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
  • E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
  • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
  • B63B35/00—Vessels or similar floating structures specially adapted for specific purposes and not otherwise provided for
  • B63B35/44—Floating buildings, stores, drilling platforms, or workshops, e.g. carrying water-oil separating devices
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
  • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
  • B63B27/00—Arrangement of ship-based loading or unloading equipment for cargo or passengers
  • B63B27/16—Arrangement of ship-based loading or unloading equipment for cargo or passengers of lifts or hoists
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
  • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
  • B63B27/00—Arrangement of ship-based loading or unloading equipment for cargo or passengers
  • B63B27/30—Arrangement of ship-based loading or unloading equipment for transfer at sea between ships or between ships and off-shore structures
• • 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
  • E21B15/00—Supports for the drilling machine, e.g. derricks or masts
• • 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
  • E21B15/00—Supports for the drilling machine, e.g. derricks or masts
  • E21B15/003—Supports for the drilling machine, e.g. derricks or masts adapted to be moved on their substructure, e.g. with skidding means; adapted to drill a plurality of wells
• • 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
• • 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
  • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
  • E21B41/0007—Equipment or details not covered by groups E21B15/00 - E21B40/00 for underwater installations
• • 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
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
  • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
  • B63B3/00—Hulls characterised by their structure or component parts
  • B63B3/14—Hull parts
  • B63B2003/147—Moon-pools, e.g. for offshore drilling vessels

Definitions

• the present invention relates to the provision and arrangement of equipment on vessels for performing deployments into the sea through a moon pool, for example deployments of coiled tubing, wireline, and well entry equipment.
• operations in the well may be performed through a subsea wellhead using tools deployed on coiled tubing or on wirelines from a surface vessel.
• the subsea wellhead is provided with a subsea well entry assembly including typically a well control package and a lubricator provided on the well control package for containing the well pressure whilst tools are deployed.
• the coiled tubing or wireline is submerged in the sea between the vessel and the well entry assembly on the wellhead. This is sometimes referred to as riserless subsea operations. That is, the subsea coiled tubing or wireline is not deployed inside a riser between the wellhead and the surface.
• the tools may be used for well intervention or workover.
• the coiled tubing is typically deployed through a moon pool of the vessel.
• a handling tower on the vessel extends upward from deck and can be used to arrange operations equipment above the moon pool.
• the equipment typically includes a coiled tubing injector head provided with a gooseneck.
• the coiled tubing extends through the injector head with the gooseneck guiding the coiled tubing from the reel into the coiled tubing injector head.
• the injector head acts on the coiled tubing to urge the tubing through sea toward or away from the wellhead.
• the coiled tubing is arranged through well intervention equipment, such as a subsea injector device and/or a subsea stripper. These are connected to the coiled tubing topsides and deployed along with the coiled tubing into the sea for connection to the subsea entry assembly on the subsea wellhead.
• wireline equipment When wireline rather than coiled tubing is required, wireline equipment is employed. The wireline may then be deployed through the moon pool into the sea, and a tool string on the end of the wireline may be lowered to the wellbore to perform work, for example, light intervention work.
• the wireline equipment typically comprises a wireline winch which is operable to spool and unspool the wireline from the winch drum.
• a heave compensated support member is arranged on the tower over which the wireline from the winch drum is passed.
• the wireline with the tool string attached to the end thereof is thus suspended over the moon pool from the heave compensated support for deployment into the sea.
• the wireline and tool string may thus also be heave compensated.
• the wireline winch drum could also be operated to spool in or out to compensate for heave.
• Transitioning between the wireline set up and coiled tubing set up can be time consuming, complex, and costly.
• the process must generally also comply with industry safety protocols, which can pose further challenges.
• the coiled tubing and/or wireline may require load testing before the tool(s) are connected to the end of the coiled tubing.
• some types of well intervention equipment required in one set up may not be required in another.
• the changeover from coiled tubing to wireline or vice versa may also involve changing or reconfiguring the well control package and/or lubricator to be used on the subsea wellhead in the new operation.
• the existing well control package and/or lubricator may be required to be retrieved back to the surface vessel before redeploying the same or another one.
