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BACKGROUND 
     The disclosure regards a system and a method capable of functioning as an apparatus for transport and handling of equipment in a lifting arrangement used on a floating vessel. More precisely, the disclosure regards a method and an apparatus for rigging up intervention equipment in a lifting arrangement utilized on a floating vessel, and moving the intervention equipment between an inoperative and an operative position. 
     Offshore subsea wells are typically developed using floating vessels to accommodate equipment, personnel, and operations necessary to drill and complete a well in order to initiate production of hydrocarbons from a given reservoir forming the target for the well. Additionally, testing and intervention work is typically executed through the use of such floating vessels. It is to be understood, however, that such a floating vessel also could be used in context of other types of subsea wells, for example water or gas injection wells. 
     It is understood that a floating vessel will be subjected to vertical and horizontal (pitch and roll) movement due to the action of the natural environment such as wind and the waves of the sea (or a lake), which in turn introduces a challenge with respect to equipment utilized during operations carried out on the floating vessel. Such operations may include, but are not limited to drilling, completion, well testing, and well intervention. During operation at sea, said equipment will be subjected to vertical movement unless compensated for such movement. 
     As a floating vessel moves up and down in response to the waves, e.g. a drill string and a drill bit extending down below the vessel from a load-bearing structure, such as a top drive located within a drilling rig, will also move up and down. As it is essential that the weight on the drill bit, i.e. the downward force applied to the bit, is kept as constant as possible, such up and down movements of the drill bit are undesirable and provide for inefficient drilling progress which is counterproductive. Heave will remove weight from the drill bit as the rig moves up in conjunction with the high crest of a wave, while weight will be added to the drill bit as the rig moves down into the low point between two waves. Should hydrocarbons start to flow from a reservoir and into a wellbore being drilled, a valve arrangement is utilized to prevent such hydrocarbons from discharging into the natural environment and onto the floating drilling vessel. Such a valve arrangement is commonly referred to as a Blow Out Preventer (BOP), which is capable of sealing around, or cutting and sealing above, a drill pipe cut by shear rams in the BOP. 
     In other operations, which may include well testing and well intervention, e.g. wireline operations and coiled tubing operations, several sections of a high pressure tubular, commonly referred to as workover riser, are connected between equipment located at the seafloor, such as a subsea wellhead or a subsea Christmas tree, and the floating drilling vessel. The workover riser provides a barrier element for allowing control of pressurized hydrocarbon fluids present in the reservoir, and hence in the wellbore. A subsea valve arrangement, such as a subsea BOP, is also utilized in such operations to provide a system capable of sealing the well in case of an uncontrolled discharge of hydrocarbons from the reservoir. During such operations, hydrocarbon fluids may be present throughout the wellbore and the workover riser, and discharge at surface rig level is typically prevented by means of a valve arrangement located at the surface, commonly referred to as a surface flow tree. A surface flow tree, or similar equipment attached to a workover riser, extending upwards from equipment located on the seafloor to the rig, is usually supported by, and kept in tension by, the top drive and drawworks forming part of the drilling rig on a floating drilling vessel. Various types of lifting arrangements are utilized to connect the surface flow tree to the top drive and to hold the workover riser in tension as required to prevent high loads from acting on the equipment on the seafloor. Such lifting arrangements may include, but are not limited to, rigid bails, tension frames, soft slings, and backup heave compensation systems. A backup heave compensation system is disclosed in U.S. provisional application Ser. No. 61/480,239 and is referenced herein for informative purposes. 
     Well completion involves the use of production tubulars, which typically extend downwards from the wellhead and the Christmas tree to the producing zones bound by the reservoir(s) targeted by the well(s). Some parts of a completion operation will require equipment to be in tension in a manner similar to that described above. This may comprise setting the upper lock and seal mechanism of the production tubular, commonly referred to as a tubing hanger, inside the well-head. At this point, a landing string, which is typically made up of several sections of tubular, such as drill pipe or workover riser, will be connected to said tubing hanger at the wellhead and to the top drive at the floating drilling vessel via said lifting equipment. Similar to the description above, the weight of the system is controlled by holding said landing string in tension, thereby maintaining a known force at the level of said tubing hanger. 
     In operations requiring coiled tubing it is necessary, as mentioned above, to utilize a lifting arrangement capable of maintaining tension in the tubular extending from the wellhead to the floating vessel, such as a workover riser system, to prevent high loads from acting on the equipment on the seafloor. The lifting arrangement must be of a size such that coiled tubing equipment, such as a coiled tubing BOP, coiled tubing dual stripper arrangement and coiled tubing injector head, can be fitted and supported within the lifting arrangement. Furthermore, it is beneficial and in some instances a requirement that the coiled tubing equipment is transported to and from the lifting arrangement by means of lifting devices such as winches and/or hoists integrated in the lifting arrangement. Based on this, it is common practice to utilize tension frames with integrated lifting devices to accommodate for coiled tubing equipment required to execute said operations. The complexity of such tension frames are continuously evolving with respect to functionality integrated in such frames. Such functionality may include but is not limited to lifting devices, such as winches and hoists, manipulator devices utilized to guide equipment being lifted, advanced platform devices comprising means for vertical and horizontal adjustment of equipment such as the coiled tubing injector head, and adjustable work platform devices to accommodate for risk reducing measures during operational sequences and maintenance of equipment. Additional functionality is not merely advantageous as complexity and weight increases, and in some situations limits overall applicability of a tension frame due to said complexity and amount and severity of handling operations required to rig up the tension frame and furthermore change from one mode to another, such as to change from a coiled tubing mode to a wireline mode. Additionally, complex and time consuming operations are required onshore to prepare such tension frames for coiled tubing mode. In situations requiring coiled tubing capability on a floating vessel it is normally, as a minimum, required to utilize wireline equipment prior and after the coiled tubing intervention, hence it is required to alternate between wireline and coiled tubing modes several times. Based on this, it is commonly understood that the added functionality described above introduces disadvantages and increases the risk to personnel and equipment during intervention operations executed by means of tension frames, coiled tubing equipment, and wireline equipment. 
