Patent Description:
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.

Existing systems do not disclose or render obvious an integrated control system that responds to a single operator input and controls.

Prior art document <CIT> 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 <CIT> 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 <CIT> 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. To align accurately upset ends with gap, 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 <CIT> 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.

Prior art document <CIT> discloses a downhole drilling tractor for moving within a borehole comprises a tractor body, two packerfeet, two aft propulsion cylinders, and two forward propulsion cylinders. 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. Advantageously, 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 <CIT> discloses an apparatus and methods for sequentially treating multiple zones in underground formation in a single trip of the well treatment work string. In the one embodiment, 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 <CIT> 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 <CIT> 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 <CIT> 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. In an alternative embodiment for subsea operations, 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. In each of the tubing injection systems 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.

Various figures are included herein which illustrate aspects of embodiments of the disclosed inventions.

<FIG> is a block diagram of an exemplary open water coiled tubing control system.

In a first embodiment, referring generally to <FIG>, open water coiled tubing control system l comprises reel <NUM> configured to accept and spool/unspool coiled tubing string <NUM>; one or more surface injectors <NUM> operatively in fluid communication with coiled tubing string <NUM>; one or more reel tensioners <NUM> configured to control arch <NUM> formed by coiled tubing string <NUM> where control arch <NUM> is disposed in-between reel <NUM> and surface injector <NUM>; and one or more controllers <NUM> configured to control reel tensioner <NUM> and allow movement of coiled tubing string <NUM> and surface injector <NUM> relative to each other without adding additional fatigue life consumption due to vessel heave.

Open water coiled tubing control system <NUM> typically uses surface injector motion to move coiled tubing string <NUM> into/out of the water.

Typically, coiled tubing string <NUM> is disposed about an outer surface of reel <NUM> but other embodiments are contemplated such as being disposed within or partially within reel <NUM>.

Surface injector <NUM> may be mounted on heave compensator <NUM>.

In embodiments, controller <NUM> is disposed intermediate reel <NUM> and surface injector <NUM> above a water level such as by being connected to, or otherwise mounted on or to, vessel <NUM>.

In certain embodiments, open water coiled tubing control system <NUM> further comprises subsea assist jack <NUM> to move coiled tubing string <NUM> into/out of subsea well <NUM>.

In most embodiments, open water coiled tubing control system <NUM> comprises a predetermined set of sensors (generally referred to but not specifically shown in the figure as callout "<NUM>"), which may be integrated into other components or separate. Typically, the predetermined set of sensors <NUM> are operatively in communication with controller <NUM> and comprises one or more surface injector load sensors <NUM> configured to detect and provide data related to a load at surface injector <NUM>; one or more coiled tubing string movement sensors <NUM> configured to detect and provide data related to movement of coiled tubing string <NUM> in reel tensioner <NUM> where the data comprise speed of movement; one or more surface injector movement sensors <NUM> configured to detect and provide data related to movement of surface injector <NUM>; and one or more vessel movement sensors <NUM> configured to detect and provide data related to movement of vessel <NUM> where the data comprise active heave data and/or passive heave data. In embodiments comprising subsea assist jack <NUM>, the predetermined set of sensors <NUM> typically also comprise one or more subsea assist jack load sensors <NUM> configured to detect and provide data related to a load at subsea assist jack <NUM> and one or more subsea assist jack movement sensors <NUM> configured to detect and provide data related to movement of subsea assist jack <NUM>.

In the operation of exemplary methods, referring back to <FIG>, in an embodiment, open water coiled tubing control system <NUM> is deployed such as via vessel <NUM> which may also used to support surface injector <NUM>. Open water coiled tubing control system <NUM> receives information related to a load at surface injector <NUM> and, if present, at subsea assist jack <NUM>; information on movement of coiled tubing string <NUM> in reel tensioner <NUM>, surface injector <NUM>, and, if present, subsea assist jack <NUM>; and information on movement of vessel <NUM> or a compensation system such as heave compensator <NUM> used to support surface injector <NUM>, e.g. either active or passive heave.

Open water coiled tubing control system <NUM> resolves all or a predetermined part of the information so received, e.g. by controller <NUM>, to effect movement of coiled tubing string <NUM> into and/or out from subsea well <NUM> at a predetermined desired speed to achieve an outcome by having one or more commands issued to reel tensioners <NUM> by a single input from an operator. Typically, this is accomplished by an operator using controller <NUM> to issue one or more commands to reel <NUM>, surface injectors <NUM>, and reel tensioners <NUM> substantially simultaneously.

In currently contemplated methods, part of the resolved solution is to maintain coiled tubing string <NUM> at a predetermined tension in-between surface injector <NUM> and subsea assist jack <NUM>. Typically, controller <NUM> uses the information it receives from sensors <NUM> and determines a continuous movement rate of surface injector <NUM> versus an interrupted rate of subsea assist jack <NUM>.

In certain embodiments, subsea assist jack <NUM> can be remotely disengaged from gripping coiled tubing string <NUM> when the force supplied by subsea assist jack <NUM> is no longer required to move coiled tubing string <NUM> into or out of subsea well <NUM>. This can be accomplished by traditional means and/or by an instruction provided to controller <NUM> 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 <NUM> allows a determination of required system performance and operating limits of open water coiled tubing control system <NUM> versus the "sea state.

Claim 1:
An open water coiled tubing control system (<NUM>), comprising:
a. a reel (<NUM>) configured to accept a coiled tubing string (<NUM>);
b. a surface injector (<NUM>) in fluid communication with the coiled tubing string;
c. a reel tensioner (<NUM>) configured to control an arch (<NUM>) formed by the coiled tubing string between the reel and the surface injector;
d. a subsea assist jack (<NUM>) configured to move the coiled tubing string into or out of a subsea well (<NUM>);
e. a predetermined set of sensors (<NUM>) comprising:
i. a surface injector load sensor (<NUM>) configured to detect and provide data related to a load at the surface injector;
ii. a coiled tubing string movement sensor (<NUM>) configured to detect and provide data related to movement of the coiled tubing string in the reel tensioner, the data comprising speed of movement;
iii. a surface injector movement sensor (<NUM>) configured to detect and provide data related to movement of the surface injector;
iv. a vessel movement sensor (<NUM>) configured to detect and provide data related to movement of a vessel (<NUM>), the data comprising active heave data or passive heave data;
v. a subsea assist jack load sensor (<NUM>) configured to detect and provide data related to a load at the subsea assist jack; and
vi. a subsea assist jack movement sensor (<NUM>) configured to detect and provide data related to movement of the subsea assist jack; and
f. a controller (<NUM>) operatively in communication with the predetermined set of sensors (<NUM>), the controller configured to use information it receives from the predetermined set of sensors (<NUM>) to maintain the coiled tubing string (<NUM>) at a predetermined tension by determining a continuous movement rate of the surface injector (<NUM>) versus an interrupted rate of the subsea assist jack (<NUM>).