• the wireline and coiled tubing equipment are suspended by their respective winches over the moon pool, and must thus be dealt with one at a time in view of the lack of space available.
• At least one aim of the invention is to obviate or at least mitigate one or more drawbacks of prior art.
• a frame assembly for moving well intervention equipment relative to a moon pool in a floating vessel, the frame assembly comprising: a main frame configured to be moveable between a main frame parking position and a main frame operating position; a moveable subframe supported on the main frame for supporting and hanging off the well intervention equipment, said moveable subframe being configured to be moveable relative the main frame, between a subframe parking position and a subframe operating position.
• this may allow well intervention equipment to be moved towards and away from the moon pool without requiring the use of the main winch of the handling tower assembly.
• This allows the main winch of the handling tower assembly to be used for other suboperations, enabling some suboperations to be done in parallel and reducing the overall time spent on deployment or retrieval operations.
• the frame assembly is for moving well intervention equipment over the moon pool.
• the frame assembly is for moving well intervention equipment in and out of a handling tower arranged over the moon pool.
• the moveable subframe when the moveable subframe is in each of the subframe parking position and the subframe operating position, the moveable subframe is located at least partially within a footprint of the main frame.
• the moveable subframe when the moveable subframe is in each of the subframe parking position and the subframe operating position, the moveable subframe is located entirely within the footprint of the main frame.
• the main frame comprises a first main frame portion and a second main frame portion, wherein the first and second main frame portions are configured to be detachably attached to one another to form the main frame.
• this may allow the main frame to be assembled on-site, allowing parts to be transported separately and thus preventing the need for bespoke transport due to its assembled size.
• the main frame comprises four or more rail interfaces for moving the main frame between the main frame parking and operating positions, wherein the main frame has a nonsquare rectangular footprint; at least four of the rail interfaces are arranged in a square formation; and central axes of the footprint of the main frame and the square formation of the rail interfaces are coaxial.
• each of the rail interfaces comprises one or more guide rollers.
• the frame assembly further comprises a removable pull test beam system for conducting load tests on well intervention equipment supported on the moveable subframe and coiled tubing extending through the main frame.
• the main frame comprises a side equipment opening configured to receive the well intervention equipment supported on the moveable subframe.
• this may allow for the main frame to be easily moved away from the well intervention equipment once the well intervention equipment is supported by the main winch and ready for deployment.
• the frame assembly comprises a winch for pulling coiled tubing through well intervention equipment supported on the moveable subframe.
• this may make it easier to align the coiled tubing through the well intervention equipment.
• the frame assembly is a tool handling skid.
• Figure 1 is a schematic side view of a system comprising a vessel, a handling tower arrangement, a first embodiment of a frame assembly, a topside injector head assembly, well intervention equipment, a coiled tubing arrangement, and a second embodiment of a frame assembly.
• Figure 2A is a top view of the system shown in Figure 1.
• Figure 2B is a bottom view of the first embodiment of the frame assembly shown in Figure 1.
• Figure 2C is a bottom view of the second frame assembly shown in Figure 1 , supporting a passive heave compensator.
• Figure 3 is a side view of the system shown in Figure 1 in use.
• Figure 4 is a side view of a first embodiment of the frame assembly shown and well intervention equipment shown in Figure 1.
• Figure 5 is an isometric view of a main frame of a second embodiment of a frame assembly.
• Figure 6 is an isometric view of a topside injector head frame of the first embodiment of the frame assembly shown in Figure 1 .
• Figure 7 is a side view of the first embodiment of the frame assembly shown in Figure 1.
• Figure 8 is a side view of the system shown in Figure 1 in use, showing the topside injector head assembly being lowered into position.
• Figure 9A is a side view of a subsea stripper of the well intervention equipment shown in Figure 1.
• Figure 9B is a side view of a subsea injector of the well intervention equipment shown in Figure 1.
• Figure 10 is a schematic side view of the system shown in Figure 1 in use, showing the coiled tubing arrangement, topside injector head assembly, and well intervention equipment arranged on a deck of the vessel.
• Figure 11 is a side view of the first embodiment of the system shown in Figure 1 in use, showing the topside injector head assembly in position on the first embodiment of the frame assembly.