     In accordance with prior art intervention operations, such as for wireline and coiled tubing operations are executed by means of an intervention frame, such as a coiled tubing tension frame. The tension frame is utilized as a lifting arrangement connected to a load bearing unit in top, such as a top drive, and a surface valve arrangement in bottom, such as a surface flow tree or wireline adapter, further connected to a tubular, such as a workover riser or drilling tubular, extending from the floating vessel to equipment located on the seafloor. Hence, the tension frame and top drive is organized in a manner to hold the weight of said surface flow tree and said tubular, and furthermore ensure that the tubular is in tension to prevent high loads from acting on the equipment on the seafloor. In early configurations of such tension frames, it was common that one lifting device, such as a winch or hoist, was included in a top load bearing member, such as a beam, of the tension frame, which in turn was utilized to lift intervention devices, such as coiled tubing BOP and injector head, from a deck to the tension frame and landed onto a tubular member, such as a x-over/adapter, extending from a said surface flow tree or wireline adapter into the tension frame and also in reverse order in conjunction with removing the coiled tubing equipment from the workover riser stack and tension frame to be landed back onto the deck. The x-over/adapter extending from said surface flow tree or wireline adapter is commonly utilized as the mechanical interface towards a lower load bearing member, such as a beam arranged with such an mechanical interface, of the tension frame such that all forces are maintained by this said mechanical interface. 
     During recent years several intervention frame concepts have evolved, comprising more advanced functionality related to handling of intervention devices, such as coiled tubing BOP and injector head. These more advanced tension frames typically comprise two or more handling winches/hoists attached to a top load bearing member, such as a top beam, an injector head handling apparatus, such as a platform apparatus, attached to at least two parallel guides, such as tension frame legs, forming a substantially vertical tensioning frame, a manipulator device, adjustable work platform devices, and a lower load bearing member, such as a beam, with an integrated mechanical interface towards a tubular such as a x-over/adapter, extending from a said surface flow tree or wireline adapter into the tension frame. The winches/hoists are typically split into various categories with respect to rated specifications, where a large version winch/hoist is utilized to lift the coiled tubing BOP and injector head into/out of the frame during rigging, while smaller winches/hoists are utilized to handle and rig up smaller equipment such as devices dedicated for purposes of the work in a well, such as bottom hole assemblies used for the actual operation in a well. The platform apparatus defines a landing point for a coiled tubing injector during rigup, whereupon after landing the injector head is moved horizontally and vertically by means of functionality part of the platform apparatus and/or said tension frame. The manipulator device is included to function as a guide to prevent loads hanging from winches/hoists from moving during handling. Adjustable work platforms are included to ensure safe working areas for personnel during operation and maintenance of equipment that is part of the intervention operation executed by means of the intervention frame and intervention devices described herein. 
     Despite of having some advantages, the recent technological evolvements related to coiled tubing tension frames introduce several disadvantages. The platform apparatus mentioned above requires hydraulic and/or mechanical systems to enable horizontal and vertical movement from a remote location. This functionality comprises several moving and fixed devices which add weight and complexity to the total system during handling, and additional control functions and related hydraulic conduits and/or electric conduits must be part of the tension frame during handling. Additionally, since the platform apparatus is a part of the tension frame prior to lifting intervention devices, such as a coiled tubing injector head, it is necessary to lift the injector head to a certain height prior to moving the load towards center to ensure clearance between the injector head and said platform apparatus prior to landing the injector head onto the platform apparatus, which in turn impose a large working angle onto the winch/hoist wire/chain during handling. Furthermore, the platform apparatus introduces a large sized piece of equipment which is not required for other intervention operations to be executed, such as wireline work, such that it would be beneficial to remove the platform apparatus prior to executing said wireline operations. However, due to the complexity involved with removing the platform apparatus from the tension frame in a rigged up and hence operational position, it is common to leave this as part of the tension frame during said wireline operations further implying non-optimal working environment during said wirleline operations. 
     It is commonly accepted that weight and complexity of an intervention frame should be limited to a minimum during handling to reduce risk of failure and consequences related to potential accidental situations. 
     GB 2 418 684 B discloses an apparatus and a method for protecting against problems associated with handling a coiled tubing injector head within a coiled tubing tension frame. The publication discloses a platform apparatus adapted for connection with an intervention frame, the platform apparatus comprising a supporting member, such that in use, the platform apparatus is connected to the intervention frame and the supporting member is shaped or otherwise adapted to support an intervention tool such as a coiled tubing injector. Thus, it is possible to stow an injector head on the intervention frame during use of the frame for other purposes, such as wireline. The publication further specifies that this apparatus and method will significantly reduce the amount of time required for changeover from coiled tubing intervention to wireline intervention. The publication further specifies that in preferred embodiments, the platform apparatus is rotatably connected to the frame and also comprises a turntable. Preferably the platform apparatus can rotate around the frame in a first direction whilst the turntable apparatus rotates in the opposite direction thus maintaining the direction of any coiled tubing towards a V-door provided in the derrick, regardless of the rotational position of the platform apparatus. The invention describes a method for handling a coiled tubing injector head inside an intervention frame, which in turn can be rotated to the side of the intervention frame to create free space for a wireline operation. However, one skilled in the art will recognize disadvantages and operational limitations as it is disadvantageous to position a large load, as represented by a coiled tubing injector head, on the side of an intervention frame structure, as this will generate an uneven force distribution and related bending moments in an intervention frame subjected to movements as generated by movements of the floating drilling vessel as inflicted by the natural environment. Furthermore, the disclosed apparatus illustrates a system where the platform apparatus is mounted as a part of the intervention frame prior to lifting the injector head, further meaning that it is necessary to lift the injector head to a certain height prior to moving the load towards center to ensure clearance between the injector head and platform apparatus prior to landing the injector head onto the platform apparatus, which in turn impose a large working angle onto the winch/hoist wire/chain used during handling. 
