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WO2012039707A1 - Systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage - Google Patents

Systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage Download PDF

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Publication number
WO2012039707A1
WO2012039707A1 PCT/US2010/049751 US2010049751W WO2012039707A1 WO 2012039707 A1 WO2012039707 A1 WO 2012039707A1 US 2010049751 W US2010049751 W US 2010049751W WO 2012039707 A1 WO2012039707 A1 WO 2012039707A1
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WO
WIPO (PCT)
Prior art keywords
tool
receivers
acoustic
borehole
wave
Prior art date
Application number
PCT/US2010/049751
Other languages
English (en)
Inventor
Moustafa E. Oraby
Roland E. Chemali
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to PCT/US2010/049751 priority Critical patent/WO2012039707A1/fr
Priority to US13/813,343 priority patent/US10041343B2/en
Priority to SG2013008735A priority patent/SG187720A1/en
Publication of WO2012039707A1 publication Critical patent/WO2012039707A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/002—Survey of boreholes or wells by visual inspection
    • E21B47/0025—Survey of boreholes or wells by visual inspection generating an image of the borehole wall using down-hole measurements, e.g. acoustic or electric
    • 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

  • a sonde In wireline logging, a sonde is lowered into the borehole after some or the entire well has been drilled. The sonde hangs at the end of a long cable (a "wireline") that provides mechanical support and an electrical connection between the sonde and logging equipment located at the surface of the well.
  • a long cable a "wireline”
  • 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 parameters as the formation is being penetrated. While LWD techniques allow more contemporaneous formation measurements, drilling operations create an environment that is generally hostile to electronic instrumentation and sensor operations.
  • the log can take the form of a two-dimensional "image" of the borehole wall.
  • Imaging enables analysts to study the fine-scale structure of the penetrated formations, including stratifications, fractures, dip angles, rock texture, vugs, and other features and anomalies.
  • Most imaging tools are wireline logging tools, though at least some LWD imaging tools have been proposed. See, e.g., U.S. Patent 6,600,321 (Evans); U.S. Patent 7,098,664 (Bittar); U.S. Patent 7,272,504 (Akimov); U.S. Patent 6,678,616 (Winkler).
  • Fig. 1 is an illustrative view of a logging-while-drilling (LWD) environment
  • Fig. 2 is an illustrative borehole wall image
  • Fig. 3 is a cross-sectional view of an illustrative LWD imaging tool
  • Fig. 4 is a side view of an illustrative embodiment of an LWD imaging tool
  • Fig. 5 shows the propagation of an acoustic wave in the borehole wall
  • Fig. 6 shows illustrative receive waveforms
  • Fig. 7 is a side view of an alternative embodiment of an LWD imaging tool
  • Fig. 8 is a functional block diagram of illustrative tool electronics
  • Fig. 9 is a flowchart of an illustrative sonic density imaging method.
  • Fig. 10 is a block diagram of an illustrative computer system.
  • the micro-sonic logging tool is embodied in a drill collar having at least protrusion (e.g., a stabilizer blade).
  • a drill collar having at least protrusion (e.g., a stabilizer blade).
  • One or more acoustic transmitters are set in a distal face of the protrusion to generate acoustic waves.
  • One or more receivers can also be set in the distal face of the protrusion to detect P-waves and S-waves that have propagated through the formation making up the borehole wall.
  • Processing circuitry measures the velocity or slowness of the acoustic waves and optionally associates the measured values with a spot on the borehole wall as identified, e.g., by the tool position and rotational orientation at the time the measurement is made.
  • a motion tracking unit can be included in the bottomhole assembly for this purpose. If a pair of receivers is used, the tool resolution is commensurate with the spacing between the receivers. Multiple transmitters can be used if it is desired to obtain compensated measurements.
  • the tool can further include a fluid cell to measure acoustical properties of the borehole fluid, which can be used to convert the formation slowness measurements into density measurements.
  • the logging data is usually stored in a non-volatile information storage medium and viewed by drilling engineers or other personnel interested in learning more about the formation.
  • At least some of the method embodiments include: rotating a logging-while-drilling tool as it moves along a borehole; detecting acoustic waves propagating along a wall of the borehole using at least two receivers on a distal face of a protrusion on the tool (e.g., on a stabilizer blade); processing signals from the receivers to measure P-wave and S-wave velocities or slowness values; and associating the velocities or slowness values with the tool's position and orientation.
  • the velocities or slowness values are used to generate a borehole wall image representing either the slowness values themselves or other formation properties (e.g., density) derived from the slowness values.
  • the transmitter(s) and receivers need not be positioned on the same stabilizer blade - in some embodiments the transmitter(s) are on the distal surface of a separate stabilizer blade.
  • FIG. 1 shows an illustrative logging while drilling (LWD) environment.
  • a drilling platform 2 is equipped with a derrick 4 that supports a hoist 6.
  • Rig operators drill oil and gas wells using a string of drill pipes 8.
  • the hoist 6 suspends a top drive 10 that is used to rotate the drill string 8 and to lower the drill string through the wellhead 12.
  • Connected to the lower end of the drill string 8 is a drill bit 14.
  • the bit 14 is rotated and drilling accomplished by rotating the drill string 8, by use of a downhole motor near the drill bit, or by both methods.
