WO2011135541A2

WO2011135541A2 - Modular multi-workstring system for subsea intervention and abandonment operations

Info

Publication number: WO2011135541A2
Application number: PCT/IB2011/051893
Authority: WO
Inventors: Dicky Robichaux; Eirik Enerstvedt; Frode Sunde; Cliff Meade; Shawn Mossman; Vidar Wollum
Original assignee: Rolls-Royce Marine As
Priority date: 2010-04-28
Filing date: 2011-04-28
Publication date: 2011-11-03
Also published as: WO2011135541A3

Abstract

A system for intervention or abandonment of a subsea wellbore having a production tree above waterline includes: a tower; riser joints; and a riser handler: operably coupled to the tower so that the riser handler may be raised and lowered along rails of the tower, and operable to handle the riser joints for assembly thereof; a skid connectable to skid rails of a production platform; a bottom frame connected to the skid; and a tower floor connected to the frame and having rails and runners: operably coupled to the rails at a top of the tower floor and operable to: receive the tower in the horizontal position, raise the tower to the vertical position, and move the tower along the rails; and a rotary jack: connectable to the production tree via one or more of the riser joints, and operable to raise, lower, and rotate a jointed tubular string.

Description

MODULAR MULTI-WORKSTRING SYSTEM FOR SUBSEA INTERVENTION AND

ABANDONMENT OPERATIONS

BACKGROUND OF THE INVENTION

Field of the Invention

[0001] Embodiments of the present invention generally relate to a modular multi- workstring system for subsea intervention and abandonment operations.

Description of the Related Art

[0002] Figure 1 is a cross section of a prior art sub-sea wellbore 5 drilled and completed with a land-type completion 1 . A surface casing string 10 may be set from above waterline 15, through the sea 20, and into the sea-floor or mudline 25. The surface casing 10 allows the wellhead (not shown) to be located on a production platform 30 above the waterline 15 rather than on the seafloor 25. Alternatively, the platform 30 may service a subsea-type completion or a manifold from multiple subsea-type completions. [0003] Once the surface casing 10 has been set and cemented 35 into the wellbore 5, the wellbore 5 may be drilled to a deeper depth. A second string of casing, known as intermediate casing 40, may then be run-in and cemented 45 into place. As the wellbore 5 approaches a hydrocarbon-bearing formation 50, i.e., crude oil and/or natural gas, a third string of casing, known as production casing 55, may be run-into the wellbore 5 and cemented 60 into place. Thereafter, the production casing 55 may be perforated 65 to permit the fluid hydrocarbons 70 to flow into the interior of the casing. The hydrocarbons 70 may be transported from the production zone 50 of the wellbore 5 through a production tubing string 75 run into the wellbore 5. An annulus 80 defined between the production casing 55 and the production tubing 75 may be isolated from the producing formation 50 with a packer 85. Additionally, a conductor casing (not shown) may be jetted, driven, or drilled in before the surface casing 10. The conductor casing may or may not be cemented.

[0004] As the formation 50 is depleted and the platform 30 ages, it may become desirable to plug and abandon the wellbore 5. SUMMARY OF THE INVENTION

[0005] Embodiments of the present invention generally relate to a modular multi- workstring system for subsea intervention and abandonment operations. A system for intervention or abandonment of a subsea wellbore having a production tree above waterline includes: a tower; riser joints; and a riser handler. The riser handler is: operably coupled to the tower so that the riser handler may be raised and lowered along rails of the tower, and operable to handle the riser joints for assembly thereof. The system further includes: a skid connectable to skid rails of a production platform; a bottom frame connected to the skid; and a tower floor connected to the frame and having rails and runners operably coupled to the rails at a top of the tower floor. The runners are operable to: receive the tower in the horizontal position, raise the tower to the vertical position, and move the tower along the rails. The system further includes a rotary jack. The rotary jack is: connectable to the production tree via one or more of the riser joints, and operable to raise, lower, and rotate a jointed tubular string. [0006] In another embodiment, a method for intervention or abandonment of a subsea wellbore includes loading a skid to a production platform over the subsea wellbore. The subsea wellbore has a production tree located above waterline. The method further includes: connecting the skid to skid rails of the production platform; loading a bottom frame to the production platform and on to the skid; loading a tower floor to the production platform and on to the bottom frame; raising the tower using the runners; loading a rotary jack to the production platform; assembling a riser using the tower; connecting the riser to the production tree; connecting the rotary jack to the production tree via a joint of the riser; deploying drill pipe and a connected bottomhole assembly (BHA) into the wellbore using the rotary jack; and rotating the drill pipe and connected BHA using the rotary jack.

[0007] In another embodiment, a modular work platform comprises two main skid modules, one main skid module for each of the two end portions of the work platform; one base frame module, one auxiliary basket module, which may be omitted and one work floor module, which is preferably split into two separate work floor modules. The work platform may be adapted to different spacing between the skid frame skid beams in that the base frame module length is adjustable. The work platform may be adapted height wise by the length of the base frame legs being adjustable. [0008] In one aspect of the embodiment, a mobile platform for horizontal displacement of equipment over a support deck; the work platform being provided with at least two downward projecting legs, wherein the downward projecting legs in their lower end portions are provided with moving means arranged to be able to displace the work platform in a first direction along the support deck, and wherein the work platform is provided with a work floor such that the downward projecting legs are mutually displaceable in a second direction along the longitudinal direction of the work platform. The work platform may be provided with two legs in each end portion. In another aspect, the work platform may be provided with one leg in each end portion, where the leg may be a so-called T-leg. The equipment on the work platform may comprise well intervention equipment such as equipment for coiled tubing operations.

[0009] The work platform downward projecting legs may be adjustable in the longitudinal direction of the legs. The work platform work floor may be provided with a lengthy body or track arranged for horizontal displacement of equipment in the longitudinal direction of the work floor. The work platform work floor is provided with at least one hinged deck section arranged to be able to take up an essentially vertical working position, or an essentially horizontal working position, so that the working area of the work floor may be adjusted. This has the advantage that the work platform may be moved close up to a possible drilling rig disposed on the same skid frame as the work platform.

[0010] The work platform may be assembled from modules. This has the advantage that the modules may be prepared before assembly and that assembling may be performed quickly. It is a further advantage that the size of the modules may be adapted to available crane capacity and transport capacity. [0011] The work platform may be assembled from at least two moving means arranged to be able to displace the work platform horizontally along a support deck provided with a lengthy body or a track; a bottom frame provided with at least two legs and arranged to be able to be fastened releasably to the mobility means; and a work floor arranged to be able to be fastened releasably to the upper portion of the bottom frame. The bottom frame may be telescopic in the bottom frame longitudinal direction. The work platform may be provided with an auxiliary basket arranged to be able to be fastened releasably to the bottom frame between its at least two legs. Two modules may constitute the work platform work floor. [0012] In another aspect of the embodiment, an installation for exploitation of petroleum is provided with a support deck, wherein the support deck is provided with lengthy bodies or tracks, and wherein the support deck may further be provided with a mobile work platform as previously described. The support deck may belong to a group consisting of a drill floor, a skid deck and a hatch deck. The skid beams of a skid frame may constitute the lengthy bodies.

[0013] Another aspect of the embodiment relates to a method for horizontal displacement of equipment on a support deck where the equipment is positioned on a mobile work platform as discussed above. [0014] In another embodiment, a well tubular jack is provided with a pipe run therethrough arranged to house a portion of a well tubular, such as production tubing and casing, and be encircled by a stationary, first pipe clamp arranged in a lower portion of the pipe run, and a second pipe clamp arranged displaceably along a considerable part of the pipe run, as the second pipe clamp is connected to one or more linear actuators arranged to be able to displace the second pipe clamp.

[0015] A frame encircles at least a portion of the pipe run and is arranged to house a portion of the well tubular projecting up from a wellhead. The frame lower portion is provided with a chassis arranged to be able to rest on an upper portion of an underlying well, preferably the wellhead or a pipe hanger connected with the wellhead, and to support the stationary first pipe clamp.

[0016] The linear actuator may be a hydraulic cylinder. The hydraulic cylinder is arranged depending from an upper portion of the frame, as the second pipe clamp is coupled to the downward projecting piston rod end.

[0017] The pipe clamps are independently of each other arranged for releasably gripping around a portion of the well tubular, as the first pipe clamp is used to hold the well tubular, and the second pipe clamp is together with the linear actuators used to pull the well tubular successively out of the well.

[0018] Advantageously, the lower pipe clamp may be constituted by several releasable wedges or and a corresponding wedge bearing (slips) of the kind used in a drill floor rotary table. The wedge bearing may be releasably arranged in a socket for quick changeover in adapting the well tubular jack to another pipe dimension. [0019] The frame is resting on the upper portion of the underlying well, for example the wellhead or the pipe hanger connected to the wellhead, a riser projecting up from the wellhead or a Blow Out Preventer valve (BOP) arranged on the wellhead, as this well structure is dimensioned to carry heavy loads, for example the weight of production tubing stretching down into the well. Thus a foundation for the well tubular jack is provided without it needing to be provided with bulky, lateral frame elements.

[0020] The frame may be provided with guides for the second pipe clamp arranged parallel to the pipe run.

[0021] A pipe body may form the frame. The frame may be provided with recesses to provide passages to be used during inspection and maintenance of the well tubular jack.

