WO2011083320A2 - Appareil électrique formant injecteur de tubage sous-marin enroulé - Google Patents

Appareil électrique formant injecteur de tubage sous-marin enroulé Download PDF

Info

Publication number
WO2011083320A2
WO2011083320A2 PCT/GB2011/000029 GB2011000029W WO2011083320A2 WO 2011083320 A2 WO2011083320 A2 WO 2011083320A2 GB 2011000029 W GB2011000029 W GB 2011000029W WO 2011083320 A2 WO2011083320 A2 WO 2011083320A2
Authority
WO
WIPO (PCT)
Prior art keywords
carriages
tubing injector
electrically powered
subsea
tubing
Prior art date
Application number
PCT/GB2011/000029
Other languages
English (en)
Other versions
WO2011083320A3 (fr
Inventor
Galen Herbert
Original Assignee
Halliburton Energy Services Inc
Turner, Craig Robert
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, Turner, Craig Robert filed Critical Halliburton Energy Services Inc
Priority to EP11700753A priority Critical patent/EP2524106A2/fr
Priority to BR112012016901A priority patent/BR112012016901A2/pt
Publication of WO2011083320A2 publication Critical patent/WO2011083320A2/fr
Publication of WO2011083320A3 publication Critical patent/WO2011083320A3/fr

Links

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
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/22—Handling reeled pipe or rod units, e.g. flexible drilling pipes

