EP0636763A2 - Verfahren und Einrichtung zur elektrisch-akustischen Telemetrie im Bohrloch - Google Patents

Verfahren und Einrichtung zur elektrisch-akustischen Telemetrie im Bohrloch Download PDF

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Publication number
EP0636763A2
EP0636763A2 EP94305423A EP94305423A EP0636763A2 EP 0636763 A2 EP0636763 A2 EP 0636763A2 EP 94305423 A EP94305423 A EP 94305423A EP 94305423 A EP94305423 A EP 94305423A EP 0636763 A2 EP0636763 A2 EP 0636763A2
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EP
European Patent Office
Prior art keywords
acoustic
electric
drill string
downhole
location
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.)
Withdrawn
Application number
EP94305423A
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English (en)
French (fr)
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EP0636763A3 (de
Inventor
Wallace Meyer
Macmillan Wisler
Arthur Hay
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Baker Hughes Holdings LLC
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Baker Hughes Inc
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Filing date
Publication date
Application filed by Baker Hughes Inc filed Critical Baker Hughes Inc
Publication of EP0636763A2 publication Critical patent/EP0636763A2/de
Publication of EP0636763A3 publication Critical patent/EP0636763A3/de
Withdrawn legal-status Critical Current

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    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
    • E21B47/16—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves
    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency

Definitions

  • the present invention relates generally to a downhole telemetry system for facilitating the transfer of borehole and drilling data to the surface for inspection and analysis. More particularly, the invention relates to a measurement-while-drilling ("MWD”) system that senses and transmits data measurements from a downhole location to an uphole location.
  • MWD measurement-while-drilling
  • Deep wells of the type commonly used for petroleum or geothermal exploration are typically less than 30 cm (12 inches) in diameter and on the order of 2 km (1.5 miles) long. These wells are drilled using drill strings assembled from relatively light sections (either 30 or 45 feet (9.1 or 13.7m) long) of drill pipe that are connected end-to-end by tool joints, additional sections being added to the uphole end as the hole deepens.
  • the downhole end of the drill string typically includes a drill collar, a dead weight assembled from sections of relatively heavy lengths of uniform diameter collar pipe having an overall length on the order of 300 meters (1000 feet).
  • a drill bit is attached to the downhole end of the drill collar, the weight of the collar causing the bit to bite into the earth as the drill string is rotated from the surface.
  • Drilling mud or air is pumped from the surface to the drill bit through an axial hole in the drill string. This fluid removes the cuttings from the hole, provides hydrostatic head which controls the formation gases, and sometimes provides cooling for the bit.
  • a mud pressure pulse system the drilling mud pressure in the drill string is modulated by means of a valve and control mechanism mounted in a special pulsar collar above the drill bit and motor (if one is used).
  • the pressure pulse travels up the mud column at or near the velocity of sound in the mud, which is approximately 4000-5000 feet per second (1200-1500 m/s).
  • the rate of transmission of data is relatively slow due to pulse spreading, modulation rate limitations, and other disruptive forces, such as the ambient noise in the drill string.
  • a typical pulse rate is on the order of a pulse per second.
  • a representative example of mud pulse telemetry systems may be found in U.S. Patent Nos. 3,949,354, 3,964,556, 3,958,217, 4,216,536, 4,401,134, 4,515,225, 4,787,093 and 4,908,804.
  • Hard-wire connectors have also been proposed to provide a hard wire connection from the bit to the surface.
  • wire or cable systems There are a number of obvious advantages to using wire or cable systems, such as the ability to transmit at a high data rate; the ability to send power downhole; and the capability of two-way communication. Examples of hard wire systems may be found in U.S. Patent Nos. 3,879,097, 3,918,537 and 4,215,426.
  • acoustic or seismic generator is located downhole near or in the drill collar.
  • a large amount of power is required downhole to generate a signal with sufficient intensity to be detected at the surface.
  • One way to provide sufficient power downhole is to provide a large power supply downhole.
  • a large acoustic signal is required to overcome the acoustic noise generated by the bit during drilling so that the transmitted acoustic signal can be distinguished from the downhole acoustic noise.
