WO2014046674A1 - Système de télémétrie câblé à double enveloppe - Google Patents

Système de télémétrie câblé à double enveloppe Download PDF

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Publication number
WO2014046674A1
WO2014046674A1 PCT/US2012/056624 US2012056624W WO2014046674A1 WO 2014046674 A1 WO2014046674 A1 WO 2014046674A1 US 2012056624 W US2012056624 W US 2012056624W WO 2014046674 A1 WO2014046674 A1 WO 2014046674A1
Authority
WO
WIPO (PCT)
Prior art keywords
pipe
collar
connector
inner pipe
disposed
Prior art date
Application number
PCT/US2012/056624
Other languages
English (en)
Inventor
Richard Thomas Hay
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/US2012/056624 priority Critical patent/WO2014046674A1/fr
Priority to US13/794,287 priority patent/US9431813B2/en
Priority to PCT/US2013/060166 priority patent/WO2014047063A1/fr
Publication of WO2014046674A1 publication Critical patent/WO2014046674A1/fr
Priority to US15/208,327 priority patent/US9634473B2/en

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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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/028—Electrical or electro-magnetic connections
    • E21B17/0285—Electrical or electro-magnetic connections characterised by electrically insulating elements
    • 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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/18—Pipes provided with plural fluid passages

Definitions

  • the present disclosure relates generally to well drilling operations and, more particularly, to a Pipe-in-Pipe Wired Telemetry System.
  • MWD operations utilize sensors downhole, which may measure certain formation characteristics. These measurements may be transmitted to the surface as telemetry data, which may be used to control drilling operations. Telemetry data is typically transmitted using mud pulses or custom drill pipe with an integrated wired connection.
  • the custom drill pipe can be expensive to manufacture, however, given the pressure requirements for the drill string.
  • the mud pulses typically have limited data rates, capping the amount of real-time data that can be sent.
  • Figure 1 illustrates an example drilling system, according to aspects the present disclosure.
  • Figures 2a-c illustrate a cross-section of an example wired telemetry system, according to aspects of the present disclosure.
  • Figures 3a-b illustrate a cross-section of an example wired telemetry system, according to aspects of the present disclosure.
  • the present disclosure relates generally to well drilling operations and, more particularly, to a Pipe-in-Pipe Wired Telemetry System.
  • Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, multilateral, u-tube connection, intersection, bypass (drill around a mid-depth stuck fish and back into the well below), or otherwise nonlinear wellbores in any type of subterranean formation.
  • Embodiments may be applicable to injection wells, and production wells, including natural resource production wells such as hydrogen sulfide, hydrocarbons or geothermal wells; as well as borehole construction for river crossing tunneling and other such tunneling boreholes for near surface construction purposes or borehole u-tube pipelines used for the transportation of fluids such as hydrocarbons.
  • Devices and methods in accordance with embodiments described herein may be used in one or more of MWD and LWD operations. Embodiments described below with respect to one implementation are not intended to be limiting.
  • Fig. 1 shows a drilling system 100.
  • the drilling system 100 includes a rig 102 mounted at the surface 122, positioned above a borehole 104 within a subterranean formation 106.
  • the rig 102 may be connected to multiple pipes 1 18 and 120 via a top drive 126.
  • the drilling system 100 may include a pipe-in-pipe drilling system where an inner pipe 120 is disposed within the outer pipe 1 18.
  • the outer pipe 1 18 may comprise a typical drill string that is used in conventional drilling operations.
  • Fresh drilling mud may be pumped downhole toward the drill bit 1 10 through an annulus 1 14 between the inner pipe 120 and the drill string 1 18.
  • the drilling mud may flow within the annulus 1 14 through bottom hole assembly (BHA) 108 to the drill bit 1 10.
  • BHA bottom hole assembly
  • the BHA 108 may include a variety of measurement and logging such as various LWD/MWD elements 1 12, which are coupled to the outer pipe 1 18 and inner pipe 120.
  • the drilling fluid may exit through the drill bit 110, lubricating the cutting surface as the drill bit rotates, and carrying cuttings from the formation back to the surface 122.
  • the drilling fluid may return to the surface 122 within annulus 116, or be diverted into inner pipe 120.
  • a control unit 124 at the surface 122 may control the operation of at least some of the drilling equipment.
  • the drilling system 100 may be controlled, in part, using a telemetry system.
  • a telemetry system may be used to transmit real-time drilling mechanics and formation evaluation information uphole as the well is drilled.
  • LWD/MWD element 112 may make measurements regarding certain formation characteristics, and the measurements may be modulated or encoded and sent to the control unit 124 at the surface.
  • the control unit 124 may receive the telemetry data or transmit commands/data via the surface flow di verier 128 over a communications cable or via a wireless network connection 130 or other mode of telemetry on surface.