• Figure 12 is an isometric cutaway view of the system shown in Figure 1 , showing the topside injector head assembly in position on the first embodiment of the frame assembly.
• Figure 13A shows the second frame assembly shown in Figure 1 in an extended position.
• Figure 13B shows the second frame assembly shown in Figure 1 in a retracted position.
• Figure 1 shows a system 100 for assisting the deployment of well intervention equipment.
• the system 100 comprises a first frame assembly 200.
• the system 100 further comprises a vessel 120, and/or a handling tower arrangement 140, and/or skid rails 180, and/or a topside injector head assembly 300, and/or well intervention equipment 400, and/or a coiled tubing arrangement 500, and/or a second frame assembly 600.
• the vessel 120 comprises a moon pool 125 having a centreline 126 and a hatch (not shown), a deck 130, and a hull 135.
• the moon pool 125 extends through the deck 130 through to the sea 50 below the vessel 120, in which the vessel 120 is floating.
• the handling tower arrangement 140, skid rails 180, first frame assembly 200, topside injector head assembly 300, well intervention equipment 400, coiled tubing arrangement 500, and the second frame assembly 600 are all arranged topside, on the deck 130 of the vessel 120.
• the skid rails 180 are for moving parts of the system 100, such as the first frame assembly 200 and the second frame assembly 600, along the deck 130 of the vessel 120, for example from a storage position into an operating position.
• first frame assembly 200 and second frame assembly 600 may be moved on the skid rails 180, across the deck 130.
• the handling tower arrangement 140 is for safely and efficiently assisting the deployment and retrieval of subsea equipment through the moon pool. These deployments and retrievals may be known as operations. The operation(s) may be performed as part of a riserless coiled tubing operation.
• the handling tower arrangement 140 is entirely optional, and may not be present, or may take a different form, such as a pole or other vertical support structure.
• the passive heave compensator 160 is attached to the main winch 142 and mitigates vertical motion of the vessel 120 due to swells or waves in the sea 50, stabilising the equipment being lifted.
• the passive heave compensator 160 may comprise a lifting sling 162 attached underneath, to which the lifted equipment is attached, as can be seen in Figure 3.
• the lateral support frame 170 is for supporting the topside injector head assembly 300 during an operation, restricting or preventing its lateral movement in at least one direction, and is supported by the handling tower 141.
• the lateral support frame 170 may also be known as a lower cursor frame and is described in more detail below.
• the first frame assembly 200 is for moving well intervention equipment 400, such as a subsea stripper and/or subsea injector, relative to the handling tower 141 , for example in and out of the handling tower 141 , and/or relative to the moon pool 125.
• the first frame assembly 200 comprises a main frame 210 and a moveable subframe 220.
• the first frame assembly 200 further comprises a skidding arrangement 218, a topside injector head frame 230, and/or a winch 240, and/or a sheave 250.
• the main frame 210 is for supporting the well intervention equipment and the moveable subframe 220. Further, in many advantageous embodiments, the moveable subframe 220 is housed within the main frame 210 and/or supported by the main frame 210. In the first embodiment of the main frame 210, shown clearly in Figure 4, the moveable subframe 220 is housed within and supported by the main frame 210. A second embodiment of the main frame 210 is shown in Figure 5.
• the main frame 210 comprises a first main frame portion 211 and a second main frame portion 212.
• the purpose for the first and second main frame portions 211 , 212 is to make it easier to transport the main frame 210, before it is assembled either on the deck 130 of the vessel 120, or on the quayside before the vessel 130 sets sail.
• the first and second main frame portions 211 , 212 are configured to be assembled on-site into the main frame 210.
• the first main frame portion 211 is arranged above the second main frame portion 212.
• the main frame 210 may further comprise a side equipment opening 213 for enabling well intervention equipment supported on the moveable subframe 220 to enter or exit the main frame 210.
• the side equipment opening 213 is configured to receive the well intervention equipment supported on the moveable subframe.
• the side equipment opening 213 is present in both the first and second embodiments of the main frame 210 shown in Figures 4 and 5.
• the main frame 210 in both of the first and second embodiments, comprises at least one hinged door 214.
