GB2620483A

GB2620483A - Modular well tubular handling system and method of use

Info

Publication number: GB2620483A
Application number: GB2306964.4A
Authority: GB
Inventors: Vollmar Dennis
Original assignee: Individual
Current assignee: Individual
Priority date: 2022-05-11
Filing date: 2023-05-11
Publication date: 2024-01-10
Also published as: GB202306964D0; WO2023217991A1

Abstract

A modular rig system comprising two or more modules, each module comprising at least one rig system component. The two or more modules are configured to be connected or interconnected together to form an integrated structure. Preferably, the modules comprise a frame wherein the frames of the modules assemble to form the integrated structure. Preferably, the modules can be arranged in different configurations by adding or removing at least one module from the integrated structure depending on the wellbore operation. Also described is a method of configuring the modular rig system, wherein the two or more modules are assembled in a first configuration to form the integrated structure to perform a first well operation. Also described is a method of operating the modular rig system, wherein the two or more modules are assembled in a first configuration to form the integrated structure to perform a first well operation, and wherein the modules are reconfigured to form a second configuration to perform a second well operation.

Description

1 Modular Well Tubular Handling System and Method of Use 3 The present invention relates to systems and methods of lifting, lowering and/or handling 4 tubular members in a well, and in particular to but not limited to a system for lifting, lowering and/or handling tubulars during running in, pulling out, drilling, milling, workover, 6 completion and/or decommissioning operations.

8 Background to the invention

During well drilling and workover operations, tubular lifting, lowering and handling is 11 required to install, raise, lower and/or remove tubulars in or from a well. During well drilling, 12 as a drill bit extends deeper into the well, further sections of drill pipe are attached to the 13 drill string.

During the lifespan of the well, workover operations may be required to revitalise ageing 16 wells to bring them back online to extend production. In workover operations, tools and 17 equipment are inserted into a well to perform downhole tasks. The workover operations 18 include running tubular, wireline, slickline, cutting tools, cementing operations, pumping 19 equipment, and various fishing and re-entry services. Typically tools and equipment are run in and pulled out of the well using a workover jacking unit.

22 Wells which are no longer used are decommissioned to be made safe. During 23 decommissioning operations, large diameter pipes are slowly removed from the well 24 before the well is sealed. Conventionally, this is performed by a jacking unit with grippers which attach to a pipe and slowly pull the pipe out of the well.

27 Conventional tubular member handling systems are specific for each individual operation 28 or task. This may present problems as there are space limitations associated with platform 29 rigs and may create complex planning operations.

31 Conventional systems also lack flexibility to deal with changing operational requirements 32 driven by the age of the rig, well or platform. These may cause different offshore 33 infrastructure conditions such as; downgraded crane capacity, reduced skid beam loading 34 capacity, available rig footprint, unknown well status and/or changing well conditions and of drilling/ operational requirements. This may result in significant rig down time whilst 1 suitable individual equipment packages for each operational phase can be obtained and 2 installed on the rig to adapt to a different operation phase or specific well or rig condition.

3 This may also result in increased costs to mobilize large heavy units to deal with all well- 4 related uncertainties.

6 Summary of the invention

8 It is an object of at least one aspect of the present invention to obviate or at least mitigate 9 the foregoing disadvantages of prior art tubular lifting and handling systems.

11 It is another object of an aspect of the present invention to provide a modular wellbore 12 tubular lifting system with improved productivity and/or efficiency which may be capable of 13 reliably performing a range of tubular member lifting and handling tasks over a wide range 14 of operations.

16 It is an object of an aspect of the present invention to provide a modular wellbore tubular 17 lifting system which is compact, mobile and transfigurable to adapt to a wide range of well 18 operations and conditions.

It is another object of an aspect of the present invention to provide a lifting system for a 21 modular wellbore tubular lifting system which may be capable of reliably performing a 22 range of lifting tasks over a wide range of operations.

24 A further object of at least one aspect of the present invention is to provide a lifting system that is capable of improving the performance of a modular rig system in which the lifting 26 system is deployed.

28 It is another object of an aspect of the present invention to provide a robust, reliable, 29 sturdy lifting system suitable for deployment in a wide range of well operations which is capable of rapid tripping speeds and continuous rotary function.

32 It is a further object of an aspect of the present invention to provide a system with at least 33 two lifting systems which may provide a multi-redundant lifting or hoisting system.

1 It is an object of an aspect of the present invention to provide a system capable of 2 controlling the transfer of hydraulic fluid between one module and at least another module 3 to divert, recycle and/or reuse hydraulic fluid, pressure and/or power.

It is another object of an aspect of the present invention to provide a system capable of 6 controlling the transfer of hydraulic fluid between one lifting system and another lifting 7 system to divert, recycle and/or reuse hydraulic fluid, pressure and/or power and/or adjust 8 the available hoisting load capacity.

Further aims and objects of the invention will become apparent from reading the following

11 description.

13 According to a first aspect of the invention, there is provided a modular system for lifting 14 and/or lowering a tubular in wellbore operations, the system comprising: at least one module, wherein the at least one module is configured to be removably 16 connected to at least one other module to form an integrated structure substantially above 17 a wellbore.

19 The at least one module may comprise a frame. The frame of the at least one module may be configured to be removably connected to the at least one other module to form an 21 integrated structure above a wellbore. The at least one module may be at least one 22 functional module. The at least one module may be prefabricated. The at least one module 23 may be ready for assembly into an integrated structure on a rig, platform, floor and/or 24 deck. The rig, platform, floor and/or deck may be offshore or onshore. The modular system may be suitable for application to a wide range of types and sizes of rig, platform, floor 26 and/or deck. The integrated structure may be assembled on site. The well may be a 27 hydrocarbon well, a geothermal well or a carbon capture storage well. The modular system 28 may be a modular rig system or part of a rig system. The at least one module may be 29 configured to be transported and/or stored separately. The at least one module may be conveniently transported to a rig, platform and/or vessel deck. The system may be 31 removably secured to a rig, platform and/or deck of a vessel. The integrated structure may 32 be assembled offsite and mounted above the wellbore as a single unit. The frame of the at 33 least one module may be a load-bearing structure. The integrated structure may be a load- 34 bearing structure. Any loads acting on the at least one module may be distributed through a base support, the frame and/or integrated structure. Any loads acting on the at least 1 one module may be directly transferred to a base support, the frame and/or integrated 2 structure. The at least one module may be further divided into one or more sub-modules.

