NO20240313A1

NO20240313A1 - Methods for the deployment and retrieval of well intervention equipment from and to a vessel

Info

Publication number: NO20240313A1
Application number: NO20240313A
Authority: NO
Inventors: Trond-Eivind Larsen; Andrew Newlands; Nils Olav Roaldsøy; Charlie Tramier
Original assignee: TechnipFMC Norge AS
Priority date: 2024-04-03
Filing date: 2024-04-03
Publication date: 2025-10-06
Also published as: WO2025211964A1

Description

METHODS FOR THE DEPLOYMENT AND RETRIEVAL OF WELL INTERVENTION EQUIPMENT FROM AND TO A VESSEL

TECHNICAL FIELD

The present invention relates to methods of providing, arranging, and using equipment on vessels for performing deployments into the sea through a moon pool, for example deployments of coiled tubing, wireline, and well entry equipment, and their subsequent retrieval, and a related system.

BACKGROUND

In connection with subsea wells, 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. In this arrangement, 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.

In prior art, 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. In certain applications, 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.

The coiled tubing injector head is suspended from the tower on a main hoist line. The coiled tubing injector head may also be arranged to be guided with respect to the tower, e.g., by longitudinal rails along the tower, so that movement of the suspended equipment along the tower due to heave motions of the vessel is permitted whilst being retained in lateral position relative to the tower. The hoist line can for instance spool in or out to permit movement of the coiled tubing equipment up and down the tower, and in such way compensate for the heave motions of the vessel. By way of the heave compensation functionality, the coiled tubing injector can be supported from the vessel in constant height (i.e. relative to seabed), despite the vessel heaving up or down with waves, etc.

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 and well intervention equipment 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. For example, the coiled tubing and/or wireline may require load testing before the tool(s) are connected to the end of the coiled tubing. Further, 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. Thus, 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. Furthermore, 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.

The term “move” and its derivatives (e.g. moving, moved) may also include other, more specific types of movement, such as “slide” (e.g. sliding), “roll” (e.g. rolling), and “skid” (e.g. skidding).For example, throughout the description, where the term “move” and its derivatives is used, the term “skid” and its equivalent derivatives (e.g. skidding, skidded) may be used instead. The term “skid” has a specific meaning within the field of offshore industry as would be well known to the skilled person.

SUMMARY

According to a first aspect of the disclosure, there is provided a method of assisting the deployment of well intervention equipment from a vessel comprising the steps of: providing at least one frame assembly for moving well intervention equipment in and out of a handling tower arranged over a moon pool, the frame assembly comprising: a main frame, said main frame being configured to be moveable between a main frame parking position and the main frame operating position; a moveable subframe supported on the main frame for supporting well intervention equipment, said moveable subframe being configured to be moveable between a subframe parking position and the subframe operating position, wherein the frame assembly is configured such that when the main frame is in the main frame parking position, the main frame is located outside of the handling tower; when the main frame is in the main frame operating position, at least a portion of the main frame is located within the handling tower; and when the main frame is in the main frame operating position and the moveable subframe is in the subframe operating position, at least a portion of the moveable subframe is located directly above the moonpool such that well intervention equipment supported thereon is located directly above the moonpool; providing well intervention equipment on the moveable subframe; landing an injector head assembly on the frame assembly; providing coiled tubing through the injector head assembly and well intervention equipment; and lifting the injector head assembly and well intervention equipment such that neither are supported by the frame assembly.

Advantageously, the use of the frame assembly 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. Additionally the well intervention equipment positioned on a subframe of the frame assembly, by hanging from the subframe, may be tested and connected quayside before the vessel departs for the operation and/or in a position outside of the handling tower and/or in a position within the handling tower but outside of the moon pool, before it is moved into this position above the moon pool by movement of the subframe.

Optionally, in the step of lifting the injector head assembly and well intervention equipment, the main frame is in the main frame operating position; and the method further comprises a step of moving the main frame to the main frame parking position after the step of lifting the injector head assembly and well intervention equipment.

Optionally, the main frame is provided in the parking position and the moveable subframe is provided in the subframe operating position. Optionally, 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.

Optionally, the method further comprises the steps of: moving the moveable subframe to the subframe parking position between the steps of providing well intervention equipment on the moveable subframe and landing an injector head assembly on the frame assembly; and moving the moveable subframe to the subframe operating position between the steps of landing an injector head assembly on the frame assembly and providing coiled tubing through the injector head assembly and well intervention equipment.

Optionally, the step of providing the coiled tubing through the injector head assembly and well intervention equipment connects the injector head assembly and well intervention equipment.

Optionally, the well intervention equipment is a subsea stripper and/or subsea injector.

Optionally, the frame assembly further comprises an injector head frame and the injector head assembly is landed on the injector head frame.