• the hinged door 214 is arranged at the side equipment opening 213 and enables access to the well intervention equipment 400 on the moveable subframe 220 to be restricted if desired.
• the main frame 210 may also comprise a connection means 215 for connecting the topside injector head frame 230 thereto.
• the connection means 215 comprises a pin extending from an upper surface of the main frame 210. Such a pin may act as a guiding pin for the topside injection head frame 230.
• the main frame 210 may also comprise cylinder arrangements for moving an abutment surface for the topside injector head frame 230 relative the main frame.
• the connection means 215 may comprise an aperture for receiving a portion of the topside injector head frame 230.
• the first frame assembly 200 further comprises a pull test beam system 216. More specifically, the first embodiment of the main frame 210 further comprises the pull test beam 216.
• the pull test beam system 216 may be known simple as the pull test beam 216. The purpose of the pull test beam 216 is for conducting load tests on well intervention equipment 400 and the coiled tubing arrangement 500, part of which may extend through the well intervention equipment 400.
• the pull test beam 216 may also be known as a pull test frame 216.
• the pull test beam 216 is detachably attached to the main frame 210 via a beam support part (not shown) comprised by the main frame or may be unitarily formed therewith. The beam support part may be considered as being part of the pull test beam system 216.
• the pull test beam 216 may be detachably attachable to the main frame 210, and is located at least partially underneath, for example directly underneath, the moveable subframe 220 when the moveable subframe 220 is in the subframe operating position.
• the main frame 210 is configured to be moveable between a main frame parking position and a main frame operating position.
• the main frame 210 When in the main frame parking position, the main frame 210 is located outside of the handling tower 141 and/or away from the moon pool 125.
• the main frame 210 shown in Figure 2A is in the main frame parking position.
• the main frame 210 When in the main frame operating position, the main frame 210 is located at least partially within the handling tower 141 and/or above the moon pool 125. In Figure 14, for example, the main frame 210 can be seen in the main frame operating position.
• the main frame 210 is moveable on the skid rails 180.
• the skid rails 180 are therefore suitable for moving the main frame 210 between the main frame parking position and the main frame operating position thereon.
• the main frame 210 may further comprise rails 217 for supporting the moveable subframe 220.
• the rails 217 extend horizontally across the main frame 210.
• the moveable subframe 220 is mounted on the rails 217 of the main frame 210.
• the moveable subframe 220 shown in Figure 5 further comprises an actuating means 222, which is shown as a hydraulically actuated piston.
• the actuating means 222 allows the moveable subframe 220 to be moved along the rails 217, within the main frame 210, between a subframe parking position and a subframe operating position.
• the moveable subframe 220 may comprise a subframe roller assembly (not shown) supporting the moveable subframe 220 on the rails 217 of the main frame 210, for reducing the friction between the moveable subframe 220 and the rails 217 when the moveable subframe 220 moves between its parking and operating positions.
• the first frame assembly 200 may further comprise the skidding arrangement 218, as seen in Figure 2B. More specifically, the main frame 210 may further comprise the skidding arrangement 218.
• the skidding arrangement 218 supports the main frame 210 on the skid rail assembly 180 and enables movement of the main frame 210 between the main frame parking position and the main frame operating position, for example by reducing the friction between the main frame 210 and the skid rail assembly 180 when the main frame 210 moves between the main frame parking position and the main frame operating position.
• the skidding arrangement 218 comprises at least one rail interface 219, and each rail interface 219 may comprise one or more guide rollers. In the present embodiment, there are provided four rail interfaces 219, each comprising one guide roller.
• the rail interfaces 219 are arranged in a square formation. This means that at least four rail interfaces 219 are each arranged at one of the four vertices of an imaginary square. A central axis of the square formation extends through the centre of the imaginary square.
• a footprint of the first frame assembly 200 is defined as the surface area of the deck 130 occupied by the first frame assembly 200.
• a footprint of the main frame 210 is defined as the surface area of the deck 130 occupied by the main frame 210.
• the footprint of the main frame 210 is non-square such that it has a first cross-dimension and a second cross-dimension perpendicular to the first cross-dimension, the first and second cross-dimensions being different.
• the footprint of the main frame 210 may be rectangular.