3 The one or more sub-modules may be configured to operate independently from one 4 another.

6 The system may comprise two or more modules. The two or more modules may be 7 functional modules. The system may comprise a plurality of modules. Each module may 8 comprise a frame. The frames of the two or more modules may be assembled together to 9 form the integrated structure. At least one modules may be assembled in a first configuration to perform one or more tasks in a first wellbore operation. At least one 11 module may be assembled in a second configuration to perform one or more tasks in a 12 second wellbore operation. Two or more modules may be re-configured and/or re- 13 assembled together in a different arrangement depending on the wellbore operation. At 14 least one module may be added and/or removed to perform a wellbore operation or part of a wellbore operation, depending on the wellbore operation. The modular system may be 16 transfigurable or reconfigurable. The system may be transfigurable or reconfigurable 17 between a first wellbore operation mode in which the at least one module in the system is 18 arranged in a first configuration and a second wellbore operation mode in which the at 19 least one module of the system is arranged in a second configuration. The position of the at least one module in the integrated structure may be interchangeable with at least one 21 other module in the integrated structure. The modules may be interconnectable. The 22 control and/or communication connections of each function module may be through 23 standardised interfaces.

The two or more modules may be arranged in series. The two or more modules may be 26 arranged in series surrounding or partially surrounding a wellbore. The integrated structure 27 may comprise a plurality of modules arranged in a stacked arrangement. The stacked 28 arrangement may be a horizontal stacked arrangement. The stacked arrangement may be 29 a vertical stacked arrangement. The two or more modules may be arranged in an abutting vertically stacked relationship. At least one module may be arranged in an abutting 31 horizontally side-by-side arrangement. The two or more modules may be arranged in a 32 combination of a vertical stack with at least one module branching off in a horizontally 33 side-by-side arrangement. The two or more modules may be mounted or connected in a 34 vertical and/or horizontal offset arrangement. The tubular may be selected from the group comprising: pipe, drill pipe, drill collars, conductor; reamers, shouldered pipe, risers, 1 production pipe, composite pipe, well casing, utility line, wireline, slickline, coiled tubing 2 and/or work over equipment.

4 The system may comprise two or more modules. The two or more modules may be configured to operate independently from one another. The two or more modules to move 6 and/or operate sequentially, synchronised, alternating, overlapping and/or staggered.

7 The wellbore operation may be selected from the group comprising installation of pipe, 8 drill pipe, drill collars, reamers, shouldered pipe, risers, production pipe, composite pipe, 9 well casing, utility line, wireline, slickline and/or work over equipment. The wellbore operation may be selected from the group comprising removal of: pipe, drill pipe, drill 11 collars, reamers, shouldered pipe, risers, production pipe, composite pipe, well casing, 12 utility line, wireline, slickline and/or work over equipment. The wellbore operation may be a 13 running in, pulling out, drilling, milling, workover, completion and/or decommissioning 14 operation.

16 The at least one module may be selected from the group comprising; lifting module, crane 17 module, jib crane module, iron roughneck, platforms, platform walkway, pipe deck, stairs, 18 stair tower, transverse substructure, trip tank, jacking frame, fingerboard, service 19 container, catwalk, slip assembly, top drive assembly, elevator assembly, lubricator system, mast; support mast; monkey arm, racker, radial racker, BOP module, base frame, 21 diamond cutter, skidding system, BOP substructure, driller cabin, motor control centre 22 sub-structure, bell nipple frame, pipe handling module and/or tubular storage module. The 23 system may comprise bridge and/or automation packages. The at least one platform may 24 be an open or closed platform. The size and/or height of installation of the at least one platform may depend on the operation. The at least one platform may be a telescopic or 26 extendable platform, The at least one platform may comprise a telescopic or extendable 27 section at the front enabling access to the moving platform.

29 The at least one module may comprise at least one lifting module. The at least one lifting module may comprise at least one lifting mechanism. Each lifting module may comprise 31 two or more lifting mechanisms. The at least one lifting module may comprise a movable 32 platform. The movable platform may be configured to move in a substantially vertical 33 direction by the at least one lifting mechanism. The movable platform may be a moving 34 table, a moving platform and/or a load beam. The at least one lifting module may comprise a stationary member. The at least one lifting mechanism may be mounted between the 1 movable platform and the stationary member. The stationary member may be a stationary 2 platform. The at least one lifting mechanism may be configured to move the movable 3 platform vertically relative to the position of the stationary member. The at least one lifting 4 mechanism may be configured to move the movable platform up and/or down vertically towards and/or away from the stationary member. The movable platform may comprise at 6 least one tubular gripper apparatus. The movable platform may comprise a slip assembly.

7 The slip assembly may be configured to selectively grip at least one tubular. The slip 8 assembly may be configured to selectively grip at least one section of a tubular string. The 9 movable platform may comprise a top drive assembly.

11 The at least one lifting module may comprise at least one iron roughneck. The at least one 12 iron roughneck may be configured to selectively and/or sequentially grip at least one 13 connection joint of a tubular member. The at least one iron roughneck may be configured 14 to make up or break joint between a tubular member and a tubular string. The iron roughneck may be positioned on the movable platform. The iron roughneck may be 16 positioned on a stationary platform. The iron roughneck may be positioned above the slip 17 assembly. The iron roughneck may be configured to move parallel to one of the lifting 18 system. The iron roughneck may comprise at least one jaw member. The at least one jaw 19 member may be configured to grip a tubular member. The at least one jaw member may be configured to grip at least a section of a tubular member. The at least one lifting module 21 may be configured to sequentially grip, lift and release a tubular member. The at least one 22 lifting module may be a lower or base module. The at least one lifting module may be 23 mounted on or to a lower or base module. The at least one lifting module may be an upper 24 module.

26 The at least one lifting mechanism may be selected from the group comprising a jack 27 system, screw jack, hydraulic cylinder, pulley system, rack and pinion system, linear motor 28 or any other lifting device. The at least one lifting mechanism may be configured to pull a 29 tubular member out of the well or push a tubular member into a well. The lifting mechanism may be configured to pull a section of a tubular out of the well or push a 31 section of a tubular into a well. The lifting mechanism may be configured to pull a tubular 32 out of the well or push a tubular into a well. The lifting mechanism may be a dual action 33 mechanism. The lifting mechanism may be configured to provide a lifting or pulling force in 34 a first mode. The lifting mechanism may be configured to provide a lowering or pushing force in a second mode. The lifting mechanism may be configured to provide a lifting or 36 pulling force in a substantially upward or uphole direction in a first mode. The lifting 1 mechanism may be configured to provide a lowering or pushing force in a substantially 2 downward or downhole direction in a second mode. The at least one module may 3 comprise at least one pipe handling module. The pipe handling module may comprise an 4 elevator or gripper. The pipe handling module may comprise a crane system. The at least one pipe handling module may comprise at least one component of pipe lifting equipment.