     Further, NO 322006 (B1)/U.S. Pat. No. 7,306,404 B2 also describes a platform apparatus being part of a handling device for well intervention on a floating vessel. The publications disclose a handling device for well intervention, the handling device being releasably connected, in an operative position, to a riser and to a heave compensator which is arranged to maintain a prescribed tensioning of the riser. The handling device comprising: a lower riser securing device; a substantially vertical tensioning frame provided with at least two parallel guides; a jacking table provided with an upper riser securing device; at least one tension-resistant connection between the tensioning frame and the heave compensator located there-above; the jacking table being movable connected to the at least two parallel guides, at least one of the at least two parallel guides including lifting screws for moving the jacking table along the guides in their, in the position of use, vertical extent, and the jacking table including hydraulic cylinders for moving the upper riser securing device in a horizontal direction along at least one axis of movement. One skilled in the art will recognize that the disclosure describes an intervention frame, such as a tension frame, with a moveable jacking table comprising a device and method for clamping onto a tubular, such as a riser, to function as a method for rigging tubular riser sections within the intervention frame, by means of vertical and horizontal displacement of the jacking table. One skilled in the art will furthermore recognize that the jacking table may function as a landing platform for a coiled tubing injector head, and furthermore provide means for handling said injector head in both vertical and horizontal directions. However, in the same manner as explained for the disclosed publication GB 2 418 684 B, the disclosed apparatus and method in publications NO 322006 (B1)/U.S. Pat. No. 7,306,404 B2 describes a system where the platform apparatus, by means of the jacking table, is mounted as a part of the intervention frame prior to lifting the injector head, further meaning that it is necessary to lift the injector head to a certain height prior to moving the load towards center to ensure clearance between the injector head and platform apparatus prior to landing the injector head onto the platform apparatus, which in turn impose a large working angle onto the winch/hoist wire/chain used during handling. 
     SUMMARY 
     The primary objective of the disclosure is to remedy or reduce at least one disadvantage of the prior art, or at least to provide a useful alternative to the prior art. 
     It is also an objective of the disclosure to provide equipment that simplifies the processes required to install and uninstall intervention devices, such as BOP, stripper arrangements, and injector head utilized during a coiled tubing intervention, for lifting arrangements described herein, such as tension frames and backup heave compensation system as described in U.S. provisional application Ser. No. 61/480,239, and furthermore minimize the weight of such lifting arrangement during handling and rigup. It is also an objective of the disclosure to simplify processes required to alternate between intervention modes, and furthermore facilitate for optimized setup of the lifting arrangement for such modes, such as for example coiled tubing and wireline modes. 
     The objectives are achieved by means of features disclosed in the following description and in the subsequent claims. 
     According to the disclosure, equipment comprising components simplifying processes required rigging up coiled tubing equipment in a lifting arrangement such as an intervention frame, such as a tension frame or backup heave compensation system is provided. 
     In accordance with a first aspect of the present disclosure there is provided a method of rigging up intervention equipment in a lifting arrangement utilized on a floating vessel, and moving the intervention equipment between an inactive position and an operating position, wherein the method comprising: 
     a) providing the lifting arrangement with vertically extending guiding means capable of transferring a load to the lifting arrangement; 
     b) connecting a load transferring means to the guiding means; 
     c) connecting the intervention equipment to a load carrying device provided with displacement means arranged in a manner allowing a load to be horizontally displaced while carried by the load carrying device; 
     d) connecting the load carrying device to the load transferring means; 
     e) moving the intervention equipment from an inactive position to an operating position by moving the displacement means; and 
     f) moving the intervention equipment from the operating position to the inactive position by moving the displacement means. 
     In accordance with a second aspect of the present disclosure there is provided a carrier for bringing an intervention apparatus between an inoperative position and an operative position, the carrier being utilized in a lifting arrangement for operation on a floating vessel, the lifting arrangement being provided with vertically extending guiding means capable of transferring a load to lifting arrangement, wherein the carrier comprising:
         load transferring means connected to the guiding means:   a load carrying device capable of carrying the intervention apparatus, the load carrying device being provided with displacement means arranged in a manner allowing a load to be horizontally displaced while carried by the load carrying device,   locking means for fixing the load carrying device to the load transferring means.       

     The drilling vessel comprises a rig structure for carrying out well operations in a sub-sea well, and said rig structure comprises a primary heave compensation system connected to a load-bearing structure, such as a top drive, for supporting a tubular structure connected between the floating drilling vessel and the subsea well. For several types of operations performed in a subsea well the tubular structure is connected to the load bearing structure on the rig, such as a top drive, via a lifting arrangement such as an intervention frame which may be a tension frame or a backup heave compensation type frame as described in U.S. provisional application Ser. No. 61/480,239. For this type of operations, in a subsea well, it is typical to execute wireline and coiled tubing operations, where required equipment for such operations is installed inside the intervention frame. The disclosure herein describes an apparatus for transport and handling of equipment, such as coiled tubing equipment, in a lifting arrangement, such as an intervention frame, used on a floating vessel, providing an overall simplified setup for the intervention frame, which in turn results in safer and more time efficient installation and uninstallation of coiled tubing equipment inside the intervention frame. Further, said apparatus for transport and handling of equipment in a lifting arrangement on a floating vessel comprises:
         a stripper system transportation frame comprising functionality for simplified installation of coiled tubing equipment as described herein; and   a guide system installable on the intervention frame; and   a control system for operation of said apparatus.       

     Yet further, said stripper system transportation frame comprises:
         a rigid bottom frame section comprising a stripper system vertically extending jacking device and a pulling device, such as a coiled tubing stabbing winch; and   a rigid upper frame section comprising a rotatable horizontally extending transport system for equipment such as a coiled tubing injector head, suspension system, and a guide system locking mechanism;       

     Yet further, said guide system installable on the intervention frame comprises:
         rigid guides connected to the intervention frame; and   vertical transport system interfacing towards the guide system locking mechanism, part of the upper rigid frame section being part of the stripper system transport frame, free to move in the longitudinal direction of the rigid guides   a locking mechanism to secure the vertical transport system in various positions along the rigid guides;       

     Yet further, said control system comprises:
         components required to operate all functionality of the coiled tubing rigup system   components required to interface towards other control systems to ensure that the herein disclosure can be exploited in conjunction with any type intervention frame designated for the operations;   wherein all controllable components are connected to the control system; and   wherein the control system is structured in a manner allowing it to operated said apparatus for transport and handling of equipment so as to accommodate for operations simplifying processes required to install and uninstall coiled tubing equipment in intervention frames of any type utilized on a floating vessel.       