• the first frame assembly 200 may be arranged such that the longer of the first and second cross-dimensions is substantially parallel with a central bow-stern axis of the vessel.
• a central axis of the footprint of the main frame 210 extends through the centre of the footprint.
• the main frame 210 may be moveable in a bow-stern direction of the vessel 120.
• the rail interfaces 219 are arranged in a square formation in the centre of the footprint of the main frame 210.
• the central axes of the footprint of the main frame 210 and the square formation of the rail interfaces 219 are coaxial.
• the first frame assembly 200 may also comprise at least one locking element (not shown) for locking well intervention equipment supported on the moveable subframe thereto.
• the locking element may comprise a clamp, cable ties, or bolts and nuts.
• Figure 5 shows the second embodiment of the main frame 210.
• This second embodiment of the main frame 210 differs from the first embodiment of the main frame in that the hinged door 214 is in a different form, and there is no moveable subframe 220 arranged therewithin.
• Figure 4 shows the moveable subframe 220 in the subframe operating position.
• the moveable subframe 220 In the subframe parking position, the moveable subframe 220 is located a first distance from the side equipment opening 213 of the main frame 210, and in the subframe operating position, the moveable subframe 220 is located a second distance from the side equipment opening 213 of the main frame 210.
• the second distance is shorter than the first distance, i.e. when the moveable subframe 220 is moved from its parking position to its operating position, it is moved towards the side equipment opening 213.
• the moveable subframe 220 may be moveable in a bow-stern direction of the vessel 120, and/or in the direction of the longer of the first and second cross dimensions of the footprint of the main frame 210.
• the moveable subframe 220 When the main frame 210 is in the main frame operating position, and the moveable subframe 220 is in the subframe operating position, at least a portion of the moveable subframe 220 is located such that well intervention equipment supported on the moveable subframe 220 is located directly above the moon pool. For example, at least a portion of the moveable subframe is located directly above the moon pool 125.
• the main frame 210 may further comprise lifting means (not shown), a hydraulic panel (not shown), and/or a control panel (not shown).
• the lifting means may be hydraulically actuated and is for lifting the topside injector head frame 230 shown in Figure 6.
• the lifting means may lift the topside injector head frame 230, topside injector head assembly 300, and the well intervention equipment 400.
• the topside injector head frame 230 is supported by the main frame 210.
• the topside injector head frame 230 can be seen in position on the main frame 210 in Figures 6 and 7.
• the topside injector head frame 230 is for stably supporting the topside injector head assembly 300 on the main frame 210.
• the topside injector head frame 230 comprises an injector head assembly landing portion 231 , for landing the injector head assembly 300 thereon, and a lateral support frame landing portion 232, for landing the lateral support frame 170 thereon. Both of the portions 231 , 232 comprise upper surfaces on which the injector head assembly 300 and lateral support frame 170 are landed, respectively.
• the topside injector head frame 230 further comprises at least one funnel 233, for guiding wires therethrough, for example the guide wires 146.
• at least one of the funnels 233 is located above the moon pool 125. This allows parts of some operations which utilise the guide wires 146, for example the making-up of a bottom hole assembly, which may require bottom hole assembly sections to be held such that they extend into the moon pool 125, to be carried out whilst the lateral movement of the guide wires 146 is restricted by the funnel 233, reducing unwanted movement of the guide wires 146 and reducing the risks associated with the operation.
• the topside injector head frame 230 further comprises a first connection means 234 for securely connecting the topside injector head frame 230 and the lateral support frame 170 together.
• the first connection means 234 may be in the form of a fastener assembly, for example comprising at least one locking pin and corresponding locking aperture. In the example shown in Figure 6, there are two second connection means 234.
• the topside injector head frame 230 further comprises a second connection means 235 for connecting the topside injector head frame 230 to the main frame 210.
• the second connection means 235 is in the form of a cylindrical aperture, for receiving the connection means 215 of the main frame 210, and there are two second connection means 235.
• just one of the main frame 210 and topside injector head frame 230 comprises connection means for connecting to the other.
• Figure 8 shows the topside injector head assembly 300 landing upon the topside injector head frame 230.
• the moveable subframe 220 supporting well intervention equipment 400 may be in the subframe parking position.