6 The at least one component of pipe lifting equipment is configured to lift a pipe section 7 accommodated on a rack of a pipe storage module.

9 The system may comprise two or more lifting modules. The two or more lifting modules may be configured to move and/or actuate independently. The two or more lifting modules 11 may be configured to move and/or actuate sequentially, synchronised, alternating, 12 overlapping and/or staggered. The two or more lifting modules may be a dual action 13 mechanism. The two or more lifting modules may be a dual action mechanism adding the 14 full capacity of both lifting systems regarding speed and load. The two or more lifting modules may be hydraulically connected with each other to re-use working fluids from one 16 lifting system to the other. The two or more lifting modules may be configured to transfer 17 lifting and/or lowering of a tubular between the two or more lifting modules. The two or 18 more lifting modules may be configured to handover a tubular between the modules. In a 19 tubular lifting configuration, a first lifting module may be configured to lift a tubular a first distance. A second lifting module may be configured to lift the tubular a second distance.

21 In a tubular lowering configuration, a second lifting module may be configured to lower a 22 tubular a first distance. A first lifting module may be configured to lower the tubular a 23 second distance. The system may be configured for continuously and/or automatic 24 tripping. The first lifting module and second lifting module may be configured to handover a tubular between the first lifting module and second lifting modules. The first lifting module 26 and second lifting module may be configured to transfer a load between the first lifting 27 module and second lifting modules. The first lifting module may be configured to transfer a 28 load acting the first lifting module directly to a support or base structure. The second lifting 29 module may be configured to transfer a load acting the second lifting module directly to a support or base structure. This may mitigate loads acting the on the second lifting module 31 being transfer through the first lifting module to the base structure.

33 The second lifting module may comprise a top drive assembly and/or an elevator system.

34 The first lifting module may be a lower lifting module. The second lifting module may be an upper lifting module. Each of the two or more lifting modules may be configured to 1 sequentially grip, lift, and release a tubular member. The first lifting module may be a lower 2 or base module. The first lifting module may be mounted on or to a lower or base module.

3 The second lifting module may be an upper module.

The system may comprise two or more lifting mechanisms. The two or more lifting 6 mechanisms may be configured to move and/or actuate independently. The two or more 7 lifting mechanisms may be configured to move and/or actuate sequentially, synchronised, 8 alternating, overlapping and/or staggered. The two or more lifting mechanisms may be a 9 dual action mechanism. The two or more lifting mechanisms may be a dual action mechanism adding the full capacity of both lifting systems regarding speed and load. The 11 two or more lifting mechanisms may be hydraulically connected with each other to re-use 12 working fluids from one lifting system to the other. The two or more lifting mechanisms 13 may be configured to transfer lifting and/or lowering of a tubular between the two or more 14 lifting mechanisms. The two or more lifting mechanisms may be configured to handover a tubular between the mechanisms. In a tubular lifting configuration, a first lifting mechanism 16 may be configured to lift a tubular a first distance. A second lifting mechanism may be 17 configured to lift the tubular a second distance. In a tubular lowering configuration, a 18 second lifting mechanism may be configured to lower a tubular a first distance. A first lifting 19 mechanism may be configured to lower the tubular a second distance. The system may be configured for continuously and/or automatic tripping. The first lifting mechanism and 21 second lifting mechanism may be configured to handover a tubular between the first lifting 22 mechanism and second lifting mechanism. The first lifting mechanism and second lifting 23 mechanism may be configured to transfer a load between the first lifting mechanism and 24 second lifting mechanism. The first lifting mechanism may be configured to transfer a load acting the first lifting mechanism directly to a support or base structure. The second lifting 26 mechanism may be configured to transfer a load acting the second lifting mechanism 27 directly to a support or base structure. This may mitigate loads acting the on the second 28 lifting mechanism being transferred through the first lifting mechanism to the base 29 structure. The first lifting mechanism may be a lower lifting mechanism. The first lifting mechanism may be a lower or base module. The second lifting mechanism may be an 31 upper lifting mechanism. Each of the two or more lifting mechanism may be configured to 32 sequentially grip, lift, and release a tubular member. The first lifting mechanism may be 33 mounted on or to a lower or base module. The second lifting mechanism may be an upper 34 module. The first lifting mechanism and the second lifting mechanism may be located in or on the same lifting module.

1 The system may comprise a control system. The control system may be configured to 2 control the positioning and/or actuation of the at least one module of the system. The 3 control system may be configured to control the positioning and/or actuation of at least one 4 component of the at least one module of the system. The control system may be configured to control the positioning and/or actuation of at least one a lifting mechanism, 6 iron roughneck, slip assembly, top drive assembly, crane system, elevator assembly, 7 lubricator handling system, monkey arm and/or pipe handling apparatus.

9 The control system may be configured to control the position and/or actuation of a first lifting module and/or a second lifting module. The control system may be configured to 11 control a sequential, synchronised, alternating, overlapping and/or staggered movement or 12 actuation of the first lifting module and second lifting module relative to one another.

13 The two or more lifting modules may be arranged in a stacked configuration with one lifting 14 module located above another lifting module. The stacked two or more lifting modules may facilitate continuous well bore operations. The stacked two or more lifting modules may 16 facilitate continuous tripping, drilling and/or milling operations. The control system may be 17 configured to control a sequential, synchronised, alternating, overlapping and/or staggered 18 movement or actuation of the first lifting mechanism and second lifting mechanism relative 19 to one another. The two or more lifting mechanisms may be arranged in a stacked configuration with one lifting mechanism located above another lifting mechanism. The two 21 or more lifting mechanisms may be arranged in one lifting module. The two or more lifting 22 mechanisms may be located in one lifting module arranged in side by side configuration.

23 The two or more lifting mechanisms may facilitate continuous well bore operations. The 24 two or more lifting mechanisms may facilitate continuous tripping, drilling and/or milling operations. The storage module may comprise one or more racks for accommodating a 26 plurality of tubular member sections. Each of the modules may comprise a rig component.

27 The at least one module may be connected or interconnected together to form a modular 28 system with the functionality of a rig. The modular system may be an offshore or onshore 29 modular rig.

31 According to a second aspect of the invention, there is provided a well comprising a 32 modular system according to the first aspect of the invention installed around and/or above 33 the well.

1 Embodiments of the second aspect of the invention may include one or more features of 2 the first aspect of the invention or its embodiments, or vice versa.