[0022] The well tubular jack may be provided with means to split the well tubular into desired section lengths. This may comprise means for cutting or unscrewing of threaded connections. [0023] A well tubular jack of this kind may due to its slender shape easily be moved between wells as it may be lead down through existing openings in the well decks above the wellhead and be connected to the well tubular to be removed. The connection to the well tubular may be done by in advance connecting a suitable pipe section projecting up from the wellhead to the well tubular. [0024] The well tubular jack may expediently be moved between the wells by means of equipment provided to handle the disassembled well tubular sections.

[0025] This embodiment relates more specifically to a well tubular jacking device comprising a frame, a stationary pipe clamp arranged for releasably hanging a well tubular and a displaceable pipe clamp connected to one or more linear actuators and arranged for releasably fixation of the well tubular, characterised in that the frame comprises a chassis arranged to be able to be supported on an underlying upper portion of a well.

[0026] The stationary pipe clamp may be formed by a series of releasable wedges and a corresponding, conical wedge abutment supported in the frame. Thus the stationary pipe clamp is provided by components being widely used in the industry. [0027] The wedge abutment may be releasably arranged in a socket. Adapting to different pipe dimensions may thus be done quickly.

[0028] The wedge abutment may be a rotary table. Adapting to different pipe dimensions may thus be done in a manner generally known in the industry. [0029] The linear actuator may be a hydraulic cylinder. An actuator type simple to maintain and easily adaptable to the relevant capacity needs and which may provided with energy from existing sources is thus provided.

[0030] The linear actuator may be a hydraulic cylinder arranged depending from an upper frame portion with a piston rod extending toward a lower frame portion. A relatively small diameter piston rod may thus be used without danger of deformation, such as buckling.

[0031] Advantageously the displaceable pipe clamp is fastened to the piston rod.

[0032] The upper well portion may be a wellhead, and more advantageously a pipe hanger connected to the wellhead. The well tubular jack may thus be supported by existing elements dimensioned to take heavy loads.

[0033] The chassis may comprise means arranged to be able to form a fluid tight joint with the wellhead. The chassis may thus be arranged to direct away fluids flowing out of the well during the operation.

[0034] The chassis may comprise a BOP in fluid communication with the wellhead. The advantage of this is that an unintentional pressure build-up in the well may be controlled even if the original BOP is removed.

[0035] It is within the concept of this embodiment to also use the well tubular jack in the workover of a well, for example to set down new tubulars in the well, as the process described above is reversed. This may occur when for example well tubulars need to be changed out due to corrosion or other damage.

[0036] A further aspect of this embodiment is to use the well tubular jack as a basis for a top drive in for example TTRD operations (Through Tubing Rotary Drilling). BRIEF DESCRIPTION OF THE DRAWINGS

[0037] So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

[0038] Figure 1 is a cross section of a prior art sub-sea wellbore drilled and completed with a land-type completion.

[0039] Figures 2A and 2B illustrate the modular multi-workstring system, according to one embodiment of the present invention.

[0040] Figures 3A-3D illustrate modules of the system. Figure 3A illustrates a cellar of the system. Figure 3B is another view of the cellar. Figure 3C illustrates a rotary drive of a rotary jack of the cellar. Figure 3D is another view of the cellar.

[0041] Figures 4A-4F illustrate rig-up for wireline (WL) deployment. Figure 4A illustrates a lubricator assembled and laying horizontally on the floor and a WL BOP connected to a top of the riser. Figure 4B illustrates hoisting of the lubricator. Figure 4C illustrates the lubricator swung to a vertical position. Figure 4D illustrates the lubricator aligned with the WL BOP. Figure 4E illustrates the lubricator connected to the WL BOP. Figure 4F is another view of the lubricator connected to the WL BOP.

[0042] Figures 5A-5J illustrate removing casing or production tubing from the wellbore. Figure 5A illustrates the production tubing engaged by one of the pipe handlers. Figure 5B illustrates hoisting of the joint from the power tongs. Figure 5C illustrates the joint rotated to a horizontal position. Figure 5D illustrates loading of the joint into the basket. Figure 5E illustrates carting the full baskets from the floor. Figure 5F illustrates the full baskets rolled to the platform deck. Figure 5G illustrates the full baskets rolled clear so that empty baskets may be transferred from the platform deck to the winged portions. Figure 5H illustrates alignment of empty baskets with the winged portions. Figure 5I illustrates carting of empty baskets from the platform deck to the winged portions. Figure 5J illustrates placement of the empty baskets into position to be loaded by the pipe handlers.

[0043] Figures 6A-6N illustrate an abandonment operation conducted using the system, according to another embodiment of the present invention. Figure 6A illustrates a workstring, such as CT, deployed into the wellbore. Figure 6B illustrates cement squeezed into the perforations. Figure 6C illustrates cutting the production tubing. Figure 6D illustrates section milling of the production casing and reaming of the production casing cement. Figure 6E illustrates cementing of the milled section. Figure 6F illustrates cutting of the production casing. Figure 6G illustrates freeing of the production casing from the cement. Figure 6H illustrates freeing of the intermediate casing from the wellbore. Figure 6I illustrates reaming of another section of the wellbore. Figure 6J illustrates plugging of a portion of the reamed section. Figure 6K illustrates plugging of the surface casing shoe. Figure 6L illustrates setting the top plug. Figure 6M illustrates cutting of the surface casing at the seafloor. Figure 6N illustrates the wellbore plugged and abandoned.

[0044] Figure 7A shows a perspective view of a mobile work platform, according to another embodiment of the present invention. Figure 7B shows a side view of the longitudinal side of the work platform. Figure 7C shows the same as Figure 7B, but with an increased distance between the work platform legs. Fig. 7D shows a side view of the short side of the work platform. Figure 7E shows the same as Figure 7D, but with increased leg lengths. Figure 7F shows the same as Figure 7C, and in addition a tower placed on the work platform deck and a bridge connecting the work platform with another deck. Figure 7G shows the same as Figure 7F, but where the work platform may be displaced along a support deck. Figure 7H shows a perspective view of the work platform on a skid deck.

[0045] Figure 8A shows a side view principle sketch of a well tubular jack in the initial position, having a displaceable pipe clamp in engagement with a well tubular to be pulled out, according to another embodiment of the present invention. Figure 8B shows a side view of the well tubular jack in engagement with the well tubular wherein the displaceable pipe clamp has pulled the well tubular a distance up out of a well. Figure 8C shows a side view of an alternative embodiment of the well tubular jack, as it comprises a BOP. DETAILED DESCRIPTION

[0046] Figures 2A and 2B illustrate the modular multi-workstring system 100, according to one embodiment of the present invention. The system 100 may include a cellar 105, a tower floor 1 10, a tower 1 15, one or more pipe handlers 120, a rotary jack 125, an injector platform 130, a coiled tubing (CT) blow out preventer (BOP) platform 135, power tongs 140, a control system (not shown), a control cabin 145, a Kelly swivel 150, a CT reel 155, one or more pipe baskets 160, and a utility basket 165. The system 100 may be operable to facilitate safe and efficient rig up/down, minimize rig-up height, automatically handle a riser 245 (Figure 4E), joints thereof, and a bottom hole assembly (BHA), automatically handle tubulars, such as drill pipe and casing, minimize disassembly for transportation to another well, and facilitate safe and easy access for work and inspections. The system 100 may be transported and delivered to the platform 30 in portable modules, each module not exceeding a predetermined weight, such as twenty tons. They system 100 may be adaptable to fit varying platforms 30. As discussed below, the system may interface with existing skid beams (also known as (aka) rails) 30r originally built for the drilling rig on each platform 30 on a skid deck of the platform. The platform 30 may service multiple wellbores 5 (only one shown). Once loaded and installed on the platform 30, the system 100 may perform an intervention or abandonment operation on a first of the wellbores 5 and then move to a second wellbore and perform another intervention or abandonment operation without having to disassemble the system 100.

[0047] Figures 3A-3D illustrate modules of the system 100. Figure 3A illustrates the cellar 105 of the system 100. The cellar 105 may include a skid 200, a bottom frame 206, the rotary jack 125, and the utility basket 165. Each skid 200 may include one or more modules, such as a left module and a right module (see Figure 3A of the '862 provisional for detail). The skid 200 may be operable to receive the bottom frame 206 using one or more posts (not shown). The skid 200 may also be fastened to the skid rails 30r of the platform 30 using a front clamp and a rear clamp of each module. Each skid module may include a traveling clamp and a linear actuator, such as a piston and cylinder assembly. The skid 200 may be operable to walk along the platform skid rails 30r by fastening the traveling clamp to each skid rail, extending the actuator, thereby moving the skid along the skid rail until the actuator has stroked. The traveling clamp may then be released and the actuator contracted and the walking repeated until the skid 200 is in the desired position. The front and rear clamps may then be fastened once the skid 200 is in the desired position. Each post may have a profile so that the bottom frame 206 may be fastened to the skid 200. The actuator and traveling clamp may be electrically or hydraulically powered.