Optionally, the method further comprises the step of lowering the well intervention equipment through the moonpool.

Optionally, the method further comprises the steps of: providing a well entry assembly attached to a sea well; landing the well intervention equipment on the well entry assembly; and installing the well intervention equipment on the well entry assembly.

Optionally, the method further comprises the step of providing a vessel, the vessel comprising: a deck; and a moon pool, a handling tower assembly comprising a handling tower, wherein the handling tower is arranged over the moon pool and the main frame is moveable between the main frame parking position and the main frame operating position on the deck of the vessel.

According to a second aspect of the disclosure, there is provided a method of retrieving well intervention equipment to a vessel from a sea well comprising the steps of: providing a frame assembly for moving well intervention equipment in and out of a handling tower arranged over a moon pool, the frame assembly comprising: a main frame provided in a main frame operating position, said main frame configured to be moveable between a main frame parking position and the main frame operating position; a moveable subframe supported on the main frame for supporting well intervention equipment, said moveable subframe being provided in a subframe operating position and configured to be moveable between a subframe parking position and the subframe operating position, and wherein the frame assembly is configured such that when the main frame is in the main frame parking position, the main frame is located outside of the handling tower; when the main frame in the main frame operating position, at least a portion of the main frame is located within the handling tower; and when the main frame is in the main frame operating position and the moveable subframe is in the subframe operating position, at least a portion of the moveable subframe is located directly above the moonpool such that well intervention equipment supported thereon is located directly above the moonpool; providing a well entry assembly attached to a sea well; providing well intervention equipment with coiled tubing therethrough, said well intervention equipment installed on and connected to the well entry assembly; disconnecting the well intervention equipment from the well entry assembly; recovering the well intervention equipment through the moonpool onto the deck of the vessel; landing the well intervention equipment into the moveable subframe of the frame assembly; disconnecting the coiled tubing from the well intervention equipment; and moving the main frame from the main frame operating position to the main frame parking position.

Advantageously, the use of the frame assembly may allow well intervention equipment to be moved towards and away from the moon pool without requiring the use of the handling tower assembly. For example, this may allow 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.

Optionally, the well intervention equipment comprises a subsea stripper and/or subsea injector.

Optionally, the method further comprises the step of providing: a vessel, the vessel comprising: a deck; and a moon pool; and a handling tower assembly comprising a handling tower, wherein the handling tower is arranged over the moon pool and the main frame is moveable between the main frame parking position and the main frame operating position on the deck of the vessel.

According to a third aspect of the disclosure, there is provided a floating vessel comprising: a deck; a moon pool; a handling tower assembly comprising a handling tower, wherein the handling tower is arranged over the moon pool; a frame assembly for moving well intervention equipment in and out of the handling tower, 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, wherein the frame assembly is configured such that when the main frame is in the main frame parking position, the main frame is located outside of the handling tower; when the main frame in the main frame operating position, at least a portion of the main frame is located within the handling tower; and when the main frame is in the main frame operating position and the moveable subframe is in the subframe operating position, at least a portion of the moveable subframe is located directly above the moon pool such that well intervention equipment supported thereon is located directly above the moon pool.

Optionally, the floating vessel further comprises: a topside injector head assembly supported by the main frame; and well intervention equipment supported on and hanging off the moveable subframe.

According to a fourth aspect of the disclosure, there is provided a system for assisting the deployment or retrieval of well intervention equipment from or to a vessel, the system comprising: a frame assembly for moving well intervention equipment in and out of a handling tower arranged over a moon pool, 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 well intervention equipment, said moveable subframe being configured to be moveable between a subframe parking position and a subframe operating position, wherein the frame assembly is configured such that when the main frame is in the main frame parking position, the main frame is located outside of the handling tower; when the main frame in the main frame operating position, at least a portion of the main frame is located within the handling tower; and when the main frame is in the main frame operating position and the moveable subframe is in the subframe operating position, at least a portion of the moveable subframe is located directly above the moon pool such that well intervention equipment supported thereon is located directly above the moon pool.

Optionally, 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.

Optionally, the main frame further comprises a removable pull test beam system detachably attached to the main frame.

Optionally, when the removeable pull test beam system is attached to the main frame via the beam support part and the moveable subframe is in the subframe operating position, the removeable pull test beam system is located at least partially underneath the moveable subframe.

Optionally, the main frame comprises a side equipment opening configured to receive the well intervention equipment supported on the moveable subframe.

Optionally, the system further comprises well intervention equipment supported on the moveable subframe.

Optionally, the well intervention equipment comprises a subsea stripper and/or a subsea injector.

Optionally, the system further comprises a topside injector head assembly supported by the main frame.

Optionally, the frame assembly further comprises a topside injector head frame supported by the main frame.

Optionally, the main frame is configured to be moveable between the main frame parking position and the main frame operating position when the system further comprises a topside injector head assembly supported by the main frame.

