 26 is integrated into the bottom-hole assembly near the bit 14. As the bit extends the borehole through the formations, logging tool 26 collects measurements relating to various formation properties as well as the tool orientation and various other drilling conditions.
  • the logging tool 26 may take the form of a drill collar, i.e., a thick-walled tubular that provides weight and rigidity to aid the drilling process.
  • a telemetry sub 28 may be included to transfer tool measurements to a surface receiver 30 and to receive commands from the surface. In some embodiments, the telemetry sub 28 does not communicate with the surface, but rather stores logging data for later retrieval at the surface when the logging assembly is recovered.
  • the drill string 8 may be removed from the borehole as shown in Fig. 2.
  • logging operations can be conducted using a wireline logging tool 34, i.e., a sensing instrument sonde suspended by a cable 42 having conductors for transporting power to the tool and telemetry from the tool to the surface.
  • An acoustic logging tool 34 may have pads and/or centralizing springs to maintain the tool near the axis of the borehole as the tool is pulled uphole.
  • a logging facility 44 collects measurements from the logging tool 34, and includes a computer system 45 for processing and storing the measurements gathered by the logging tool.
  • Fig. 3 shows an enlarged view of an illustrative acoustic logging tool 26 in a borehole 16.
  • the logging tool 26 includes an acoustic source 52, an acoustic isolator 54, and an array of acoustic receivers 56.
  • the source 52 may be a monopole, dipole, quadrupole, or higher-order multi-pole transmitter. Some tool embodiments may include multiple acoustic sources or one acoustic source that is configurable to generate different wave modes.
  • the acoustic source may be made up of piezoelectric elements, bender bars, or other transducers suitable for generating acoustic waves in downhole conditions.
  • the contemplated operating frequencies for the acoustic logging tool are in the range between 0.5kHz and 30kHz, inclusive.
  • the operating frequency may be selected on the basis of a tradeoff between attenuation and wavelength in which the wavelength is minimized subject to requirements for limited attenuation. Subject to the attenua- tion limits on performance, smaller wavelengths may offer improved spatial resolution of the tool.
  • the acoustic isolator 54 serves to attenuate and delay acoustic waves that propagate through the body of the tool from the source 52 to the receiver array 56. Any standard acoustic isolator may be used.
  • Receiver array 56 includes multiple sectorized receivers 58 spaced apart along the axis of the tool. Although five receivers 58 are shown in Fig. 3, the number can vary from one to sixteen or more.
  • Each sectorized receiver 58 includes a number of azimuthally spaced sectors. Referring momentarily to Fig. 4, a receiver 58 having eight sectors A1-A8 is shown. However, the number of sectors can vary and is preferably (but not necessarily) in the range between 4 and 16, inclu- sive.
  • Each sector may include a piezoelectric element that converts acoustic waves into an electrical signal that is amplified and converted to a digital signal. The digital signal from each sector is individually measured by an internal controller for processing, storage, and/or transmission to an uphole computing facility.
  • the individual sectors can be calibrated to match their responses, such calibrations may vary differently for each sector as a function of temperature, pressure, and other environmental factors. Accordingly, in at least some embodiments, the individual sectors are machined from a cylindrical (or conical) transducer. In this fashion, it can be ensured that each of the receiver sectors will have matching characteristics.
  • the internal controller controls the triggering and timing of the acoustic source 52, and records and processes the signals from the receiver array 56.
  • the internal controller fires the acoustic source 52 periodically, producing acoustic pressure waves that propagate through the fluid in borehole 16 and into the surrounding formation. At the borehole boundary, some of the acoustic energy is converted into shear waves that propagate along the interface between the borehole fluid and the formation. As these "interface waves" propagate past the receiver array 56, they cause pressure variations that can be detected by the receiver array elements.
  • the receiver array signals may be processed by the internal controller to determine the true formation shear velocity, or the signals may be communicated to the uphole computer system for processing.
  • the measurements are associated with borehole position (and possibly tool orientation) to generate a log or image of the acoustical properties of the borehole. The log or image is stored and ultimately displayed for viewing by a user.
  • the processing methods applied to the acoustic tool measurements commonly assume that the acoustic logging tool is centered, or at least that the logging tool axis parallels the borehole axis. In practice, however, the logging tool can move off-center and become tilted relative to the borehole axis as shown in Fig. 5. In Fig. 5, the acoustic logging tool is offset by 2 inches and tilted at 2.5° relative to the axis of a 10 inch borehole through a 50 ⁇ s/ft formation. Such tilts, alone or in conjunction with off-centering, have been found to cause anomalous slowness measurements.
  • the tool tilt produces a gradual shortening of the tool-to-borehole wall offset on one side of the tool, and a gradual lengthening of the offset on the opposite side of the tool.
  • the acoustic waves 62 propagating along one side of the borehole may appear to be propagating past the receiver array at a greater velocity than the acoustic waves 64 propagating along the opposite side of the borehole.
  • Fig. 6A shows a set of amplitude versus time waveforms 62 recorded from (say) the A3 sectors of each receiver in the receiver array.