  • the control unit 124 may further demodulate the received data or modulate the transmitted commands or data, and translate the received data to some other useful form.
  • the measurements may be translated to evaluate certain formation characteristics, optimize the drilling system, or steer the drilling system to intersect a target formation.
  • the transmitted data or commands can be used to actuate a mechanism such as an under reamer to extend or retract its blades; to adjust the depth of cut with a bit control mechanism, such as a bit jack or other bit actuation mechanisms; to control tests; to control wellbore steering; and to adjust down hole drilling parameters, such as weight on bit and applied torque, by commanding down hole control mechanisms for these parameters.
  • the system may be used to relay, exchange or receive data/commands/information to or from other subsurface modules within telemetry range of a secondary down hole transmitter or receiver.
  • telemetry data is typically transmitted to the surface using mud pulses or a wired connection.
  • Mud pulses may be sent to the surface using pressure waves in the drilling mud.
  • Existing wired connections typically require a specially manufactured drill pipe with an integral wire.
  • the specially manufactured drill pipe is more expensive than standard drill pipe, and can significantly increase the overall costs of drilling operations. The manufacturing costs further may be exacerbated because the drill string is exposed to substantial pressures and torque during drilling, and therefore must be especially robust.
  • Embodiments of the present disclosure relate to a pipe-in-pipe wired telemetry system, as illustrated in Fig. 1 .
  • the pipe-in-pipe wired telemetry system may comprise an outer pipe and an inner pipe disposed within the outer pipe.
  • embodiments of the present disclosure may utilize standard drill pipe as the outer pipe, reducing the overall system cost.
  • a conductive element may be coupled to an outer surface of the inner pipe, disposed within an annulus between the outer surface of the inner pipe and the inner surface of the outer pipe.
  • the inner pipe of a pipe-in-pipe drilling system does not carry the string weight, which is born by the drill string or outer pipe. Accordingly, the inner pipe elements may be made of cast rather than machined, or with reduced machining effort subsequent to the cast, reducing the system cost.
  • Figs. 2A and 2B show elements of an example pipe-in-pipe telemetry system 200, according to aspects of the present disclosure.
  • the system 200 may include an outer pipe 202 and an inner pipe 210 disposed within the outer pipe 202.
  • the outer pipe 202 may axially support the inner pipe 210, as will be explained below.
  • a conductive element 250 may be coupled to and disposed proximate to an outer surface of the inner pipe 210, such that it is disposed in an annulus between the inner pipe 210 and the outer pipe 202.
  • the conductive element 250 may comprise, for example a wire or segments of wire with an insulative layer to protect the wire from shorting against the inner pipe 210 or outer pipe 202.
  • a conduit may be used to sheath and protect the wire from damage.
  • Telemetry signals may be sent along the conductive element 250.
  • telemetry signals may be sent along the conductive element 250 and also along one or both of the inner pipe 210 and outer pipe 202, thus making at least two electrical paths.
  • a plurality of insulated conductive wires can be grouped together to form at least one conductive wire pair. Such pairs can reside in the same sheath or in separate protective sheaths (not shown).
  • the telemetry signals may propagate in either direction along the conductor paths to and from downhole sensors and a control unit at the surface.
  • locating the conductive element 250 in the annulus between the inner pipe 210 and outer pipe 202 may be advantageous by primarily exposing the conductive element 250 to clean, or mostly clean, drilling mud, instead of drilling mud which carries cuttings that may damage the conductive element 250.
  • the outer pipe 202 may include a plurality of segments 202a-c mechanically and electrically connected at tool joints 216 and 218.
  • some or all of the plurality of segments 202a-c may be standard drill pipe segments that are coupled together to form a drill string, as will be appreciated by one of ordinary skill in view of this disclosure.
  • Segment 202b may include an upper portion with an outer shoulder 204 and a threaded portion 206 disposed on an inner surface.
  • Segment 202b may also comprise a bottom portion comprising an outer shoulder 212 disposed on an outer surface of the segment 202b, an inner shoulder 208 disposed on an inner surface of segment 202b, and a fastening portion 214.
  • the fastening portion 214 may comprise a threaded portion.
  • some or all of the segments of the outer pipe 202, including segments 202a and 202c, may comprise similarly configured upper and lower portions.
  • the inner pipe segments need not be electrically connected to provide a mechanical seal and mechanical support and to prevent fluid exchange between the two fluid flow paths within the pipe-in-pipe drilling system.
  • the conductive element 250 can be spiraled around the inner pipe 210 to reduce the likelihood that it will break due to pipe stretch.
  • the conductive element 250 can include axial lengthwise loops to allow sliding members to expand or contract.
  • the conductive element 250 may further be secured firmly or loosely to the outer surface of the inner pipe 210 with various means of fasteners or laid down in a support groove on or in the inner pipe material.
