EP4028630B1 - System zur steuerung eines gewickelten rohrstranges in offenen gewässern - Google Patents

System zur steuerung eines gewickelten rohrstranges in offenen gewässern Download PDF

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Publication number
EP4028630B1
EP4028630B1 EP20879225.9A EP20879225A EP4028630B1 EP 4028630 B1 EP4028630 B1 EP 4028630B1 EP 20879225 A EP20879225 A EP 20879225A EP 4028630 B1 EP4028630 B1 EP 4028630B1
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EP
European Patent Office
Prior art keywords
coiled tubing
subsea
tubing string
movement
reel
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Active
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EP20879225.9A
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English (en)
French (fr)
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EP4028630A4 (de
EP4028630A1 (de
Inventor
Torleif CARLSEN
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Oceaneering International Inc
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Oceaneering International Inc
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Publication of EP4028630A1 publication Critical patent/EP4028630A1/de
Publication of EP4028630A4 publication Critical patent/EP4028630A4/de
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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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/01—Risers
    • E21B17/017—Bend restrictors for limiting stress on risers
    • 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

  • Running coiled tubing (CT) in open water from a vessel, and then possibly directly through a subsea tree, as well as running CT by utilizing an injector on a vessel and an injector on the subsea tree/wellhead typically comprises concerns with maintenance of tension between vessel injector and subsea injector and/or reliance of passive heave control for the vessel injector.
  • a direct hydraulic control system e.g. a vessel to subsea assist jack, is impractical as the whip effect stress wave travels at near the speed of sound in the coiled tubing steel (damped by the surrounding water) whereas the transmission of a hydraulic pressure change command travels at the speed of sound in the hydraulic fluid. The former is approximately four times faster than the later.
  • Prior art document U.S. 2015/101799 A1 discloses methods and apparatus for monitoring loads on an arched tubing guide of a coiled tubing injector caused by tension on coiled tubing.
  • the load is sensed by a load sensor, for example, a load cell placed in a strut that supports the arched tubing guide, or in a load pin or load cell placed within the structure arched tubing guide or the connection of the arched tubing guide to a frame for the coiled tubing injector, at a location where the load is representative of the load placed on an arched tubing guide by tension in the coiled tubing.
  • the load sensor generates a feedback signal.
  • the load is monitored, either by an operator or a controller, and torque applied to a reel around which the tubing is wound is adjusted to avoid, or in response to, excessive loads on the arched tubing guide.
  • Prior art document U.S. 2018/080850 A1 discloses a technique that facilitates monitoring and managing fatigue related a flexible conduit deployed from a surface vessel. Movements of the surface vessel may be measured to obtain vessel movement/position data. Based on this data, a flexible conduit bend profile may be determined via a computer-based data processing system. The flexible conduit bend profile may then be used to provide a flexible conduit fatigue profile for assessment of the flexible conduit in light of the environmental conditions. In some embodiments, the fatigue profile and assessment of the flexible conduit may be based on both functional loading and environmental loading.
  • Prior art document U.S. 5,975,203 A discloses an apparatus and method for pulling or inserting jointed pipe sections having upset ends within a well utilizing a coiled tubing injector.
  • the coiled tubing injector has a pair of opposed endless chains including gripper blocks for gripping the pipe sections.
  • An axial gap is provided in chains between adjacent gripper blocks to receive the upset ends.
  • a sensing mechanism is provided to sense the location of upset end and a sensing mechanism is provided to sense the location of gap.
  • An operator in response to signals from the sensors accurately aligns upset ends with gap.
  • Prior art document U.S. 2004/065475 A1 discloses an apparatus and method for offshore riserless drilling.
  • the preferred embodiments comprise a system for riserless drilling of a subsea borehole from a platform and through a cased borehole, the system comprising a lightweight drill string suspending a bottomhole assembly and extending from the platform downwardly through a depth of water into the cased borehole; a first limiter limiting the range of motion of the drill string adjacent the platform; and a second limiter limiting the range of motion of the drill string adjacent the cased borehole.