     In a preferred embodiment, said apparatus for transport and handling of equipment may comprise the stripper system transportation frame, further comprising the rigid bottom frame section, comprising a stripper system vertically extending jacking device and a pulling device, and the rigid upper frame section comprising a horizontally extending transport system, suspension system, and a guide system locking mechanism, where the rigid upper frame and said rigid bottom frame are locked to one another by means of a locking device, such as for example locking pins. The horizontally extending transport system may also comprise a turntable providing rotatable functionality, to ensure that equipment placed on the horizontally extending transport system, such as a coiled tubing injector head, can be rotated around a vertical axis to ensure a correct orientation of the coiled tubing injector head with respect to other devices such as coiled tubing extending from a coiled tubing reel on the deck to the coiled tubing injector head mounted on the turntable. 
     Furthermore, the stripper system may be connected to the stripper system vertically extending jacking device and secured therein by means of a mechanical interface which may be a quick connection device normally used to connect a stripper system to a coiled tubing BOP. 
     Moreover, the embodiment describes the apparatus for transport and handling of equipment in a transport position utilized to transport the apparatus from one location to another, where one location may be an onshore facility, and where another location may be a location on a floating vessel, such as the rig floor. 
     Further, to a preferred embodiment of the disclosure, said rigid guides may be connected to said lifting arrangement, such as an intervention frame of any type. 
     Furthermore, said vertical transport system, which may comprise an interface towards the guide system locking mechanism, being part of the upper rigid frame section which is part of the stripper system transport frame, and locking mechanism to secure the vertical transport system in various positions along the rigid guides, may be connected to the rigid guides in a predefined position. 
     Moreover, the facilitation of the rigid guides and said vertical transport system may be executed in any location, such as in an onshore facility, a floating vessel, or after the lifting arrangement is installed in the rig of a floating vessel. 
     The vertical transport system is typically split into as many vertical transport systems as the amount of rigid guides as defined by the amount of said tension legs. Alternatively, vertical transport systems may be connected to provide for one such vertical transport system, where the connection method is designed in a manner ensuring that the vertical transport system will not introduce an obstacle to equipment being moved horizontally, such as the stripper system. 
     In another embodiment of the disclosure, a coiled tubing injector head may be placed on top of the horizontally extending transport system, being part of the rigid upper frame section, which is part of the stripper system transportation frame, where the injector head comprises mechanical interfaces, such as funnels, which in turn match with opposing members, such as pins, being part of the horizontally extending transport system, whereupon the mechanical interface may be secured by means of locking pins. 
     Furthermore, the stripper system may be disengaged from the mechanical interface in bottom, which may be of a quick connection device normally used to connect a stripper system to a coiled tubing BOP, whereupon the stripper system may be lifted by means of operation of the vertically extending jacking device, such that the upper part of the stripper system may be connected to a predefined mechanical interface being part of the coiled tubing injector head. 
     Furthermore, the pulling device may be used to stab a coiled tubing into the coiled tubing injector head by means of extending a wire or chain from the pulling device through the inside of the stripper system, through the inside of the coiled tubing injector head, over the gooseneck, part of the injector head, and to the coiled tubing placed on a coiled tubing reel. The coiled tubing reel may be located on the deck of a floating vessel, where the wire or chain is connected to the end of the coiled tubing by means of a connection device, such as a stabbing connector. The pulling device may be used to pull the coiled tubing into the coiled tubing injector head in a controlled manner, whereupon the coiled tubing is engaged inside the coiled tubing injector head, the wire or chain is disengaged from the coiled tubing and stored back onto the pulling device. The coiled tubing may be extended to exit through the stripper system whereupon a securing device is attached to the coiled tubing to ensure that the coiled tubing cannot exit upwards through the stripper system and as such disengage from the coiled tubing injector head. 
     In a preferred embodiment of the disclosure, a wire or chain extending from a lifting device, such as a winch or hoist, being part of the intervention frame is attached to the lifting sling being part of the coiled tubing BOP, whereupon the coiled tubing BOP is lifted into the intervention frame and connected to the top of the x-over/adapter, extending from a said surface flow tree or wireline adapter into the tension frame by means of a connection device, such as a flanged connection. However, the connection device is not part of the herein disclosure and as such not explained in further detail. 
     Further to a preferred embodiment of the disclosure, the wire or chain extending from the winch or hoist, part of the intervention frame is attached to the lifting sling being part of the coiled tubing injector head. 
     Furthermore, the locking device enabling a mechanical lock between the rigid upper frame and said bottom frame, being part of the stripper system transport frame, is disengaged, such that upon lifting the coiled tubing injector head by means of operation of the lifting device part of the intervention frame, the rigid upper frame and said stripper system will be part of the load, whilst the rigid bottom frame will remain on the deck. It should be noted that the rigid upper frame is designed such that in this embodiment, where the stripper system is engaged with the coiled tubing injector head, the bottom part of the stripper system is situated above the bottom part of the upper rigid frame, and as such the load can be placed back onto the deck without engagement with the rigid bottom frame. This feature may be an advantage in terms of a situation requiring to land the load onto the deck without access to the rigid bottom frame, such as for example an emergency situation which may occur due to bad weather, malfunction of critical components, or any other cause. 
     Moreover, a load, which may be described to comprise the coiled tubing injector head, said rigid upper frame, and said stripper system, is lifted by means of operation of the lifting device part of the intervention frame, where the load is guided by means of operation of at least one lifting device part of the floating vessel rig, such as a tugger winch, engaged to the load by means of installing the wire from the at least one said tugger winch into at least one wire wheel device, such as a sheave wheel, attached to the load, whereupon the load can be guided by means of tension applied to the at least one said tugger winch. 
     Furthermore, as the load is lifted from the deck towards the intervention frame by means of operation of the lifting device part of the intervention frame, the load is continuously held back from the intervention frame by means of operation of the at least one said tugger winch, whereupon when the load is in correct height the load is guided towards the vertical transport system by means of operation of the at least one said tugger winch, until the load is engaged with the vertical transport system by means of engaging the guide system locking mechanism with the interface part of the vertical transport system. It should be noted that the suspension system may be used to facilitate a controlled engagement of the guide system locking mechanism, to limit movements and related impacts during the process described. From this position it may be necessary to extend the coiled tubing from the injector head to the deck of the floating vessel, where a coiled tubing end connector is connected to the coiled tubing. However, one skilled in the art will recognize that the coiled tubing end connector may be connected at an earlier time depending on the type used, but such devices are not part of the herein disclosure and as such not explained in further detail. 