  • Mud recirculation equipment 16 pumps drilling fluid through supply pipe 18, through top drive 10, and down through the drill string 8 at high pressures and volumes to emerge through nozzles or jets in the drill bit 14. The mud then travels back up the hole via the annulus formed between the exterior of the drill string 8 and the borehole wall 20, through a blowout preventer, and into a mud pit 24 on the surface. On the surface, the drilling mud is cleaned and then recirculated by recirculation equipment 16. The drilling mud cools the drill bit 14, carries cuttings from the base of the bore to the surface, and balances the hydrostatic pressure in the rock formations.
  • the bottomhole assembly (i.e., the lowermost part of drill string 8) includes thick- walled tubulars called drill collars to add weight and rigidity to aid the drilling process.
  • the thick walls of these drill collars make them useful for housing instrumentation and LWD sensors.
  • the bottomhole assembly of Fig. 1 includes a natural gamma ray detector 24, a micro- sonic imaging tool 26, a resistivity tool 28, a porosity tool 30, and a control & telemetry module 32.
  • Other tools and sensors can also be included in the bottomhole assembly to gather measurements of various drilling parameters such as position, orientation, weight-on-bit, borehole diameter, etc.
  • the tool orientation may be specified in terms of a tool face angle (rotational orientation), an inclination angle (the slope), and compass direction, each of which can be derived from measurements by magnetometers, inclinometers, and/or accelerometers, though other sensor types such as gyroscopes may alternatively be used.
  • the tool includes a 3 -axis fluxgate magnetometer and a 3 -axis accelerometer. As is known in the art, the combination of those two sensor systems enables the measurement of the tool face angle, inclination angle, and compass direction. Such orientation measurements can be combined with gyroscopic or inertial measurements to accurately track tool position.
  • micro-sonic imaging tool 26 rotates and collects acoustic wave slowness measurements that a downhole controller associates with tool position and orientation measurements to form a slowness image map of the borehole wall.
  • Control/telemetry module 32 collects data from the micro-sonic tool and the other bottomhole assembly instruments and stores them in internal memory. Selected portions of the data can be communicated to the surface by, e.g., mud pulse telemetry. Other logging-while drilling telemetry methods also exist and could be employed.
  • the drillstring 8 could be formed from wired drillpipe that enables waveforms or images to be transmitted to the surface in real time to enable quality control and processing to optimize the logging resolution.
  • telemetry module 32 modulates a resistance to drilling fluid flow to generate pressure pulses that propagate to the surface.
  • One or more pressure transducers 34, 36 (isolated from the noise of the mud pump 16 by a desurger 40) convert the pressure signal into electrical signal(s) for a signal digitizer 38.
  • the digitizer 38 supplies a digital form of the pressure signals to a computer 50 or some other form of a data processing device.
  • Computer 50 operates in accordance with software (which may be stored on information storage media 52) and user input received via an input device 54 to process and decode the received signals.
  • the resulting telemetry data may be further analyzed and processed by computer 50 to generate a display of useful information on a computer monitor 56 or some other form of a display device. For example, a driller could employ this system to obtain and view an sonic density image log.
  • Fig. 2 shows an illustrative borehole wall image 122 that results when formation measurements (such as acoustic slowness or density) are associated with tool position L and rotational orientation ⁇ .
  • the surface of the borehole wall is divided into "bins", with each bin representing a pair of tool position L and rotational orientation ⁇ values.
  • the combined measurements can then be processed (as discussed further below) to obtain a density estimate that can be displayed as a pixel color and/or a pixel intensity.
  • Such an image often reveals bedding structures (such as structures 124) and fractures (such as fracture 126).
  • Such features often exhibit a sinusoidal dependence on rotational angle, indicating that the borehole encountered the feature at an angle other than 90 degrees.
  • the image resolution is largely determined by the measurement resolution of the sensing surface. The measurement resolution depends not only on the size and spacing of the acoustic receivers, but also on the standoff between the borehole wall and the sensing surface, and to some extent upon the signal frequency.
  • Fig. 3 shows a cross-section of an illustrative LWD embodiment of sonic logging tool 26 in a borehole 20.
  • the logging tool 26 shown includes three stabilizer blades 130, 132, 134 that keep the tool centralized.
  • the precise configuration and number of stabilizer blades can vary based on the expected drilling environment and should in general be expected to increase in number as the borehole diameter increases.
  • Fig. 4 shows a side view of the illustrative tool embodiment, while Fig. 5 shows a cross-section detail. In these views it can be seen that the distal face of the stabilizer blade has an inset transmitter 142 separated from an array of inset receivers 146 by an acoustic isolation zone.
  • the acoustic isolation zone is designed to attenuate and delay acoustic wave energy propagating via through the tool body from the transmitter to the receivers.
  • the acoustic isolation zone can include voids or inserts 144 that provide an arrangement of acoustic contrasts to reflect and attenuate acoustic wave energy.
  • Inserts 144 can be made of a resilient material (e.g., vulcanized rubber) that efficiently dissipates acoustic wave energy as heat, thereby providing further attenuation.
  • Careful design of the void shapes can create a series of acoustic propagation paths that cause destructive interference at the receivers over a desired frequency band.