  • the preferred methods include lowering a bottomhole assembly suspended on a lightweight drill string from a platform through a depth of water; limiting the bend radius of the drill string adjacent the platform; guiding the bottomhole assembly into a cased borehole; limiting the bend radius of the drill string adjacent the cased borehole; maintaining the bottomhole assembly in the cased borehole, and drilling the subsea borehole.
  • the body comprises aft and forward shafts and a central control assembly.
  • the packerfeet and propulsion cylinders are slidably engaged with the tractor body.
  • Drilling fluid can be delivered to the packerfeet to cause the packerfeet to grip onto the borehole wall.
  • Drilling fluid can be delivered to the propulsion cylinders to selectively provide downhole or uphole hydraulic thrust to the tractor body.
  • the tractor receives drilling fluid from a drill string extending to the surface.
  • a system of spool valves in the control assembly controls the distribution of drilling fluid to the packerfeet and cylinders.
  • the valve positions are controlled by motors.
  • a programmable electronic logic component on the tractor receives control signals from the surface and feedback signals from various sensors on the tool.
  • the feedback signals may include pressure, position, and load signals.
  • the logic component also generates and transmits command signals to the motors, to electronically sequence the valves.
  • the logic component operates according to a control algorithm for intelligently sequencing the valves to control the speed, thrust, and direction of the tractor.
  • Prior art document U.S. 2004/040707 A1 discloses an apparatus and methods for sequentially treating multiple zones in underground formation in a single trip of the well treatment work string.
  • the work string includes composite tubing having electrical conductors embedded within the walls, the conductors enabling power transmission and two way communication between the surface and the sensor or detectors downhole so that real time data can be sensed and communicated.
  • Isolation packers are actuated via electrical signals from the surface communicated to the bottom hole assembly via the conductors.
  • a detector located in the bottom hole assembly may be provided to detect perforations or other anomalies in the casing, such as joints, enabling the surface controller to position packers properly in blank segments of casing so that well intervals can be properly isolated and the adjacent formation effectively treated.
  • Prior art document U.S. 7,530,399 A1 discloses a delivery system for downhole use comprising an elongate delivery member, such as a length of wireline cable or coiled tubing, an injector to control the insertion of the delivery member into the well, and a storage device such as a reel to store at least a portion of the delivery member prior to insertion into the well.
  • the system has a motion compensator arranged to compensate for relative motion between the injector and the storage device.
  • the motion compensator optionally is arranged to compensate for relative movement between the injector and the well, and the movement of the motion compensator on the storage device and the motion compensator on the injection head can be coordinated by a motion controller adapted and arranged to measure the movement of the injector and to signal the motion compensator on the storage device to move in accordance with the movement of the injector.
  • Prior art document U.S. 2016/369614 A1 discloses a coiled tubing deployment system which includes an offshore rig having a reel positioned thereon and coiled tubing wound on the reel.
  • a guide arch receives the coiled tubing from the reel and a monitoring support guide fixed to the offshore rig receives and directs the coiled tubing into water.
  • the monitoring support guide has a frame and at least two hydraulic rams.
  • a depth counter measures the coiled tubing deployed from the reel and generates length measurement signals, and sensors coupled to the at least two hydraulic rams measure real-time lateral movement of the coiled tubing with respect to the monitoring support guide as the coiled tubing is deployed into the water and thereby generate sensor signals.
  • a data acquisition system receives and processes the length measurement and sensor signals to provide an output signal indicative of real-time bending fatigue of the coiled tubing at select locations along the coiled tubing.
  • Prior art document U.S. 6,116,345 discloses a tubing injection system that contains one injector for moving a tubing from a source thereof to a second injector.
  • the second injector moves the tubing into the wellbore.
  • the system may contain a first injector placed under water over the wellhead equipment for moving the tubing to and from the wellbore.
  • a second injector at the surface moves the tubing to the first injector and a third injector moves the tubing from the tubing source to the second injector.
  • sensors are provided to determine the radial force on the tubing exerted by the injectors, tubing speed, injector speed, and the back tension on the source.
  • a control unit containing a computer continually maintains the tubing speed, tension and radial pressure on the tubing within predetermined limits.