     Furthermore to a preferred embodiment, the locking mechanism to secure the vertical transport system in various positions along the rigid guides may be disengaged and as such facilitate for vertical movement of the vertical transport system and hence the load by means of operation of the lifting device part of the intervention frame. Thus, said vertical movement described is executed in a guided manner preventing the load from horizontal movement as may be expected due to movements of the floating vessel as inflicted by the natural environment. Once the load is in a desired position vertically along the rigid guides, the locking mechanism for securing the vertical transport system in various positions along the rigid guides may be engaged. In one possible embodiment, the locking mechanism to secure the vertical transport system in various positions along the rigid guides may be activated and deactivated by means of operation of a device part of the rigid upper frame, further implying that such activation and deactivation devices and its required control conduits need not to be connected to the rigid guides or the vertical transport system. 
     Further to a preferred embodiment, another lifting device, such as a winch or hoist, being part of the intervention frame may be used to lift devices dedicated for purposes of the work in a well, such as bottom hole assemblies, used for the actual operation in a well, into the top of the coiled tubing BOP attached to the surface flow tree, which is further attached to the workover riser extending to and connected to equipment located on the seafloor, whereupon the bottomhole assembly is secured on top of the BOP by means of equipment normally utilized for this purpose. However, this equipment is not part of the herein disclosure and therefore not explained in further detail. 
     A bottom hole assembly may comprise several sections where following sections are lifted into and connected to the previous section former secured to the top of the BOP, by utilizing a second lifting device. Once the bottom hole assembly is complete the coiled tubing injector head attached to the stripper system may be horizontally displaced, by means of operation of the horizontally extending transport system, such that the center of the bore of the stripper system will match with the center of the bore of the well as represented by the coiled tubing BOP. Thereafter, the coiled tubing is attached to the bottomhole assembly by means of connecting the bottomhole assembly to the coiled tubing end connector. Thereafter, the locking mechanism for securing the vertical transport system in various positions along the rigid guides may be disengaged and as such facilitate for vertical movement of the vertical transport system. Hence, the coiled tubing injector head and said stripper system is lowered and connected to the coiled tubing BOP by means of operation of the chain or hoist part of the intervention frame. The connection between the coiled tubing BOP and said stripper system may be facilitated by a quick connection device normally used for such connections. At this point the coiled tubing equipment is installed into the intervention frame and operational sequences can be initiated. One skilled in the art will recognize that the above described procedure is reversed in a situation where it is required to uninstall the coiled tubing equipment. 
     Further to a preferred embodiment, in situations where it may become necessary to change the bottomhole assembly the quick connection is disengaged, whereupon the coiled tubing injector head and said stripper system is lifted by means of operation of the lifting device, part of the intervention frame. Then the locking mechanism to secure the vertical transport system in various positions along the rigid guides may be engaged. Thereafter, the bottomhole assembly is disconnected from the coiled tubing by means of disconnecting the bottomhole assembly from the coiled tubing end connector, whereupon the coiled tubing injector and said stripper system can be horizontally displaced into the rigid upper frame, by means of operation of the horizontally extending transport system. Whereupon, the bottomhole assembly can be lifted from the coiled tubing BOP to the deck of the floating vessel by means of operation of the another lifting device part of the intervention frame. Accordingly, a new bottomhole assembly can be installed in the same manner as explained above for the initial said bottomhole assembly and the injector head and said stripper system is connected to the BOP in the same manner as explained above. It should be noted that the same procedure may be repeated for yet a new bottomhole assembly and so on. It should be noted that one skilled in the art will recognize that the disconnection point may also be below the coiled tubing BOP for the operations described for a preferred embodiment the procedures described for changing from the bottomhole assembly to the new bottomhole assembly, and further for yet a new bottomhole assembly and so on, and as such the coiled tubing BOP would be attached to the stripper system, which in turn is attached to the coiled tubing injector head, which in turn is lifted by the lifting device part of the intervention frame. 
     In another embodiment of the disclosure, a control system is utilized to operate all functionality of the herein disclosure, further comprising the possibility to operate the functionality of the system from a local control panel and/or from a remote control panel. It should further be noted that the functionality described herein may be by electrical and or mechanical and or hydraulic means. 
     One skilled in the art will understand that the description of the control system, and also the operation of the lifting arrangement disclosed herein, is based on the use of one control system and method, but that several other control systems and methods can be utilized to achieve the same system functionality. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure will now be described by way of non-limiting embodiments, referring also to the accompanying figures, in which: 
         FIG. 1  illustrates a simplified example of one embodiment of the disclosed apparatus. 
         FIG. 2  illustrates examples of preferred general system features for a generalised embodiment of the disclosed apparatus. 
         FIG. 3  illustrates a rigid upper frame of the disclosed apparatus. 
         FIG. 4  illustrates a top view of the rigid frame described in relation to  FIG. 3 . 
         FIG. 5  illustrates a rigid bottom frame of the disclosed apparatus. 
         FIG. 6  illustrates a guide system of the disclosed apparatus. 
         FIG. 7-14  illustrates an operational setting of the disclosed apparatus. 
         FIG. 15  illustrates an upper guide system locking mechanism. 
         FIG. 16  illustrates a lower guide system locking mechanism. 
     
    
    
     The figures are somewhat schematic and only depict details and equipment necessary for the understanding of the disclosure. Moreover, the figures may be somewhat distorted with respect to relative dimensions of details and components shown therein. Furthermore, the figures are simplified with respect to the shape and richness in detail of such components and equipment shown therein. Hereinafter, equal, equivalent or corresponding details of the figures will be given substantially the same reference numbers. 
     Terms “horizontal”, “vertical”, “upper”, “lower”, “left”, “right” refers to the positions in the figures. 