  • An example of an acoustic telemetering system is Cameron Iron Works' CAMSMART downhole measurement system, as published in the Houston Chronicle on May 7, 1990, page 3B.
  • Other examples of acoustic telemetry systems are found in U.S. Patent Nos. 5,050,132, 5,056,067, 5,124,953, 5,128,901, 5,128,902 and 5,148,408.
  • the last major prior art technique involves the transmission of electromagnetic ("EM”) waves through a drill pipe and the earth.
  • EM electromagnetic
  • downhole data is input to an antenna positioned downhole in a drill collar.
  • a large pickup assembly or loop antenna is located around the drilling rig, at the surface, to receive the EM signal transmitted by the downhole antenna.
  • Propagation of EM waves is characterized by an increase in attenuation with an increase in distance, data rate and earth conductivity.
  • the distance between the downhole antenna and the surface antenna may be in the range of 5,000 to 10,000 feet (1500 to 3000m).
  • the conductivity of the earth and the drilling mud also may vary significantly along the length of the drill string, causing distortion and/or attenuation of the EM signal.
  • the large amount of noise in the drilling string causes interference with the EM wave.
  • the primary way to supply the requisite amount of power necessary to transmit the EM wave to the surface is to provide a large power supply downhole or to run a hard wire conductor downhole.
  • Representative examples of EM systems can be found in U.S. Patent Nos. 2,354,887, 3,967,201, 4,215,426, 4,302,757, 4,348,672, 4,387,372, 4,684,946, 4,691,203, 4,710,708, 4,725,837, 4,739,325, 4,766,442, 4,800,385 and 4,839,644.
  • U.S. Patent No. 4,087,781 issued to Grossi, et al., for example, discloses the use of repeater stations to relay low frequency signals to and from sensors near the drilling assembly.
  • U.S. Patent No. 3,793,632 uses repeater stations to increase data rate and, in addition, suggests using two different modes of communication to prevent interference.
  • U.S. Patent Nos. 2,411,696 and 3,079,549 also suggest using repeater stations to convey information from downhole to the surface. None of these systems has been successful, based primarily on the varying conditions encountered downhole, where conductivity may range over several orders of magnitude.
  • one of the drill collar sections of a drill string includes an electric transmitter/receiver assembly which communicates with an electric/acoustic repeater assembly which communicates with an acoustic transmitter/receiver assembly uphole of the drill string by the transmission and receipt of electric and acoustic signals through the drill string.
  • the electric transmitter/receiver assembly may be positioned above or below the motor.
  • an apparatus for transmitting information through a drill string having an upper end and a lower end with a drill bit disposed at the lower end comprising: means for transmitting an electromagnetic data signal from a first location near the lower end of the drill string; means for receiving said electromagnetic data signal at a second location between the lower and upper ends of the drill string; means for transmitting an acoustic data signal from said second location in response to said electromagnetic data signal received; and means for receiving said acoustic data signal at third location at or near the upper end of the drill string.
  • uphole telemetry comprises an electric current induced in the drill string by the downhole electric transmitter.
  • the electric current contains encoded information of downhole conditions and travels up the drill string where it is detected at the electric receiver of the electric/acoustic repeater.
  • the received signal is processed to drive the acoustic transmitter of the electric/acoustic repeater.
  • An acoustic signal containing the encoded information is induced into the drill string by this acoustic transmitter and permeates up the drill string to the uphole acoustic receiver. This received signal is processed and utilized to evaluate and/or optimize the drilling process.
  • downhole telemetry comprises an acoustic signal induced in drill string by the uphole acoustic transmitter.
  • the acoustic signal contains encoded information of uphole commands and travels down the drill string where it is detected at the acoustic receiver of the electric/acoustic repeater.
  • the received signal is processed to drive the electric transmitter of the electric/acoustic repeater.
  • An electric signal containing the encoded information is induced in the drill string by this electric transmitter and travels down the drill string to the downhole electric receiver. This received signal is processed and utilized to command a downhole processor (i.e., computer).
  • the present invention resolves the prior art problems encountered with electromagnetic and acoustic telemetry by utilizing: (1) electric telemetry (electromagnetic telemetry) downhole, thereby avoiding the problem of detection at the surface; and (2) acoustic telemetry uphole, thereby avoiding the problem of acoustic noise near the bit (i.e., downhole).