[0048] The bottom frame 206 may include one or more legs 210, one or more beams 208, one or more braces, one or more shelves 207, and one or more telescopic connections 209 between the beams. Each telescopic connection 209 may allow adjustment of the bottom frame 206 to suit varying gauges between the skid rails 30r for different platforms 30. The utility basket 165 may be used to store various equipment and as a working platform for personnel. Additionally, an elevator (not shown) may be added between the utility basket 165 and the bottom frame 206 for raising and lowering the utility basket relative to the bottom frame. The cellar 105 may further include an elevator (not shown) disposed between the bottom frame legs and posts 213 for mounting of the tower floor 1 10. The elevator may be operable to raise or lower the floor 1 10 relative to the bottom frame 206 to account for variations in pipe deck heights of different platforms 30 by telescopically extending or retracting the posts 213 into or out of the bottom frame legs. The elevator may include a piston and cylinder or lead screw and be hydraulically or electrically operated.

[0049] The cellar 105 may further include one or more traveling cranes 225 connected to the utility basket 165 (see Figure 3D of the '862 provisional for detail). Each traveling crane 225 may be operable to lift a hatch 212 of the skid deck for access to a production tree (XT, not shown) of the wellhead. The traveling cranes 225 may be further capable of handling components of a XT BOP 21 1 , such as crossovers and shear-seals.

[0050] Figure 3B is another view of the cellar 105. Figure 3C illustrates a rotary drive 219, 220 of the rotary jack 125. Figure 3D is another view of the cellar 105. The rotary jack 125 may include a jack actuator 218, a traveling clamp 215, a stationary clamp 216 (not shown in Figure 3C, see Figure 3A), a frame 217, and a rotary drive 219, 220. The stationary clamp 216 and an end of the jack actuator 218 may be connected to the frame 217. The rotary drive 219, 220 may be connected to the frame 217 using guides to rotationally connect the rotary drive 219, 220 to the frame while allowing relative longitudinal movement of the rotary drive relative to the frame. For transport between wellbores 5 and to facilitate assembly of the system 100, the frame 217 may be connected to a bottom of the tower floor 1 10 via a bracket 214. The bracket 214 may include clamps and a linear actuator operable to move the bracket along rails 221 connected to a bottom of the tower floor, similar to that discussed above for the skid 200. An opening in the utility basket 165 may accommodate movement of the rotary jack 125 along the rails 221 . [0051] For operation of the rotary jack 125, the frame 217 may be connected to a top of the XT BOP 21 1 , such as by a flanged connection. The XT BOP 21 1 may in turn be connected to the XT by one or more joints of the riser 245 so that reaction forces generated during operation of the rotary jack 125 are transferred to the wellhead. Each clamp 215, 216 may include slips, a conical bowl, and a slip actuator, such as one or more piston and cylinder assemblies, operable to move the slips longitudinally relative to the bowl. The jack actuator 218 may include one or more piston and cylinder assemblies. The rotary jack 125 may be operable to lift production tubing and casing from the wellbore 5 for a plug and abandonment operation (discussed below). The production tubing or casing may be jacked by engaging the traveling clamp 215 with the casing or tubing, contracting the jack actuator 218, thereby moving the casing or tubing upward until the jack actuator has stroked. The stationary clamp 216 may then be engaged with the casing or tubing and the traveling clamp 215 released. The jack actuator 218 may then be extended, thereby moving the traveling clamp 215 downward along the tubing or casing until the actuator has stroked. The process may be repeated until the casing or tubing is raised from the wellbore 5.

[0052] The rotary drive 219, 220 may be operable to rotate the traveling clamp 215 for rotation of a jointed workstring, such as drill pipe 415 (see Figure 6D). An end of the jack actuator 218 may be connected to a housing of the rotary drive 219, 220. The rotary drive may include a motor 219 and a swivel 220. The jack actuator 218 may be operated during rotation of the traveling clamp 215 for raising or lowering the drill pipe 415, thereby mimicking operation of a top drive. The swivel 220 may include a bearing and hydraulic fluid paths, electrical contact couplings, or wireless electromagnetic (i.e., inductive) couplings (not shown) to supply hydraulic or electrical energy to operate the traveling clamp 215 and allow rotation thereof while longitudinally supporting the traveling clamp. The drill pipe 415 may be rotated for a section milling or casing cutting operation (discussed below). [0053] The tower floor 1 10 may be assembled as one or more modules, such as two (see Figure 3E of the '862 provisional for detail). The floor 1 10 may include a central hub 229 (see Figure 4F) having an opening, one or more skid rails 228, a runner 226 fastened to each skid rail, and one or more wings 230. A longitudinal axis of the tower skid rails 228 may be perpendicular to a longitudinal axis of the platform skid rails 30r, thereby providing two-dimensional horizontal movement capability of the tower 1 15 relative to the platform 30. The opening may be covered by hatches 227 which may be removed as necessary. Each runner 226 may include clamps and an actuator operable to move the runner along the respective skid rail 228, similar to that discussed above for the skid 200. The runners 226 may also receive the tower 1 15 and be operable to hoist the tower to a vertical position.

[0054] The tower floor 1 10 may further include a frame, one or more mounts, and a bridge (see Figure 3F of the '862 provisional for detail). The mounts may be slidable along the frame to account for the adjustability of the bottom frame 206, discussed above. The mounts may receive respective posts 213 of the bottom frame 206. The bridge may be pivoted to the frame to interface with a pipe deck of the platform 30. The tower floor 1 10 may further include a bridge actuator (not shown) for pivoting the bridge relative to the hub 229 between a folded (vertical) position and an unfolded (horizontal) position. The wings 230 may be pivoted to the frame so that the system 100 may be positioned proximate to a drilling derrick of the platform 30. The tower floor 1 10 may further include a wing actuator (not shown) for pivoting each wing 230 relative to the hub 229 between a folded (vertical) position and an unfolded (horizontal) position. The wing actuator and the bridge actuator may be electric or hydraulic. The tower 1 15 may include lifts for the injector platform 130, the CT BOP platform 135, personnel, each pipe handler 120, and Kelly swivel 150 (see Figure 3G of the '862 provisional for detail). The lifts may travel on rails of the tower 1 15 and each lift may be operated independently of the other lifts. The tower 1 15 may further include personnel platforms and ladders connecting the personnel platforms. The tower 1 15 may further include a standpipe for transporting milling fluid, such as mud, from pumps of the platform 30 or supply vessel (not shown) to the Kelly swivel 150.

[0055] The CT BOP platform 135 (see Figure 3H of the '862 provisional for detail) may include wind walls to protect personnel, a CT BOP 232 (Figure 4B), an opening for passage of coiled tubing 157 and CT BHA (not shown), a BOP stand, and a riser clamp, such as a claw (not shown). The CT BOP 232 may be stored in the stand when not in use and easily deployed over the opening to be connected to the riser 245 when in use (discussed below).

[0056] The injector platform 130 may include a coiled tubing injector 233 (Figure 4B), an injector lift 234, the riser handler, and a CT BOP clamp (see Figure 3I of the '862 provisional for detail). The injector 233 may include a gooseneck, a head, and one or more strippers. Each stripper may include a seal and a piston disposed in a housing. A hydraulic packoff port and a hydraulic release port may be formed through the housing in fluid communication with a respective face of the piston. Each port may be connected to a hydraulic power unit (HPU, not shown) of the control system via a respective hydraulic conduit. When operated by pressurized hydraulic fluid via the pack-off port, the piston may longitudinally compress the seal, thereby radially expanding the seal inward into engagement with the CT 157. The stripper seal may be released by application of pressurized hydraulic fluid via the release port. Alternatively, an electric actuator may be used instead of the piston. Alternatively, the stripper may include a spring instead of the release port.

[0057] The injector head may include a traction assembly (not shown) to engage the CT 157 and drive the CT into or out of the wellbore 5. The traction assembly may include opposing chain loops guided by bearing assemblies. Gripping members may be secured to individual links of the chain loops, so as to grip the coiled tubing. The gripping members and the chain loops may thus move together longitudinally at the area of contact with the CT 157 to move the CT into or out of the wellbore 5. The chain loops may be routed over sprockets or gears within the housing, rotating about the axis of the bearings assemblies, and the chain loops may thus be guided by the bearing assemblies. A hydraulic or electric drive motor may drive the chain loops. The drive motor may be in hydraulic/electric communication with the control system via a conduit/cable.

[0058] The injector lift 234 may be operated independently of the injector platform lift for inspection and maintenance of the injector 233. The riser handler may include a clamp, such as a claw, for engaging the riser and a table operable to move the claw horizontally along one or more axes, such as both. The table may also be operable to rotate the claw relative to the platform. The table may also be operable to pivot the claw relative to the platform. When not in use, the injector 233 may be stowed at the top of the tower 1 15 while retaining the CT 157 therein. This frees the rest of the tower 1 15 for perfornning intervention or abandonment operations with other types of workstrings and keeps the injector 233 primed for quick switchover to a CT operation.

[0059] The CT BOP clamp may include a latch, such as a collet, a lock, such as a sleeve, and a release, such as a sleeve. The CT BOP clamp may be electrically or hydraulically operated. The CT BOP 232 may include a profile for receiving the latch. The lock may be movable between a locked position and an unlocked position. The collet may be radially movable between an extended position and a retracted position when the lock is in the unlocked position and held in the extended position when the lock is in the locked position. The release may be operable between an extended position and a retracted position. The release may engage a shoulder of the CT BOP 232 and hold the CT BOP 232 down in the extended position so that the collet may be freed from the profile.