• the well intervention equipment 400 may comprise a subsea stripper 410, and/or a subsea injector 420, and/or a bottom hole assembly 430 (shown in Figure 18).
• parts of the well intervention equipment 400 for example the subsea stripper 410 and/or the subsea injector 420, may be supported on the moveable subframe 220.
• the subsea stripper 410 is supported on the moveable subframe 220.
• the well intervention equipment 400 supported on the moveable subframe 220 may be detachably attached to the first frame assembly 200 to prevent it falling off.
• the bottom hole assembly 430 may be provided in sections, which are then made up on deck 130 and/or, for example, in the moon pool 125.
• One or more of these sections may have a lifting cap to assist with their lifting, for example by guide wires 146.
• the coiled tubing arrangement 500 comprises coiled tubing 520.
• the term “coiled tubing” would be well known to the skilled person and may be considered as a generic term for a long, continuous length of piping or tubing. Though coiled tubing is typically made from a combination of steel and elastomeric materials, there are no formal restrictions on the materials used. Coiled tubing is typically wound on a large reel.
• the coiled tubing arrangement 500 further comprises a reel body 505, a reel base 507, a reel brake 510, and an end connector 530.
• the reel base 507 supports the reel body 505 and the reel brake 510, and is fixed to the deck 139 of the vessel 120.
• the coiled tubing 520 is wound around the reel body 505, and the reel brake 510 prevents the reel body 505 from rotating, unspooling the coiled tubing 520.
• the end connector 530 is only connected to the end of the coiled tubing 520 after the coiled tubing 520 has been stabbed through the injector head assembly 300 and the well intervention equipment 400 supported on the moveable subframe 220.
• the coiled tubing arrangement 500 may further comprise a cable head and/or a motor head assembly (not shown). These are well known parts in the state of the art which a person skilled in the art would know well.
• the winch 240 of the first frame assembly 200 is for assisting the stabbing of the coiled tubing 520 through the topside injector head assembly 300 and at least one piece of well intervention equipment 400 supported on the moveable subframe 220, for example the subsea stripper 410.
• the winch 240 and the sheave 250 are mounted on the main frame 210 in the embodiment shown, but in other embodiments may be mounted elsewhere.
• the winch 240 comprises a winch body 242 and a winch cable 244.
• the winch body 242 is located at a base of the main frame 210, and the winch cable 244 is wound around the winch body 242.
• the winch cable 244 may be pulled through the sheave 250 and up through well intervention equipment 400 supported on the main subframe 220, up through the topside injector head assembly 300 and connecting to the coiled tubing 520.
• the winch 240 is then actuated to pull the coiled tubing 520 back through the topside injector head assembly 300 and well intervention equipment 400 supported on the moveable subframe 220 before being detached from the coiled tubing 520.
• the topside injector head assembly 300 comprises an injector head 310, a gooseneck 320, and a bend restrictor device 330.
• the coiled tubing 520 of the coiled tubing arrangement 500 extends through the topside injector head assembly 300, as can be seen in Figures 10 and 11.
• Figure 12 shows the topside injector head assembly 300 supported by the main frame.
• the topside injector head assembly 300 is in position on the topside injector head frame 230.
• the main frame 210 is moveable between the main frame parking position and the main frame operating position even when supporting the topside injector head assembly 300.
• the injector head 310 remains topside and controls in part the movement of coiled tubing 520 into and out of the wellbore.
• the injector head 320 may comprise chains which are openable and closable and are for gripping the coiled tubing 520.
• the gooseneck 320 guides and supports the coiled tubing 520 through the injector head 310, controlling the bending radius of the coiled tubing 520 and distributing the stress on the coiled tubing 520 across its length.
• the bend restrictor device 330 is located on the opposite side of the injector head 310 to the gooseneck 330, and also controls the bending radius of the coiled tubing 520.
• the bend restrictor device 330 comprises a main opening which may be actuated, for example hydraulically actuated. In other words, the bend restrictor device 330 is configured to be openable, i.e. in an open configuration, and closable, i.e. in a closed configuration.
• the second frame assembly 600 may comprise a bed 610, a gallows 620, a slips bowl 630, a dog collar (not shown), and/or a skidding arrangement 650.