     DETAILED DESCRIPTION 
       FIG. 1  illustrates an example of operating according to the disclosed apparatus. A drilling vessel is described only by important components such as a rig floor  101 , a drilling rig  105 , which further comprise various components  109  as required to operate and move a load-bearing unit, such as a top drive  108 , which is further connected to an elevator  106  via rigid bails  107 . Various components  109  further comprise a heave compensator as required to compensate vertical movement inflicted onto the drilling vessel by the waves of the sea. The heave compensator ensures that other equipment including top drive  108  and all equipment attached below the top drive  108  is maintained in a stationary position with required tension applied in accordance with accepted force applied to the equipment located on the seafloor, and hence avoid excessive tensional and compressive forces as the drilling vessel moves vertically up and down as a result of waves of the sea. It should be noted that various components  109  are not further explained herein as one skilled in the art will understand various methods, apparatuses and devices that exist to allow for functionality of such various components  109 , and further that these various methods, apparatuses and devices will not affect the execution of the herein disclosure.  FIG. 1  further illustrates how a tubular such as a workover riser  102  is connected to a surface valve arrangement such as a surface flow tree  103 , which in turn is connected to the top drive  108  on the drilling vessel via lifting arrangement  104 , such as an intervention frame as described herein. The lower end of the workover riser  102  is connected to equipment on the seafloor further defined as a lock to bottom situation, further meaning that all equipment in the stack comprising the workover riser  102 , surface flow tree  103 , intervention frame  104 , elevator  106 , rigid bails  107 , top drive  108 , and parts of various components  109  are in a stationary mode and hence will not move up and down in relation to the drilling vessel as inflicted by waves of the sea. Due to a heave compensation system part of various components  109 , excessive tensional and compressive forces as a result of vertical movement of the drilling vessel will not be inflicted onto the equipment subjected in a stationary mode as described above. To further describe the disclosure herein the intervention equipment  111  is installed into the intervention frame  104  by means of an apparatus for transport and handling of equipment in a lifting arrangement on a floating vessel. The functionality and preferred embodiments of apparatus  110  is further described in relation to  FIGS. 2-16 . 
       FIG. 2  illustrates an operational setting of the disclosed apparatus described herein. In  FIG. 2 , a possible embodiment of the apparatus is shown, where an intervention frame  104  is illustrated in an operational setting. In the operational setting the intervention frame  104  comprises a top interface sub  201 , which facilitates as a connection point towards the elevator  106  (shown in  FIG. 1 ), a top load bearing member  202 , typically a beam, a substantially vertical tensioning frame provided with at least two parallel guides, such as tension legs  204 , a lower load bearing member  211 , typically a beam, which comprise an interface  220  towards a x-over/adapter piece extending from a surface flow tree  103 , which in turn is connected to a workover riser  102 , extending to equipment located on the seafloor and connected thereto. Further, to the intervention frame  104 , lifting devices  221  and  213 , typically winches, are attached to the top beam  202 . With reference to  FIG. 2 , the embodiment illustrates coiled tubing equipment  111  installed inside the intervention frame  104 , where parts of the coiled tubing equipment  111  is installed and handled by means of an apparatus  110  according to the disclosure. The coiled tubing equipment  111  comprises a coiled tubing BOP  210 , connected to the x-over/adapter piece extending from a surface flow tree  103 , a stripper system  219  connected to the top of the BOP  210 , a coiled tubing injector  206  connected to the top of the stripper system  219 , a coiled tubing gooseneck  217  connected to the top of the injector head  206 , and coiled tubing  212  extending from a reel located on the deck of the floating vessel via the gooseneck  217 , the coiled tubing injector  206 , stripper system  219 , BOP  210  and into the well via the surface flow tree  103  and workover riser  102 , as relevant for an operational setting of the described coiled tubing equipment  111 . The apparatus  110  comprises rigid guides  203 , which may be mounted to the tension legs  204  or to the top beam  202  and lower beam  211 , vertical transport system  215 , rigid upper frame section  209 , further comprising a rigid frame  216 , a horizontally extending transport system  214 , and upper and lower guide system locking mechanisms  207  and  208  respectively. The rigid upper frame section  209  is also denoted “a load carrying device” and the vertical transport system  215  is also denoted “a load transferring means”. In combination the load carrying device  209  and the load transferring means  215  is said to constitute a carrier which constitutes a second aspect of the disclosure. 
     Further to the operational setting illustrated in  FIG. 2 , the weight of the coiled tubing injector head  206 , stripper system  219 , BOP  210  is directed to the tension frame  104  via the x-over/adapter piece, extending from the surface flow tree  103 , which is mechanically attached to the intervention frame by means of the interface  220 . A hook and wire assembly  218  extending from the winch  221  is attached to the coiled tubing injector head sling  205  for providing double security. One skilled in the art will recognize that  FIG. 2  illustrates one possible embodiment of the described operation and further that components may comprise any form or shape not apparently described in the figure. 
       FIG. 3  illustrates a side view of the rigid upper frame section  209  of the disclosure. The upper frame section  209  comprises: a rigid frame structure  216 ; a horizontally extending transport system  214 ; an upper guide system locking mechanism  207 ; a lower guide system locking mechanism  208 ; and horizontally extending members  302 , such as hydraulic cylinders. In  FIG. 3  is also shown a suspension system  301 , such as hydraulic dampeners. The suspension system  301  further comprises engagement devices  305  being shaped to ensure a dedicated engagement towards an opposing member such as the rigid guides  203 , vertical transport system  215 , and tension legs  204  shown in  FIG. 2 , or any other component which may function as an opposing member for the engagement devices  305 . Furthermore, the rigid upper frame section  209  comprises a horizontally extending transport system  214 , further comprising guide pins  303 , which are designed to interface towards guide funnels being part of the coiled tubing injector  206  shown in  FIG. 2 . The horizontally extending transport system is attached to the hydraulic cylinders  302  via connecting member  304 , and as such horizontal displacement of the transport system  214  is facilitated by operation of cylinders  302 . One skilled in the art will recognize that the transport system  214  must be designed in a manner bearing the loads introduced by coiled tubing equipment  111  previously described and further that a load bearing interface is required in the rigid frame  216  to ensure that the forces generated by the loads carried are transferred to the rigid frame  216 . 