  • the terms “uphole”, “upper”, “above” and the like are used synonymously to reflect position in a well path, where the surface of the well is the upper or topmost point.
  • the terms “bottomhole”, “downhole”, “lower”, “below” and the like are also used to refer to position in a well path where the bottom of the well is the furthest point drilled along the well path from the surface, and the term “subsurface” indicates a downhole location remote from the surface of the well.
  • a well may vary significantly from the vertical, and, in fact, may at times be horizontal.
  • the foregoing terms should not be regarded as relating to depth or verticality, but instead should be construed as relating to the position in the path of the well between the surface and the bottom of the well.
  • FIGURE 2A illustrates a prior art drilling system that operates solely in a rotary mode
  • FIGURE 2B depicts a prior art steerable system that permits both straight and directional drilling.
  • the rotary drilling system shown in FIGURE 2A includes a drill bit with a telemetry device for relaying data to the surface.
  • a sensor sub which includes a variety of sensors for measuring parameters in the vicinity of the drill collar, such as resistivity, gamma, weight-on-bit, and torque-on-bit.
  • the sensors transmit data to the telemetry device, which in turn, transmits a signal to the surface.
  • a non-magnetic drill collar typically is located above the sensor modules.
  • the drill collar includes a directional sensor probe.
  • the drill collar connects to the drill string, which extends to the surface.
  • Drilling occurs in a rotary mode by rotation of the drill string at the surface, causing the bit to rotate downhole.
  • Drilling fluid e.g., drilling mud
  • the drilling mud then circulates back to the surface by flowing on the outside of the drill string.
  • the prior art steerable system shown in FIGURE 2B has the added ability to drill in either a straight mode or in a directional or "sliding" mode, as shown in U.S. Patent No. 4,667,751, which is incorporated herein by reference.
  • the steerable system includes a motor which functions to operate the bit.
  • the motor includes a motor housing, a bent housing, and a bearing housing.
  • the motor housing preferably includes a stator constructed of an elastomer bonded to the interior surface of the housing and a rotor mating with the stator.
  • the stator has a plurality of spiral cavities, n, defining a plurality of spiral grooves throughout the length of the motor housing.
  • the rotor has a helicoid configuration, with n-1 spirals helically wound about its axis (e.g., see U.S. Patent Nos. 1,892,217, 3,982,858 and 4,051,910).
  • drilling fluid is forced through the motor housing into the stator.
  • the rotor is forced to rotate and to move from side to side within the stator, thus creating an eccentric rotation at the lower end of the rotor.
  • the bent housing includes an output shaft or connecting rod, which connects to the rotor by a universal joint or knuckle joint.
  • the bent housing facilitates directional drilling (e.g. see U.S. Patent Nos. 4,299,296 and 4,667,751).
  • the bit is positioned to point in a specific direction by orienting the bend in the bent housing in a specific direction.
  • the motor then is activated by forcing drilling mud therethrough, causing operation of the drill bit.
  • the drill bit will drill in the desired direction according to the arc of curvature established by the degree of bend in the bent housing, the orientation of the bend and other factors such as weight-on-bit.
  • the degree of bend in the bent housing may be adjustable to permit varying degrees of curvature (e.g., see U.S. Patent Nos. 4,067,404 and 4,077,657).
  • a concentric stabilizer also is provided to aid in guiding the drill bit (e.g. see U.S. Patent No. 4,667,751).
  • the drill string is rotated at the same time the motor is activated, thereby causing a wellbore to be drilled with an enlarged diameter (e.g. see U.S. Patent No. 4,667,751).
  • the diameter of the wellbore is directly dependent on the degree of bend in the bent housing and the location of the bend. The smaller the degree of bend and the closer the placement of the bend is to the drill bit, the smaller will be the diameter of the drilled wellbore.
  • FIGURE 3 a schematic of a drill string utilizing an electric/acoustic telemetry system of the present invention is shown.
  • a drilling rig 10 is positioned on the surface 12 above a borehole 14 which is traversed by a drill string 16.