Optionally, the topside injector head assembly comprises an injector head, a gooseneck, and a bend restrictor device.

Optionally, the system further comprises a handling tower assembly comprising a handling tower configured to be arranged over a moon pool of a vessel, wherein the frame assembly is for moving well intervention equipment in and out of the handling tower.

Optionally, the system further comprises a vessel, the vessel comprising: a deck; and a moon pool, wherein the handling tower is arranged over the moon pool.

Optionally, the main frame is configured to be moveable on the deck of the vessel between the main frame parking position and the main frame operating position.

Optionally, the handling tower assembly comprises a vertically moveable lateral support frame configured to prevent lateral movement of a topside injector head assembly supported on the main frame when the main frame is in the main frame operating position.

Optionally, at least one of the topside injector head frame and the lateral support frame comprises a connection means for securely connecting the injector head frame and the lateral support frame together.

Optionally, the system further comprises skid rails for moving the main frame between the main frame parking position and the main frame operating position thereon.

BRIEF DESCRIPTION OF THE FIGURES

The present disclosure will now be described by way of example, with reference to the following drawings, in which:

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 tool handling skid.

Figure 2 is a top view of part of the system shown in Figure 1.

Figure 3 is a side view of part 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 13 is an isometric view of a lateral support frame of the handling tower arrangement shown in Figure 1.

Figure 14 is a side view of the system shown in Figure 1 in use, showing the lateral support frame shown in Figure 13 being lowered into position around the topside injector head assembly.

Figure 15 is a side view of the system shown in Figure 1 in use, showing the lateral support frame shown in Figure 13 in position around the topside injector head assembly.

Figure 16 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, and the lateral support frame shown in Figure 13 in position around the topside injector head assembly.

Figure 17A shows the tool handling skid of the system shown in Figure 1 in an extended position.

Figure 17B shows the tool handling skid of the system shown in Figure 1 in a retracted position.

Figure 18 is a side view of the system shown in Figure 1 in use, showing the making up of a bottom hole assembly.

Figure 19A is a side view of the system shown in Figure 1 in use, showing the connecting of the coiled tubing arrangement to the bottom hole assembly shown being made up in Figure 18.

Figure 19B is a detail view of Figure 19A, showing the tool handling skid in detail.

Figure 20 is a side view of a second embodiment of the system, different to the first embodiment of the system in that the well intervention equipment further comprises a subsea injector.

Figure 21 is a side view of the second embodiment of the system shown in Figure 20 after deployment further comprising a well entry assembly.

DETAILED DESCRIPTION

System 100 (overview)

Figure 1 shows a system 100 for assisting the deployment of well intervention equipment. The system 100 comprises a frame assembly 200. In some embodiments, for example the embodiment shown in Figure 1, 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 tool handling skid 600. The vessel 120 may also be considered as comprising the system 100, or as comprising one or more of the features comprised in the system 100, such as the handling tower arrangement 140, frame assembly 200, etc.

Vessel 120

As seen in Figure 1, the vessel 120 comprises a moon pool 125 having a centreline 126 and a hatch (not shown), a deck 130, and a hull 135. In the embodiment shown in Figure 1, 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.

As can be seen in Figures 1 and 2, the handling tower arrangement 140, skid rails 180, frame assembly 200, topside injector head assembly 300, well intervention equipment 400, coiled tubing arrangement 500, and the tool handling skid 600 are all arranged topside, on the deck 130 of the vessel 120. As can be seen in Figure 2, the skid rails 180 are for moving parts of the system 100 thereon, such as the frame assembly 200 and the tool handling skid 600, along the deck 130 of the vessel 120, for example from a storage position into an operating position.

The frame assembly 200 and tool handling skid 600 may be moved on the skid rails 180, across the deck 130, as is explained in more detail below.

Handling tower arrangement 140

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.

As can be seen in Figure 3, the handling tower arrangement 140 comprises a handling tower 141, a passive heave compensator 160, and a lateral support frame 170. The handling tower 141 may be any vertically extending structure comprising a hoisting arrangement such as a winch, for example a derrick. The handling tower 141 is arranged over the moon pool 125, as can be seen in Figure 1, and comprises a main winch 142 for lifting, lowering, and precisely positioning heavy equipment during operations, rails 144 for guiding and stabilising the movement of equipment up and down the handling tower 141. Further, in some embodiments the handling tower arrangement 140 further comprises one or more guide wires 146 for lifting relatively light equipment, such as bottom hole assembly sections. Guide wires 146 can be seen in Figure 18. The handling tower 141 may be arranged such that its centreline coincides with that of the moon pool 125.

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.