  • the control unit is programmed to automatically control the operation of the tubing injection systems according to programs or models provided to the control unit.
  • Fig. 1 is a block diagram of an exemplary open water coiled tubing control system.
  • open water coiled tubing control system l comprises reel 20 configured to accept and spool/unspool coiled tubing string 100; one or more surface injectors 30 operatively in fluid communication with coiled tubing string 100; one or more reel tensioners 10 configured to control arch 110 formed by coiled tubing string 100 where control arch 110 is disposed in-between reel 20 and surface injector 30; and one or more controllers 40 configured to control reel tensioner 10 and allow movement of coiled tubing string 100 and surface injector 30 relative to each other without adding additional fatigue life consumption due to vessel heave.
  • Open water coiled tubing control system 1 typically uses surface injector motion to move coiled tubing string 100 into/out of the water.
  • coiled tubing string 100 is disposed about an outer surface of reel 20 but other embodiments are contemplated such as being disposed within or partially within reel 20.
  • Surface injector 30 may be mounted on heave compensator 32.
  • controller 40 is disposed intermediate reel 20 and surface injector 30 above a water level such as by being connected to, or otherwise mounted on or to, vessel 210.
  • open water coiled tubing control system 1 further comprises subsea assist jack 50 to move coiled tubing string 100 into/out of subsea well 200.
  • open water coiled tubing control system 1 comprises a predetermined set of sensors (generally referred to but not specifically shown in the figure as callout "60"), which may be integrated into other components or separate.
  • the predetermined set of sensors 60 are operatively in communication with controller 40 and comprises one or more surface injector load sensors 61 configured to detect and provide data related to a load at surface injector 30; one or more coiled tubing string movement sensors 62 configured to detect and provide data related to movement of coiled tubing string 100 in reel tensioner 10 where the data comprise speed of movement; one or more surface injector movement sensors 63 configured to detect and provide data related to movement of surface injector 30; and one or more vessel movement sensors 64 configured to detect and provide data related to movement of vessel 210 where the data comprise active heave data and/or passive heave data.
  • the predetermined set of sensors 60 typically also comprise one or more subsea assist jack load sensors 65 configured to detect and provide data related to a load at subsea assist jack 50 and one or more subsea assist jack movement sensors 66 configured to detect and provide data related to movement of subsea assist jack 50.
  • open water coiled tubing control system 1 is deployed such as via vessel 210 which may also used to support surface injector 30.
  • Open water coiled tubing control system 1 receives information related to a load at surface injector 30 and, if present, at subsea assist jack 50; information on movement of coiled tubing string 100 in reel tensioner 10, surface injector 30, and, if present, subsea assist jack 50; and information on movement of vessel 210 or a compensation system such as heave compensator 32 used to support surface injector 30, e.g. either active or passive heave.
  • Open water coiled tubing control system 1 resolves all or a predetermined part of the information so received, e.g. by controller 40, to effect movement of coiled tubing string 100 into and/or out from subsea well 200 at a predetermined desired speed to achieve an outcome by having one or more commands issued to reel tensioners 10 by a single input from an operator. Typically, this is accomplished by an operator using controller 40 to issue one or more commands to reel 20, surface injectors 30, and reel tensioners 10 substantially simultaneously.
  • part of the resolved solution is to maintain coiled tubing string 100 at a predetermined tension in-between surface injector 30 and subsea assist jack 50.
  • controller 40 uses the information it receives from sensors 60 and determines a continuous movement rate of surface injector 30 versus an interrupted rate of subsea assist jack 50.
  • subsea assist jack 50 can be remotely disengaged from gripping coiled tubing string 100 when the force supplied by subsea assist jack 50 is no longer required to move coiled tubing string 100 into or out of subsea well 200. This can be accomplished by traditional means and/or by an instruction provided to controller 40 from a remote location or the like.
  • Open water coiled tubing control system l typically needs to have limited hysteresis to avoid a "whip effect” caused in part by an induced vessel movement resulting from wave action.
  • Knowledge of the "whip effect” and the speed of translation on the stress wave through coiled tubing string 100 allows a determination of required system performance and operating limits of open water coiled tubing control system 1 versus the "sea state.”