  • segment 202b may be coupled to adjacent segments 202a and 202c at joints 216 and 218 along the outer pipe 202. Joints along the outer pipes may be characterized by two pipe segments being coupled together. In certain embodiments, segment 202b may be coupled to segments 202a and 202c at joints 216 and 218 using threaded engagements. In the embodiment shown, the fastening portion 206 at the upper portion of segment 202b may engage with a fastening portion at the lower portion of segment 202a. Likewise fastening portion 214 at the lower portion of segment 202b may engage with a fastening portion at the upper portion of segment 202c.
  • joints 216 and 218 may further include compression engagements between shoulders on segment 202b and shoulders on segments 202a and 202c.
  • shoulder 204 of segment 202b may be compressed against an outer shoulder of segment 202a when the segments are coupled together.
  • shoulder 212 of segment 202b may engage with an outer shoulder of segment 202c at joint 216, but the inner shoulder 208 may not engage with a corresponding inner shoulder of segment 202c.
  • the inner pipe 210 may comprise a plurality of inner pipe segments 210a-c, with the segments being coupled at or proximate to joints 216 and 218 of the outer pipe 202.
  • the conductive element 250 may comprise a variety of segments 250a-c, each being coupled together at or proximate to joints 216 and 218.
  • the inner pipe 210 may comprise a first collar 220 with a first connector 222 disposed therein.
  • the first connector 222 may comprise, for example, one half of an electric coupling such as an inductive coupling, a conductive coupling, a capacitive coupling, and a piezo- electromechanical coupling.
  • the first connector 222 may comprise a coil of wire that is inserted into an inset on the bottom portion of the first collar 222, coaxial with the inner pipe 210.
  • the first connector 222 may be coupled to the conductive element 250, which may include being coupled to a segment 250a of the conductive element 250.
  • the conductive element segment 250a may be coupled to the first connector 222 through element 252, which may comprise, for example, a coaxial coupling that corresponds to the geometry of the conductive element segment 250a.
  • conductive element segment 250a may comprise a coaxial wire, with the inner wire being coupled to a first end of the coil of wire forming first connector 222, and the insulating jacket of the coaxial cable being connected to a second end of the coil of wire forming first connector 222.
  • a wire 254 disposed within the first collar 220 may couple the conductive element 250b to the first connector 222, such that signals can travel bi-directionally between the conductive element segment 250a and the first connector 222.
  • the inner pipe 210 may further comprise a second collar 224 with a second connector 226 disposed therein.
  • the second connector 226 may comprise, for example, one half of an electric coupling such an inductive coupling, a conductive coupling, a capacitive coupling, and a piezo-electromechanical coupling, and may correspond to the coupling type of the first connector 222.
  • the second connector 226 may be a coil or partial loop of wire similar to first connector 222, except that it is disposed on a top surface of second collar 224.
  • the second connector 226 may be coupled to conductive element segment 250b similar to the way first connector 222 is coupled to conductive element segment 250a.
  • the conductive element 250b may be coupled to the second connector 226 through element 256, which may comprise, for example, a coaxial coupling that corresponds to the geometry of the conductive element segment 250b, and may be similar to element 252.
  • element 256 may comprise, for example, a coaxial coupling that corresponds to the geometry of the conductive element segment 250b, and may be similar to element 252.
  • a wire 258 disposed within the second collar 226 may couple the conductive element 250b to the second connector 226, such that signals can travel bi-directionally between the conductive element 250b and the second connector 226.
  • load balancing impedances 280 and 282 may be coupled to wires 254 and 258, respectively.
  • the load balancing impedances 280 and 282 may help reduce signal deflection from the connectors at high data rates.
  • the load balancing impedances 280 and 282 may comprise a network of resistors, capacitors, and inductors that match the load on either end of an inner pipe segment to improve power transfer of the signal and reduce signal reflections.
  • the first collar 220 and the second collar 224 may align to form an electrical coupling between the first connector 222 and the second connector 226.
  • the first collar 220 and second collar 224 may be manufactured such that the first connector 222 and second connector 226 automatically align when the inner pipe 210 is assembled.
  • the second collar 224 may be at least partially installed within a bottom opening of the first collar 220, such that they form a substantially constant inner bore.
  • the first connector 222 may align with the second connector 226 such that the first connector 222 and second connector 226 form an electrical coupling.
  • Fig. 2C shows an alternative location for first and second connectors 222 and 226, respectively.
  • the first and second connectors 222 and 226 may be positioned within grooves on interior or exterior surfaces of the collars.