  • Drill string 16 is assembled from sections of drill pipe 18 that are connected end-to-end by tool joints 20. It will be appreciated that additional sections of drill pipe 18 are added to the uphole end of drill string 16 as the hole deepens.
  • the downhole end of the drill string includes a drill collar 22 comprised of drill collar pipe having a diameter which is relatively larger than the diameter of drill pipe sections 18.
  • Drill collar section 22 includes a bottom hole assembly 23 which terminates at a drill bit 24 and which may include several drill collar sections housing downhole sensors for sensing parameters such as pressure, position, resistivity or temperature.
  • one of the drill collar sections 25 includes an electric transmitter/receiver assembly 26 which communicates with an electric/acoustic repeater assembly 28 which communicates with an acoustic transmitter/receiver assembly 29 uphole of drill string 16 by the transmission (and receipt) of electric and acoustic signals through the drill string.
  • the downhole end of the drill string includes drill collar 22 and a motor 30 with an extended sub 32 connected to a drill bit 34.
  • Electric transmitter/receiver assembly 26 is disposed at sub 32 along with at least one downhole sensor.
  • electric transmitter/receiver assembly 26 and at least one downhole sensor are located downhole of motor 30.
  • the downhole end of the drill string includes drill collar 22 with one of the drill collar sections 35 including electric transmitter/receiver assembly 26 and motor 30 connected to drill bit 34.
  • Downhole sensors are disposed at a drill collar section 36.
  • electric transmitter/receiver assembly 26 and the downhole sensors are located uphole of motor 30.
  • Motor 30 for example, comprises a Dyna-Drill positive displacement motor with a bent housing, made by Smith International, Inc. as described hereinbefore and as shown in U.S. Patent No. 4,667,751.
  • Other motors including mud turbines, mud motors, Moineau motors, creepy crawlers and other devices that generate motion at one end relative to the other, may be used without departing from the principles of the present invention.
  • motor 30 in accordance with the preferred embodiment, connects to extended sub 32 which houses at least one sensor module and communicates via electric transmitter/receiver assembly 26.
  • extended sub 32 may be removed and used interchangeably in a variety of downhole assemblies.
  • electric transmitter/receiver assembly 26 comprises a sensor antenna 38 (e.g. a toriod) mounted in an annular channel 40 of the drill collar section 25 (FIGURE 3), 32 (FIGURE 4), 35 (FIGURE 5).
  • the toriod includes a core 42 and an electrical conductor 44 wrapped around the core.
  • Core 42 is preferably comprised of a highly permeable material, such as an iron/nickel alloy.
  • the alloy is formed into laminated sheets coated with insulation such as magnesium oxide, wound about a mandrel to form the core, and heat treated for maximum initial permeability.
  • the electrical conductor 44 is wound about the core 42 to form the coils of the antenna 38 (i.e., the toriod).
  • the conductor 44 is preferably sheathed in CAPTON, or any other suitable dielectric material.
  • the sensor antenna 38 preferably is vacuum-potted in an insulating epoxy 46.
  • the epoxy comprises TRA-CON TRA-BOND F202 or equivalent.
  • Electrical leads of conductor 44 pass through a passage 48 to a sealed hatch 50 in the drill collar, as is known in the art. Hatch 50, for example, houses the electronics for providing transmitting signals to and/or receiving signals from antenna 38.
  • the electronics is in communication with downhole sensors, a power source, downhole memory and signal processor, as is well known. An electric field generated by the toroid couples a current into the drill string.
  • electric transmitter/receiver assembly 26 may be of the type described in U.S. Patent No. 5,160,925 which is expressly incorporated herein by reference (e.g., antenna 25 and associated hardware).
  • an electric field applied across an insulating joint as a source may be used to generate a current in the drill string (i.e., direct-coupled) as is known in the art.
  • Electric/acoustic repeater assembly 28 comprises an electric transmitter/receiver in communication with an acoustic transmitter/receiver.
  • the electric transmitter/receiver is preferably the same type as electric transmitter/receiver 26 described hereinbefore.
