EP2742205A1 - Systèmes et procédés de verrouillage de joints tournant lors de l'exécution d'opérations sous-marines - Google Patents

Systèmes et procédés de verrouillage de joints tournant lors de l'exécution d'opérations sous-marines

Info

Publication number
EP2742205A1
EP2742205A1 EP11746110.3A EP11746110A EP2742205A1 EP 2742205 A1 EP2742205 A1 EP 2742205A1 EP 11746110 A EP11746110 A EP 11746110A EP 2742205 A1 EP2742205 A1 EP 2742205A1
Authority
EP
European Patent Office
Prior art keywords
swivel joint
coiled tubing
segments
segment
pair
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Withdrawn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
EP11746110.3A
Other languages
German (de)
English (en)
Inventor
Ronald Johannes DIRKSEN
Loyd Eddie East, Jr.
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Halliburton Energy Services Inc
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
Publication of EP2742205A1 publication Critical patent/EP2742205A1/fr
Withdrawn legal-status Critical Current

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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
    • E21B17/05—Swivel joints
    • 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
    • E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
    • 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

  • coiled tubing Different stages of a subterranean drilling and completion operation often involve the use of coiled tubing. For example, all or part of a wellbore may be drilled using coiled tubing instead of more traditional drillpipe.
  • FIG. 1 An exemplary embodiment of a typical coiled tubing oil well drilling system is shown in Figure 1.
  • the drilling system comprises a coiled tubing 102 which is placed on a reel 104.
  • the coiled tubing 102 passes over a gooseneck 106 and is directed downhole through an injector head 108 into the formation 1 10.
  • the coiled tubing 102 is fed off the reel 104 over an injector head 108 into the wellbore.
  • Drilling fluid is delivered to the bottomhole assembly 114 and the drill bit 116 through the coiled tubing 102.
  • the drilling fluid is then returned to the surface through the annulus between the wellbore wall or casing and the coiled tubing 102.
  • the returned fluid which may contain drill cuttings and other materials, is directed to a returned fluid pipe 1 18 and delivered to a mud pit 120.
  • a recirculation pump 122 may then recirculate the drilling fluid through the pipe 124 to the coiled tubing 102.
  • coiled tubing drilling has limitations related to the inability to rotate the coiled tubing in the wellbore. Such limitations include inefficient transfer of power to the drill bit, inefficient hole cleaning and an inability to overcome the friction between the wellbore and the tubing, limiting the ultimate reach of the system. An ability to rotate the portion of the coiled tubing string that is in the wellbore alleviates many of these limitations, making coiled tubing drilling a more viable alternative to traditional drilling operations using a drill rig and drillpipe. BRIEF DESCRIPTION OF THE DRAWINGS
  • Figure 1 shows an exemplary embodiment of a typical coiled tubing oil well drilling system
  • Figure 2 shows a perspective view of a swivel joint in accordance with an exemplary embodiment of the present invention
  • Figure 3 shows a side view of a coiled tubing oil well drilling system in accordance with an exemplary embodiment of the present invention
  • Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells.
  • the terms “couple” or “couples,” as used herein are intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or through an indirect mechanical connection via other devices and connections.
  • uphole as used herein means along the drillstring or the hole from the distal end towards the surface
  • downhole as used herein means along the drillstring or the hole from the surface towards the distal end.
  • oil well drilling equipment or "oil well drilling system” is not intended to limit the use of the equipment and processes described with those terms to drilling an oil well.
  • the terms also encompass drilling natural gas wells or hydrocarbon wells in general. Further, such wells can be used for production, monitoring, or injection in relation to the recovery of hydrocarbons or other materials from the subsurface.
  • the present application is directed to methods and systems for performing subterranean operations and particularly, to using coiled tubing with lockable swivel joints when performing drilling operations.
  • the swivel joints may be locked and unlocked using a sliding sleeve that slides up as the coiled tubing goes through the injector head into the borehole. By sliding up, the sleeve locks the swivel joint to substantially prevent the relative rotation of adjoining coiled tubing segments.
  • the sleeve may slide down and allow the swivel joint to rotate again, thereby permitting adjoining segments of coiled tubing to rotate relative to each other.
  • a locking mechanism may be used to lock and/or unlock the swivel joints 10.
  • the locking mechanism may engage the swivel joints 10 such that the adjoining segments of the coiled tubing are rotationally coupled, and/or it may disengage the swivel joints such that the adjoining segments of coiled tubing 16 can be independently rotatable.
  • Two segments are deemed “rotationally coupled” when rotating one of the two segments will rotate the other one of the two segments.
  • two segments are deemed “rotationally decoupled” when rotating one of the two segments will not rotate the other segment.
  • the swivel joint 10 is comprised of a latch mechanism.
  • the swivel joint 10 includes a first portion 11 having one or more latch receptacles 12 and a sleeve portion 14 which may include one or more latch portions 13 formed as projections that may be locked into the one or more latch receptacles 12 on the first portion 11 of the swivel joint 10.
  • the first portion 11 may be provided on a first segment of the coiled tubing and the sleeve portion 14 may be on a second, adjoining segment of coiled tubing.
  • the swivel joint 10 may be engaged and disengaged by a locking device located at or near an injector head. Accordingly, the locking device is operable to couple the first portion 11 to the sleeve portion 14.