       FIG. 4  illustrates a top view of a rigid upper frame section  209  previously described in relation to  FIG. 3 . This view further illustrates that the frame  209  is designed in a manner providing an opening  401  to facilitate for horizontal movement of the transport system  214  carrying equipment such as a coiled tubing injector head  206  attached, which in turn is attached to the stripper system  219 . It should be noted that the opening  401  is towards the same direction as will be for the intervention frame respective of the rigid upper frame section  216 . 
       FIG. 5  illustrates a rigid lower frame section  501  comprising: a frame  502 ; guide pins  504 , which are designed to interface towards guide funnels part of the rigid frame  216 . The frame  501  further comprises a pulling device  503 , such as a coiled tubing stabbing winch, a vertically extending jacking device  505  comprising an interface  506  towards a quick connection device typically utilized for connecting a stripper system to a BOP  210 , such that a stripper system  219  can be landed and secured onto the vertical extending jacking device  505  by means of the interface  506 . 
       FIG. 6  illustrates one possible embodiment for the rigid guides  203  and the vertical transport system  215  indicated in  FIG. 2 . For the illustrated embodiment the rigid guide  203  is attached to a tension leg  204  by means of connection interfaces  603 , and further comprises: a funnel shaped top portion  601  to accommodate for one possible method of installing the vertical transport system  215 ; an end stop device  609  to prevent the vertical transport system  215  from exiting in the lower part of the guide  203 ; locking mechanism interfaces  602  to accommodate for engagement of locking mechanism  610  forming part of the vertical transport system  215 . The vertical transport system  215  comprising: a load bearing structure  606 ; an upper guide system locking mechanism interface  605 ; a lower guide system locking mechanism interface  607  which interface towards guide system locking mechanisms  207  and  208  part of the rigid upper frame section  209  respectively; an upper low friction guide  604 ; a lower low friction guide  608 , further comprising a locking mechanism  610 , which is designed to engage with any of the locking mechanism interfaces  602 , and as such facilitate for a possibility to park the vertical transport system  215 . Hence, the coiled tubing injector head  206  and stripper system  219 , in any position as defined by the locking mechanism interfaces  602  along the length of the rigid guides  203 . In  FIG. 6 , the locking mechanism  610  is illustrated as part of lower low friction guide  608 . However, one skilled in the art will recognize that the locking mechanism  610  may be a part of upper low friction guide mechanism  604 , rigid guides  203 , or other sections of the vertical transport system  215 . 
       FIGS. 7-14  illustrates operational steps utilizing the disclosed method and system described herein. 
       FIG. 7  illustrates a stripper system transport frame  706  comprising: a rigid lower frame section  501 , as described in relation to  FIG. 5 ; a rigid upper frame section  209 , as described in relation to  FIGS. 3 and 4 ; locking mechanisms  705 , utilized to engage the rigid upper frame section  209  to the rigid lower frame section  501 ; a stripper system  219  comprising: a quick connection device  701  interfacing towards typical quick connection devices utilized to connect a stripper system  219  to a BOP  210 ; a lower stripper  702 ; an upper stripper  703 ; and an injector head interface  704 , typically shaped as a drip tray for a coiled tubing injector head  206 , and further interfaced towards an injector head  206  by means of locking bolts. The embodiment in  FIG. 7  illustrates the stripper system transport frame  706  being utilized as a means for transport the stripper system  219  from one location to another such as for example from an onshore facility to a floating vessel, whereby the stripper system transport frame  706  may be placed on the rigfloor  101  of the floating vessel. 
       FIG. 8  illustrates the step following placement of the stripper system transport frame  706  in a location on the floating vessel dedicated to installation of the coiled tubing equipment into an intervention frame  104 , such as a rigfloor  101 . With reference to  FIG. 8 , a coiled tubing injector head  206  is installed onto the horizontally extending transport system  214 , part of a stripper system transport frame  706 , by interface between funnels part of the bottom of the injector head frame structure and guide pins  303 , whereupon the injector head  206  is locked onto the transport system  214  by means of locking mechanisms  801 . One skilled in the art will recognize that the funnels part of the bottom of the injector head frame is commonly utilized for the purpose described herein and hence such functionality is not described in further detail. 
       FIG. 9  illustrates the step following placement of the injector head  206  onto the stripper system transport frame  706 , where the stripper system  219  is lifted by means of operation of the vertically extending jacking device  505 , until the injector head interface  704  can be engaged with opposing part of the injector head  206 . The vertically extending jacking device  505  may be operated by means of a mechanical and/or hydraulic and/or electrical operation. 
       FIG. 10  illustrates the step following engagement of the stripper system  219  towards the injector head  206 . For this step the quick connection device  701 , which is part of the stripper system  219 , is disconnected from the opposing member  506  being part of the vertically extending jacking table  505 , which in turn is lowered to create an access window between the two quick connection components  701  and  506  respectively, whereupon a bundle of conduits  1004 , comprising conduits for control and monitoring of all functionality related to the coiled tubing injector head  206 , stripper system  219 , stripper system transport frame  706 , and vertical transport system  215 , is connected. A wire  1001  is extended from the stabbing winch  503  via a guide  1002 , such as a sheave wheel, stripper system  219 , injector head  206 , gooseneck  217  and down to a coiled tubing reel placed on the deck of the floating vessel, where a pulling connection  1003 , such as a stabbing connector is connected to the coiled tubing  212 , whereupon the coiled tubing  212  is pulled over the gooseneck  217 , and into the injector head  206  and stripper system  219  by means of operation of the stabbing winch  503 . It should be noted that one skilled in the art will recognize that the bundle of conduits  1004  may be connected to the injector head  206 , and/or rigid upper frame section  209 , and/or stripper system  219 , or by any practical means, and further that preparation of conduits between components may be executed as practical by means of common practice as related to conduits for control and monitoring of the mentioned functionality. 
       FIG. 11  illustrates the step following the stabbing of the coiled tubing  212  into the injector head  206  and stripper system  219 , whereupon the coiled tubing  212  is secured below the stripper system  219  by means of a securement device  1104 , further preventing the coiled tubing  212  from exiting through the stripper system  219 . A guide system  1101 , such as a rig tugger wire is attached to a fixed point  1103 , which may be at the rigfloor  101 , and to the injector head  206  by means of guide  1102 , such as a sheave wheel. The wire and hook  218  extending from the winch  221  (see  FIG. 2 ) is attached to the injector head sling  205 . The locking mechanism  705  is disengaged to release the rigid upper frame section  209  from the rigid lower frame section  501 , whereupon the injector head  206  and rigid upper frame section  209  is lifted off deck by means of operation of the winch  221 , as the load is guided by a mount of tension applied to the rig tugger wire  1101 , and the coiled tubing  212  is allowed to follow the lift by manipulation of the coiled tubing reel placed on deck of the floating vessel. 