[0060] The system 100 may be transported to the platform 30 using a supply vessel (see Figures 4A-4H of the '862 provisional for detail). One or more cranes of the platform 30 may then be used to load each module from the supply vessel to the platform 30. The skid modules may be loaded from the supply vessel to the platform skid beams 30r. Once the skid 200 has been installed, the bottom frame 206 may be loaded from the supply vessel. The bottom frame 206 may be adjusted and locked before or after loading from the supply vessel. As discussed above, legs of the bottom frame 206 may receive posts of the skid 200 and then clamps may be operated to fasten the legs to the posts. Once the bottom frame 206 has been installed, the utility basket 165 may be received by the shelves 207 of the bottom frame. Further, the utility basket 165 may be fastened to the bottom frame 206, such as by one or more fasteners. The rotary jack 125 may then be loaded from the supply vessel on to the skid deck of the platform 30. The XT BOP 21 1 may then be loaded from the supply vessel on to the skid deck of the platform 30 proximate to the bottom frame 206. Alternatively, the rotary jack 125 and the XT BOP 21 1 may be loaded into the bottom frame and the utility basket set on the frame over the rotary jack and XT BOP.

[0061] Once the utility basket 165 has been installed, each tower floor module may be loaded from the supply vessel and connected to the bottom frame 206 (see Figure 3B). The legs may be adjusted before loading. The floor modules may also be connected to each other to increase stability. Once the floor 1 10 has been connected to the bottom frame 206, the wings 230 may be unfolded by operating the wing actuator. A height of the floor 1 10 may be adjusted to correspond to a height of the platform pipe deck using the elevator. The bridge may then be unfolded. The tower runners 226 may then be operated to a position to receive the tower 1 15. The runners 226 may be pre-installed on respective floor modules prior to loading or may be loaded separately.

[0062] The tower 1 15 may be loaded from the supply vessel in a horizontal position. The tower 1 15 may be loaded onto the runners 226. The tower 1 15 may be loaded with the riser 245 pre-installed or the riser may be loaded onto the tower separately. The runners 226 may be operated to hoist the tower 1 15 to the vertical position and then the runners may be operated to walk the tower along the tower skid rails 228. Once raised, the personnel lift, pipe handlers 120, injector platform 130, and CT BOP platform 135 may be mounted on the tower 1 15. Each may be loaded and mounted as separate modules. Once the tower 1 15 has been outfitted, the control cabin 145 may be loaded from the supply vessel and connected to the floor 1 10. Control lines may then be run from the various equipment to the control cabin 145.

[0063] The skid 200 may then be operated to walk to the rotary jack 125 and XT BOP 21 1 (if the rotary jack and XT BOP 21 1 were loaded after the utility basket 165). The tower floor 1 10 may be lowered until the bracket 214 engages a top of the jack frame 217. The bracket may be connected to the jack frame 217 and the tower floor may be raised (along with the rotary jack 125) and the bracket actuator operated to stow the rotary jack 125 until jointed tubular rig up (discussed below). [0064] To assemble the riser 245 (see Figures 5A-5D of the '862 provisional for detail), the injector platform 130 may be raised or lowered to a height for engaging a first riser joint. The table may then be operated to engage the riser handler clamp with the first riser joint. The table may then be operated to remove the first riser joint from the pipe rack. The table may then be operated to align the first riser joint with the riser clamp of the CT BOP platform. The injector platform lift may then be used to lower the first riser joint and the CT BOP platform riser clamp may be operated to engage the first riser joint. The riser handler clamp may be disengaged from the first riser joint. The injector platform 130 may then be raised to engage the second riser joint. The table may then be operated to engage the riser handler clamp with the second riser joint. The riser handler clamp may be engaged with the second riser joint and the table may be operated to remove the second riser joint from the rack and align the second riser joint with the first riser joint. The injector platform may then be lowered to engage the second riser joint with the first joint. The two riser joints may then be connected, such as with a flanged connection. The CT BOP platform riser clamp may then be disengaged and the first and second riser joints may be lowered and the CT BOP platform riser clamp reengaged. The riser handler clamp may then be disengaged from the connected riser joints. [0065] The pipe handler 120 may be used to pick up a flow tee (not shown). The pipe handler 120 may then be elevated along the tower 1 15 to an elevation of a top of the second riser joint. The pipe handler 120 may then be articulated to align the tee with the second riser joint top. The tee may then be connected to the second riser joint, such as with a flanged connection. The tee may serve as a circulation port for return fluid flow from the wellbore 5. Alternatively, the tee may be located anywhere along the riser 245. The third riser joint may be removed from the rack and connected to the tee as discussed above for the second riser joint.

[0066] Once the riser 245 and CT BOP 232 have been assembled, the tower 1 15 may be walked to a position over the XT if not already in position. The traveling crane 225 may be operated to remove and stow the well hatch 212 over the production tree. The XT cap (not shown) may then be unscrewed from the XT. The traveling crane 225 may then be used to hoist and stow the XT cap. The traveling crane 225 may be used to lower a crossover (not shown) to the XT at a wellhead deck (not shown) of the production platform 30. The riser may be lowered to the XT and the first riser joint may be connected to the crossover, such as by a flanged connection. Alternatively, the crossover may be assembled with the riser. The first riser joint may be disconnected from the rest of the riser 245. The tower 1 15 may then be moved over the XT BOP 21 1 using the runners and/or the skid 200. A bottom of the remaining riser 245 may be connected to the XT BOP, such as by a flanged connection. The remaining riser and XT BOP 21 1 may be raised and the tower 1 15 walked over to the first riser joint. The riser and XT BOP may be lowered to the first riser joint and the XT BOP 21 1 connected to the first riser joint, such as by a flanged connection. [0067] Alternatively, the XT BOP 21 1 may be installed directly on the XT at the wellhead deck. The traveling crane may be used to lower the XT BOP either assembled or in sections to the XT before assembly of the riser 245. The riser 245 may then be assembled and connected to the XT BOP 21 1 . [0068] To rig-up the system 100 for CT deployment (see Figures 6A-6E of the '862 provisional for detail), the injector platform 130 may be lowered using the elevator and aligned with the CT BOP 232 using the table. The CT BOP clamp may be operated to engage the CT BOP 232. The injector platform 130 may then be raised to hoist the CT BOP 232 over a top of the third riser joint. The CT BOP may then be connected to the third riser joint, such as by a flanged connection. The CT BOP platform riser clamp may then release the riser joints and the connected CT BOP 232. The coiled tubing 157 may be stabbed into the CT injector 233. A guide rope (not shown) may be manually inserted through the traction assembly of the injector head. The guide rope may then be connected to a pulling tool (not shown) on stabbing wire. The rope may then be used to pull the stabbing wire through the CT injector head and gooseneck to an end of the CT 157. The pulling tool may then be connected to an end of the CT 157. A stabbing winch of the injector 233 may then be operated to pull the CT 157 through the gooseneck and injector head. A coupling may then be connected to an end of the CT 157. The end of the CT 157 may exit the injector through the BOP clamp.

[0069] Each pipe handler 120 may include a base, one or more arm segments, and a clamp, such as a claw. Each pipe handler 120 may be electrically or hydraulically operated. A first arm segment may be pivoted to the base and pivoted to the second arm segment for articulation. The base may be connected to a tower rail and include a driver for raising or lowering the pipe handler along the rail. The pipe handler may further include an actuator for rotating each arm about the pivot, an actuator for rotating the claw, and an actuator for extending and retracting the claw. The claw may include a housing pivoted to a distal end of the second arm and pincers pivoted to the housing. [0070] Once the CT BHA has been assembled by personnel on a workbench (not shown) (in a horizontal position), the workbench may be moved to a position proximate the pipe handler 120. The pipe handler 120 may then be operated to grip a top of the CT BHA. The pipe handler 120 may be raised along the rail while the pipe handler is articulated to raise the CT BHA to a vertical position. The CT BHA may be raised to a position so that a bottom thereof is above the CT BOP. The pipe handler 120 may then be articulated to align the CT BHA with the CT BOP. The handler base may be lowered to insert the CT BHA into the CT BOP 233 and riser 245. A clamp, such as a C plate (not shown), may be connected to the CT BHA to support the CT BHA from the CT BOP 233. The pipe handler 120 may then release the CT BHA. If the CT BHA includes additional joints, the process may be repeated and the joints connected, such as by flanged connections. Once the CT BHA is assembled, the injector may be aligned with the CT BHA and the CT 157 may be connected to the CT BHA, such as by a flanged connection. The BOP clamp may be engaged with the CT BOP 233 and the CT 157 and CT BHA may be deployed into the wellbore 5 for performing an intervention or abandonment operation.

[0071] Figures 4A-4E illustrate rig-up for wireline (WL) 305 deployment. To rig-up for WL deployment, the CT BOP 233 and CT BHA may be removed from the riser 245. The CT injector platform 130 may be raised to a top of the tower 1 15. The third riser joint (with or without the tee) may be removed from the second riser joint and stowed in the tower rack. A WL BOP 300 may be connected to a top of the second riser joint 245, such as by a flanged connection.