4 According to a third aspect of the invention, there is provided a modular wellbore tubular lifting system, the system comprising: 6 two or more functional modules; 7 wherein each functional module has a frame; 8 wherein the frames of the two or more functional modules are configured to be removably 9 connectable to one another to form an integrated structure.

11 The frame of the at least one functional module may be load-bearing. The integrated 12 structure when it is assembled may be configured to distribute loads acting on a frame of 13 the at least one the functional module.

Embodiments of the third aspect of the invention may include one or more features of any 16 of the first or second aspects of the invention or their embodiments, or vice versa.

18 According to a fourth aspect of the invention, there is provided a modular system for 19 movement of tubulars into or from a well; the system comprising: at least one module configured to be assembled into one or more configurations; 21 wherein the system is configured to be transfigurable between a first well operation mode 22 wherein one or more modules is arranged in a first configuration; 23 and a second well operation mode wherein one or more module is arranged in a second 24 configuration.

26 The one or more modules may be arranged in a first stacked or ordered configuration in 27 first well operation mode. The one or more modules may be arranged in a second stacked 28 or ordered configuration in second well operation mode. The stack or order of the one or 29 more modules may be different in the first and second well operation modes. At least one or more modules may be different in the first and second well operation modes. The well 31 operation may be a hydrocarbon well operation, a geothermal well operation or a carbon 32 capture storage well operation. The at least one module may be selected from the group 33 comprising lifting module; crane module; BOP module; pipe handling module and/or 34 tubular storage module.

1 Embodiments of the fourth aspect of the invention may include one or more features of 2 any of the first to third aspects of the invention or their embodiments, or vice versa.

4 According to a fifth aspect of the invention, there is provided a method of installing modular wellbore tubular lifting system above a well, method comprising: 6 providing a modular wellbore tubular lifting system; the system comprising 7 at least one module configured to be assembled into one or more configurations; 8 assembling the at least a one module into a first configuration to form an integrated 9 structure.

11 The system may comprise two or more modules. The method may comprise arranging the 12 two or more modules in a stacked arrangement to form an integrated structure. The 13 integrated structure may comprise a load-bearing frame. The method may comprise re- 14 arranging at least one module into a second configuration. The method may comprise re-arranging the two or more modules in a form of an integrated structure in a second 16 stacked arrangement. The method may comprise removably attaching or removably 17 mounting the at least one modules to one another to form an integrated structure. The at 18 least one module to may be connected to one another by pins, manually actuated pins, 19 hydraulically actuated pins, welds, bolts, clips, latches and/or flanges pins. The at least one module may be manually and/or hydraulically operated 22 The system may comprise at least one lifting module. The at least one lifting module may 23 comprise at least one lifting mechanism. The system may comprise two or more lifting 24 modules. The method may comprise arranging a first lifting module above a second lifting module. The method may comprise stacking the first lifting module above the second lifting 26 module. The method may comprise arranging a second lifting module above a first lifting 27 module. The method may comprise stacking the second lifting module above the first lifting 28 module. The method may comprise positioning, locating, coupling and/or stacking the at 29 least one lifting modules parallel, side by side and/or next to each other. The method may comprise positioning, locating, coupling and/or stacking the at least one modules on top of 31 one another. The method may comprise positioning, locating, coupling and/or stacking the 32 at least one modules parallel, side by side and/or next to each other.

34 Embodiments of the fifth aspect of the invention may include one or more features of any of the first to fourth aspects of the invention or their embodiments, or vice versa.

1 According to a sixth aspect of the invention, there is provided a method of reconfiguring a 2 modular wellbore tubular lifting system, the method comprising: 3 providing a modular wellbore tubular lifting system; the system comprising: 4 at least one module assembled in an integrated structure in a first configuration above a well; 6 removing or adding at least one module and/or repositioning the at least one module in the 7 integrated structure to form a second configuration above the well.

9 The method may comprise removably attaching and/or removably mounting the at least one modules to one another to form an integrated structure. The at least one module may 11 be connected to one another by pins, manually actuated pins, hydraulically actuated pins, 12 welds, clips, latches, bolts and/or flanges pins. The system may comprise two or more 13 modules. The method may comprise removably attaching and/or removably mounting the 14 two or more modules in a stacked arrangement to form an integrated structure. The method may comprise re-arranging a stacked arrangement of at least a first module into 16 the second configuration. The method may comprise re-arranging two or more modules in 17 a first stacked configuration to form a second stacked configuration. The system may 18 comprise at least one lifting module. The at least one lifting module may comprise at least 19 one sub-module. Each sub-module may comprise at least one lifting mechanism. The system may comprise two or more lifting modules. The method may comprise arranging a 21 first lifting module above a second lifting module. The method may comprise stacking a 22 first lifting module above a second lifting module. The method may comprise assembling 23 and/or reconfiguring the arrangement of at least one module in a second arrangement for 24 a second well operation. The method may comprise adding, removing and/or repositioning at least one module in the second arrangement. When not in use, at least one or more 26 modules may be put into storage to optimise the use of space on the rig, floor, deck and/or 27 platform. The method may comprise assembling and/or reconfiguring the arrangement of 28 at least one module in a third arrangement for a third well operation. The method may 29 comprise adding, removing and/or repositioning at least one module in the third arrangement. The method may comprise removably mounting a BOP module below at 31 least one lifting module. The method may comprise removably mounting a crane module 32 above at least one lifting module. The method may comprise removably mounting a pipe 33 handling module above the at least one lifting module. The method may comprise 34 removably mounting two or more lifting modules in series above a BOP module. The method may comprise transferring a hoisting load directly to the base structure. This may 1 avoid transferring loads acting on the upper hoisting through the lower hoisting system 2 down to the base structure.

4 Embodiments of the sixth aspect of the invention may include one or more features of any of the first to fifth aspects of the invention or their embodiments, or vice versa.

7 According to a seventh aspect of the invention, there is provided a method of removing a 8 tubular member from a wellbore, the method comprising: 9 providing a modular wellbore tubular lifting system, the system comprising: at least one function module; wherein at least one module comprises a lifting module 11 comprising a lifting mechanism configured to lift and/or lower a tubular; 12 wherein the at least one module comprises a frame configured to be removably 13 connectable to another module to form an integrated structure; 14 locating the modular wellbore tubular lifting system above a wellbore, connecting a tubular string comprising a plurality of tubular members to the lifting 16 mechanism; 17 lifting the tubular string a first distance out of the wellbore; 18 disconnecting a first tubular member from the tubular string; and 19 moving the first tubular member to a storage position.