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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)

Claims (9)

  1. Freiwasser-Wickelrohr-Steuersystem (1), umfassend:
    a. eine Spule (20), die dazu konfiguriert ist, einen Wickelrohrstrang (100) aufzunehmen;
    b. einen Oberflächeninjektor (30) in Fluidverbindung mit dem Wickelrohrstrang;
    c. eine Spulenspannvorrichtung (10), die dazu konfiguriert ist, eine von dem Wickelrohrstrang zwischen der Spule und dem Oberflächeninjektor gebildete Bogenform (110) zu steuern;
    d. eine Untersee-Hilfshebevorrichtung (50), die dazu konfiguriert ist, den Wickelrohrstrang in eine oder aus einem Unterseebohrloch (200) zu bewegen;
    e. einen vorgegebenen Satz von Sensoren (60), umfassend:
    i. einen Oberflächeninjektor-Lastsensor (61), der dazu konfiguriert ist, mit einer Last an dem Oberflächeninjektor zusammenhängende Daten zu erfassen und bereitzustellen;
    ii. einen Wickelrohrstrang-Bewegungssensor (62), der dazu konfiguriert ist, mit Bewegung des Wickelrohrstrangs in der Spulenspannvorrichtung zusammenhängende Daten zu erfassen und bereitzustellen, wobei die Daten die Bewegungsgeschwindigkeit umfassen;
    iii. einen Oberflächeninjektor-Bewegungssensor (63), der dazu konfiguriert ist, mit Bewegung des Oberflächeninjektors zusammenhängende Daten zu erfassen und bereitzustellen;
    iv. einen Schiffsbewegungssensor (64), der dazu konfiguriert ist, mit Bewegung eines Schiffs (210) zusammenhängende Daten zu erfassen und bereitzustellen, wobei die Daten Daten zu aktiver Tauchbewegung oder Daten zu passiver Tauchbewegung umfassen;
    v. einen Untersee-Hilfshebevorrichtungs-Lastsensor (65), der dazu konfiguriert ist, mit einer Last an der Untersee-Hilfshebevorrichtung zusammenhängende Daten zu erfassen und bereitzustellen; und
    vi. einen Untersee-Hilfshebevorrichtungs-Bewegungssensor (66), der dazu konfiguriert ist, mit Bewegung der Untersee-Hilfshebevorrichtung zusammenhängende Daten zu erfassen und bereitzustellen; und
    f. eine Steuereinheit (40) in Wirkverbindung mit dem vorgegebenen Satz von Sensoren (60), wobei die Steuereinheit dazu konfiguriert ist, Informationen, die sie von dem vorgegebenen Satz von Sensoren (60) empfängt, zu verwenden, um den Wickelrohrstrang (100) durch Bestimmen einer kontinuierlichen Bewegungsrate des Oberflächeninjektors (30) gegenüber einer unterbrochenen Rate der Untersee-Hilfshebevorrichtung (50) auf einer vorgegebenen Spannung zu halten.
  2. Freiwasser-Wickelrohr-Steuersystem nach Anspruch 1, wobei die Spule dazu konfiguriert ist, den Wickelrohrstrang um eine Außenoberfläche der Spule aufzunehmen und/oder den Wickelrohrstrang teilweise innerhalb der Spule aufzunehmen.
  3. Freiwasser-Wickelrohr-Steuersystem nach Anspruch 1, wobei die Steuereinheit (40) zwischen der Spule (20) und dem Oberflächeninjektor (30) angeordnet ist.
  4. Freiwasser-Wickelrohr-Steuersystem nach Anspruch 1, wobei die Steuereinheit (40) mit dem Schiff (210) verbunden oder anderweitig daran angebracht ist.
  5. Freiwasser-Wickelrohr-Steuersystem nach Anspruch 1, wobei die Untersee-Hilfshebevorrichtung (50) von dem Schiff aus in das Wasser eingebracht wird.
  6. Verfahren zum Bewegen eines Wickelrohrstrangs in und/oder aus Wasser, umfassend:
    a. Einbringen eines Freiwasser-Wickelrohr-Steuersystems (1) auf See mit einem Schiff, wobei das Freiwasser-Wickelrohr-Steuersystem (1) Folgendes umfasst: eine Spule (20), die dazu konfiguriert ist, einen Wickelrohrstrang (100) aufzunehmen, einen von dem Schiff getragenen Oberflächeninjektor (30) in Fluidverbindung mit dem Wickelrohrstrang, eine Spulenspannvorrichtung (10), die dazu konfiguriert ist, eine von dem Wickelrohrstrang zwischen der Spule und dem Oberflächeninjektor gebildete Bogenform (110) zu steuern, eine Untersee-Hilfshebevorrichtung (50), die dazu konfiguriert ist, den Wickelrohrstrang in ein oder aus einem Unterseebohrloch zu bewegen, einen vorgegebenen Satz von Sensoren (60), umfassend einen Lastsensor, der dazu konfiguriert ist, mit einer Last an dem Oberflächeninjektor zusammenhängende Daten zu erfassen und bereitzustellen, einen Wickelrohrstrang-Bewegungssensor, der dazu