[0072] Figure 4A illustrates a lubricator 301 assembled and laying horizontally on the floor 1 10 and the WL BOP 300 connected to a top of the riser 245. The lubricator 301 may include a tool housing 301 h and a pressure control head (PCH) 301 p. The pressure control head 301 p may include a grease injector and one or more stuffing boxes. Each stuffing box may include a seal, a piston, and a spring disposed in a housing. A hydraulic port may be formed through the housing in communication with the piston. The port may be connected to the HPU via a hydraulic conduit. When operated by hydraulic fluid, the piston may longitudinally compress the seal, thereby radially expanding the seal inward into engagement with the wireline 305. The spring may bias the piston away from the seal. Alternatively, an electric actuator may be used instead of the piston. [0073] The grease injector may include a housing integral with the stuffing box housing and one or more seal tubes. Each seal tube may have an inner diameter slightly larger than an outer diameter of the wireline 305, thereby serving as a controlled gap seal. An inlet port and an outlet port may be formed through the grease injector/stuffing box housing. A grease conduit may connect an outlet of a grease pump (not shown) with the inlet port and another grease conduit may connect the outlet port with a grease reservoir (not shown). Another grease conduit may connect an inlet of the pump to the reservoir. The grease pump may be electrically or hydraulically driven via cable/conduit connected to the control system and may be operable to pump grease from the grease reservoir into the inlet port and along the slight clearance formed between the seal tube and the wireline 305 to lubricate the wireline, reduce pressure load on the stuffing box seals, and increase service life of the stuffing box seals. [0074] Once the lubricator 301 is assembled, the WL BHA may be inserted into the lubricator. The WL BHA (not shown) may be supported from the lubricator 301 by a clamp, such as a C plate. Once the WL BHA is installed in the lubricator 301 , the pipe handler 120 may be operated to engage the lubricator and hoist the lubricator. A safety clamp may be fastened to the lubricator 301 for hoisting the lubricator. The WL 305 may then be threaded through sheave wheels 304b, p of the lubricator 301 and the WL BOP 300 and connected to the WL BHA.

[0075] Figure 4B illustrates hoisting of the lubricator 301 . The lubricator 301 may be raised to a height sufficient for swinging the lubricator to a vertical position. Figure 4C illustrates the lubricator 301 swung to a vertical position. The pipe handler 120 may be operated to swing the lubricator 301 to a vertical position. Figure 4D illustrates the lubricator aligned with the WL BOP 300. The pipe handler 120 may then be operated to align the lubricator 301 with the WL BOP 300.

[0076] Figures 4E illustrates the lubricator 301 connected to the WL BOP 300.

The lubricator 301 may be connected to the WL BOP 300, such as by a flanged connection. A winch 303 may be connected to the tower floor proximate the control cabin 145. Alternatively, the winch 303 may be connected to the control cabin 145.

The winch 303 may include a reel having the wireline 305 wrapped therearound and a motor for winding and unwinding the wireline on to and from the reel. The motor may be electrically or hydraulically driven. A conduit/cable may connect the motor to the control system. The winch 303 may also include an electrical coupling for providing data and power communication between the wireline 305 and the control system.

The WL BHA and WL 305 may then be deployed into the wellbore 5 for conducting an intervention or abandonment operation. [0077] Figures 5A-5L illustrate removing production tubing 75 from the wellbore 5. To rig-up for jointed tubular handling, the WL BOP 300 and WL lubricator 301 may be removed from the riser 245 (assuming the last mode was WL). The second and third riser joints 245 (depending on what whether the last mode was CT or WL) may be disconnected from the XT BOP 21 1 , disassembled, and stowed in the tower rack. The rotary jack 125 may be moved over the XT BOP 21 1 using the bracket actuator and the tower floor 1 10 may be lowered using the elevator until a bottom of the jack frame 217 rests on the XT BOP. The jack frame 217 may be connected to the XT BOP 21 1 , such as by a flanged connection, and the jack frame may be disconnected from the bracket 214. The tower floor 1 10 may then be raised back into position.

[0078] The power tongs 140 may be moved to a location adjacent the tower 1 15 on the floor 1 10. The Kelly swivel 150 may be connected to a tower lift and pipe baskets 160 may be moved to the wing portions 230 of the floor 1 10. The power tongs 140 may be used to connect a tubing hanger running tool (THRT, not shown) to a workstring joint, such as a drill pipe joint, with a threaded connection. The drill pipe joint may be moved from the pipe basket 160 by one of the pipe handlers 120. The pipe handler 120 may then lower the drill pipe joint and THRT to the rotary jack 125. The jack 125 may then lower the drill pipe joint into the XT BHA 21 1 and another joint may be added using the power tongs 140. The drill pipe workstring 415 may be assembled until the THRT reaches the tubing hanger in the wellhead. The THRT may be engaged with the tubing hanger. The jack 125 may then raise the workstring 415 and the production tubing 75 to the floor 1 10. The workstring 415 may be disassembled as the workstring and production tubing 75 are raised.

[0079] Figure 5A illustrates the production tubing 75 engaged by one of the pipe handlers 120. The claws of the pipe handlers 120 may be replaced by pipe clamps. Once a top joint 76 of the production tubing string 75 has been disengaged from the rest of the string 75, the pipe handler 120 may be engaged with the joint 76. The Kelly swivel 150 may then be removed from the joint 76. Since the system 100 may include two pipe handlers 120, the operation may be continuous. While one pipe handler 120 is loading the joint 76 into the basket 160 the power tongs 140 may be unthreading the next joint and the other pipe handler 120 may engage the next joint and load the next joint into the other basket and so on. [0080] Figure 5B illustrates hoisting of the joint 76 from the power tongs 140. The pipe handler 120 may raise the joint 76 from the power tongs 140. Figure 5C illustrates the joint 76 rotated to a horizontal position. The pipe handler 120 may then be operated to rotate the joint 76 from a vertical to a horizontal position. Figure 5D illustrates loading of the joint 76 into the basket. The pipe handler 120 may then be articulated to align the joint 76 with the basket 160 and the handler base may be lowered to load the joint 76 into the basket.

[0081] Figure 5E illustrates carting the full baskets 160f from the floor 1 10. The baskets 160 or the winged portion 230 may include a roller system (not shown) to facilitate moving of the full baskets 160f from the floor 1 10 to the platform deck. The full baskets 160f may be pushed by personnel with or without assistance from a hand cart (not shown) or the rollers may be powered electrically or hydraulically and controlled from the control cabin 140. Figure 5F illustrates the full baskets 160f rolled to the platform deck. Figure 5G illustrates the full baskets 160f rolled clear so that empty baskets 160e may be transferred from the platform deck to the winged portions 230. Figure 5H illustrates alignment of empty baskets 160e with the winged portions. Figure 5I illustrates carting of empty baskets 160e from the platform deck to the winged portions 230. Figure 5J illustrates placement of the empty baskets 160e into position to be loaded by the pipe handlers 120. Once the empty baskets 160e have replaced the full baskets 160f, removal of the production tubing 75 may continue. The process may be repeated to remove one or more casing strings 10, 40, 55 from the wellbore 5 (discussed below) and/or to deploy or retrieve the drill pipe workstring 415 into/from the wellbore 5.

[0082] The Kelly swivel 150 may be connected to a Kelly hose which is connected to the standpipe. The Kelly swivel 150 may be connected to a top of a jointed tubular for circulating fluid, such as milling fluid or kill fluid through the jointed tubular string. The Kelly swivel 150 may be connected to the jointed tubular, such as by a clamp, such as a spear. The spear may be electrically or hydraulically operated. The clamp may include a seal head to engage an inner surface of the tubular so that circulation may be maintained. The Kelly swivel 150 may support the joint from the tower 1 15 as the power tongs 140 assemble or disassemble the joint from the string. The Kelly swivel 150 need not be capable of supporting string weight as the rotary jack 125 may support the string weight (discussed above). [0083] The power tongs 140 may include a frame, a drive tong, and a backup tong. Each tong may include jaws operable between an extended position and a retracted position and an actuator for operating the jaws between the positions. The drive tong may further include a driver to rotate the drive tong relative to the frame. The drive tong may engage a pin of a joint to be assembled with or removed from the tubular string and the backup tong may engage a box of the tubular string. The drive tong may then be operated to rotate the pin relative to the backup tong, thereby engaging or disengaging a threaded connection between the pin and the box.

[0084] Although the different modes of the system 100: CT, WL, and jointed tubular have been discussed in a particular order, the system 100 may be shifted between the modes in any order and may only require one or more of the modes for a particular intervention or abandonment operation.

[0085] The control system (see Figure 9A of the '862 provisional for detail) may include a programmable logic controller (PLC) and an operator interface. The control system may be in data communication with the various equipment discussed above via a bus. The operator interface may include controllers, such as joysticks, buttons, and/or touch screens for operating the various equipment. The operator may monitor operation of the equipment via one or more video monitors, such as an LCD, LED, or plasma display. The control cabin 145 may house the PLC and operator interface. The control cabin 145 may further include a climate control system and one or more operator's chairs. The control cabin 145 may include a frame made from a metal or alloy, such as stainless steel. The control cabin 145 may include wall panels, ceiling panels, a floor, and a door. To facilitate visibility, a front, ceiling, and side panels facing the tower may be made from a transparent material, such as PMMA, polycarbonate, or composite glass. The transparent panels may be shielded by netting or bars.

[0086] The control system may further include a BOP panel. The BOP panel may include analog controls and instruments for immunity to failure of the control system. The HPU may include one or more hydraulic pumps driven by electric motors. The HPU may further include a reservoir for hydraulic fluid, such as mineral oil. The HPU may further include a cooler, one or more filters, and one or more sensors, such as filter sensor, reservoir level sensor, and fluid temperature sensor. The control system may further include one or more manifolds (not shown) having control valves for selectively providing or receiving hydraulic fluid to the various equipment. The control valves may be operated by the PLC.