Definitions

  • the present disclosure relates to use of coiled tubing in the oil industry, and, more particularly, to an electric subsea coiled tubing injector apparatus.
  • Coiled tubing generally includes cylindrical tubing made of metal or composite.
  • the continuous length of coiled tubing is a flexible product, typically several thousand feet long and wound on a reel.
  • Coiled tubing may be introduced into an oil or gas well bore or pipeline through wellhead control equipment to perform various tasks during the exploration, drilling, production, and workover of the well/pipeline.
  • Coiled tubing may be used, for example, to inject gas or other fluids into the well bore or pipeline, to inflate or activate bridges and packers, to transport tools downhole such as logging tools, to perform remedial cementing and clean-out operations in the bore, to deliver drilling tools downhole, for electric wireline logging and perforating, drilling, wellbore cleanout, fishing, setting and retrieving tools, for displacing fluids, and for transmitting hydraulic power into the well.
  • Coiled tubing is often used for offshore well operations.
  • Offshore coiled tubing systems typically involve equipment with hydraulic elements.
  • coiled tubing systems may use fluids, such as mineral-based, oil-based, or glycol-based fluids, in conjunction with various equipment, such as hydraulic motors and hydraulic beam cylinders.
  • fluids such as mineral-based, oil-based, or glycol-based fluids
  • using hydraulic elements in a subsea environment can be problematic. Hydraulic elements are vulnerable to subsea conditions such as temperature and pressure.
  • a hydraulic-based system is subject to greater hydrostatic pressure on the equipment that requires compensation, such as gear compensation and sealing of bearings and other elements.
  • the viscosity of fluids is increased.
  • the potential for leaks and spills from equipment, such as fittings, hoses and other connections is likewise increased.
  • the problems with hydraulic-based systems include depth limitations and leak potential. These and other issues make hydraulic-based systems less desirable for subsea well operations.
  • the present disclosure relates to use of coiled tubing in the oil industry, and, more particularly, to an electric subsea coiled tubing injector apparatus.
  • a subsea coiled tubing injector apparatus comprising: one or more carriages; one or more electrically-powered linea actuators adapted to move said one or more carriages; wherein the apparatus is configured to engage and move tubing.
  • a subsea coiled tubing injector apparatus comprising: a linear actuator; and a pair of carriages coupled via the linear actuator; wherein the linear actuator is electrically powered and is configured to apply lateral force to the carriages; wherein the carriages are configured to move substantially laterally with respect to one another; and wherein each carriage comprises a tubing engagement assembly configured to engage tubing interposed between the carriages.
  • an elecgtrically- powered subsea tubing injector comprising: a plurality of carriages, where the carriages are linked by a plurality of actuators adapted to move the carriages, and where the actuators are electrically powered; a chain drive assembly coupled to each carriage; and an electrically powered chain drive motor attached to each carriage; wherein the carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing without using hydraulic power.
  • a method of injecting coiled tubing into subsea wellbore comprising: aligning an electrically powered subsea tubing injector with a wellbore, wherein the tubing injector comprises apparatus as defined herein; engaging tubing with the subsea tubing injector; and inserting the tubing into the wellbore with the subsea tubing injector; wherein the method is performed without using hydraulic power.
  • a subsea coiled tubing injector apparatus includes a linear actuator and a pair of carriages coupled via the linear actuator.
  • the linear actuator is electrically powered and is configured to apply lateral force to the carriages.
  • the carriages are configured to move substantially laterally with respect to one another.
  • Each carriage includes a tubing engagement assembly configured to engage tubing interposed between the carriages.
  • a electrically powered subsea tubing injector in another aspect, includes a plurality of carriages. The carriages are linked by a plurality of actuators adapted to move the carriages. The actuators are electrically powered. A chain drive assembly coupled to each carriage. An electrically powered chain drive motor attached to each carriage. The carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing without using hydraulic power.
  • a method of injecting coiled tubing into subsea wellbore includes aligning an electrically powered subsea tubing injector with a wellbore.
  • the tubing injector includes a plurality of carriages. The carriages are linked by a plurality of actuators adapted to move the carriages. The actuators are electrically powered.
  • the tubing injector also includes a chain drive assembly coupled to each carriage and an electrically powered chain drive motor attached to each carriage. The carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing.
  • the method also includes engaging tubing with the subsea tubing injector and inserting the tubing into the wellbore with the subsea tubing injector. The method is performed without using hydraulic power.
  • Figure 1 is a cross-sectional, side view of a coil tubing handling system in accordance with certain embodiments of the present disclosure.
  • Figure 2 shows a partial schematic perspective of the inner side of a carriage, with the tracks and chains removed, in accordance with certain embodiments of the present disclosure.
  • Figure 3 shoes a schematic front view of carriages in accordance with certain embodiments of the present disclosure.
  • Figure 4 shows a side view of a subsea linear actuator according to certain embodiments of the present disclosure.
  • Figure 5 shows a schematic of electrical connections for an injector apparatus according to certain embodiments of the present disclosure.
  • the present disclosure provides for a coiled tubing injector apparatus that is useable at greater subsea depths and pressures than those achievable with conventional injectors.
  • the present disclosure relates to use of coiled tubing in the oil industry, and, more particularly, to an electric subsea coiled tubing injector apparatus.
  • FIG. 1 Shown in Figure 1 is a cross-sectional, side view of a coiled tubing handling system 100.