21 The lifting module may comprise at least a first lifting mechanism and a second lifting 22 mechanism. The method may comprise lifting the tubular member a first distance out of 23 the wellbore using the first lifting mechanism and lifting the tubular member a second 24 distance out of the wellbore using the second lifting mechanism. The system may comprise a second lifting module comprising a lifting mechanism. The method may 26 comprise lifting the tubular member a first distance out of the wellbore using the first lifting 27 module and lifting the tubular member a second distance out of the wellbore using the 28 second lifting module. The method may comprise actuating the first and second lifting 29 modules independently. The method may comprise actuating the first and second lifting mechanisms independently. The method may comprise actuating the first and second 31 lifting modules to sequentially, synchronised or alternatively lift the tubular member. The 32 method may comprise actuating the first and second lifting mechanisms to sequentially, 33 synchronised or alternatively lift the tubular member The method may comprise 34 transferring the lifting of the tubular between the two or more lifting modules and/or between the two or more lifting mechanisms. The ability to transfer lifting between the two 1 or more lifting modules and/or two or more lifting mechanisms may speed up the recovery 2 of the tubular from the well. While one lifting member is lifting the tubular the other lifting 3 member may be repositioning itself to a takeover position to allow a continuous lifting 4 action. The method may comprise actuating a slip assembly to grip the tubular. The method may comprise actuating a first lifting mechanism to lift the movable platform of the 6 first lifting module and gripped tubular string to a first distance or a first height. The method 7 may comprise actuating the first lifting mechanism to lift the movable platform of the first 8 lifting module and gripped tubular string to a tubular grip handover position. The method 9 may comprise actuating the second lifting mechanism to lower a movable platform on the second lifting module or support module to a tubular grip handover position. The movable 11 platform on the second lifting module or lift support module may be a load beam.

13 The method may comprise actuating a gripping system on a top drive assembly to grip the 14 tubular. The method may comprise actuating the slip assembly on the movable platform on the first lifting module to release the tubular. The method may comprise actuating the 16 second lifting mechanism to lift the movable platform on the second lifting module or lift 17 support module to pull or lift the tubular string to a second distance or a second height.

18 The method may comprise actuating the first lifting mechanism to reposition the movable 19 platform of the first lifting module. The method may comprise actuating the first lifting mechanism to lower the first lifting module to a tubular break position. The method may 21 comprise moving the at least one iron roughneck assembly into alignment with a 22 connection on the tubular. The method may comprise breaking the connection joint with 23 the iron roughneck assembly. The method may comprise actuating the iron roughneck to 24 break the connection between the tubular and the tubular string. The method may comprise de-actuating the iron roughneck.

27 The method may comprise actuating an elevator system to tilt the disconnected tubular 28 member. The method may comprise lowering the disconnected pipe to a laydown area.

29 The method may comprise transporting disconnected tubulars to a buffer zone area. The method may comprise actuating a crane module to pick up and/or transport a bundle of 31 disconnected pipes. The method may comprise moving a disconnected tubular member to 32 a tubular storage area using the pipe handling system. The method may comprise moving 33 a disconnected tubular member to a temporary intermediate buffer and/or storage area.

34 Providing an intermediate buffer and/or area may optimise cycle times. The method may comprise providing a radial racking system and/or vertical storage system. The method 1 may comprise providing a monkey arm connected to the lower hoisting frame. The method 2 may comprise moving a position of a tubular and/or at least one module using a monkey 3 arm. The method may be automated or semi-automated. The method may comprise 4 connecting the top drive to a mud circulation system. The method may comprise actuating the slip assembly. The method may comprise lifting the disconnected tubular member from 6 the tubular string.

8 Embodiments of the seventh aspect of the invention may include one or more features of 9 any of the first to sixth aspects of the invention or their embodiments, or vice versa.

11 According to an eighth aspect of the invention, there is provided a method of installing a 12 tubular member into a wellbore, the method comprising: 13 providing a modular wellbore tubular lifting system, the system comprising: 14 at least one function module; wherein at least one module comprises a lifting module comprising a lifting mechanism configured to lift and/or lower a tubular; 16 wherein each of the modules comprises a frame configured to be removably connectable 17 to another module to form an integrated structure; 18 locating the modular wellbore tubular lifting system above a wellbore, 19 moving a first tubular member from a storage position into alignment with the wellbore; connecting the first tubular member to the lifting mechanism; and 21 lowering the first tubular member a first distance into the wellbore.

23 The method may comprise connecting the first tubular member to a tubular string in the 24 wellbore before the lowering the first tubular member a first distance into the wellbore. The lifting module may comprise at least a first lifting mechanism and a second lifting 26 mechanism. The method may comprise lowering the tubular member a first distance out of 27 the wellbore using the first lifting mechanism and lowering the tubular member a second 28 distance out of the wellbore using the second lifting mechanism. The system may 29 comprise a second lifting module comprising a lifting mechanism. The method may comprise lowering the tubular member a first distance into the wellbore using the first lifting 31 module and lowering the tubular member a second distance into the wellbore using the 32 second lifting module. The method may comprise pushing the tubular into the well. The 33 method may comprise actuating the first and second lifting modules independently. The 34 method may comprise actuating the first and second lifting modules and/or first and second lift mechanisms to sequentially, synchronised or alternatively push or lower the 1 tubular member into the well. The method may comprise transferring the lowering or 2 pushing of the tubular between the two or more lifting modules and/or between the two or 3 more lifting mechanisms. The ability to transfer lowering of the tubular between the two or 4 more lifting modules or lifting mechanisms may speed up the installation or running of the tubular into the well. While one lifting member is lowering the tubular the other lifting 6 member may be repositioning itself to a takeover position to allow a continuous lifting 7 action.

9 It will be understood that term "lifting module" refers to a module capable of lifting and/or lowering depending on the direction of movement in which it is actuated. In a lifting 11 operation one or more lifting mechanisms in the lifting module are operated in a generally 12 upward direction to pull or lift. In a lowering operation the one or more lifting mechanism 13 are operated in a generally downward direction to push or lower.

The method may comprise transporting disconnected tubulars from a buffer zone area.

16 The method may comprise actuating the crane to pick up and/or transport disconnected 17 pipes. The method may comprise moving the disconnected tubular member from a tubular 18 storage area to the elevator system using the pipe handling system. The method may 19 comprise actuating the elevator system to tilt to engage the disconnected tubular member.