Frame assembly 200

The frame assembly 200 is for moving well intervention equipment 400, such as a subsea stripper and/or subsea injector, in and out of the handling tower 141. The frame assembly 200 comprises a main frame 210 and a moveable subframe 220. In some embodiments, the frame assembly 200 further comprises a topside injector head frame 230, and/or a winch 240, and/or a sheave 250, pull test beam system and/or a skidding arrangement (not shown).

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. In other words, 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. In other words, 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. There may be hinged doors or access openings arranged at other locations of the main frame for personnel to access the interior of the main frame 210 and the moveable subframe 220.

The main frame 210 may also comprise a connection means 215 for connecting the topside injector head frame 230 thereto. As can be seen in the first and second embodiments of the main frame 210, 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. In other examples not shown, the connection means 215 may comprise an aperture for receiving a portion of the topside injector head frame 230.

The 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. When in the main frame parking position, the main frame 210 is located outside of the handling tower 141. The main frame 210 shown in Figure 2 is in the main frame parking position. When in the main frame operating position, the main frame 210 is located at least partially within the handling tower 141. 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.

As can be seen in Figure 4, 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 frame assembly 200 may further comprise the skidding arrangement. More specifically, the main frame 210 may further comprise the skidding arrangement. The skidding arrangement supports the main frame 210 on the skid rail assembly 180 and enables the 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 skids between the main frame parking position and the main frame operating position.

A footprint of the frame assembly 200 is defined as the surface area of the deck 130 occupied by the 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 nonsquare 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 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 bowstern direction of the vessel 120.

The skidding arrangement of the frame assembly 200 is arranged in the centre of the footprint of the main frame 210.

The 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. 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. In the present examples, 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.

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 directly above the moon pool 125 such that well intervention equipment supported on the moveable subframe 220 is located directly above the moon pool.

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. Thetopside injector head assembly 300 may be supported on the topside injector head frame 230 and connected by coiled tubing to well intervention equipment 400 supported on the moveable subframe 220 , as can be seen in Figure 19A and Figure 19B. As such,lifting means may be configured to lift the topside injector head frame 230, topside injector head assembly 300, and/or 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. When the topside injector head frame 230 is in position on the main frame 210 and the main frame 210 is in the main frame operating position, 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. In the present example, 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. In some examples, 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. In such an operation, the moveable subframe 220 supporting well intervention equipment 400 may be in the subframe parking position.

Well intervention equipment 400

As can be seen in Figure 9A and Figure 9B, 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). In some operations, 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. In Figure 8, for example, the subsea stripper 410 is supported on the moveable subframe 220. During use, the well intervention equipment 400 supported on the moveable subframe 220 may be detachably attached to the 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.

Coiled tubing arrangement 500

The coiled tubing arrangement 500, as can be seen in Figure 10, 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.

In the present example, 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.

Winch 240 of the frame assembly 200

The winch 240 of the frame assembly 200, as seen in use in Figure 11, 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. In use, 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.

Topside injector head assembly 300

The topside injector head assembly 300 comprises an injector head 310, a gooseneck 320, and a bend restrictor device 330. In operation, 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. As can be seen, 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.

Lateral support frame 170

As shown in Figure 13, the lateral support frame 170 comprises a main body 171, a connection means 172, a roller assembly 174, and retention plates 176. The lateral support frame 170 is vertically moveable up and down the handling tower 141. The main body 171 supports the connection means 172, the roller assembly 174, and the retention plates 176. The connection means 172 is for securely connecting the lateral support frame 170 to the topside injector head frame 230. Just one of the lateral support frame 170 and topside injector head frame 230 may have connection means for securely connecting the lateral support frame 170 and topside injector head frame 230 together. The roller assembly 174 is for reducing the friction between the lateral support frame 170 and the handling tower 141 when the lateral support frame 170 is moved along the handling tower 141, for example being raised or lowered. The roller assembly 174 may be active, in that its rollers are driven, or may be passive, in that the lateral support frame 170 is raised and lowered by a winch. The retention plates 176 restrict the lateral movement of the topside injector head assembly 300 when in position. The retention plates 176 of the embodiment shown in Figure 13 are three in number and restrict the movement of the topside injector head assembly 300 in three lateral directions. In other embodiments, there may be one or more retention plates 176, for example two, or four, and the movement of the topside injector head assembly 300 may be restricted in one, two, or four lateral directions.

As can be seen in Figure 14, the lateral support frame 170 descends down the handling tower 141 upon the topside injector head assembly 300, from above, when the topside injector head assembly 300 is in position on the topside injector head frame 230 supported by the main frame 210 when the main frame 210 is in the main frame operating position. Figure 15 and Figure 16 show the lateral support frame 170, topside injector head frame 230, and topside injector head assembly 300 in position.

Tool handling skid 600

As can be seen in Figure 17A and Figure 17B, the tool handling skid 600 may comprise a bed 610, a gallows 520, a slips bowl 630, a dog collar 640, and/or a skidding arrangement (not shown). The tool handling skid 600 may be known as a frame assembly.