  • first connector 222 may be located within a groove on an interior surface of the first collar 220.
  • second connector 226 may be located on an exterior surface of the second collar 224.
  • the first connector 222 and second connector 226 may align axially, creating an electrical coupling.
  • Other placements for the first and second connectors 222 and 226 are possible, as would be appreciated by one of ordinary skill in the art in view of this disclosure.
  • the electrical coupling may comprise at least one of an inductive coupling, a conductive coupling, a capacitive coupling, and a piezo-electromechanical coupling.
  • the first connector 222 and the second connector 226 may be formed within the first collar 220 and second collar 224, respectively. The positioning of the first connector 222 and second connector 226 within collars may ensure that an electrical coupling is formed between the two connections.
  • the electrical coupling may allow bi-directional communications and/or electric power transmission from the conductive element 250a to the conductive element 250b, through the collars 220 and 224.
  • placing similar couplings throughout the length of the drilling string may effectuate wired telemetric communications with the surface.
  • the outer pipe 202 may axially support the inner pipe 210.
  • Axially supporting the inner pipe 210 may comprise limiting the axial movement of the inner pipe 210 within the outer pipe 202.
  • axially supporting the inner pipe 210 may also include applying a biasing force to the inner pipe 210 to maintain the electrical coupling between the first connector 222 and second connector 226.
  • the biasing force allows the first connector 222 and second connector 226 to align and reduce the air gap between the two connectors. This may improve the magnetic or piezoelectric coupling between the first and second connectors 222 and 226, which may be otherwise difficult to maintain due to downhole pressures during installation and drilling operations.
  • a shoulder 260 may be disposed on an inner surface of the outer pipe 202, and may axially support at least one of the first collar 220 and the second collar 226 on the inner pipe 210.
  • the shoulder 260 may be integral to the outer pipe 202, or may comprise a wedge ring 260a installed within the outer pipe 202 such that in contacts a pipe hanger on an inner surface of the outer pipe 202, as is shown in Figs. 2A and 2B.
  • Axial support for the inner pipe 210 may be provided by a compression member 264 positioned between the at least one of the first collar 220 and the second collar 224 and the shoulder 260.
  • the second collar 224 may comprise a projection 262, which may have a diameter similar to a diameter of an inner surface of the outer pipe 202.
  • the compression member 264 may be positioned between the projection 262 and the shoulder 260, and may comprise a spring stack.
  • the projection 262 may contact the compression member 264, which may impart a first axial force in a first direction on the projection 262 and the second collar 224.
  • the first direction of the first axial force may be opposite a second direction of a second axial force generated by the weight of the inner pipe 210 on the projection 262, thereby urging the first connection 222 toward the second connection 226.
  • the projection 262 is shown extending from the second collar 224, other locations are possible, such as one the first collar 220, or on one of the pipe segments.
  • the pipe-in-pipe wired telemetry system 200 may further comprise a tensioning member 266 positioned between the projection 262 and an unengaged shoulder of an outer pipe segment, such as segment 202a.
  • the tensioning member 266 may impart a static load on the compression member 264 when the telemetry system 200 is assembled.
  • the wedge ring 260a, compression member 264, second collar 224, and tensioning member 266 may be positioned within the outer pipe 202.
  • the tensioning member 266 may contact an inner shoulder of segment 202a, causing the tensioning member 266 to impart a static load on the compression member 264.
  • the static load may depend, for example, on a spring force of the compression member 264 and the distance which the tensioning member 266 causes the compression member 264 to compress under static conditions.
  • the static force may be altered by changing the length of the tensioning member 266.
  • the static force may be configured such that the first connection 222 and second connection 226 are urged together with a pre-determined biasing force that corresponds to the force required to maintain the electrical coupling between the first connection 222 and the second connection 226.
  • Figs. 3A and 3B show elements of an example pipe-in-pipe telemetry system 300, according to aspects of the present disclosure.
  • the system 300 may include an outer pipe 302 and an inner pipe 310 disposed within the outer pipe 302.
  • the outer pipe 302 may axially support the inner pipe 310.
  • a conductive element 350 may be coupled to and disposed proximate to an outer surface of the inner pipe 310, such that it is disposed in an annulus between the inner pipe 310 and the outer pipe 302.
  • the conductive element 350 may comprise, for example, a wire or segments of wire 350a and 350b with an insulative layer to protect the wire from shorting against the inner pipe 310 or outer pipe 302.
  • Telemetry signals may be sent along the conductive element 350 from downhole sensors to a control unit at the surface.