The method may comprise connecting the elevator system to a disconnected tubular 21 member. The method may comprise actuating a gripping system on a top drive assembly 22 to grip the tubular. The method may comprise lifting the disconnected tubular member and 23 aligning the tubular member with a tubular string. The method may comprise handling 24 and/or transferring a tubular between a storage rack and the rig floor. The method may comprise handling and/or transferring a tubular between a storage rack and the rig floor 26 using a catwalk. The catwalk may comprise a deck and a ramp. The method may 27 comprise loading a tubular onto a deck of the pipe handling catwalk. The method may 28 comprise transferring a tubular from the deck to a ramp. The method may comprise raising 29 one end of the ramp. The method may comprise driving, lifting or pushing the tubular to move it axially along the ramp. The ramp surface may span or partially span a distance 31 between the deck and a top drive apparatus. The method may comprise transferring the 32 tubular from the ramp to a top drive apparatus. The method may comprise moving the 33 tubular to a pick up location where the tubular is accessible for pick up by a top drive 34 apparatus. The method may comprise lowering at one end of a raised ramp. The method may comprise transferring the tubular from a top drive apparatus to the ramp. The method 1 may comprise driving, lifting or pushing the tubular to move it axially along the ramp 2 towards the deck. The method may comprise transferring a tubular from the ramp to the 3 deck. The method may comprise supporting the movement of a tubular from the catwalk to 4 the well centre. The method may comprise supporting the movement of a tubular from the catwalk to the well centre using at least one monkey arm. The at least one monkey arm 6 may be equipped with a roller or gripper system on one end. The method may comprise 7 actuating the first lifting mechanism to reposition the movable platform of the first lifting 8 module. The method may comprise actuating the first lifting mechanism to move the first 9 lifting module to a tubular break position. The method may comprise moving the at least one iron roughneck assembly into alignment with at least one connection on the tubular.

11 The method may comprise making the connection joint with the iron roughneck assembly.

12 The method may comprise actuating the iron roughneck to make the connection between 13 the tubular and the tubular string. The method may comprise de-actuating the iron 14 roughneck. The method may comprise make up and/or breakout of tubulars. The method may comprise actuating a cathead apparatus to make up and/or breakout tubulars. The 16 method may comprise actuating a cutting device to cut a section of tubular. The method 17 may comprise actuating a diamond cutter to cut a section of tubular. The method may 18 comprise replacing an iron roughneck with a diamond cutter and/or a hydraulic cutting 19 clamp. The method may comprise actuating the second lifting mechanism to push or lower the movable platform of the second lifting module or lift support module to push or lower 21 the tubular string to a first distance into the well. The method may comprise actuating the 22 second lifting mechanism to lower the movable platform of the second lifting module or lift 23 support module to a tubular grip handover position. The method may comprise actuating 24 the slip assembly to grip the tubular. The method may comprise actuating the slip assembly to grip the tubular. The method may comprise actuating a first lifting mechanism 26 to lower or push the movable platform of the first lifting module and gripped tubular string a 27 second distance into the well.

29 Embodiments of the eighth aspect of the invention may include one or more features of any of the first to seventh aspects of the invention or their embodiments, or vice versa.

32 According to a ninth aspect of the invention, there is provided a modular rig system for 33 wellbore operations, the system comprising: 34 two or more modules each module comprising at least one rig system component; 1 wherein the two or more modules are configured to be connected or interconnected 2 together so as to form an integrated structure.

4 The modular rig system may be configured to be assembled, positioned and/or installed substantially above and/or adjacent to a wellbore. The two or more modules may 6 comprise a frame. The frames of the two or more modules may be configured to be 7 assembled together to form the integrated structure. The two or more modules may be 8 configured to be assembled and/or arranged into a first configuration to perform one or 9 more tasks in a first wellbore operation. The two or more modules may be configured to be assembled and/or arranged into a second configuration to perform one or more tasks in a 11 second wellbore operation. The two or more modules may be configured to be arranged in 12 a different configurations by adding to or removing at least one module from the integrated 13 structure depending on the wellbore operation. The two or more modules may be 14 configured to be arranged in a vertical and/or horizontal stacked arrangement. The arrangement of the two or more modules in the integrated structure may be configured to 16 transfer any loads acting on the two or more modules through the integrated structure.

17 The arrangement of the two or more modules in the integrated structure may be 18 configured to transfer loads acting on each of the two or more modules directly to a base 19 support structure. The arrangement of the two or more lift mechanisms may be configured to transfer loads acting on each of the two or more modules directly to a base support 21 structure.

23 The modular rig system may be selected from the group comprising a tubular handling 24 system, a tubular lifting system, a pipe removal system, a conductor pipe handling system, a drill system, completion system and/or a wireline system. The wellbore operation may be 26 selected from the group comprising running in, pulling out, drilling, milling, workover, 27 and/or decommissioning operation. The two or more modules may be selected from the 28 group comprising lifting module, crane module, iron roughneck, platforms, slip assembly, 29 top drive assembly, elevator assembly, lubricator system, mast; support mast; monkey arm, racker, radial racker, BOP module, catwalk module, base support module, crane 31 module, jib crane, diamond cutter, skidding system, driller cabin, motor control centre, sub- 32 structure, bell nipple frame, pipe handling module and/or tubular storage module.

34 The at least one module may comprise at least one lifting module. The at least one lifting module may comprise at least one lifting mechanism selected from the group comprising a 1 jack system, screw jack, hydraulic cylinder, pulley system, rack and pinion system, linear 2 motor or any other lifting device. The modular system may comprise two or more lifting 3 mechanisms. A first lifting mechanism may be configured to lift or lower a tubular a first 4 distance. A second mechanism may be configured to lift or lower a tubular a second distance. The combined first and second distance may be configured to cover a complete 6 length of a drill pipe section. The combined first and second distance may be configured to 7 cover a complete length of an API Range 3 drill pipe. The at least one lifting mechanism 8 may be configured to pull a tubular member out of the well and/or push a tubular member 9 into a well. The two or more lifting modules or two or more lifting mechanism may be configured to move and/or actuate independently. The two or more lifting mechanisms 11 may be configured to transfer lifting and/or lowering of a tubular between the two or more 12 lifting mechanisms. The two or more lifting mechanisms may be hydraulically connected 13 and configured to transfer hydraulic fluids between the two or more lifting mechanisms.

14 The at least one lifting module may be integrated into or mounted to a base module. The at least one lifting mechanism may be integrated into or mounted in or to a base module.