  • the system 100 may include a reel 105 for storing and deploying coiled tubing 115, as well as a tubing injector apparatus 110.
  • the reel 105 may store thousands of feet of tubing 115.
  • the outer diameters of tubing 115 may range from approximately one inch (2.5 cm) or less to approximately five inches (12.5 cm) or more.
  • the reel 105 may be located near the sea surface— for example, on a seagoing vessel or a platform.
  • the tubing injector apparatus 110 may be lowered from a near the sea surface, with a deployment system (not shown) known in the art, and may be located on the sea floor.
  • the injector apparatus 110 may include a frame 112, may be mounted above a wellhead 135, and may be aligned along an axis of the well bore or pipeline 125.
  • the injector apparatus 110 may push/pull the tubing 115 in/out the well bore 125 with an engagement assembly.
  • the injector apparatus 110 is shown to interface a well bore/pipeline with a substantially vertical longitudinal axis, the orientation depicted is exemplary.
  • the injector apparatus 110 may be adapted to interface well bores/pipelines having other orientations.
  • the injector apparatus 110 may be adapted to interface pipelines that lay in a substantially horizontal direction relative to the sea floor.
  • the tubing 115 may extend from the reel 105 and into the injector apparatus 110.
  • the reel 105 may rotate on an axle 120.
  • the reel 105 may be part of a reel assembly, which, though not depicted in Figure 1, may include a cradle for supporting the reel, a gooseneck, a drive motor, and a rotary coupling.
  • the drive motor may be rotary coupled to the reel 105.
  • the rotary coupling may provide an interface between a fluid line from the pump and the reel 105.
  • the drive motor may rotate the reel 105 to pay out the tubing 115 and the gooseneck may aid in directing the tubing 115 toward the tubing injector apparatus 110. Fluids may be pumped through the tubing 115 by a pump (not shown) that is fluidly connected to the tubing 115 through the reel 105.
  • the injector apparatus 110 may include a pair of carriages 140. In alternative embodiments, the injector apparatus 110 may include a different number of carriages. The injector apparatus 110, for example, may be adapted to include three or four carriages.
  • the carriages 140 may be slidably and/or pivotably coupled to the frame 112 of the injector apparatus 110 in order to allow for lateral movement.
  • each of carriages 140 may be slidably coupled at its base to the frame 112 with lugs.
  • the base frame 112 may have a pair of attachment lugs extending upwardly therefrom.
  • the attachment lugs may mate with corresponding carriage lugs located at a lower end of the carriages 140.
  • the carriages 140 may be attached to the frame 112 with a load pin extending through the attachment lugs and corresponding carriage lugs.
  • the attachment lugs may be slidably connected to the frame 112, so that the carriages 140 are laterally movable with respect to the frame 112 and to each other.
  • Each carriage 140 may include a chain drive system 145.
  • the chain drive system 145 may include a plurality of opposing tracks 130.
  • the tracks 130 may include endless drive chains arranged in a common plane. Alternative embodiments may include a different number and arrangement of tracks 130 than that illustrated in Figure 1.
  • Figure 2 shows a partial schematic perspective of the inner side of a carriage with the tracks and chains removed.
  • Figure 3 shows a front view of the carriages. Referring to Figures 2 and 3, the tracks 130 each may have a plurality of treaded paddles or gripper elements 132 that engage the tubing 1 15. Because the tracks 130 are positioned on opposite sides of the tubing 1 15, the tubing 115 may be squeezed between the opposing tracks 130.
  • a direct drive electric motor 165 coupled to the tracks 130 via linkage elements including sprockets, may drive the tracks 130 so that the tracks 130 may sequentially engage the tubing 1 15.
  • each chain has a gripper element 132 contacting the tubing 1 15 as another gripper element 132 on the same chain is breaking contact with the tubing 115.
  • the sequential engagement may continue as the tubing 115 is pushed into or pulled out of the wellbore 125.
  • the gripper elements 132 may be adapted for engaging coiled tubing 115 and moving it through apparatus 110, when a gripping force is applied to the tubing by the gripper elements 132.
  • the gripper elements 132 may have an inner face and may contact an outer diameter of tubing 115.
  • the gripper elements 132 may have a V-shaped groove for engaging tubing 1 15.
  • Each chain drive system 145 may include chain drive sprockets 150 in the carriage 140.
  • the sprockets 150 may be mounted on a shaft 155.
  • Shaft 112 may extend through an upper mounting boss on the forward side of the apparatus and into to a flanged bearing.
  • a bearing adapter may also be included and attached to the upper mounting boss.
  • the chain drive system may also includes a pair of spaced idler sprockets 152 which are rotatably disposed in the lower end of the carriage.
  • the idler sprockets may be mounted on a shaft 154.
  • Chain tensioners may be connected to the opposite ends of shaft 154. The tensioners may be mounted so that they can be vertically adjusted within rectangular openings of outer plates of the carriage.
  • the tracks 130 which may include a chain, may be engaged with drive sprockets 150 and idler sprockets 152 in each carriage.
  • the tracks 130 may be of a kind known in the art and have a plurality of outwardly facing gripper blocks 132 disposed thereon.
  • a roller chain drive system 149 may be rigidly positioned in each carriage between the outer plates.
  • Roller chain drive system 149 may include a linear or pressure beam 147 rigidly fixed to the outer plates of the carriage.
  • the linear beam 147 may be comprised of a linear beam frame with a bearing plate attached thereto.
  • the linear beam 147 may be rigidly attached to the carriage.
  • a pair of spaced lower, or second roller chain sprockets 148 may be rotatably disposed on a lower end of the linear beam 147.
  • a corresponding pair of spaced upper, or first roller chain sprockets may be rotatably disposed on an upper end of linear beam 147.
  • the upper and lower sprockets may be mounted on bearings supported by shafts.
  • a roller chain 149 may engage the upper and lower roller chain sprockets.
  • the roller chain 149 may have an outer side which will engage an inner side of a chain of tracks 130.
  • the lower sprockets may incorporate a tensioner, of a type known in the art to keep the proper tension on roller chain 149.