  • the acoustic transmitter/receiver is preferably the same type as described in U.S. Patent No. 5,128,901 which is expressly incorporated herein by reference. Electrical communication is provided between the electric transmitter/receiver and the acoustic transmitter/receiver. These interfacing signals may require processing in accordance with the prior art teachings incorporated above.
  • Acoustic transmitter/receiver 29 is also preferably of the same type as described in U.S. Patent No. 5,128,901. Further, it will be appreciated the method of acoustic transmission may be in accordance with any of the methods taught in U.S. Patent Nos. 5,128,901, 5,128,902 and 5,148,408.
  • One advantage of the present invention is that the electric transmission is only needed at large depth from the surface.
  • the resistivities are usually not as low at large depths because the porosity is reduced due to the high pressure.
  • the addition of an electric-electric repeater would reduce the data rate by a factor of two, because the repeater can not transmit and receive at the same time.
  • the electric-acoustic repeater 28 is the upper most repeater in the drill string and is expected to have a range of at least 7000 feet (2100m). With the acoustic signal covering the top 7000 feet (2100m) and the electric signal covering the bottom 5000 feet (1500m) the telemetry system of the present invention can operate to 12000 feet (3600m) even under difficult conditions. Again using the Wait et al model the attenuation against source receiver distance is plotted in FIGURE 8, for a 10.0 ohm-meter formation for frequencies of 1, 5, 10, 15 and 20 Hertz.
  • the attenuation rate is 6.7 dB per 1000 feet (300m) at 10 Hz so the electric signal can travel about 13000 feet (3900m) giving a total depth of 20000 feet (6000m) in this more resistive formation (i.e., 7000 feet (2100m) acoustic transmission and 13000 feet (3900m) electric transmission).
  • the same depth can be achieved in more conductive formations by either adding electric-electric repeaters or reducing the frequency, both of which would reduce the data rate.
  • the angle between the electric transmitter and the electric receiver could be as high as 90 degrees.
  • a drill string having a changing dip can be modeled using an electric dipole source.
  • the electric dipole is a very poor approximation near the source, but it is correct for large distances as the current on the surface of the drill string will die off faster than the field of the electric dipole. This limit will be reached faster in conductive formations or for the higher frequencies.
  • an electric dipole model for the attenuation against source receiver distance is plotted for a 1.0 ohm-meter formation for frequencies of 1, 5, 10, 15 and 20 Hertz.
  • uphole telemetry in accordance with the present invention comprises an electric current induced in drill string 16 by electric transmitter 26.
  • the electric current contains encoded information of downhole conditions as is well known.
  • This electric current travelling up drill string 16 is detected at the electric receiver of assembly 28.
  • the received signal is processed to drive the acoustic transmitter of assembly 28.
  • An acoustic signal containing the encoded information is induced into drill string 16 by the acoustic transmitter of assembly 28 and permeates up the drill string to acoustic receiver 29.
  • This received signal is processed and utilized to evaluate and/or optimize the drilling process, as is known.
  • an electric-electric repeater may be employed for greater depths.
  • an acoustic-acoustic repeater may be employed for greater depths.
  • Downhole telemetry in accordance with the present invention comprises an acoustic signal induced in drill string 16 by acoustic transmitter 29.
  • the acoustic signal contains encoded information of uphole commands as is well known.
  • the acoustic signal travelling down drill string 16 is detected at the acoustic receiver of assembly 28.
  • the received signal is processed to drive the electric transmitter of assembly 28.
  • An electric signal containing the encoded information is induced in the drill string by the electric transmitter of assembly 28 and travels down the drill string to electric receiver 26.
  • This received signal is processed and utilized to command a downhole processor (i.e., computer) as is known.
  • a downhole processor i.e., computer
  • the acoustic telemetry is located away from the noisy downhole environment.
  • the downhole noise presents a significant problem in efficient acoustic telemetry.
  • the electric telemetry is not located uphole where detection at the surface has posed a significant problem.
  • the present invention resolves these problems by utilizing: (1) electric telemetry downhole, thereby avoiding the problem of detection at the surface; and (2) acoustic telemetry uphole, thereby avoiding the problem of acoustic noise near the bit (i.e., downhole).