  • the acoustic transmitters are electrical transducers made of a piezoelectric material, enabling the tool to generate programmable acoustic signals.
  • bender bars or other acoustic transducers can be used.
  • the receivers can be electrical transducers made of a piezoelectric material.
  • the transmitter and receiver transducers are flush with the surface of a wall-contacting face to minimize standoff, while in other embodiments the transducers are slightly inset, covered with a protective layer, and/or set in a protrusion face that is kept at a small standoff from the borehole wall to prevent undue erosion of the transducers.
  • the transducers are inset by approximately 1/8 inch, or possibly up to about 1/4 inch, and the total inset area surrounding the transducer is no more than 10 times the sensing area of the transducer itself.
  • the distal face of the protrusion is kept at a small standoff (e.g., about 1/10 of an inch) as the tool rotates within the borehole. This configuration could be achieved using a set of stabilizers on either side of the tool, with a slightly larger outer diameter than the circle traced by the distal face of the tool protrusion(s).
  • At least two receivers are preferably employed, enabling the tool to make slowness measurements having a resolution on the order of the spacing between the receivers.
  • One or more laterally spaced receivers can be added to enable direction-of-arrival determination. Such measurements enable the tool to correct for the effects of tool rotation.
  • the contemplated operating frequencies for the sonic logging tool are in the range between
  • the internal controller controls the triggering and timing of the acoustic source 142, and records and processes the signals from the receivers 146.
  • the internal controller fires the acoustic source 142 periodically, producing acoustic pressure waves that propagate into the formation and along the borehole wall 20. As these pressure waves propagate past the array of receivers 146, they cause pressure variations that can be detected by the receiver transducers.
  • Fig. 6 shows a set of illustrative signals 162 detected by the acoustic receivers in response to having the transmitter driven with a pulsed sine wave.
  • the internal controller can process the signals in accordance with the principles and techniques provided in Willis and Toksoz, "Automatic P and S velocity determination from full waveform digital acoustic logs", Geophysics, v48 nl2, December 1983, pl631-44, to determine arrival time delays between the various receivers for P-waves and S-waves. Differences in arrival times represent the propagation delay, which is combined with the distance information to obtain slowness, i.e., the inverse of velocity. Because they can be readily derived from each other, the terms “slowness” and “velocity” are sometimes used interchangeably.
  • the detected waveforms will represent a variety of wave types, including waves propagating through the body of the tool (tool waves), compression waves from the formation (P-waves), shear waves from the formation (S-waves), waves propagating through the borehole fluid (mud waves), and Stoneley waves propagating along the borehole wall.
  • the controller can process the signals using semblance processing techniques such as those disclosed by B. Mandal in U.S. Pat. 7,099,810 to separate the different wave types and determine their individual slownesses.
  • the receiver array signals may be processed by a downhole controller to determine Vs (the formation shear wave velocity) and Vc (the formation compression wave velocity), or the signals may be communicated to the uphole computer system for processing.
  • the measurements are associated with borehole position and tool orientation to generate one or more images of the acoustical properties of the borehole wall.
  • the log or image is stored and ultimately displayed for viewing by a user.
  • Fig. 7 shows an alternative tool embodiment having a second transmitter 172.
  • the two transmitters and two receivers are co-linear, with the two receivers being equally-spaced from the midpoint between the two transmitters.
  • the receivers' responses to each of the two transmitters can be combined to form compensated measurements that automatically account for minor differences in the electronics for each receiver. (Specifically, because the receivers switch roles as the "near” and “far” receivers, any minor timing or attenuation differences will cancel out when the responses to the opposite transmitters are averaged together.) Such processing also helps compensate for borehole rugosity.
  • the line is parallel to the tool axis, but this is not a requirement.
  • the stabilizer blades twist to form a partial spiral along the outer surface of the drill collar.
  • the transmitters and receivers may be aligned along the midline of a stabilizer blade's distal face.
  • the transmitters are embedded in stabilizer blades different from the stabilizer blade in which the receivers are embedded.
  • the illustrative sonic logging tool 26 includes a fluid cell 136 located between stabilizer blades 132,134 and opposite the slowness-measuring stabilizer blade 130.
  • Various suitable fluid cells exist in the art, such as e.g., the fluid cell employed by the Halliburton CAST-VTM wireline tool, or that disclosed by B. Mandal, U.S. Pat.
  • the fluid cell 136 can be operated in a manner that avoids interference from firings of the source 142, e.g., the borehole fluid property measurements can be made while the source 142 is quiet, and the formation wave velocity measurements can be made while the fluid cell is quiet.
  • Fig. 8 is a functional block diagram of the illustrative sonic logging tool 26.
  • a digital signal processor 180 operates as an internal controller for tool 26 by executing software stored in memory 181.
  • the software configures the processor 180 to collect measurements from various measurement modules such as position sensor 182 and fluid cell 183. (Note that these modules can alternatively be implemented as separate tools in the bottomhole assembly, in which case such measurements would be gathered by a control/telemetry module.)