  • the injector apparatus 1 10 may include various other linkage elements which are known in the art and employed with conventional coiled tubing injectors.
  • the sprockets 150 are driven by a reversible hydraulic motor, which may be of a type known in the art, may be driven by a planetary gear, and may include an integral brake.
  • a direct drive electric motor 165 coupled to the shaft 155 and sprockets 150 of each carriage 140, in lieu of using hydraulic motors and planetary gearboxes.
  • the direct drive electric motor 165 may be bolted directly to the shaft 155 and sprockets 150.
  • the direct drive electric motors 165 may inject, retract or suspend tubing 115 in a well.
  • the drive electric motors 165 may have the capabilities of driving the chain drive system 145 in similar fashion to a hydraulic motor implementation, but without the attendant problematic issues of hydraulics.
  • the drive electric motors 165 may be capable of operating in subsea conditions to depths of 10,000 feet or more. This allows the injector apparatus 1 10 to operate in a subsea environment without having to deal with the effects of hydrostatic pressure on hydraulic components.
  • the electric drive system also removes the potential of hydraulic spills into the sea through leaks or failures.
  • the injector apparatus 1 10 also includes linear actuators 170 for moving the carriages 140 with respect to one another.
  • linear actuators 170 for moving the carriages 140 with respect to one another.
  • Actuator mounting plates 171 may have lugs 172 extending therefrom and rigidly mounted to the outer plates of the carriages. The ends of actuators 170 may be attached to lugs 172.
  • Mounting plates 171 may be attached utilizing bolts extending through the mounting plates and the outer plates of the carriage. Bolts may also extend through side webs of the linear beam to rigidly attach the linear beam to the outer plates.
  • Figure 4 shows a side view of one embodiment of a subsea linear actuator.
  • the linear actuator 170 may be attached to one carriage at end 171.
  • the linear actuator 170 may be attached to another carriage at another point, which in certain embodiments may be at end 172 and in certain embodiments may be at another point 173 that is more toward the middle of linear actuator 170.
  • the linear actuators 170 may be electrically powered, e.g., via subsea connector 172, and may be capable of operating in subsea conditions to depths of 10,000 feet or more.
  • the linear actuator 170 may be coupled to one or more pressure compensators 175 configured to allow the internal pressure in the electric motors of linear actuators 170 to be equalized with ambient pressures.
  • the linear actuators 170 accordingly may provide the force on the tubing necessary for tracks 130 to cooperatively inject, retract, or hold the tubing 115.
  • the linear actuators 170 thus may have the capabilities of hydraulic cylinders, but without the attendant problematic issues of hydraulics.
  • the linear actuators 170 may include any subsea actuator capable of satisfactorily providing the force on the tubing necessary for tracks 130 to cooperatively inject, retract, or hold the tubing 115.
  • a manual actuator may be set at the surface so that, instead of the electric motor being coupled to the drive screw.
  • FIG. 5 shows a schematic of electrical connections for injector apparatus 1 10 according to certain embodiments of the present disclosure.
  • the electrical enclosure box 180 may include a connection terminal 185 with the capabilities of connecting to power the systems within the injector apparatus 1 10.
  • Motor power cables 185 may electrically couple the direct drive electric motors 165 to the enclosure box 180.
  • Actuator power cables 190 may electrically couple the linear actuators 170 to the enclosure box 180.
  • enclosure box 180 may be firmly attached to a portion of the injector apparatus 110, such as frame 112. Accordingly, the enclosure box 180 may act as a junction box for connections of the direct drive electric motors 165 and the linear actuators 170.
  • the enclosure box 180 may include any means capable of satisfactorily terminating the electrical connections for the purpose of connection to the surface.
  • the enclosure box 180 may further include an umbilical terminal 210 coupling the enclosure box 180 to an umbilical line 215.
  • the umbilical line 215 may extend toward the sea surface and be adapted for the transmission of power, control signals, and/or data.
  • Umbilical line 215 may include one or more umbilical lines providing transmission of power necessary to drive the direct drive electric motors 165, the linear actuators 170, and other devices.
  • Umbilical line 215 may include multiple conductors.
  • the umbilical line 215 may include a conduit with the electrical connections molded into one member.
  • the conduit may be a 2" OD (outside diameter) coiled tubing. Conduit may provide the means to take returns through the coiled tubing and also provide power from a power source located at or near the sea surface.
  • the enclosure box 180 may contain control circuits configured to allow safe operation of the injector speed and motor operation.
  • the enclosure box 180 may contain wireless transmission means used for transceiving signals to/from the surface, e.g., for communication of control signals and/or data associated with the injector and/or well bore.
  • the enclosure box 180 may be further adapted to interface with peripheral devices, such as a remotely operated underwater vehicle (ROV), that may receive power via the umbilical line 215.
  • ROV remotely operated underwater vehicle
  • the enclosure box 180 may be further adapted to allow a peripheral device, such as a ROV, may control and/or power the injector apparatus 110.
  • ROV remotely operated underwater vehicle
  • the injector apparatus 1 10 may also include load cells 195 and/or a depth counter 200.
  • the enclosure box 180 may be further coupled to the injector apparatus 110 via data cables 205, which may allow for the transmission of load cell information and/or depth information.
  • data communication may be alternatively achieved via other means, such as wireless means.
  • the present disclosure provides for a coiled tubing injector apparatus that is useable at greater subsea depths and pressures than those achievable with conventional injectors.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Mechanical Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Transmission Devices (AREA)
  • Other Liquid Machine Or Engine Such As Wave Power Use (AREA)