  • the system 300 further comprises one or more signal repeaters 380 (one is shown) coupled to the conductive element 350.
  • the inclusion of the signal repeater 380 in system 300 should not be read the limit the inclusion of the signal repeater 380 in the system 200. Rather, as will be described below, a signal repeater may be included in any pipe-in-pipe telemetry system incorporating aspects of the present disclosure.
  • the outer pipe 302 may include a plurality of segments 302a-c which are similar to segments 202a-c, and which may be coupled together in a similar fashion.
  • segments 302a-c may comprise standard drill pipe coupled together to form a drill string.
  • the inner pipe 310 may comprise a plurality of inner pipe segments 31 Oa-c which are similar to segments 21 Oa-c described above.
  • the inner pipe 310 may comprise a first collar 320 with a first connector 322 disposed therein, and a second collar 324 within a second connector 326 disposed therein, with the first and second connectors 322 and 326, respectively, being positioned and functioning similar to the first and second connectors 222 and 226.
  • the outer pipe 302 may further axially support the inner pipe 310, including providing a biasing force via shoulder 360, projection 362, compression member 364, and tensioning member 366.
  • the second collar 324 may be elongated to accommodate the signal repeater 380.
  • the signal repeater 380 may be coupled to the conductive element 350b via wire 370 and element 372.
  • Element 372 may be a coaxial connector similar to element 256 in Fig. 2B.
  • the signal repeater 380 may also be coupled to connector 326 via wire 374.
  • the signal repeater 380 may receive bi-directional communications, and retransmit the signal, boosting the power of the signal and ensuring that a signal of sufficient strength is either reached at the surface or at the following signal repeater.
  • drill strings may be thousands of feet long, and signals transmitted over a wire may lose signal strength, increasing the signal to noise ratio in the transmission. This may lead to errors in the transmission. By incorporating one or more signal repeaters, the signal strength may be maintained and the transmission errors reduced.
  • the signal repeater 380 may comprise a controller and a memory element such that it can temporarily buffer and re-transmit the signal.
  • the signal repeater 380 may be coupled to a power source 382 positioned proximate the signal repeater to power the controller and memory element and provide the necessary power to re-transmit the telemetry signal.
  • the signal repeater 380 may be programmed to accommodate a variety of signals and frequencies, depending on the application.
  • shoulder 360 of segment 302b may be positioned to accommodate the elongated second collar 324.
  • Segments 202a-c may comprise standard drill pipe segments with a pipe hangar interface located at substantially the same axial location along the segment.
  • Segment 302b in contrast, includes an integral shoulder 360 that is positioned axially lower within the segment 302, to allow for the installation of the elongated second collar 324 with the signal repeater 380 while still accommodating compression member 364 and tensioning member 366. Accordingly, the outer pipe 302 may still axially support inner pipe 310, including providing a biasing force, even though custom drill pipe segments are used.
  • custom drill pipe segments may be included at multiple locations throughout the drill string while still within the scope of this disclosure.
  • the signal repeater 380 is shown positioned within second collar 324, it may be positioned elsewhere within the pipe-in-pipe telemetry system described herein. In certain embodiments, the signal repeater 380 may be installed within a custom outer pipe segment 302b.
  • a method for a pipe-in-pipe telemetry system may include introducing an outer pipe into a borehole.
  • the outer pipe may comprise standard drill pipe and introducing the outer pipe into a borehole may comprise attaching additional drill pipe segments to a drill pipe that is at least partially disposed within the borehole.
  • the method may also include positioning an inner pipe within the outer pipe.
  • the inner pipe segments may be positioned and installed within the outer pipe.
  • positioning the inner pipe within the outer pipe may include using the outer pipe to axially support the inner pipe.
  • the inner pipe may include a projection which may be axially supported by at least one of a shoulder, compression member, and tensioning member.
  • the method may further include coupling a conductive element to the inner pipe.
  • the inner pipe may include a first collar with a first connection and a second collar with a second connection.
  • Coupling a conductive element to the inner pipe may comprise coupling a first segment of the conductive element to the first connector and coupling a second segment of the conductive element to the second connector.
  • the first connector and second connector may form an electrical coupling, allowing telemetry signals to be transmitted along the conductive element.
  • a projection of the inner pipe may be disposed on at least one of the first collar and the second collar. As described above, axially supporting the projection may comprise applying a biasing force to the projection to maintain an electrical coupling between the first connector and the second connector.
  • the method may further include transmitting telemetry data through the conductive element.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Abstract