[0087] Figures 6A-6N illustrate an abandonment operation conducted using the system 100, according to another embodiment of the present invention. If the production tubing 75 has collapsed, an expander (not shown) may be run-in on a workstring, such as drill pipe 415, and operated to re-open a bore of the production tubing.

[0088] Figure 6A illustrates a workstring, such as CT 157, deployed into the wellbore 5. Once access through a bore of the production tubing 75 has been established, the CT 157 may be deployed using the system 100, as discussed above. The CT 157 may be deployed using the riser and the CT BOP while the formation 50 is live. Alternatively, the formation 50 may be killed by pumping heavy weight mud (aka kill fluid) into the wellbore 5. The CT BHA may include a packer 400. The packer 400 may be set at or near a distal end of the production tubing 75. Figure 6B illustrates cement 405a squeezed into the perforations 65. Cement 405a may then be pumped through the CT 157 using a plug (not shown) and a pumping fluid, such as kill fluid.

[0089] Figure 6C illustrates cutting the production tubing 75. Once the cement 405a has cured, the CT 157 may be redeployed with a cutter 41 Ot as part of the CT BHA. The CT BHA may further include a mud motor (not shown) to rotate the cutter. The cutter 41 Ot may include extendable blades and a piston hydraulically operable to extend the blades. The cutter and mud motor may be operated by pumping fluid, such as mud or kill fluid, through the CT 157. The production tubing string 75 may be cut just above the production packer 85. Once cut, the production tubing 75 may be removed from the wellbore, as discussed above.

[0090] Figure 6D illustrates section milling of the production casing 55 and reaming of the production casing cement 60. Once the production tubing 75 has been removed, a workstring, such as drill pipe 415, may be deployed with a BHA. The BHA may include a section mill 420 and an underreamer (UR) 425. Each of the section mill 420 and UR 425 may include extendable blades and a piston operable to hydraulically extend the blades. The UR blades 425 may initially be restrained in a retracted position and be freed by a predetermined flow rate or by pumping a ball through the workstring 415. The section mill 420 may be operated by pumping milling fluid or kill fluid through the workstring 415 and rotating the workstring using the jack 125, as discussed above. Once milling of the production casing 75 has started, the UR 425 may be activated and ream the remaining cement 60. [0091] Figure 6E illustrates cementing of the milled section. Once a desired section of the production casing 55 has been milled, a workstring, such as CT 157 may be deployed and cement 405b may be pumped in to plug the milled section. The CT 157 may then be retrieved to the surface. Alternatively, a bridge plug (not shown) may be set and the cement 405b pumped on top of the bridge plug. The cement plug 405b may serve as an additional barrier to the formation 50. Figure 6F illustrates cutting of the production casing 55. Once the cement 405b has cured, a workstring, such as drill pipe 415, and a casing cutter BHA 410c may be deployed to cut the production casing 55. The production casing 55 may be cut just above the cement plug 405b sealing the milled and reamed section. [0092] Figure 6G illustrates freeing of the production casing 55 from the cement 60. The BHA may further include a pulling tool 430. The pulling tool 430 may include an anchor hydraulically operable to engage an inner surface of the production casing 55 above the cut and seal a lower chamber from a rest of the wellbore. Fluid pressure may then be pumped into the isolated chamber, thereby exerting a fluid force on the casing to break the cement 60 bonding the casing 55 to the wellbore 5. Alternatively or additionally, the pulling tool 430 may include a piston to exert force on the casing 55. Once the cement 60 is fractured, the workstring 415 may be retrieved to the surface and the production casing 55 may be removed from the wellbore 5. Figure 6H illustrates freeing of the intermediate casing 40 from the wellbore 5. The pulling tool 430 may be redeployed and operated to free the intermediate casing 55 from the wellbore 5. The workstring 415 may then be retrieved to the surface and the intermediate casing 40 may be removed from the wellbore 5.

[0093] Figure 6I illustrates reaming of another section of the wellbore 5. Once the intermediate casing 40 has been removed, the UR 425 may be redeployed and a section of the wellbore 5 lined by the intermediate casing 40 may be reamed. Figure 6J illustrates plugging of a portion of the reamed section. Once the section lined by the intermediate casing 40 has been reamed, a workstring, such as CT 157, may be deployed and cement 405c pumped in to plug at least a portion of the reamed section. The CT string 157 may then be retrieved to surface and the cement 405c allowed to cure. Alternatively a bridge plug (not shown) may be set and the cement 405c pumped on top of the bridge plug. The cement plug 405c may serve to isolate any other formations, such as aquifers or non-productive hydrocarbon bearing formations.

[0094] Figure 6K illustrates plugging of the surface casing shoe. Once the cement 405c has cured, the CT 157 may be redeployed. A bridge plug 435a may be set just below a distal end of the surface casing 10. Cement 405d may then be pumped in to seal the distal end of the surface casing 10. The CT 157 may be retrieved to the surface and the cement 405d allowed to cure. Figure 6L illustrates setting the top plug. Once the cement 405d cures, the workstring 157 may be redeployed and a bridge plug 435b set just below the seafloor 25. Cement 405e may then be pumped in to seal the surface casing 10 at the seafloor 25. The CT 157 may be retrieved to the surface and the cement 405e allowed to cure. [0095] Figure 6M illustrates cutting of the surface casing 10 at the seafloor 25. A workstring, such as drill pipe 415, may be deployed with the casing cutter 410c. The casing cutter 410c may be operated to cut the surface casing 10 at or near the seafloor 25. The workstring 415 may be retrieved to the surface. The surface casing 10 above the cut may then be retrieved. Figure 6N illustrates the wellbore 5 plugged and abandoned. Once the wellbore 5 has plugged and abandoned, the system 100 may walk to the next wellbore serviced by the production platform 30 and the process may be repeated.

[0096] In another embodiment, instead of or in addition to the cement, a viscoelastic or semisolid sealant may be used. Used with the cement, the sealant may form a composite plug to account for subsistence of the wellbore after setting of the plug by sealing any fractures formed in the cement due to the subsistence and/or forming an independent seal in addition to the cement. The composite plug may include a top layer of cement and an intermediate or bottom layer of sealant so that pressure drives the sealant against or into the cement. Additionally, the plug may further include a bottom layer of cement. Used instead of the cement, the viscoelastic or semisolid sealant may form a plug more resistant to subsistence than the cement. A suitable sealant is discussed and illustrated in U.S. Pat. App. No. 12/71 1 ,639, filed February 24, 2010, which is herein incorporated by reference in its entirety. [0097] Figure 7A shows a perspective view of a mobile work platform 501 , according to another embodiment of the present invention. Figure 7B shows a side view of the longitudinal side of the work platform 501 . Figure 7C shows the same as Figure 7B, but with an increased distance between the work platform legs. Fig. 7D shows a side view of the short side of the work platform 501 . Figure 7E shows the same as Figure 7D, but with increased leg lengths. The work platform 501 is of modular construction and comprises the modules: two main skid shoes 502, in the industry referred to as the "main skid system", a bottom frame 503, an auxiliary basket 504, in the industry referred to as a "utility basket", and a work floor 505. The utility basket 504 may be omitted in an alternative embodiment.

[0098] The main skid shoe 502 comprises a first skid shoe 521 and a second skid shoe 521 ' arranged to be able to be skidded along a skid beam 563 allocated to a skid frame 561 on a skid deck 506 as shown in Figures 7C, 7F and 7G. In the example the term skid deck 506 is used for a support deck, and may include other decks as hatch deck and drill floor when these are provided with a skid frame. A displacement shoe 523, in the industry known as a "traveling clamp", is displaceably arranged between the first 521 and the second 521 ' skid shoes. An actuator 525 connects the first skid shoe 521 and the displacement shoe 523. The actuator 525 is arranged to be able to displace the displacement shoe 523 in the direction toward or away from the second skid shoe 521 '. It is thereby achieved that the main skid shoe 502 may be displaced along the skid beam.

[0099] The bottom frame 503 is provided with two pairs of downward projecting legs 531 , which in their lower end portions 512 are placed resting on the two main skid shoes 502. The skid shoes 521 , 521 ' are provided with upward projecting pegs (not shown) and the legs 531 are in their lower end portions 512 arranged to be able to house the not shown pegs such that a stable connection is formed between the main skid shoes 502 and the bottom frame 503. Between the two pairs of downward projecting legs 531 are extending two essentially horizontal spacing struts 533 in the longitudinal direction of the work platform 501 . The spacing strut 533 is bisected and arranged to be able to be adjusted lengthwise with a telescopic connection 532 as shown in Figures 7C, 7F and 7G. The telescopic connection 532 makes it possible to place the same bottom frame 503 on the main skid shoes 502 even if the centre spacing between the skid beams 563 in the skid frame 561 is different from a first skid deck 506 to a second skid deck 506. The telescopic connection 532 may be hydraulically operated. The legs 531 are bisected and arranged in an upper end portion 513 to be able to adjust the bottom frame 503 height wise with a telescopic connection 515 as shown in Figures 7E and 7G. The telescopic connection 515 may be hydraulically operated. The upper end portion 513 is terminated in its free end portion in a coned portion 517.