  • the software further configures the processor 180 to fire the source(s) 142 via a digital to analog converter 184, and further configures the processor 180 to obtain receive waveforms from the array of receivers 146A-146N via analog to digital converters 184-186.
  • the digitized waveforms can be stored in memory 181 and/or processed to determine compression and shear wave velocities.
  • the processor can combine the compression and shear wave velocities with measurements of drilling fluid velocity and density to obtain an estimate of formation density. Alternatively, these measurements can be communicated to a control module or a surface processing facility to be combined there. In either case, the formation density estimates are associated with the position of the logging tool to provide a density log.
  • a network interface 187 connects the sonic logging tool to a control/telemetry module via a tool bus, thereby enabling the processor 180 to communicate information to the surface (e.g., velocity measurements or density logs) and to receive commands from the surface (e.g., activating the tool or changing its operating parameters).
  • information to the surface e.g., velocity measurements or density logs
  • commands from the surface e.g., activating the tool or changing its operating parameters
  • Equation (1) When expanded in terms of the density of the borehole fluid ("mud") 3 ⁇ 4, the acoustic velocity of the borehole fluid VM, the bulk density of the formation 3 ⁇ 4, the acoustic velocity of compressional waves in the formation Vc, and the acoustic velocity of shear waves in the formation Vs, equation (1) becomes:
  • equation (2) ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ 0.0009.
  • equation (2) reveals that when the logging tool is designed to measure compressional and shear wave velocities of the formation as well as density and acoustic velocity of the borehole fluid, the only remaining unknown is the bulk density of the formation.
  • equation (2) can be rewritten in the form:
  • FIG. 9 is a flowchart of an illustrative density imaging method that employs this principle. It is assumed that the equation coefficients ⁇ 3 ⁇ 4 have been previously determined during calibration of the tool, although this is not required.
  • the rotational orientation and position of the logging tool along the borehole is determined. This determination can be performed using a motion sensing and orientation tracking module.
  • the acoustical properties of the borehole fluid are measured using a fluid cell.
  • the measured properties include the acoustic impedance of the borehole fluid, or alternatively the density of the fluid and the propagation velocity of acoustic waves through the fluid.
  • the logging tool measures the propagation velocities of shear waves and compressional waves through the formation and associates them with the current tool position and orientation.
  • the acoustic measurements for the borehole fluid and the formation are combined to calculate the formation density for the current tool position, and the process repeats beginning with block 192.
  • the density calculations are accumulated and made available in perceptible form to a user as an image of the borehole wall.
  • Fig. 9 The functions described in Fig. 9 can be distributed throughout the logging system or concentrated within the internal processor for the logging tool.
  • the position measurements, fluid measurements, and formation wave velocity measurements can be made by separate tools and communicated to a separate processing facility where the density calculation is performed.
  • the functions can be carried out in a parallel or asynchronous fashion even though they are described for explanatory purposes as occurring in a sequential order.
  • Fig. 10 is a block diagram of an illustrative surface processing system suitable for collecting, processing, and displaying logging data.
  • a user may further interact with the system to send command to the bottom hole assembly to adjust its operation in response to the received data.
  • the system of Fig. 10 can take the form of a computer that includes a chassis 50, a display 56, and one or more input devices 54A, 54B.
  • Located in the chassis 50 is a display interface 802, a peripheral interface 804, a bus 806, a processor 808, a memory 810, an information storage device 812, and a network interface 814.
  • Bus 806 interconnects the various elements of the computer and transports their communications.
  • the surface telemetry transducers are coupled to the processing system via a data acquisition unit 38 and the network interface 814 to enable the system to communicate with the bottom hole assembly.
  • the processor processes the received telemetry information received via network interface 814 to construct formation property logs (including one or more borehole wall images) and to display them to the user.
  • the processor 808, and hence the system as a whole, generally operates in accordance with one or more programs stored on an information storage medium (e.g., in information storage device 812 or removable information storage media 52).
  • the bottom hole assembly control module and/or internal controller for the sonic logging tool 26 operates in accordance with one or more programs stored in an internal memory.
  • One or more of these programs configures the tool controller, the bottomhole assembly control module, and the surface processing system to individually or collectively carry out at least one of the density logging methods disclosed herein.
  • the wave velocities can be measured as slowness values or propagation delays.
  • the transducers can be mounted in distal faces of protrusions other than stabilizer blades, e.g., steering fins, extendable pads, or the body of a decentralized tool.
  • borehole fluid properties can optionally be measured at the surface rather than downhole. It is intended that the following claims be interpreted to embrace all such variations and modifications.