16 The at least one module may comprise sub-modules. The at least one lifting mechanism 17 may be a submodule of the at least one lifting module. The position of the at least one 18 module in the integrated structure may be interchangeable with at least one other module 19 in the integrated structure. The modular system may comprise a control system. The control system may be configured to control the positioning and/or actuation of the two or 21 more modules of the system. The control system may be configured to control the 22 positioning and/or actuation of the at least one or lifting mechanisms. The control system 23 may be configured to control the positioning and/or actuation of one or more submodule.

24 The two or more modules and/or two or more lifting mechanisms may be configured for continuously and/or automatic tripping.

27 The system may comprise a hydraulic system. The one or more modules may comprise a 28 hydraulic system. The hydraulic system may be connectable to two or more hydraulic 29 devices. The hydraulic system may be configured to control the actuation of the at least one lifting mechanism. The hydraulic system may be connectable to two or more hydraulic 31 cylinders. The hydraulic system may be configured to transfer hydraulic pressure and/ or 32 hydraulic fluid between the two or more lifting mechanisms. The hydraulic system may be 33 configured to transfer hydraulic pressure and/ or hydraulic fluid between the two or more 34 hydraulic devices and/or cylinders. This may facilitate improved control of the actuation of the at least one lifting mechanism, hydraulic devices and/or cylinders. This may facilitate 1 increased hoisting capacity. The hydraulic system may be configured to transfer hydraulic 2 pressure and/or hydraulic fluid between the two or more lifting mechanisms to reuse or 3 recycle hydraulic pressure and/ or hydraulic fluid. The hydraulic system may be configured 4 to transfer hydraulic pressure and/ or hydraulic fluid between the two or more hydraulic devices and/or cylinders to reuse or recycle hydraulic pressure and/ or hydraulic fluid.

7 Embodiments of the ninth aspect of the invention may include one or more features of any 8 of the first to eighth aspects of the invention or their embodiments, or vice versa.

According to a tenth aspect of the invention, there is provided a method of configuring a 11 modular rig system comprising: 12 providing a modular rig system comprising 13 two or more modules wherein each module comprising at least one rig system component; 14 wherein the two or more modules are configured to be connected or interconnected together so as to form an integrated structure; 16 assembling the two or more modules in a first configuration to form an integrated structure 17 to perform a first well operation.

19 The method may comprise assembling the two more modules into at least a second configuration to perform at least a second well operation. The first well operation and/or 21 second well operation may be selected from the group comprising a wellbore tubular lifting 22 operation, a drilling operation, a pipe removal operation, a conductor jacking operation 23 and/or a wireline operation. The method may comprise arranging the two or more modules 24 in a stacked or connected arrangement to form an integrated structure. The method may comprise removing, adding and/or repositioning at least one module in the integrated 26 structure to form the second configuration.

28 Embodiments of the tenth aspect of the invention may include one or more features of any 29 of the first to eleventh aspects of the invention or their embodiments, or vice versa.

31 According to an eleventh aspect of the invention, there is provided a method operating a 32 modular rig system comprising: 33 providing a modular rig system comprising 34 two or more modules each module comprising at least one rig system component; 1 wherein the two or more modules are configured to be connected or interconnected 2 together so as to form an integrated structure; 3 assembling the two or more modules in a first configuration to form an integrated structure; 4 performing a first well operation; reconfiguring the two or more module to form a second configuration-and 6 performing a second well operation.

8 The first and/or second well operation may be a tubular handling operation. The system 9 may comprise at least a lifting module comprising a lifting mechanism configured to lift and/or lower a tubular; and actuating the lifting mechanism to lift or lower a tubular section 11 out from or into the wellbore. The first and/or second well operation may be a drilling 12 operation. The system may comprise at least one lifting module and a top drive module.

13 The at least one lifting module may comprise at least one lifting mechanism. The at least 14 one lifting module may comprise two or more lifting mechanisms. The at least one lifting module may comprise two or more lifting mechanisms configured to support the load of the 16 top drive module. The method may comprise moving a top drive module connected to a 17 drill pipe member a first vertical distance using a first lifting mechanism. The method may 18 comprise transferring a load of the top drive module and/or a load of the drill pipe member 19 to a second lifting mechanism. The method may comprise transferring the top drive module to a second lifting mechanism. The method may comprise moving the top drive 21 module a second vertical distance using the second lifting mechanism. The method may 22 comprise releasing the drill pipe member from the top drive module. The method may 23 comprise transferring the top drive module from the second lifting mechanism to the first 24 lifting mechanism. The method may comprise connecting the top drive module to a next drill pipe member. The first and/or second well operation may be a wireline operation. The 26 system may comprise at least a wireline assembly. The system may comprise a crane 27 module. The method may comprise lifting the wireline assembly into position above the 28 wellbore. The method may comprise passing a wireline into the well. The method may 29 comprise conducting the wireline operation. The method may comprise moving the wireline assembly into a handling position. The method may comprise connecting, 31 disconnecting and/or changing a wireline tool. The method may comprise actuating a 32 monkey arm to change the position of the wireline assembly into or out of alignment with 33 well centre.

1 Embodiments of the eleventh aspect of the invention may include one or more features of 2 any of the first to tenth aspects of the invention or their embodiments, or vice versa.

4 According to a twelfth aspect of the invention, there is provided a method of drilling a well comprising providing the system according to any of the first, second, fourth or ninth aspects 6 of the invention; 7 assembling the system in a desired configuration; and 8 performing a drilling operation.

Embodiments of the twelfth aspect of the invention may include one or more features of 11 any of the first to eleventh aspects of the invention or their embodiments, or vice versa.

13 According to a thirteenth aspect of the invention, there is provided a method of performing 14 a wireline operation comprising providing the system according to any of the first: second, fourth or ninth aspects of the invention; 16 assembling the system in a desired configuration; and 17 performing a wireline operation.

19 Embodiments of the thirteenth aspect of the invention may include one or more features of any of the first to twelfth aspects of the invention or their embodiments, or vice versa.

22 According to a fourteenth aspect of the invention, there is provided a method of pulling out 23 or running in a tubular comprising providing the system according to any of the first, second, 24 fourth or ninth aspects of the invention; assembling the system in a desired configuration: and 26 performing a pulling out or running in operation.

28 Embodiments of the fourteenth aspect of the invention may include one or more features 29 of any of the first to thirteenth aspects of the invention or their embodiments, or vice versa.

31 According to a fifteenth aspect of the invention, there is provided a hydraulic system for 32 controlling flow of hydraulic fluid to or between two or more modules of the system 33 according to any of the first, second, fourth or ninth aspects of the invention.

Embodiments of the fifteenth aspect of the invention may include one or more features of 36 any of the first to fourteenth aspects of the invention or their embodiments, or vice versa.