  • the receivers are located at 3, 3.5, 4, 4.5, and 5 ft from the acoustic source, and various slowness value slopes are shown to aid interpretation.
  • Fig. 6B shows the set of amplitude versus time waveforms 64 recorded from A7, the sector opposite A3 and tilting away from the borehole wall.
  • the time scale is from 68 to 1832 ⁇ s.
  • Each of the waveforms is shown for a corresponding receiver as a function of time since the transmitter firing. (Note the increased time delay before the acoustic wave reaches the increasingly distant receivers.)
  • the internal controller After recording the waveforms, the internal controller typically normalizes the waveform so that they have the same signal energy.
  • the internal controller or uphole processing system may calculate the time semblance E(t,s) as a function of slowness and time for the data.
  • This information in turn may be used to determine various formation properties, including wave propagation velocity and dispersion of acoustic waves.
  • N is the number of receiver elements, and hence is also the number of recorded waveforms
  • *,(0 is the waveform recorded by the fth receiver, d, is the distance of the /th receiver from the transmitter
  • s is the slowness.
  • the quantity (t-sd,) is the relative time at the /th receiver for a given slowness s.
  • Semblance values E(t,s) range between zero and one. Values near one indicate a high correlation between the various recorded waveforms at the given time and slowness, and hence indicate the presence of a propagating wave having that slowness value. Values near zero indicate little correlation between the various waveforms at the given time and slowness value, and hence provide no indication of a propagating wave having that slowness value.
  • Fig. 7A shows a plot of the time semblance E(t,s) as a function of time and slowness for the waveforms of Fig. 6A
  • Fig. 7B shows a similar plot for the waveforms of Fig. 6B.
  • slowness are the first-arrival peaks, i.e., the peaks in the lower left comer, corresponding to the fastest waves.
  • the graph on the right shows the maximum semblance value found for a given slowness value.
  • the first arrival peak 72 has a maximum semblance value at 41.7 ⁇ s/ft
  • the first arrival peak has a maximum semblance value at 58 ⁇ s/ft.
  • the receiver sectors tilting toward the borehole wall measure a reduced slowness (i.e., a faster propagation speed)
  • the receiver sectors tilted away from the borehole wall measure an increased slowness (i.e., a slower propagation speed). If, in each receiver, all the sector measurements were combined, the resulting semblance calculations would have revealed an unnecessarily broad distribution of propagation speeds, possibly having a peak at an incorrect value.
  • Fig. 8 is a flow diagram of an illustrative acoustic logging method with tilt compensation.
  • the acoustic logging tool is inserted in the borehole, and as the drilling process progresses or as the wireline sonde is pulled, the logging tool moves along the borehole as indicated in block 82.
  • the logging tool's internal controller periodically fires the acoustic transmitter and collects sector-specific measurements from each of the receivers in the receiver array.
  • the internal controller processes the measurements to determine the tool tilt effect, and may further calculate the tool offset and tilt relative to the borehole axis.
  • the internal controller determines tool offset and tilt by first summing the sector-specific measurements for each receiver to obtain each receiver's full radial response. The internal controller then measures the time semblance as given in equation (1) to determine a first arrival window, i.e., a time window in which the transmitted acoustic signal first reaches each of the receivers.
  • a suitable window length might be 100 ⁇ s, centered on the time value for the first-arrival peak and shifted for subsequent receivers in accordance with the slowness value for the first-arrival peak.
  • the internal controller analyzes the sector-specific signals to determine a time offset between the waveforms of the different signals.
  • the internal controller may employ a threshold crossing or a peak-detection technique to measure a time offset for each sector-specific signal, e.g. relative to the center or leading edge of the time window.
  • the peak detection may be performed on an envelope of the sector specific signals, the envelope being determined by rectification and low-pass filtering.
  • the internal controller may select one of the sector-specific signals as a reference and perform a semblance or correlation calculation to determine the time offset of the other waveforms relative to the reference signal.
  • the time-offset determination is performed between the sectors for each of the receivers.
  • the internal controller determines whether a tilt effect correction is needed.
  • the maximum time offset (or the average time offset magnitude) is compared to a threshold, and corrections are deemed unnecessary when the threshold is not exceeded. For those corrections deemed necessary, the internal controller applies individual time shifts to the sector-specific signals to correct for tilt and to potentially correct for tool decentralization.
  • the measured time offset is simply corrected by a corresponding time shift. In other embodiments, a more sophisticated processing technique is employed to determine the appropriate time shifts.
  • the internal controller determines a tilt effect model that best fits the measured time-offsets.
  • the tilt effect model assumes a time offset that varies sinusoidally as a function of azimuth, and has the same size and orientation for each of the receivers so that, e.g., the time offset is the same in sector Al of each receiver. With the size and orientation of the time-offset as model parameters, the internal controller determines a least-squares fit to the measured time offsets.
  • the tilt effect model includes an time-offset dependence due to a tool-offset parameter to account for de-centralization of the tool relative to the borehole axis.