[00100] The utility basket 504 is placed inside the bottom frame 503 between the legs 531 and the spacing struts 533. The legs 531 are provided with outward projecting brackets 535 on which the utility basket 504 is resting. The utility basket 504 may in its lower edge portion 541 be provided with cranes 543 able to move in the longitudinal direction of the utility basket 504. To make access to the utility basket 504 deck 545 easier, the utility basket 504 is provided with a downward projecting ladder 547 and an upward projecting ladder 547'.

[00101] The work floor 505 may be assembled from two modules 505', 505" for each module not to exceed the lifting capacity of the relevant canes 510. The work floor 505 may in an alternative embodiment be constituted by one module. The work floor 505 comprises when assembled two main supporting beams 551 , 551 ' positioned side by side and extending in the length direction of the work floor 505. On the underside of the main supporting beams 551 , 551 ' are arranged attachment elements (not shown) arranged to house the upper conical portion 517 of the bottom frame 503. The upper portions 51 1 , 51 1 ' of the main supporting beams 551 , 551 ' constitute a skid beam for an equipment, which may be positioned resting on the main supporting beams 551 , 551 '. Between the main supporting beams 551 , 551 ' the work floor 505 is provided with a longitudinal split 553 covered with a plurality of hatch covers 555. On one or both long sides the work floor may be provided with a hinged floor section 557. In the Figures are shown two hinged floor sections 557 in a horizontal working position. This has the advantage that the working area 559 of the work floor 505 may be made relatively large. The work floor 505 may when needed be led very close to a drilling rig 500 arranged to be able to be moved along the skid frame 561 , in that the floor section 557 is turned upward to a vertical position about the hinges 571 . Thereby is achieved that equipment positioned on the work floor 505 is given access to wells close to the drilling rig. [00102] The work platform 501 may in one embodiment be provided with a hinged bridge 507 on one of its short ends as shown in Figures 7F and 7G. The bridge 507 connects the work floor 505 with another deck, such as a pipe deck 508. This give easy access to the work floor 505 from the pipe deck 508. Since the bridge 507 is hinged the level of the work floor and the pipe deck may be somewhat different. By adjusting the height of the bottom frame 531 with the telescopic connection 515, the work floor 505 level may be brought to coincide with the pipe deck 508 level as shown in Figure 7F.

[00103] Figures 7F and 7G show equipment placed on the work floor 505 of the work platform 501 . The equipment is shown as a tower 509 provided with a coiled tubing injector 591 , which is movably arranged to the side of the tower 509. The coiled tubing injector is provided with a gooseneck 593. In Figure 7F the tower is shown positioned in a first position on the end portion of the work floor 505. The tower 509 may be displaced along the skid beams 51 1 , 51 1 ' to a second position as shown in Figure 7G. In Figure 7G is shown an embodiment wherein the coiled tubing injector 591 is connected to a first BOP valve 595 and from the lower portion of the BOP valve 595 a pressure balancing arrangement 599 shown here as a riser, projects downward.

[00104] The riser 599 projects downward through the split in the work platform 553 and down through the deck of the utility basket 504 deck 545. The lower portion of the riser 599 towers freely over the skid deck 506. The riser 599 is attached to the first BOP valve 595 and is in addition held by one of the hanging mechanisms 597. The hanging mechanism 597 may comprise a false rotary and slips. The work platform 501 shown in the Figures may be displaced along the skid frame 561 while the tower 509 may be displaced along the skid beams 51 1 , 51 1 '. The riser 599 towers freely over the skid deck 506 and is no hindrance to the horizontal displacing of the work platform 501 and the tower 509. Material 565 may be stored on the skid deck 506 as schematically shown in Figures 7F and 7G. Material 565 will not hinder displacing of the work platform 501 as long as it is not placed on or in the immediate vicinity of the skid beams 563. The material 565 will neither hinder displacing of the work platform 501 when it is provided with a coiled tubing injector 591 and there from the coiled tubing injector 591 projects downward a riser 599. If necessary the tower 509 may be displaced back and forth on the work deck 505 for the downward projecting riser 599 to be able to pass past material 565 when the work platform 501 is displaced along the skid frame 561 .

[00105] As shown in Figure 7G, the bridge 507 may be raised when the work platform 501 is to be displaced along the skid deck 506. When the riser 599 is positioned over a hatch opening 520 between the skid beams 553 in the skid deck 506, the riser may be lowered down through the skid deck 506 by lowering the coiled tubing injector from an upper position in the tower 509 as shown in Figure 7G to a lower position in the tower 509 as shown in Figure 7F. The riser 599 may thereby be connected to a second BOP valve (not shown) on a cellar deck (not shown) below the skid deck 506. Thereby is achieved the advantage that equipment being used in a well operation, may easily and quickly be displaced from a first well (not shown) to a second well (not shown) without the equipment having to be dismantled. In the embodiment example this is shown with equipment for coiled tubing operations. Equipment for wireline or slickline operations, equipment for operating a downhole tractor or snubbing equipment are examples of other well operation equipment that may be used together with this embodiment.

[00106] Figure 8A shows a side view principle sketch of a well tubular jack 604 in the initial position, having a displaceable pipe clamp in engagement with a well tubular 612 to be pulled out, according to another embodiment of the present invention. Figure 8B shows a side view of the well tubular jack 604 in engagement with the well tubular 612 wherein the displaceable pipe clamp 643 has pulled the well tubular 612 a distance up out of a well 601 . Figure 8C shows a side view of an alternative embodiment of the well tubular jack 604, as it comprises a BOP 613b.

[00107] The well tubular jack 604 is provided with a frame 641 formed by a lower and an upper frame portion 626, 619. The lower frame portion 626 comprises a chassis 613 arranged to be able to be supported on the upper portion 61 1 , also called the wellhead, of an underlying well 601 . In the upper frame portion 619 is arranged a first, stationary pipe clamp 642 arranged for releasable hanging of a well tubular 612. In the upper frame portion 619 two linear actuators 644 are dependency arranged, shown here as hydraulic cylinders 620 each having a piston rod 625 projecting downward toward the lower frame portion 626. The piston rods 625 are fastened to a displaceable, second pipe clamp 643 arranged for releasable fixation of the well tubular 612. The hydraulic cylinders 620 are in a fluid-communicating manner connected to a hydraulic plant (not shown).

[00108] The pipe clamps 642, 643 may be formed in a great number of manners, for example as releasable wedges 616, also called slips, arranged to abut in a corresponding, conical wedge abutment 617. Hydraulic operated clamping jaws (not shown) are another example. In one embodiment the upper pipe clamp 642 is formed as a rotary table, as the wedge abutment 617 is rotatably arranged in a socket 618.

[00109] The chassis 613 is provided with means 613a arranged to be able to form a fluid tight joint with the wellhead 61 1 (see Figures 8A and 8B). In one embodiment (see Figure 8C) the chassis 613 comprises a BOP 613b, which, in an operative position is in fluid communication with the wellhead 61 1 .

[00110] A well deck 602 is provided with a series of well deck openings 621 forming access to the wellheads 61 1 of each well 601 . To simplify maneuvering of the well tubular jack 604 between the various wells 601 , the well tubular jack 604 may during displacement be hung from working rig (not shown) provided with means arranged for horizontal movement of the well tubular jack 604 over the whole extent of the well deck 602 and also to lower the well tubular jack 604 to abutment against the wellhead 61 1 and to raise the well tubular jack 604 up from abutment against the wellhead 61 1 after the operation of pulling the well tubular 612 is completed. [00111] The well tubular jack 604 is maneuvered into position over the relevant well 601 and lowered down onto the wellhead 61 1 , as the chassis 613 of the well tubular jack 604 abuts supportingly a for the purpose suited portion of the wellhead 61 1 . Depending on the actual well condition, the well tubular jack 604 may be provided with a wellhead connection 613a or a BOP 613b providing a prescribed abutment and/or seal between the well tubular jack 604 and the wellhead 61 1 . The displaceable pipe clamp 643 is displaced to its lower position and fastened to the well tubular 612 to be pulled up. The pipe clamp 643 is activated, for example by the wedges 616 being disposed around the well tubular 612 and being lead down against the wedge abutment 617. The linear actuators 644 are activated and pull the lower pipe clamp 643 and the well tubular 612 upward. When in need for a renewed grip, the upper pipe clamp 642 is activated so that the well tubular 612 is held in a secure grip before the lower pipe clamp 643 is released and returns to its lower position for a renewed grip. The reaction forces from the well tubular jack 604 are transmitted via the chassis 613 to the wellhead 61 1 . As the well tubular 612 is pulled up, it is split into smaller sections in a for the purpose suitable manner and removed from the work site by means of for the purpose suitable means (not shown). [00112] While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Claims

Claims:

1 . A system for intervention or abandonment of a subsea wellbore having a production tree above waterline, comprising:

a tower;

riser joints;

a riser handler:

operably coupled to the tower so that the riser handler may be raised and lowered along rails of the tower, and

operable to handle the riser joints for assembly thereof; a skid connectable to skid rails of a production platform;

a bottom frame connected to the skid;

a tower floor connected to the frame and having rails and runners operably coupled to the rails at a top of the tower floor, wherein the runners are operable to:

receive the tower in the horizontal position,

raise the tower to the vertical position, and

move the tower along the rails; and

a rotary jack:

connectable to the production tree via one or more of the riser joints, and

operable to raise, lower, and rotate a jointed tubular string.