Abstract

L'invention porte sur un appareil injecteur de tubage sous-marin enroulé. L'appareil injecteur de tubage sous-marin enroulé comprend un actionneur linéaire et deux chariots accouplés au moyen de l'actionneur linéaire. L'actionneur linéaire est mû électriquement et il est configuré pour appliquer une force latérale aux chariots. Les chariots sont configurés pour se déplacer sensiblement latéralement l'un par rapport à l'autre. Chaque chariot comprend un ensemble d'attaque du tubage, configuré pour attaquer le tubage interposé entre les chariots.
PCT/GB2011/000029 2010-01-11 2011-01-11 Appareil électrique formant injecteur de tubage sous-marin enroulé WO2011083320A2 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
EP11700753A EP2524106A2 (fr) 2010-01-11 2011-01-11 Appareil électrique formant injecteur de tubage sous-marin enroulé
BR112012016901A BR112012016901A2 (pt) 2010-01-11 2011-01-11 "aparelho submarino injetor de tubulação enrolada, injetor de tubulação submarina eletricamente acionado, e, método para injetar tubulação enrolada no interior de um furo de poço submarino"

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US12/685,162 2010-01-11
US12/685,162 US20110168401A1 (en) 2010-01-11 2010-01-11 Electric Subsea Coiled Tubing Injector Apparatus

Publications (2)

Publication Number Publication Date
WO2011083320A2 true WO2011083320A2 (fr) 2011-07-14
WO2011083320A3 WO2011083320A3 (fr) 2012-02-16

Family

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Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/GB2011/000029 WO2011083320A2 (fr) 2010-01-11 2011-01-11 Appareil électrique formant injecteur de tubage sous-marin enroulé

Country Status (4)

Country Link
US (1) US20110168401A1 (fr)
EP (1) EP2524106A2 (fr)
BR (1) BR112012016901A2 (fr)
WO (1) WO2011083320A2 (fr)

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
NO340928B1 (no) * 2013-03-11 2017-07-17 C6 Tech As Petroleumsbrønninjektor-system for en intervensjonskabel med et brønnverktøy som kjøres ned i eller ut av en brønn i en brønnoperasjon
GB2540316A (en) * 2014-07-31 2017-01-11 Halliburton Energy Services Inc Storage and deployment system for a composite slickline
US9074432B1 (en) * 2015-03-05 2015-07-07 Total E&S, Inc. Coil tubing injector using linear bearings

Citations (1)

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US6209634B1 (en) 1996-04-26 2001-04-03 Halliburton Energy Services, Inc. Coiled tubing injector apparatus

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Also Published As

Publication number Publication date
EP2524106A2 (fr) 2012-11-21
WO2011083320A3 (fr) 2012-02-16
US20110168401A1 (en) 2011-07-14
BR112012016901A2 (pt) 2018-06-05

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