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Remote Sensing (AREA)
  • Geophysics (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Acoustics & Sound (AREA)
  • Electromagnetism (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
  • Earth Drilling (AREA)
  • Geophysics And Detection Of Objects (AREA)
EP94305423A 1993-07-26 1994-07-22 Verfahren und Einrichtung zur elektrisch-akustischen Telemetrie im Bohrloch. Withdrawn EP0636763A3 (de)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US9757093A 1993-07-26 1993-07-26
US97570 1993-07-26

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EP0636763A2 true EP0636763A2 (de) 1995-02-01
EP0636763A3 EP0636763A3 (de) 1995-08-09

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Cited By (55)

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FR2740827A1 (fr) * 1995-11-07 1997-05-09 Schlumberger Services Petrol Procede de recuperation, par voie acoustique, de donnees acquises et memorisees dans le fond d'un puits et installation pour la mise en oeuvre de ce procede
EP0922836A1 (de) * 1997-12-10 1999-06-16 Halliburton Energy Services, Inc. Unterwasserverstärker und Verfahren für dessen Anwendung
EP0932054A3 (de) * 1998-01-27 2000-06-14 Halliburton Energy Services, Inc. Bohrlochtelemetrieanordnung und Verfahren zur Fernübertragung
EP0919697A3 (de) * 1997-12-01 2001-05-16 Halliburton Energy Services, Inc. Elektromagnetish zu akustische und akustisch zu elektromagnetische Wiederholer und Verfahren zu ihrer Anwendung
EP1083298A3 (de) * 1999-09-07 2001-11-28 Halliburton Energy Services, Inc. Anzeigevorrichtung der Freilassung eines Bohrlochstopfens
US7080699B2 (en) 2004-01-29 2006-07-25 Schlumberger Technology Corporation Wellbore communication system
US7172038B2 (en) * 1997-10-27 2007-02-06 Halliburton Energy Services, Inc. Well system
WO2007019319A1 (en) * 2005-08-04 2007-02-15 Schlumberger Canada Limited Bi-directional drill string telemetry system for measurement and drilling control
RU2305183C2 (ru) * 2005-09-14 2007-08-27 Ооо "Битас" Ретрансляционный модуль для телеметрической системы с электромагнитным каналом связи (варианты)
US7557492B2 (en) 2006-07-24 2009-07-07 Halliburton Energy Services, Inc. Thermal expansion matching for acoustic telemetry system
US7595737B2 (en) 2006-07-24 2009-09-29 Halliburton Energy Services, Inc. Shear coupled acoustic telemetry system
EP2157278A1 (de) 2008-08-22 2010-02-24 Schlumberger Holdings Limited Drahtlose Telemetriesysteme für Bohrlochwerkzeuge
EP2157279A1 (de) 2008-08-22 2010-02-24 Schlumberger Holdings Limited Sender- und Empfänger-Synchronisation zur Herstellung drahtloser Telemetriesysteme
RU2401378C1 (ru) * 2009-08-06 2010-10-10 Николай Викторович Беляков Способ проводки стволов наклонных и горизонтальных скважин
WO2012131600A2 (en) 2011-03-30 2012-10-04 Schlumberger Technology B.V. Transmitter and receiver synchronization for wireless telemetry systems
US8322461B2 (en) 2008-11-03 2012-12-04 Halliburton Energy Services, Inc. Drilling apparatus and method
US8605548B2 (en) 2008-11-07 2013-12-10 Schlumberger Technology Corporation Bi-directional wireless acoustic telemetry methods and systems for communicating data along a pipe
WO2014100262A1 (en) * 2012-12-19 2014-06-26 Exxonmobil Upstream Research Company Telemetry for wireless electro-acoustical transmission of data along a wellbore
EP2763335A1 (de) 2013-01-31 2014-08-06 Service Pétroliers Schlumberger Sender- und Empfängerbandpassauswahl für drahtlose Telemetriesysteme
EP2762673A1 (de) 2013-01-31 2014-08-06 Service Pétroliers Schlumberger Mechanischer Filter für einen akustischen Telemetrie-Repeater
US9388635B2 (en) 2008-11-04 2016-07-12 Halliburton Energy Services, Inc. Method and apparatus for controlling an orientable connection in a drilling assembly
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