       FIG. 12  illustrates the step following lifting the injector head  206  and the rigid upper frame section off deck, where the described load is guided by means of tension applied to the tugger winch wires  1101  as the load is lifted to an elevation similar to the position of the vertical transport system  215 , preinstalled onto the rigid guides  203 , preinstalled onto the tension legs  204 , whereupon the load is landed onto the vertical transport system  215  such that the upper guide system locking mechanism interfaces  605  and lower guide system locking mechanism interfaces  607 , engage and secure with the guide system locking mechanisms  207  and  208  part of the rigid upper frame section  209  respectively. The suspension system  301  may be used to accommodate for a dedicated engagement of the opposing members. Typically the vertical transport system  215  is secured to a predefined position by means of activated locking mechanism  610  prior to engaging the rigid upper frame section  209  to the transport system  215 . The coiled tubing  212  is extended to the deck of the floating vessel where the securement device  1104  is removed and a coiled tubing end connector  1201  is attached to the end of the coiled tubing  212 , whereupon the coiled tubing  212  is retracted such that the end connector  1201  is place near or inside the stripper system  219 . 
       FIG. 13  illustrates the step following the engagement of the rigid upper frame section  209  to the vertical transport system  215 , where the locking mechanism  610  is disengaged, whereupon the injector head  206 , rigid upper frame section  209 , and stripper system  219  is lifted to a new elevated position, by means of operation of winch  221  connected to wire and hook  218 , further connected to the injector head sling  205 , where locking mechanism  610  is engaged. Tools intended for work in the well  1302 , such as sections of bottom hole assemblies are lifted and installed into top of the BOP  210 , by use of winch  213  attached to wire and hook  1301 , whereupon the bottomhole assembly sections  1302  are secured to the top of the BOP  210  by means of securing devices typically utilized for such operations. In situations requiring more than one section of bottomhole assemblies  1302 , a following section is typically connected to the previous section at the top level of the BOP  210 , whereupon the new length of bottom hole assembly is lowered into the workover riser  102 , whereupon the top of the bottomhole assembly is secured to the top of the BOP  210  by use of devices typically utilized for such operations. 
       FIG. 14  illustrates the step following installation of sections of bottomhole assemblies  1302  into the BOP  210 , where the coiled tubing injector head  206  and stripper system  219  is horizontally displaced such that the center is lined up with the center of the BOP  210 , whereupon the coiled tubing  212  is extended lowered towards the top of the bottom hole assembly  1302  and connected thereto by means of the coiled tubing end connector  1201 , whereupon the stripper system  219  and coiled tubing injector head  206  are lowered towards the BOP  210 , by means of disengaging locking mechanism  610  and operation of winch  221  attached to wire and hook  218  further attached to injector head sling  205 , whereupon the quick connection device  701  is connected to an opposing member part of the BOP  210 . The system is now installed and an operation in a well may commence. 
       FIG. 15  illustrates a possible embodiment for the upper guide system locking mechanism interface  605  and guide system locking mechanisms  207 . A hook shaped member  1501  is part of the guide system locking mechanism  207  and a slot shaped member  1502  is part of the upper guide system locking mechanism  605 , where the hook shaped member  1501  comprise a recess  1504  which is designed to interface with a pocket  1505  part of the slot shaped member  1502 , which further comprises a funnel shaped opening  1503  in top to facilitate for easy entry for the hook shaped member  1501 , whereupon full engagement the members  1501  and  1502  accommodates for a connection ensuring structural strength and limited movement as defined by requirements to weight and forces related to the equipment, natural environment, and embodiments described herein. 
       FIG. 16  illustrates a possible embodiment for the lower guide system locking mechanism interface  607  and guide system locking mechanism  209 . A slot shaped member  1601  is part of the guide system locking mechanism  208  and an opposing shaped member  1602  is part of the guide system locking mechanism interface  607 , where the opposing shaped member comprises a guide  1603 , which further comprises a locking bolt hole  1604 . The slot shaped member comprises a funnel shaped opening  1605  in the bottom to facilitate easy entry for the opposing shaped member  1602 , and furthermore the slot shaped member comprises a recess shaped in accordance with the guide  1603 , which upon engagement may be secured by means of locking mechanism  1606 , whereupon full engagement the members  1601  and  1602  accommodate a connection ensuring structural strength and limited movement as defined by requirements to weight and forces related to the equipment, natural environment, and embodiments described herein. 
     Finally, the descriptions and drawings presented herein only represent examples of embodiments related to the disclosure. Further, any concept, system and method as well as combination(s) of concept(s), system(s) and method(s) described in any text or figure herein could be extended to apply in conjunction or combination with other concepts, systems and methods described in the art. All combinations of concepts, systems and/or methods also comprise part of the objective of the disclosure. All interfacing, combination and utilization with existing equipment, techniques and methods also comprise part of the disclosure.

Summary:
A method and an apparatus for rigging up intervention equipment ( 111 ) in a lifting arrangement ( 104 ) utilized on a floating vessel, and moving the intervention equipment between an inoperative and an operative position, wherein the method comprising: a) providing the lifting arrangement ( 104 ) with vertically extending guiding means ( 203 ) capable of transferring a load to the lifting arrangement; b) connecting a load transferring means ( 215 ) to the guiding means ( 203 ); c) connecting the intervention equipment ( 111 ) to a load carrying device ( 209 ) provided with displacement means ( 214 ) arranged in a manner allowing a load to be horizontally displaced while carried by the load carrying device; d) connecting the load carrying device ( 209 ) to the load transferring means ( 215 ); e) moving the intervention equipment from an inactive position to an operating position by moving the displacement means ( 214 ); and f) moving the intervention equipment from the operating position to the inactive position by moving the displacement means ( 214 ).