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  • Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Geophysics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Acoustics & Sound (AREA)
  • General Physics & Mathematics (AREA)
  • Fluid Mechanics (AREA)
  • Remote Sensing (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics And Detection Of Objects (AREA)

Abstract

La présente invention concerne divers systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage. Dans certaines formes au moins, l'outil de diagraphie par micro-sons est incorporé dans une masse-tige comportant au moins une lame de stabilisateur. Un ou plusieurs émetteurs acoustiques sont installés dans une face distale de la lame de stabilisateur afin de générer des ondes acoustiques. Un ou plusieurs récepteurs peuvent également être installés dans la face distale de la lame de stabilisateur afin de détecter les ondes P et les ondes S qui se sont propagées à travers la formation composant la paroi du forage. Des circuits de traitement mesurent la rapidité ou la lenteur des ondes acoustiques, et, en option, associent les valeurs mesurées à un point sur la paroi du forage tel qu'il a été identifié. Il est possible d'utiliser plusieurs émetteurs si l'on souhaite obtenir des mesures compensées. L'outil peut en outre comprendre une cellule de fluide pour mesurer les propriétés acoustiques du fluide de forage, ce qui peut servir à convertir les mesures de lenteur dans la formation en mesures de densité.
PCT/US2010/049751 2009-06-02 2010-09-22 Systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage WO2012039707A1 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
PCT/US2010/049751 WO2012039707A1 (fr) 2010-09-22 2010-09-22 Systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage
US13/813,343 US10041343B2 (en) 2009-06-02 2010-09-22 Micro-sonic density imaging while drilling systems and methods
SG2013008735A SG187720A1 (en) 2010-09-22 2010-09-22 Micro-sonic density imaging while drilling systems and methods