In the example shown in Figure 17A and Figure 17B, the tool handling skid 600 supports the passive heave compensator 160 in a storage position. In the examples shown in Figure 3 and Figure 18, the tool handling skid 600 supports the bottom hole assembly 430 in a storage position.

As can be seen in Figure 2, the tool handling skid 600 is moveable along the skid rails 180. The tool handling skid 600 is moveable between a tool handling skid parking position, a tool handling skid first operating position, and a tool handling skid second operating position.

In the tool handling skid parking position, the tool handling skid 600 is located outside of the handling tower 141. This can be seen in Figure 3, for example. In the tool handling skid first operating position, 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.This can be seen in Figure 18. 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 well intervention equipment held in the slips bowl 630. In the tool handling skid second operating position, as seen in Figure 19A, 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 tool handling skid 600 allow well intervention 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 well intervention equipment 400 such as the subsea stripper 410 arranged in its centreline 126, restricting vertical space for the making up of the well intervention equipment 400 here. Once the well-intervention equipment 400 has been made up in the slips bowl 630 of the tool handling skid 600 in the first operating position, with, for example, the wellintervention equipment extending into the moon pool 125, the tool handling skid 600 is moved into the second tool handling skid operating position, moving the well intervention equipment 400 into the centreline 126 of the moon pool 125.

The tool handling skid 600 can be seen in detail in Figure 17A. The bed 610 of the tool handling skid 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. When the carriage 614 is extended, the tool handling skid 600 may be said to be in an extended position. This can be seen in Figure 17A. When the carriage 614 is retracted, the tool handling skid 600 may be said to be in a retracted position. This position can be seen in Figure 17B. The gallows 520 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 640 can be seen in Figure 19B and sits within the slips bowl 630. The dog collar 640 is used to prevent well intervention 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. In some embodiments, the slips bowl 630 and dog collar 640 may be unitarily formed as one integral part.

The tool handling skid 600 may further comprise the skidding arrangement. More specifically, the main body 612 may further comprise the skidding arrangement. The skidding arrangement supports the main body 612 on the skid rail assembly 180 and enables the movement of the tool handling skid 600 between the tool handling skid parking position and the tool handling skid operating positions, for example by reducing the friction between the main body 612 and the skid rail assembly 180 when the main body 612 skids between the tool handling skid parking position and the tool handling skid operating positions.

A footprint of the tool handling skid 600 is defined as the surface area of the deck 130 occupied by the tool handling skid 600. A footprint of the main body 612 is defined as the surface area of the deck 130 occupied by the main body 612. The footprint of the main body 612 is nonsquare 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 body 612 may be rectangular. The tool handling skid 600 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 body 612 extends through the centre of the footprint. The main body 612 may be moveable in a bow-stern direction of the vessel.

The skidding arrangement of the tool handling skid 600 is arranged in the centre of the footprint of the main body 612.

The tool handling skid 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.

Figure 20 shows a second embodiment of the system 100, wherein the well intervention equipment 400 comprises the subsea stripper 410 and subsea injector 420. The well intervention equipment 400 is ready to deploy into the moon pool 125.

As can be seen in Figure 21, the system 100 may further comprise a well entry assembly 700. The well entry assembly 700 may comprise a bottom hole assembly guide cone 710, an upper lubricator part 720, a lubricator section 730, and a well control package 740. In some embodiments of the system 100, the well entry assembly 700 may be considered as being separate therefrom. The well entry assembly 700 is typically deployed through the moon pool 125 without the use of the frame assembly 200, and is connected to a sea well in a way which would be very well known to a person skilled in the art. The upper lubricator part 720 may comprise a lockable connector (not shown).

An ROV 800 may also be provided as part of the system 100, for assisting the connection between the well intervention equipment 400 deployed using the frame assembly 200, and the well entry assembly 700.

METHOD

Aside from the provision of the frame assembly 200, each part of each step of the method described below may be optional and may be performed in a different order.

Method of installing the frame assembly 200

A method of installing the system 100 is now described.

Initially, the system 100 comprises the vessel 130, comprising the moon pool 125 and the deck 130, the handing tower arrangement 140 arranged on the deck 130 over the moon pool 125, and the frame assembly 200 comprising the main frame 210 and the moveable subframe 220. The main frame 210 is arranged on the deck 130, and may be secured to the deck 130. The main frame 210 at this stage may be in the main frame parking position or the main frame operating position.

The pull test beam 216 is then provided and installed in the main frame 210. The well intervention equipment, for example the subsea stripper 410, is then installed on the moveable subframe 220. The moveable subframe 220 is in the subframe operating position.

The subsea stripper 410 is then detachably attached to the frame assembly 200. The system 100 at this stage can be seen in Figure 4.