  • the time-offsets determined by the best-fitting model are corrected by appropriate time shifts to the measured sector-specific signals, thereby correcting for tilt and "pushing" the summed receiver signal to the center of the borehole.
  • the foregoing discussion determines the corrections for the receiver array as a whole, the same approaches can be applied independently to each receiver in the array to achieve similar results with reduced complexity. If sufficient computing resources are available to deal with additional complexity, the method may be refined to track tool movement from measure- ment to measurement and to use the movement information to refine estimates of tool tilt and position effects.
  • the corrected (if correction was needed) sector-specific signals are processed to measure formation slowness, measure acoustic anisotropy, perform acoustic imaging, evaluate cement bonding, and/or to determine the borehole shape and size in accordance with existing techniques.
  • Formation slowness can be measured using the techniques outlined in U.S. Patent 7,089,1 19, entitled “Acoustic Signal Processing Method Using Array Coherency”.
  • Acoustic anisotropy can be measured using the techniques outlined in U.S. Patent 6,188,961, entitled “Acoustic Logging Apparatus and Method”.
  • Acoustic imaging can be performed by mapping attenuation or intensity measurements to borehole wall pixels in a fashion similar to the tech- niques outlined in U.S.
  • Patent 6,021,093 entitled “Transducer configuration having a multiple viewing position feature”.
  • borehole calipering can be performed using the techniques outlined in G.J. Frisch and B. Mandal, “Advanced Ultrasonic Scanning Tool and Evaluation Methods Improve and Standardize Casing Inspection", SPWLA 42 nd Annual Logging Symposium, June 17-21, 2001.
  • the measurements determined from the processing operations of block 87 are associated with tool position measurements. If the logging tool includes a navigation package, this associate may be performed by the internal controller or the downhole telemetry transmitter. Alternatively, or in addition, this association may be performed by an uphole computer system that collects position information from surface instruments and combines it with the telemetry data. The measurements, once associated with position, are stored in the form of a log or image and updated as new information becomes available.
  • the uphole system displays the log and/or images to a user. The user may be a driller, a completions engineer, or other professional needing information regarding the well. The process of Fig. 8 repeats as logging continues.
  • Fig. 8 is a block diagram of an illustrative computer system suitable for determining and correcting for logging tool tilt and offset.
  • the 9 includes a chassis 90, a display 91, and one or more input devices 92, 93.
  • the chassis 90 is coupled to the display 91 and the input devices 92, 93 to interact with a user.
  • the display 91 and the input devices 92, 93 together operate as a user interface.
  • the display 91 often takes the form of a video monitor, but may take many alternative forms such as a printer, a speaker, or other means for communicating information to a user.
  • the input device 92 is shown as a keyboard, but may similarly take many alternative forms such as a button, a mouse, a keypad, a dial, a motion sensor, a camera, a microphone or other means for receiving information from a user.
  • the display 91 and the input devices 92, 93 are integrated into the chassis 90.
  • a display interface 94 Located in the chassis 90 is a display interface 94, a peripheral interface 95, a bus 96, a processor 97, a memory 98, an information storage device 99, and a network interface 100.
  • the display interface 94 may take the form of a video card or other suitable interface that accepts information from the bus 96 and transforms it into a form suitable for display 91.
  • the peripheral interface may accept signals from input devices 92, 93 and transform them into a form suitable for communication on bus 96.
  • Bus 96 interconnects the various elements of the computer and transports their communications.
  • Processor 97 gathers information from the other system elements, including input data from the peripheral interface 95 and program instructions and other data from the memory 98, the information storage device 99, or from a remote location via the network interface 100.
  • the network interface 100 enables the processor 97 to communicate with remote systems via a wired or wireless network.
  • the processor 97 carries out the program instructions and processes the data accordingly.
  • the program instructions may further configure the processor 97 to send data to other system elements, including information for the user which may be communicated via the display interface 94 and the display 91.
  • the processor 97 and hence the computer as a whole, generally operates in accordance with one or more programs stored on an information storage device 99.
  • One or more of the information storage devices may store programs and data on removable storage media such as a floppy disk or an optical disc. Whether or not the information storage media is removable, the processor 97 may copy portions of the programs into the memory 98 for faster access, and may switch between programs or carry out additional programs in response to user actuation of the input device.
  • the additional programs may be retrieved from information the storage device 99 or may be retrieved from remote locations via the network interface 100.
  • One or more of these programs configures the computer to carry out at least one of the acoustic logging methods with tilt effect correction disclosed herein.
  • the disclosed methods can be adapted for use with monopole, dipole, quadrupole, and higher-order acoustic transmitters.
  • the tool tilt is collected from other instruments (e.g., borehole calipers) and employed to determine the appropriate time shifts for the individual sector signals. It is intended that the following claims be interpreted to embrace all such variations and modifications.