2. The system of claim 1 , further comprising:

a CT injector platform comprising a CT injector and the riser handler;

a CT blowout preventer (BOP) platform comprising a riser clamp, a CT BOP, and a CT BOP clamp; and

a rack connected to the tower for racking the riser joints.

3. The system of claim 1 , further comprising:

a utility basket supported in the bottom frame; and

a traveling crane connected to the utility basket and operable to lift a hatch of the skid deck.

4. The system of claim 1 , wherein: a bottom of the tower floor has one or more rails,

the system further comprises:

an elevator operable to raise and lower the tower floor relative to the bottom frame; and

a bracket operable to connect the rotary jack to the tower floor, the bracket operably coupled to the bottom of the tower floor so that the bracket may move along the tower floor bottom rails.

The system of claim 1 , wherein:

the tower floor has wing portions,

the system further comprises baskets operable to store tubular joints, and the baskets are movable along the wing portions to a deck of the platform.

6. The system of claim 1 , further comprising:

a pipe handler connected to the tower, the pipe handler operable to grip a tubular joint and articulate the tubular joint; and

a lift operable to raise and lower the pipe handler along a rail of the tower.

7. The system of claim 1 , further comprising:

a Kelly swivel operable to connect a Kelly hose to a tubular string while allowing rotation of the tubular string relative to the Kelly hose; and

power tongs operable to connect and disconnect joints to and from a tubular string.

8. The system of claim 1 , wherein the rotary jack comprises:

a jack frame;

a stationary clamp connected to the jack frame;

an actuator connected to the jack frame;

a rotary drive rotationally connected to the jack frame and longitudinally movable relative to the jack frame by the actuator; and

a traveling clamp longitudinally connected to the rotary drive, wherein the rotary drive is operable to rotate the traveling clamp relative to the jack frame.

9. The system of claim 1 , further comprising a control cabin connected to the tower floor and having a transparent front panel facing the tower.

10. The system of claim 9, further comprising:

a winch connected to the tower floor or the control cabin and having

wrapped therearound;

a lubricator for housing a wireline BHA and sealing the wireline; and

a wireline BOP connectable to the lubricator.

1 1 . A method for intervention or abandonment of a subsea wellbore, comprising: loading a skid to a production platform over the subsea wellbore having a production tree located above waterline and connecting the skid to skid rails of the production platform;

loading a bottom frame to the production platform and on to the skid;

loading a tower floor to the production platform and on to the bottom frame; loading a tower to the production platform and connecting the tower to runners of the tower floor;

raising the tower using the runners;

loading a rotary jack to the production platform;

assembling a riser using the tower;

connecting the riser to the production tree;

connecting the rotary jack to the production tree via a joint of the riser;

deploying drill pipe and a connected bottomhole assembly (BHA) into the wellbore using the rotary jack; and

rotating the drill pipe and connected BHA using the rotary jack.

12. The method of claim 1 1 , further comprising:

connecting a blowout preventer (BOP) to the production tree via the riser joint, wherein the rotary jack is connected to the production tree via the BOP.

13. The method of claim 12, further comprising:

loading a coiled tubing (CT) injector platform to the production platform and connecting the CT injector to the tower; loading a CT BOP platform to the production platform and connecting the CT BOP platform to the tower,

wherein:

the CT injector platform comprises a CT injector and a riser handler, the CT BOP platform comprises a CT BOP and a riser clamp, and the riser is assembled using the injector and CT BOP platforms.

14. The method of claim 1 1 , further comprising:

deploying a CT string into the wellbore; and

squeezing cement into a hydrocarbon bearing formation of the wellbore using the CT string.

15. The method of claim 14, further comprising:

removing the production tubing string from the wellbore using the rotary jack, comprising:

removing a joint from the production tubing string using power tongs; articulating the removed joint from the power tongs into a basket located on the tower floor using a pipe handler;

repeating the removing and articulating steps until the basket is full; rolling a full basket from the tower floor; and

rolling an empty basket to the tower floor.

16. The method of claim 15, wherein:

the BHA further comprises a section mill; and

the drill pipe and BHA are rotated to section mill a portion of production casing of the wellbore.

17. The method of claim 16, further comprising:

deploying the CT string into the wellbore; and

pumping cement through the CT string to plug the milled section.

18. The method of claim 17, further comprising:

deploying the drill pipe and a connected second BHA into the wellbore using the rotary jack, wherein the second BHA comprises a pulling tool; the method further comprises operating the pulling tool to engage the production casing and break the production casing free from the wellbore; and

the method further comprises removing the production casing from the wellbore.

19. The method of claim 18, further comprising:

deploying the coiled tubing string into the wellbore;

setting a bridge plug proximate to a shoe of surface casing of the wellbore; and pumping cement on top of the bridge plug.

20. The method of claim 19, further comprising:

deploying the drill pipe and a third BHA into the surface casing using the rotary jack, wherein the third BHA comprises a casing cutter;

rotating the drill pipe and the casing cutter to cut the surface casing proximate the sea floor; and

removing the surface casing above the cut from the sea.

21 . A mobile work platform (501 ) for horizontal displacement of equipment over a support deck (506); the work platform (501 ) being provided with at least two downward projecting legs (531 ), where the downward projecting legs (531 ) at their lower end portions (512) are provided with moving means (502) arranged to be able to displace the work platform (501 ) in a first direction along the support deck (506), and where the work platform (501 ) is provided with a work floor (505), characterised in that the downward projecting legs (531 ) are mutually displaceable in a second direction along the longitudinal direction of the work platform (501 ).

22. A work platform (501 ) according to claim 21 , characterised in that the downward projecting legs (531 ) of the work platform (501 ) are adjustable in the longitudinal direction of the legs (531 ).

23. A work platform (501 ) according to claim 21 , characterised in that the work floor (505) of the work platform (501 ) is provided with at least one lengthy body or track (51 1 , 51 1 ') arranged for horizontal displacing of an equipment in the longitudinal direction of the work platform (501 ).

24. A work platform (501 ) according to claim 21 , characterised in that the work floor (505) of the work platform (501 ) is provided with at least one hinged deck section (557) arranged to be able to take up an essentially vertical work position, or an essentially horizontal work position, such that the work area of the work floor (505) may be adjusted.

25. A work platform (501 ) according to claim 21 , characterised in that work platform (501 ) is assembled from modules.

26. A work platform (501 ) according to claim 25, characterised in that work platform (501 ) is assembled from at least two moving means (502) arranged to be able to displace the work platform (501 ) horizontally along a support deck (506) provided with a lengthy body or track (563); a bottom frame (503) provided with at least two legs (531 ) and arranged to be able to be releasably attached to the moving means (502); and a work floor (505) arranged to be able to be releasably attached to the upper portion of the bottom frame (503).

27. A work platform (501 ) according to claim 26, characterised in that the bottom frame (503) is telescopic in the longitudinal direction of the bottom frame (503).

28. A work platform (501 ) according to claim 26, characterised in that the work platform (501 ) is provided with a utility basket (504) arranged to be able to be releasably attached to the bottom frame (503) between the at least two legs (531 ).

29. A work platform (501 ) according to claim 26, characterised in that the work floor (505) is constituted by two modules (505', 505").

30. An installation for exploitation of petroleum, where the installation is provided with a support deck (506), wherein the support deck (506) is provided with lengthy bodies or tracks (563), characterised in that the support deck (506) is further provided with a movable work platform (501 ) according to claim 21 .

31 . An installation according to claim 30, characterised in that the support deck (506) belongs to a group consisting of a drill floor, skid deck and hatch deck.

32. An installation according to claim 30, characterised in that the lengthy bodies (563) are constituted by the skid beams (563) of a skid frame (561 ).

33. A method for horizontal displacing of equipment on a support deck (506) wherein the equipment is positioned on a mobile work platform (501 ) according to claim 21 .

34. A well tubular jacking device (604) comprising a frame (641 ), a stationary pipe clamp (642) arranged for releasably hanging of a well tubular (612) and a

displaceable pipe clamp (643) connected to one or more linear actuators (644) and arranged for releasable fixation of the well tubular, characterised in that the frame

(641 ) comprises a chassis (613) arranged to be able to be supported on an

underlying upper portion (61 1 ) of a well (601 ).

35. A device according to claim 34, characterised in that the stationary pipe clamp

(642) is formed by a series of releasable wedges (616) and a corresponding, conical wedge abutment (617) supported in the frame (641 ).

36. A device according to claim 35, characterised in that the wedge abutment (617) is releasably arranged in a socket.

37. A device according to claim 35, characterised in that the wedge abutment (622) is a rotary table.

38. A device according to claim 34, characterised in that the linear actuator (644) is a hydraulic cylinder.

39. A device according to claim 34, characterised in that the linear actuator (644) is a hydraulic cylinder (620) arranged hanging from an upper frame portion (619) with a piston rod (625) extending toward a lower frame portion (626).

40. A device according to claim 39, characterised in that the displaceable pipe clamp (643) is fastened to the piston rod (625).

41 . A device according to claim 34, characterised in that the upper well portion (61 1 ) is a wellhead.

42. A device according to claim 34, characterised in that the upper well portion (61 1 ) is a pipe hanger (615) connected with the wellhead.

43. A device according to claim 34, characterised in that the chassis (613) comprises means (613a) arranged to be able to form a fluid tight joint with the wellhead (61 1 ).

44. A device according to claim 34, characterised in that the chassis (613) comprises a BOP (613b) in fluid communication with the wellhead (61 1 ).