The topside injector head frame 230 is then provided, and landed on the main frame 210, for example by a quayside derrick. The main frame connection means 215 and the topside injector head frame first connection means 235 secure the topside injector head frame and main frame 210 together. The system 100 at this stage can be seen in Figures 6 and 7.

The moveable subframe 220 is then moved from the subframe operating position to the subframe parking position. The moveable subframe 220 is moved using the actuating means 222.

The topside injector head assembly 300, comprising the injector head 310, gooseneck 320, and bend restrictor device 330 is then provided and landed on the topside injector head frame 230, for example by a quayside derrick. During this landing, the bend restrictor device 330 is in a closed configuration. The topside injector head frame 230 is then connected to the main winch 142 of the handling tower 141 via the passive heave compensator 160 and lifting sling 162. The system 100 at this stage can be seen in Figure 8.

Once landed, the bend restrictor device 330 is moved into the open configuration. The moveable subframe 220 is then moved to the subframe operating position.

The coiled tubing arrangement 500 is then provided. The coiled tubing 520 is then stabbed through the topside injector head assembly 300 and well intervention equipment 400 supported on the moveable subframe 220. To do this, the frame assembly 200 further comprises the winch 240 and sheave 250. The end of the winch cable 244 is pulled from the winch body 242, through the sheave 250 mounted on the main frame 210, through the well intervention equipment 400 supported on the main subframe 220, up through the bend restrictor device 330, the injector head 310, and gooseneck 320, before attaching to an end of the coiled tubing 520. The reel brake 510 is engaged, and the winch 240 is actuated, to verify the connection between the winch 240 and the coiled tubing 520. The system 100 at this stage can be seen in Figure 11.

The reel brake 510 is then disengaged, chains of the injector head 310 are opened, and the winch 240 is actuated, pulling the coiled tubing 520 back through the gooseneck 320, injector head 310, bend restrictor device 330, and well intervention equipment 400 until the coiled tubing 520 extends underneath the well intervention equipment 400. The chains of the injector head 310 are then closed retaining the coiled tubing 520 in position, and the winch cable 244 is detached from the coiled tubing 520.

The end connector 530 of the coiled tubing arrangement 500 is then mounted onto the end of the coiled tubing 520. Whether the pull test beam 216 of the main frame 210 is mounted correctly on the main frame 210 is then verified. The end connector 530 is then connected to the pull test beam 216. The end connector 530 is then pull tested. Once the pull testing is complete, the end connector is disconnected from the pull test beam 216, and the pull test beam 216 is removed.

If required, a cable head of the coiled tubing arrangement is then connected to the end connector 530. The coiled tubing 520 is then flushed, for example using a non-compressible fluid. The motor head assembly of the coiled tubing arrangement 500 is then connected to the cable head of the coiled tubing arrangement 500. The motor head assembly is then pressure tested.

If the main frame 210 is in the main frame parking position, the main frame 210 is then moved into the main frame operating position. If the main frame 210 is already in the main frame operating position, it remains there.

The handling tower arrangement 140 further comprises the lateral support frame 170 which is provided thereon. The lateral support frame 170 is lowered down the handling tower 141. The system 100 at this stage can be seen in Figure 14.

The lateral support frame 170 is landed on the topside injector head frame 230, and is securely connected to the topside injector head frame 230 using the connection means 172. The system 100 at this stage can be seen in Figure 15.

The lifting sling 162 of the passive heave compensator 160 connected to the main winch 142 of the handling tower 141 is then connected to the topside injector head frame 230. The connection means 235 of the topside injector head frame 230 and the connection means 215 of the main frame 210 are then disengaged, and the main winch 142 is actuated to tension the lifting slings 162 connected to the topside injector head frame 230. The system 100 at this stage can be seen in Figure 3.

The tool handling skid 600, in this case supporting sections of the bottom hole assembly 430, is provided, as can be seen in Figure 3. The tool handling skid 600 is moved from the tool handling skid parking position to the tool handling skid first operating position. The guide wire 146 of the handling tower 141 is connected to a lifting cap of one of the sections of the bottom hole assembly 430. This section is then lifted using the guide wire 146 and lowered into the slips bowl 630 of the tool handling skid 600. The system 100 at this stage can be seen in Figure 18.

Once the section of the bottom hole assembly 430 has been lowered into the slips bowl 630, the dog collar 640 is connected around the section in order to prevent it from falling into the moon pool 125. The subsequent sections of the bottom hole assembly 430 are then connected to the preceding section, one by one, and are each lowered into the slips bowl 630, one by one. The bottom hole assembly 430 is now made up.

The lifting cylinders of the topside injector head frame 230 are then actuated to jack-up the topside injector head frame.