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  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Acoustics & Sound (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geology (AREA)
  • Remote Sensing (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • General Physics & Mathematics (AREA)
  • Geophysics (AREA)
  • Geophysics And Detection Of Objects (AREA)

Abstract

L'invention concerne divers systèmes et procédés de diagraphie acoustique qui compensent l'inclinaison de l'outillage de diagraphie par rapport à l'axe du trou de forage. Certains modes de réalisation des procédés incluent : la génération d'un signal acoustique qui se propage le long d'un trou de forage en formation, la réception d'un signal provenant de chacun d'un ensemble de transducteurs acoustiques disposés de manière azimutale, le traitement des signaux pour compenser l'inclinaison de l'outil de diagraphie, ainsi que la détermination d'une propriété de la formation fondée au moins en partie sur les signaux compensés. Certains modes de réalisation d'outils incluent un contrôleur interne qui traite les signaux provenant de différentes directions afin de déterminer et corriger les décalages dans le temps qui peuvent être attribués à l'inclinaison de l'outil de diagraphie. Ensuite, les signaux compensés en termes d'inclinaison peuvent être utilisés pour mesurer des paramètres de la formation et du trou de forage qui peuvent être associés à la position et affichés sous la forme de diagraphes et/ou d'images du trou de forage.
PCT/US2007/012087 2007-05-21 2007-05-21 Systèmes et procédés de diagraphie avec compensation d'inclinaison pour des outils acoustiques spécifiques à un secteur Ceased WO2008150253A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
CA2673243A CA2673243C (fr) 2007-05-21 2007-05-21 Systemes et procedes de diagraphie avec compensation d'inclinaison pour des outils acoustiques specifiques a un secteur
PCT/US2007/012087 WO2008150253A1 (fr) 2007-05-21 2007-05-21 Systèmes et procédés de diagraphie avec compensation d'inclinaison pour des outils acoustiques spécifiques à un secteur