L'invention concerne un système et un procédé permettant de réaliser un système de télémétrie à double enveloppe. Le système de télémétrie câblé à double enveloppe comprend un tuyau externe (202) et un tuyau interne (210) disposé au sein du tuyau externe. Le tuyau externe (202) peut soutenir en sens axial le tuyau interne (210). Un élément conducteur (250) peut être couplé au tuyau interne et disposé sur une surface externe du tuyau interne (210). L'élément conducteur (250) peut être couplé à un premier (222) et un second (226) connecteurs disposés au sein du tuyau interne, et le soutien en sens axial du tuyau interne peut comprendre l'application d'une force de sollicitation (264) pour maintenir un accouplement électrique entre les premier et second connecteurs.
PCT/US2012/056624 2012-09-21 2012-09-21 Système de télémétrie câblé à double enveloppe WO2014046674A1 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
PCT/US2012/056624 WO2014046674A1 (fr) 2012-09-21 2012-09-21 Système de télémétrie câblé à double enveloppe
US13/794,287 US9431813B2 (en) 2012-09-21 2013-03-11 Redundant wired pipe-in-pipe telemetry system
PCT/US2013/060166 WO2014047063A1 (fr) 2012-09-21 2013-09-17 Système de télémétrie câblé pour conduite à double enveloppe
US15/208,327 US9634473B2 (en) 2012-09-21 2016-07-12 Redundant wired pipe-in-pipe telemetry system