This also has the effect of lifting the well intervention equipment 400 supported on the moveable subframe 220 from the moveable subframe 220, which is then moved into the subframe parking position. Hydraulics of the topside injector head frame 230 are then disconnected, including the hydraulic panel.

The tool handling skid 600 is then moved from the tool handling skid first operating position to the tool handling skid second operating position, moving the bottom hole assembly 430 into the centre of the moon pool 125. The system 100 at this stage can be seen in Figure 19A and Figure 19B.

The bottom hole assembly 430 is then connected to the end of the coiled tubing 520, for example to the motor head assembly, and the dog collar 640 is removed. The tool handling skid 600 is then moved into the tool handling skid parking position.

The topside injector head frame 230 is then lifted using the main winch 142, in turn lifting the well intervention equipment 400 supported on the moveable subframe 220 from the moveable subframe 220. The lifting cylinders of the topside injector head frame 230 are then retracted, and the main frame 210 is then moved to the main frame parking position.

The coiled tubing 520 is then run down to clear the well intervention equipment 400 from the bend restrictor device 330. The bend restrictor device 330 is then closed. A distance between the end connector 530 of the coiled tubing arrangement 500 and the bend restrictor device 330 of the topside injector head assembly 300 is then measured. As would be clear to the skilled person, running the coiled tubing 520 a distance of 500 metres, for example, will then give a depth reading of 500 metres.

The well intervention equipment 400 is now ready for deployment. The system 100, wherein the well intervention equipment 400 comprises the subsea stripper 410 and the subsea injector 420, can be seen at this stage in Figure 20.

Method of deploying well intervention equipment 400 using the system 100

A method of deploying the system 100 is now described. The system 100 further comprises the well entry assembly 700, which has already been deployed through the moon pool 125 and connected to the sea well.

Once the well intervention equipment 400 is ready for deployment, as described above, it is then deployed through the moon pool 125 and landed upon the well entry assembly connected to the sea well. Once the well intervention operation is complete, the well intervention equipment 400 is retrieved up through the moon pool 125, and recovered back onto the deck 130 of the vessel 120.

Method of retrieving well intervention equipment 400 using the system 100

Once the well intervention operation is complete, the well intervention equipment 400 is then disconnected from the well entry assembly 700, and recovered back to deck.

The well intervention equipment 400 may then be pulled towards the surface of the sea 50. The well intervention equipment 400 is then recovered to the deck 130 of the vessel 120. The subsea injector 420 and the subsea stripper 410 are pulled up through the moon pool 125 up to the topside injector head assembly 300 supported by the topside injector head frame 230, lateral support frame 170, and lifting slings 162 connected to the main winch 142 via the passive heave compensator 160. The topside injector head frame 230 and lateral support frame 170 are connected together. The subsea injector 420 and the subsea stripper 410 are located above the deck 130. The hatch of the moon pool 125 may then be closed, having an aperture through which the bottom hole assembly 430 may continue to extend through, through the moon pool 125. The system 100 at this stage can be seen in Figure 20.

The bend restrictor device 330 of the topside injector head assembly 300 is then opened. The main frame 210 is then moved from the main frame parking position to the main frame operating position, and the subsea stripper 410 and subsea injector 420 are landed into the moveable subframe 220 by running the coiled tubing 520.

The tool handling skid 600 is then moved from the tool handling skid parking position to the tool handling skid second operating position. The coiled tubing 520 is then run to place the uppermost connection of the bottom hole assembly 430 above the slips bowl 630. The dog collar 640 is then connected to the lower section of the bottom hole assembly. The slips bowl 630 is then jacked up, and the connection to the coiled tubing 540 is broken.

The lifting slings 162 are disconnected from the injector head frame, and the topside injector head frame first connection means 234 is disconnected from the lateral support frame 170, disconnecting the topside injector head frame 230 and the lateral support frame 170.

The lateral support frame 170 is then moved vertically up the handling tower 141. The main frame 210 is then moved to the main frame parking position, still supporting the topside injector head assembly 230, subsea stripper 410, and/or subsea injector 420.

The guide wire 146 of the handling tower is then connected to the bottom hole assembly lifting cap, and the uppermost section of the bottom hole assembly 430 held in the slips bowl is lifted slightly. The dog collar 640 is then removed, before being replaced when the next section of the bottom hole assembly 430 protrudes from the slips bowl 630. The exposed sections of the bottom hole assembly 430 are then disconnected from one another, and the uppermost section is then lifted into the main body 612 of the tool handling skid 600. This process is repeated until the entire bottom hole assembly 430 has been retrieved and lifted into the main body 612 of the tool handling skid 600. The passive heave compensator 160 is then removed from the main winch 142 of the handling tower 141, and landed into the tool handling skid 600. The tool handling skid 600 is then moved into the tool handling skid parking position.

The system is then easily ready for performing a wireline operation in relation to the well if needed.