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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2011051776A3 (fr) * 2009-10-26 2012-01-05 Schlumberger Technology B.V. Appareil de mesures acoustiques pour diagraphie en cours de forage
WO2012134496A3 (fr) * 2011-04-01 2013-01-17 Halliburton Energy Sevices, Inc. Traitement basé sur le temps amélioré de données acoustiques de trou de forage à large bande
WO2013022429A1 (fr) * 2011-08-09 2013-02-14 Halliburton Energy Services, Inc. Systèmes et procédés pour effectuer des mesures acoustiques optimisées de fond de trou
EP2745145A4 (fr) * 2011-08-17 2015-11-04 Halliburton Energy Services Inc Mesure et traitement du bruit acoustique dans un forage
EP2593817A4 (fr) * 2010-08-18 2017-10-04 Smith International, Inc. Empilement de formes d'onde acoustiques utilisant un compartimentage azimutal et/ou de distance annulaire

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US4346460A (en) * 1978-07-05 1982-08-24 Schlumberger Technology Corporation Method and apparatus for deriving compensated measurements in a borehole
US5027331A (en) * 1982-05-19 1991-06-25 Exxon Production Research Company Acoustic quadrupole shear wave logging device
US5753812A (en) * 1995-12-07 1998-05-19 Schlumberger Technology Corporation Transducer for sonic logging-while-drilling
US20030037963A1 (en) * 2001-08-17 2003-02-27 Barr John D. Measurement of curvature of a subsurface borehole, and use of such measurement in directional drilling

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4346460A (en) * 1978-07-05 1982-08-24 Schlumberger Technology Corporation Method and apparatus for deriving compensated measurements in a borehole
US5027331A (en) * 1982-05-19 1991-06-25 Exxon Production Research Company Acoustic quadrupole shear wave logging device
US5753812A (en) * 1995-12-07 1998-05-19 Schlumberger Technology Corporation Transducer for sonic logging-while-drilling
US20030037963A1 (en) * 2001-08-17 2003-02-27 Barr John D. Measurement of curvature of a subsurface borehole, and use of such measurement in directional drilling

Cited By (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2011051776A3 (fr) * 2009-10-26 2012-01-05 Schlumberger Technology B.V. Appareil de mesures acoustiques pour diagraphie en cours de forage
US9823375B2 (en) 2009-10-26 2017-11-21 Schlumberger Technology Corporation Apparatus for logging while drilling acoustic measurement
EP2593817A4 (fr) * 2010-08-18 2017-10-04 Smith International, Inc. Empilement de formes d'onde acoustiques utilisant un compartimentage azimutal et/ou de distance annulaire
WO2012134496A3 (fr) * 2011-04-01 2013-01-17 Halliburton Energy Sevices, Inc. Traitement basé sur le temps amélioré de données acoustiques de trou de forage à large bande
AU2011363572B2 (en) * 2011-04-01 2015-01-22 Halliburton Energy Services, Inc. Improved time-based processing of broadband borehole acoustic data
US10353090B2 (en) 2011-04-01 2019-07-16 Halliburton Energy Services, Inc. Time-based processing of broadband borehole acoustic data
WO2013022429A1 (fr) * 2011-08-09 2013-02-14 Halliburton Energy Services, Inc. Systèmes et procédés pour effectuer des mesures acoustiques optimisées de fond de trou
AU2011374932B2 (en) * 2011-08-09 2015-01-29 Halliburton Energy Services, Inc. Systems and methods for making optimized borehole acoustic measurements
US9798031B2 (en) 2011-08-09 2017-10-24 Halliburton Energy Services, Inc. Systems and methods for making optimized borehole acoustic measurements
EP2745145A4 (fr) * 2011-08-17 2015-11-04 Halliburton Energy Services Inc Mesure et traitement du bruit acoustique dans un forage
US10215884B2 (en) 2011-08-17 2019-02-26 Halliburton Energy Services, Inc. Borehole acoustic noise measurement and processing

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Publication number Publication date
CA2673243C (fr) 2015-07-07
CA2673243A1 (fr) 2008-12-11

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