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2012/056624 WO2014046674A1 (fr) 2012-09-21 2012-09-21 Système de télémétrie câblé à double enveloppe

Related Child Applications (1)

Application Number Title Priority Date Filing Date
US13/794,287 Continuation-In-Part US9431813B2 (en) 2012-09-21 2013-03-11 Redundant wired pipe-in-pipe telemetry system

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WO2014046674A1 true WO2014046674A1 (fr) 2014-03-27

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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2017087453A1 (fr) * 2015-11-20 2017-05-26 Baker Hughes Incorporated Guide de tuyau câblé à guidage automatique
CN113969752A (zh) * 2020-07-23 2022-01-25 中国石油天然气股份有限公司 井下智能注采管柱快速连接装置
EP4253715A1 (fr) * 2022-03-29 2023-10-04 Werner Zimmer Dispositif de terrassement, section de tuyau et procédé de terrassement

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Publication number Priority date Publication date Assignee Title
US4496203A (en) * 1981-05-22 1985-01-29 Coal Industry (Patents) Limited Drill pipe sections
DE4002795C1 (fr) * 1990-01-31 1991-05-23 Eastman Christensen Co., Salt Lake City, Utah, Us
US5285846A (en) * 1990-03-30 1994-02-15 Framo Developments (Uk) Limited Thermal mineral extraction system
DE10313758A1 (de) * 2003-03-27 2004-10-14 Bauer Spezialtiefbau Gmbh HDI-Gestände mit Online-Datenübertragung
US20060021799A1 (en) * 2004-07-27 2006-02-02 Hall David R Biased Insert for Installing Data Transmission Components in Downhole Drilling Pipe
US20110057810A1 (en) * 2009-09-09 2011-03-10 Ashers Partouche Wired drill pipe connection for single shouldered application and bha elements

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4496203A (en) * 1981-05-22 1985-01-29 Coal Industry (Patents) Limited Drill pipe sections
DE4002795C1 (fr) * 1990-01-31 1991-05-23 Eastman Christensen Co., Salt Lake City, Utah, Us
US5285846A (en) * 1990-03-30 1994-02-15 Framo Developments (Uk) Limited Thermal mineral extraction system
DE10313758A1 (de) * 2003-03-27 2004-10-14 Bauer Spezialtiefbau Gmbh HDI-Gestände mit Online-Datenübertragung
US20060021799A1 (en) * 2004-07-27 2006-02-02 Hall David R Biased Insert for Installing Data Transmission Components in Downhole Drilling Pipe
US20110057810A1 (en) * 2009-09-09 2011-03-10 Ashers Partouche Wired drill pipe connection for single shouldered application and bha elements

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2017087453A1 (fr) * 2015-11-20 2017-05-26 Baker Hughes Incorporated Guide de tuyau câblé à guidage automatique
CN113969752A (zh) * 2020-07-23 2022-01-25 中国石油天然气股份有限公司 井下智能注采管柱快速连接装置
CN113969752B (zh) * 2020-07-23 2023-10-31 中国石油天然气股份有限公司 井下智能注采管柱快速连接装置
EP4253715A1 (fr) * 2022-03-29 2023-10-04 Werner Zimmer Dispositif de terrassement, section de tuyau et procédé de terrassement

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