Claims

1. A method of assisting the deployment of well intervention equipment from a vessel comprising the steps of:

providing at least one frame assembly for moving well intervention equipment in and out of a handling tower arranged over a moon pool, the frame assembly comprising:

a main frame, said main frame being configured to be moveable between a main frame parking position and the main frame operating position;

a moveable subframe supported on the main frame for supporting and hanging off well intervention equipment, said moveable subframe being configured to be moveable between a subframe parking position and the subframe operating position, wherein

the frame assembly is configured such that

when the main frame is in the main frame parking position, the main frame is located outside of the handling tower;

when the main frame is in the main frame operating position, at least a portion of the main frame is located within the handling tower; and

when the main frame is in the main frame operating position and the moveable subframe is in the subframe operating position, at least a portion of the moveable subframe is located directly above the moonpool such that well intervention equipment supported thereon and hanging off therefrom is located directly above the moonpool;

providing well intervention equipment on the moveable subframe;

landing an injector head assembly on the frame assembly;

providing coiled tubing through the injector head assembly and well intervention equipment; and

lifting the injector head assembly and well intervention equipment such that neither are supported by the frame assembly.

2. The method of claim 1, wherein

in the step of lifting the injector head assembly and well intervention equipment, the main frame is in the main frame operating position; and

the method further comprises a step of moving the main frame to the main frame parking position after the step of lifting the injector head assembly and well intervention equipment.

3. The method of claim 1 or 2, wherein the main frame is provided in the parking position and the moveable subframe is provided in the subframe operating position.

4. The method of claim 3, further comprising the steps of:

moving the moveable subframe to the subframe parking position between the steps of providing well intervention equipment on the moveable subframe and landing an injector head assembly on the frame assembly; and

moving the moveable subframe to the subframe operating position between the steps of landing an injector head assembly on the frame assembly and providing coiled tubing through the injector head assembly and well intervention equipment.

5. The method of any preceding claim, wherein the step of providing the coiled tubing through the injector head assembly and well intervention equipment connects the injector head assembly and well intervention equipment.

6. The method of any preceding claim, wherein the well intervention equipment is a subsea stripper and/or subsea injector.

7. The method of any preceding claim, wherein the frame assembly further comprises an injector head frame and the injector head assembly is landed on the injector head frame.

8. The method of any preceding claim, further comprising the step of lowering the well intervention equipment through the moonpool.

9. The method of claim 8, further comprising the steps of:

providing a well entry assembly attached to a sea well;

landing the well intervention equipment on the well entry assembly; and

installing the well intervention equipment on the well entry assembly.

10. The method of any preceding claim, further comprising the step of providing

a vessel, the vessel comprising:

a deck; and

a moon pool,

a handling tower assembly comprising a handling tower, wherein the handling tower is arranged over the moon pool and the main frame is moveable between the main frame parking position and the main frame operating position on the deck of the vessel.

11. A method of retrieving well intervention equipment to a vessel from a sea well comprising the steps of:

providing a frame assembly for moving well intervention equipment in and out of a handling tower arranged over a moon pool, the frame assembly comprising:

a main frame provided in a main frame operating position, said main frame configured to be moveable between a main frame parking position and the main frame operating position;

a moveable subframe supported on the main frame for supporting and hanging off well intervention equipment, said moveable subframe being provided in a subframe operating position and configured to be moveable between a subframe parking position and the subframe operating position, and wherein

the frame assembly is configured such that

when the main frame in the main frame operating position, at least a portion of the main frame is located within the handling tower; and

providing a well entry assembly attached to a sea well;

providing well intervention equipment with coiled tubing therethrough, said well intervention equipment installed on and connected to the well entry assembly;

disconnecting the well intervention equipment from the well entry assembly;

recovering the well intervention equipment through the moonpool onto the deck of the vessel;

landing the well intervention equipment into the moveable subframe of the frame assembly;

disconnecting the coiled tubing from the well intervention equipment; and

moving the main frame from the main frame operating position to the main frame parking position.

12. The method of claim 11, wherein the well intervention equipment comprises a subsea stripper and/or subsea injector.

13. The method of claim 11 or 12, further comprising the step of providing:

a vessel, the vessel comprising:

a deck;

a moon pool; and

14. A floating vessel comprising:

a deck;

a moon pool;

a handling tower assembly comprising a handling tower, wherein the handling tower is arranged over the moon pool;

a frame assembly for moving well intervention equipment in and out of the handling tower, 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, wherein the frame assembly is configured such that

when the main frame is in the main frame operating position and the moveable subframe is in the subframe operating position, at least a portion of the moveable subframe is located directly above the moon pool such that well intervention equipment supported thereon is located directly above the moon pool.

15. The floating vessel of claim 14, further comprising:

a topside injector head assembly supported by the main frame; and

well intervention equipment supported on and hanging off the moveable subframe.