  • the locking device may be a mechanical system, an electrical system, a magnetic system and/or a combination of one or more of these systems.
  • the locking device may mechanically flip the latch 13 into the latch receptacle 12 as the coiled tubing 16 moves downhole through the injector head and it may disengage the latch 13 from the latch receptacle 12 when the coiled tubing 16 is pulled out of the wellbore through the injector head.
  • the swivel joints may be remotely controlled by an operator.
  • the operator may selectively engage or disengage particular swivel joints, thereby controlling which coiled tubing segments can rotate independently and which ones cannot.
  • wired or wireless communications systems may be used to engage or disengage the first portion 11 and the sleeve portion 14 of the swivel joint 10. Such communications systems are well known to those of ordinary skill in the art and will, therefore, not be discussed in detail herein.
  • latch mechanism may be used without departing from the scope of the present disclosure.
  • a latch mechanism is depicted in Figure 2
  • other mechanisms may be used to engage and/or disengage the swivel joint.
  • a magnetic connection between the first portion 1 1 and the sleeve 14 may be used to engage and/or disengage the swivel joints 10.
  • the operator may activate the magnetic force between the first portion 1 1 and the sleeve portion 14 for swivel joints that are desired to be engaged, and deactivate the magnetic force for swivel joints 10 that are desired to be disengaged.
  • FIG 3 a side view of a coiled tubing oil well drilling system in accordance with an exemplary embodiment of the present invention is shown where the swivel joints 10 separate different segments of the coiled tubing 16.
  • a swivel joint 10 may be provided at the interface between a pair of segments of coiled tubing 16 as shown in Figure 3.
  • the present invention is not limited by the number or positioning of the swivel joints 10 or the coiled tubing segments and Figure 3 is used for illustrative purposes.
  • swivel joints 10 may be selectively engaged. Specifically, one or more swivel joints 10 may be disengaged initially. In one embodiment, the swivel joints 10 downhole may be locked in position as discussed above with reference to Figure 2, and discussed in more detail below.
  • the coiled tubing 16 may be directed downhole through an injector head 20.
  • the swivel joints 10A which are located above the ground and/or above the injector head 20 may be disengaged while the swivel joints 10B located below the ground and/or below the injector head may be engaged.
  • the operator may decide at which point the swivel joints 10 are locked and/or unlocked. Specifically, in one embodiment, the swivel joints 10 may be locked and/or unlocked at a point further downhole from the injector head 20.
  • the segments of coiled tubing 16 located above the ground and/or above the injector head 20 may rotate relative to their adjoining segments as well as relative to the coiled tubing segment located below the injector head 20.
  • the rotation of the coiled tubing 16 portion located below the injector head will not impact the portion of the coiled tubing located above the ground, on the gooseneck 28 or the reel 26.
  • the swivel joints 10B may be engaged, rotationally coupling the adjoining segments of the coiled tubing 16 located downhole.
  • the rotation from a rotation device 24, located at or near the surface, mounted in, on or below the injector head 20, may be used to rotate the drill bit 22.
  • rotation may be transferred downhole to the drill bit 22.
  • the torque generated by the rotation device at or near the injector head 20 may be transferred downhole by the coiled tubing to the Bottom Hole Assembly 18 and the drill bit 22.
  • any suitable device may be used to rotate the portion of the coiled tubing 16 downhole.
  • the rotation device 24 may be a rotary table where one directional slips can be used to clamp the coiled tubing 16 and couple the rotation of the rotary table to the coiled tubing 16.
  • a high torque spinner may be mounted below the injector head 20 or inside the injector head 20.
  • the rotation device may clamp around the coiled tubing 16 when rotation is required and may be powered using hydraulics, an air motor, or an electric motor.
  • the swivel joint 10 may be equipped with a cleaning device.
  • the cleaning device may be used to clean the different swivel joint 10 components such as the bearings and the grooves thereon.
  • the cleaning device may be in the form of a hig-power water or air flow, or it may be in the form of a simple wiper seal, or in the form of rotating brushes, or any combination of two or more of such devices.
  • the swivel joints 10 having a locking mechanism in accordance with an embodiment of the present invention may render the coiled tubing segmented string spoolable. Accordingly, the spoolable segmented coiled tubing may provide continuous circulation and axial movement and control the axial speed of the drilling process. Moreover, the improved segmented coiled tubing is better suited for use in conjunction with Managed Pressure Drilling ("MPD”) and underbalanced drilling (“UBD").
  • MPD Managed Pressure Drilling
  • ULD underbalanced drilling
  • the present invention allows both clockwise and anti-clockwise rotation of the coiled tubing, which may facilitate hole cleaning, motor toolface orientation for directional drilling, or working through tight spots in the wellbore, as well as be used to activate and de-activate downhole devices, such as underreamers, circulating subs and the like.
  • the present invention may also be used in this fashion to seat and unseat packers and like devices in completions, workover, or well intervention-type operations.
  • the systems and methods disclosed herein may be used in conjunction with an embodiment with a hybrid string of tubing located below the coiled tubing.
  • the locking mechanism must be strong enough to withstand the torque imparted onto the coiled tubing during rotation and must lock in so as not to allow the system to become unlocked downhole.