konfiguriert ist, mit Bewegung des Wickelrohrstrangs in der Spulenspannvorrichtung zusammenhängende Daten zu erfassen und bereitzustellen, wobei die Daten Bewegungsgeschwindigkeit umfassen, einen Oberflächeninjektor-Bewegungssensor, der dazu konfiguriert ist, mit Bewegung des Oberflächeninjektors zusammenhängende Daten zu erfassen und bereitzustellen, einen Schiffsbewegungssensor, der dazu konfiguriert ist, mit Bewegung des Schiffs zusammenhängende Daten zu erfassen und bereitzustellen, wobei die Daten Daten zu aktiver Tauchbewegung oder Daten zu passiver Tauchbewegung umfassen, einen Untersee-Hilfshebevorrichtungs-Lastsensor, der dazu konfiguriert ist, mit einer Last an der Untersee-Hilfshebevorrichtung zusammenhängende Daten zu erfassen und bereitzustellen, und einen Untersee-Hilfshebevorrichtungs-Bewegungssensor, der dazu konfiguriert ist, mit Bewegung der Untersee-Hilfshebevorrichtung zusammenhängende Daten zu erfassen und bereitzustellen, und eine Steuereinheit (40) in Wirkverbindung mit dem vorgegebenen Satz von Sensoren (60), wobei die Steuereinheit dazu konfiguriert ist, durch Verwenden von Informationen, die sie von dem vorgegebenen Satz von Sensoren (60) empfängt, den Wickelrohrstrang (100) auf einer vorgegebenen Spannung zu halten, um eine kontinuierliche Bewegungsrate des Oberflächeninjektors (30) gegenüber einer unterbrochenen Rate der Untersee-Hilfshebevorrichtung (50) zu bestimmen;
    b. Verwenden von Bewegung des Oberflächeninjektors und der Untersee-Hilfshebevorrichtung, um einen von der Spule aufgenommenen Wickelrohrstrang durch Folgendes in ein und/oder aus einem Unterseebohrloch (200) zu bewegen:
    i. Empfangen von Informationen von dem vorgegebenen Satz von Sensoren, an der Steuereinheit, die eine Last an dem Oberflächeninjektor und an der Untersee-Hilfshebevorrichtung repräsentieren;
    ii. Empfangen von Informationen von dem vorgegebenen Satz von Sensoren, an der Steuereinheit zu Bewegung des Wickelrohrstrangs in der Spulenspannvorrichtung, dem Oberflächeninjektor und der Untersee-Hilfshebevorrichtung;
    iii. Empfangen von Informationen von dem vorgegebenen Satz von Sensoren, an der Steuereinheit zu Bewegung des zum Tragen des Oberflächeninjektors verwendeten Schiffs;
    iv. Verwenden der Steuereinheit, um die empfangenen Informationen aufzulösen, um den Wickelrohrstrang mit einer vorgegebenen Sollgeschwindigkeit in das oder aus dem Unterseebohrloch zu bewegen, um ein durch eine Einzeleingabe von einer Bedienperson befohlenes Resultat zu erreichen, wobei die Einzeleingabe von der Bedienperson einen im Wesentlichen gleichzeitig an die Spule, den Oberflächeninjektor und die Spulenspannvorrichtung gesendeten Befehl umfasst.
  7. Verfahren zum Bewegen eines Wickelrohrstrangs in und/oder aus Wasser nach Anspruch 6, wobei das Halten des Wickelrohrstrangs auf einer vorgegebenen Spannung zwischen dem Oberflächeninjektor und der Untersee-Hilfshebevorrichtung ferner das Steuern der Spulenspannvorrichtung dazu umfasst, Bewegung des Wickelrohrstrangs und des Oberflächeninjektors relativ zueinander zu ermöglichen, ohne zusätzliches Aufbrauchen von Ermüdungslebensdauer infolge Tauchbewegung des Schiffs hinzuzufügen.
  8. Verfahren zum Bewegen eines Wickelrohrstrangs in und/oder aus Wasser nach Anspruch 6, ferner umfassend das Verwenden der Steuereinheit, um eine kontinuierliche Bewegungsrate des Oberflächeninjektors gegenüber einer unterbrochenen Rate der Untersee-Hilfshebevorrichtung zu bestimmen.
  9. Verfahren zum Bewegen eines Wickelrohrstrangs in und/oder aus Wasser nach Anspruch 6, ferner umfassend das Lösen aus der Ferne des Greifens des Wickelrohrstrangs durch die Untersee-Hilfshebevorrichtung, wenn eine von der Untersee-Hilfshebevorrichtung bereitgestellte Kraft zum Bewegen des Wickelrohrstrangs in das oder aus dem Unterseebohrloch nicht mehr benötigt wird.
EP20879225.9A 2019-10-21 2020-09-30 System zur steuerung eines gewickelten rohrstranges in offenen gewässern Active EP4028630B1 (de)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201962924045P 2019-10-21 2019-10-21
PCT/US2020/053398 WO2021080752A1 (en) 2019-10-21 2020-09-30 Open water coiled tubing control system