• the second frame assembly 600 may be known as a tool handling skid 600.
• the second frame assembly 600 supports the passive heave compensator 160.
• the second frame assembly 600 supports the bottom hole assembly 430.
• the second frame assembly 600 is moveable along the skid rail assembly 180.
• the second frame assembly 600 is moveable between a second frame assembly parking position, a second frame assembly first operating position, and a second frame assembly second operating position.
• the second frame assembly 600 is located outside of the handling tower 141.
• the slips bowl 630 In the second frame assembly first operating position (not shown), the slips bowl 630 is located within the handling tower 141 , above the moon pool 125 but away from a centre of the moon pool 125. In this position, the slips bowl 630 may be vertically aligned with a centreline of one of the funnels 233 of the injector head frame 230, allowing the winch 240 to assist the making up of equipment 400 held in the slips bowl 630.
• the slips bowl 630 In the second frame assembly second operating position (not shown), the slips bowl 630 is located within the handling tower 141 , above the moon pool 125 and above a centre of the moon pool 125.
• the first and second operating positions of the second frame assembly 600 allow equipment 400, for example the bottom hole assembly 430, to be assembled/made-up away from the centreline 126 of the moon pool 125. This may be useful because the moon pool 125 may have a different piece of equipment 400 such as the subsea stripper 410 arranged in its centreline 126, restricting vertical space for the making up of the equipment 400 here.
• the equipment 400 has been made up in the slips bowl 630 of the second frame assembly 600 in the first operating position, with, for example, the equipment extending into the moon pool 125, the second frame assembly 600 is moved into the second operating position, moving the equipment 400 into the centreline 126 of the moon pool 125.
• the second frame assembly 600 can be seen in detail in Figure 13A.
• the bed 610 of the second frame assembly 600 may comprise a main body 612 and a carriage 614.
• the carriage 614 is configured to controllably extend and retract with respect to the main body 612.
• the second frame assembly 600 may be said to be in an extended position. This can be seen in Figure 13A.
• the carriage 614 is retracted, the second frame assembly 600 may be said to be in a retracted position.
• the gallows 620 may be located on the main body 612 of the bed 610, and the slips bowl 630 may be located on the carriage 614 of the bed 610.
• the carriage 614 may extend telescopically from the main body 612.
• the main body 612 may be considered as a main frame, and the carriage 614 may be considered as a moveable subframe.
• the carriage 614 differs from the moveable subframe 220 in that in one of its positions may extend at least partially outside of a footprint of the main body 612.
• the gallows 620 comprise a horizontal portion, and a vertical portion.
• the vertical portion of the gallows 620 is configured to be extended and retracted such that the horizontal portion of the gallows 620 is height-adjustable.
• the slips bowl 630 may comprise a height adjustment means for adjusting the height thereof. This height adjustment means may comprise one or more hydraulic cylinders.
• the dog collar sits within the slips bowl 630. The dog collar is used to prevent equipment 400, for example the bottom hole tool 430, from accidentally falling into the moon pool, for example while being made-up, uncontrollably down into the sea 50, potentially irretrievably.
• the slips bowl 630 and dog collar may be unitarily formed as one integral part.
• the second frame assembly 600 may further comprise the skidding arrangement 650, as seen in Figure 2C.
• the skidding arrangement 650 supports the second frame assembly 600 on the skid rail assembly 180, and enables movement of the second frame assembly 600 between the parking position and the operating positions, for example by reducing the friction between the second frame assembly 600 and the skid rail assembly 180 when the second frame assembly 600 moves between the parking position and the operating positions. Similar to the skidding arrangement 218, the skidding arrangement 650 comprises four quadridirectional rail interfaces 651 , each comprising one roller. The rail interfaces 651 are arranged in a square formation.
• the second frame assembly 600 may optionally further comprise an operator panel (not shown) configured to allow a user to adjust the height of the horizontal portion of the gallows 620 and/or extend or retract the carriage 614 from the main body 612.
• an operator panel (not shown) configured to allow a user to adjust the height of the horizontal portion of the gallows 620 and/or extend or retract the carriage 614 from the main body 612.

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