Landscapes

  • 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)
  • Quick-Acting Or Multi-Walled Pipe Joints (AREA)

Abstract

L'invention concerne un système pour effectuer des opérations sous-marines. Le système comprend un tubage enroulé constitué d'un premier et d'un second segment ; un joint tournant positionné sur une interface du premier et du second segment ; et un mécanisme de verrouillage fonctionnant pour venir en contact et s'écarter du joint tournant.
EP11746110.3A 2011-08-11 2011-08-11 Systèmes et procédés de verrouillage de joints tournant lors de l'exécution d'opérations sous-marines Withdrawn EP2742205A1 (fr)

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2011/047351 WO2013022449A1 (fr) 2011-08-11 2011-08-11 Systèmes et procédés de verrouillage de joints tournant lors de l'exécution d'opérations sous-marines

Publications (1)

Publication Number Publication Date
EP2742205A1 true EP2742205A1 (fr) 2014-06-18

Family

ID=44630539

Family Applications (1)

Application Number Title Priority Date Filing Date
EP11746110.3A Withdrawn EP2742205A1 (fr) 2011-08-11 2011-08-11 Systèmes et procédés de verrouillage de joints tournant lors de l'exécution d'opérations sous-marines

Country Status (7)

Country Link
US (1) US20140124219A1 (fr)
EP (1) EP2742205A1 (fr)
CN (1) CN103748312B (fr)
BR (1) BR112014003180A2 (fr)
CA (1) CA2844479C (fr)
MX (1) MX340246B (fr)
WO (1) WO2013022449A1 (fr)

Families Citing this family (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013130977A2 (fr) * 2012-03-01 2013-09-06 Saudi Arabian Oil Company Système de forage rotatif continu et procédé d'utilisation
AU2017393950B2 (en) 2017-01-18 2022-11-24 Minex Crc Ltd Mobile coiled tubing drilling apparatus
CN107939318B (zh) * 2017-11-30 2018-11-09 中国石油大学(北京) 局部欠平衡钻井回流装置
WO2019199377A1 (fr) * 2018-04-13 2019-10-17 Exxonmobil Upstream Research Company Ensemble colonne de production spiralée
RU191421U1 (ru) * 2019-04-29 2019-08-05 Публичное акционерное общество «Татнефть» имени В.Д. Шашина Штанговращатель с гибкой тягой
CA3144649A1 (fr) * 2020-12-31 2022-06-30 Rus-Tec Engineering, Ltd. Systeme et methode d'obtention d'echantillons de formations au moyen d'un tube de production concentrique
AU2022381174A1 (en) * 2021-11-03 2024-05-16 Conocophillips Company Downhole joint rotator

Family Cites Families (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5738178A (en) * 1995-11-17 1998-04-14 Baker Hughes Incorporated Method and apparatus for navigational drilling with a downhole motor employing independent drill string and bottomhole assembly rotary orientation and rotation
WO1998029637A1 (fr) * 1996-12-31 1998-07-09 Helms Charles M Dispositif de tete d'injection verrouillable et procede correspondant
US6186238B1 (en) * 1998-08-19 2001-02-13 Ypf S.A. Assembly and method for the extraction of fluids from a drilled well within a geological formation
US6446737B1 (en) * 1999-09-14 2002-09-10 Deep Vision Llc Apparatus and method for rotating a portion of a drill string
NO311100B1 (no) * 1999-10-26 2001-10-08 Bakke Technology As Apparat for bruk ved mating av et roterende nedihullsverktöy, samt anvendelse av apparatet
CN101382069A (zh) * 2007-09-04 2009-03-11 中国石油天然气集团公司 连续管水平井测井工艺技术及装置
EP2108780A1 (fr) * 2008-04-10 2009-10-14 Robert Graham Procédé de forage hybride

Also Published As

Publication number Publication date
CA2844479C (fr) 2015-08-04
RU2014109012A (ru) 2015-09-20
CA2844479A1 (fr) 2013-02-14
US20140124219A1 (en) 2014-05-08
MX2014001588A (es) 2014-04-30
BR112014003180A2 (pt) 2017-03-14
WO2013022449A1 (fr) 2013-02-14
CN103748312A (zh) 2014-04-23
MX340246B (es) 2016-07-01
CN103748312B (zh) 2016-12-21

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