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EP4028630A1 EP4028630A1 (de) 2022-07-20
EP4028630A4 EP4028630A4 (de) 2023-07-26
EP4028630B1 true EP4028630B1 (de) 2025-03-26

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Publication number Priority date Publication date Assignee Title
NO20240316A1 (en) * 2024-04-03 2025-10-06 TechnipFMC Norge AS Method of operating a subsea coiled tubing injector, and related apparatus and control device

Family Cites Families (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6116345A (en) * 1995-03-10 2000-09-12 Baker Hughes Incorporated Tubing injection systems for oilfield operations
US5975203A (en) * 1998-02-25 1999-11-02 Schlumberger Technology Corporation Apparatus and method utilizing a coiled tubing injector for removing or inserting jointed pipe sections
US6347674B1 (en) * 1998-12-18 2002-02-19 Western Well Tool, Inc. Electrically sequenced tractor
US20040040707A1 (en) * 2002-08-29 2004-03-04 Dusterhoft Ronald G. Well treatment apparatus and method
US7150324B2 (en) * 2002-10-04 2006-12-19 Halliburton Energy Services, Inc. Method and apparatus for riserless drilling
GB0522971D0 (en) * 2005-11-11 2005-12-21 Qserv Ltd Apparatus and method
US9581009B2 (en) * 2013-10-15 2017-02-28 National Oilwell Varco, L.P. Coiled tubing injector with load sensing tubing guide
WO2016130155A1 (en) * 2015-02-13 2016-08-18 Halliburton Energy Services, Inc. Real-time tracking and mitigating of bending fatigue in coiled tubing
US10883894B2 (en) * 2016-09-16 2021-01-05 Onesubsea Ip Uk Limited Conduit fatigue management systems and methods

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EP4028630A4 (de) 2023-07-26
BR112022007453A2 (pt) 2022-07-12
WO2021080752A1 (en) 2021-04-29
EP4028630A1 (de) 2022-07-20

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