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PCT/US2010/049751 WO2012039707A1 (fr) 2010-09-22 2010-09-22 Systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage

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Cited By (7)

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US8440960B2 (en) 2008-09-30 2013-05-14 Halliburton Energy Services, Inc. Salt concentration logging systems and methods
US8510051B2 (en) 2008-09-30 2013-08-13 Halliburton Energy Services, Inc. Systems and methods for evaluating formations having unknown or mixed salinity
NL1041990A (en) * 2015-10-09 2017-04-24 Halliburton Energy Services Inc Hazard avoidance during well re-entry
US9765609B2 (en) 2009-09-26 2017-09-19 Halliburton Energy Services, Inc. Downhole optical imaging tools and methods
WO2018052411A1 (fr) * 2016-09-14 2018-03-22 Halliburton Energy Services, Inc. Stabilisateur modulaire
US10041343B2 (en) 2009-06-02 2018-08-07 Halliburton Energy Services, Inc. Micro-sonic density imaging while drilling systems and methods
US10353111B2 (en) 2008-08-21 2019-07-16 Halliburton Energy Services, Inc. Automated leg quality monitoring systems and methods

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US20050078555A1 (en) * 2000-11-13 2005-04-14 Baker Hughes Incorporated Method and apparatus for LWD shear velocity measurement
US6909666B2 (en) * 2000-11-13 2005-06-21 Baker Hughes Incorporated Method and apparatus for generating acoustic signals for LWD shear velocity measurement
US20060198242A1 (en) * 2005-02-22 2006-09-07 Halliburton Energy Services, Inc. Acoustic logging-while-drilling tools having a hexapole source configuration and associated logging methods
US20100020638A1 (en) * 2008-07-24 2010-01-28 Precision Energy Services, Inc. Monopole acoustic transmitter ring comprising piezoelectric material

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US20050078555A1 (en) * 2000-11-13 2005-04-14 Baker Hughes Incorporated Method and apparatus for LWD shear velocity measurement
US6909666B2 (en) * 2000-11-13 2005-06-21 Baker Hughes Incorporated Method and apparatus for generating acoustic signals for LWD shear velocity measurement
US20050006090A1 (en) * 2003-07-08 2005-01-13 Baker Hughes Incorporated Electrical imaging in conductive and non-conductive mud
US20060198242A1 (en) * 2005-02-22 2006-09-07 Halliburton Energy Services, Inc. Acoustic logging-while-drilling tools having a hexapole source configuration and associated logging methods
US20100020638A1 (en) * 2008-07-24 2010-01-28 Precision Energy Services, Inc. Monopole acoustic transmitter ring comprising piezoelectric material

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10353111B2 (en) 2008-08-21 2019-07-16 Halliburton Energy Services, Inc. Automated leg quality monitoring systems and methods
US8440960B2 (en) 2008-09-30 2013-05-14 Halliburton Energy Services, Inc. Salt concentration logging systems and methods
US8510051B2 (en) 2008-09-30 2013-08-13 Halliburton Energy Services, Inc. Systems and methods for evaluating formations having unknown or mixed salinity
US10041343B2 (en) 2009-06-02 2018-08-07 Halliburton Energy Services, Inc. Micro-sonic density imaging while drilling systems and methods
US9765609B2 (en) 2009-09-26 2017-09-19 Halliburton Energy Services, Inc. Downhole optical imaging tools and methods
NL1041990A (en) * 2015-10-09 2017-04-24 Halliburton Energy Services Inc Hazard avoidance during well re-entry
WO2018052411A1 (fr) * 2016-09-14 2018-03-22 Halliburton Energy Services, Inc. Stabilisateur modulaire
US10900297B2 (en) 2016-09-14 2021-01-26 Halliburton Energy Services, Inc. Systems and methods of a modular stabilizer tool

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