1 Brief description of the drawings

3 There will now be described, by way of example only, various embodiments of the 4 invention with reference to the following drawings (like reference numerals referring to like features) in which: 7 Figures 1A and 1B presents a modular tubular lifting and handling system in accordance 8 with an embodiment of the invention, shown in front and perspective views respectively; Figure 2A presents a lower lifting module of the pipe handling system of Figure 1A, shown 11 in front view; 13 Figure 2B presents an upper lifting module of the pipe handling system of Figure 1A, 14 shown in front view; 16 Figure 2C presents a BOP module of the pipe handling system of Figure 1A, shown in 17 front view; 19 Figures 3A to 3F presents the modular tubular lifting and handling system of Figure lA in front views during stages of moving the upper and lower jacks to pull out a tubular from a 21 well, the BOP has been removed for clarity; 23 Figure 4 presents a modular tubular lifting and handling system with an elevator system in 24 accordance with an embodiment of the invention, shown in front view; 26 Figure 5 presents an optional crane module for use with a modular tubular lifting and 27 handling system such as shown in Figure 1A in accordance with an embodiment of the 28 invention, shown in front view; Figure 6 presents a modular tubular lifting and handling system in accordance with another 31 embodiment of the invention, shown in side view; 33 Figure 7 presents a modular tubular lifting and handling system for wireline operations in 34 accordance with another embodiment of the invention, shown in front view; 1 Figure 8 presents a modular tubular lifting and handling system in a wireline bottom hole 2 assembly change mode operation in accordance with another embodiment of the 3 invention, shown in side view; and Figure 9 presents a modular tubular lifting and handling system in accordance with another 6 embodiment of the invention, shown in front view.

8 Figures 10A and 10B show a modular tubular lifting and handling system in accordance 9 with an embodiment of the invention, shown in profile and front views respectively; 11 Figures 11A to 11D show overhead, profile and front views respectively of a lifting module 12 of the modular tubular lifting and handling system of Figure 10A; 14 Figures 12A to 12B show profile and front views of a lifting support module of the modular tubular lifting and handling system of Figure 10A; 17 Figures 13A and 13B show a perspective and overhead views of a moving platform of the 18 modular tubular lifting and handling system of Figure 10A; Figure 14 shows an enlarged cross sectional view of the hydraulic cylinders and support 21 mast of the modular tubular lifting and handling system of Figure 10A; 23 Figures 15A and 15B show perspective views of the load beam and top drive assembly 24 respectively of the modular tubular lifting and handling system of Figure 10A; 26 Figures 16A to 16E show front views of modular tubular lifting and handling system during 27 stages of a drilling operation; 29 Figures 17A to 17E show front views of a modular tubular lifting and handling system during stages of a tubular removal process operation; 32 Figures 18A to 18C show front views of a modular tubular lifting and handling system 33 during stages of a removal of an outer completion tubing; 1 Figures 19A to 19C show front and side views of a modular tubular lifting and handling 2 system configured for workover wireline operations during stages of a wireline operation; 4 Figure 20 shows a perspective view of a modular rig in accordance with an embodiment of the present invention with optional modules attached; 7 Figure 21A to 21D show schematic figures of a valve arrangement in a hydraulic system 8 that may be used to control components of the modular system of Figure 10A during 9 stages of a tubular pull out operation; 11 Figure 22A to 220 show schematic figures of a valve arrangement in a hydraulic system 12 that may be used to control components of the modular system of Figure 10A during 13 stages of a tubular run in operation; and Figures 23A to 230 show schematic figures of a valve arrangement in a hydraulic system 16 that may be used to control components of the modular system of Figure 10A for 17 increased hoisting capability.

19 Detailed description of preferred embodiments

21 Figures 1A and 1B show front profile and perspective views respectively, of modular 22 tubular lifting and handling system 10. The system 10 has a frame 20. The system 10 23 comprises a lower lifting module which in this example is described as a lower jacking 24 module 14 (best shown in Figure 2A); an upper lifting module which in this example is described as an upper jacking module 16 (best shown in Figure 2B) and an optional BOP 26 module 18 (best shown in Figure 20). Figure 1A shows an example setup of modular 27 tubular handling system 10 where the BOP module 18, lower jacking module 14 and upper 28 jacking module 16 are assembled on top of each other. In this example jacking 29 mechanisms are used as the lifting mechanisms and are referred to as jacking modules for clarity.

32 The lower jacking module 14 comprises a frame 20b, a static platform 22 and a moving 33 platform 24. The moving platform 24 has a slip assembly 30 and a power tong 31. The 34 power tong is configured for making/ breaking or rotating a connected pipe string. A plurality of hydraulic cylinders 26, four are used in this example, are connected to the static 1 platform 22 and moving platform 24. However, it will be appreciated that more or less than 2 four cylinders 26 may be used. The cylinders 26 when actuated control the lifting or 3 lowering the moving platform 24 relative to the static platform 22. The lower jacking 4 module 14 comprises two hollow telescopic columns 25 (best shown in Figure 1B) which provide structural support and guide the movement of the cylinders 26. Optionally the 6 lower jacking module 14 comprises an intermediate platform 42 with the frame 20b.

8 The upper jacking module 16 comprises a frame 20a, a static platform 32 and a moving 9 platform 34. The moving platform 34 has a top drive assembly 40 configured to engage a drill string. A plurality of hydraulic cylinders 36, two are used in this example are connected 11 to the static platform 32 and moving platform 34. However, it will be appreciated that more 12 or less than two hydraulic cylinders 36 may be used. The cylinders 36 when actuated 13 control the lifting or lowering of the moving platform 34 relative to the static platform 32.

14 The upper jacking module 16 comprises two hollow columns 35 (best shown in Figure 1B) which provide structural support and guide the movement of the cylinders 36. The 16 cylinders 36 are connected to the static platform 32 of the upper jacking module 16 and 17 lower static platform 22 allowing mechanical and potentially hydraulically connection of all 18 cylinders of the lower and upper jacking modules. The static platform 32 provides space to 19 work with additional tooling. The static platform 32 optionally has a slot towards the pipe feeding direction for transporting pipe by an elevator system between the well center and 21 intermediate pipe buffer zone.

23 Figures 1A and 2C show an optional BOP module 18 for well control operations. The BOP 24 module 18 comprises an adjustable bell nipple 44 with a flow return line 46 and static frame 20c to host at least an annular BOP and well control system 48 with kill line 50 and 26 choke line 52. The static frame 20c optionally has the capacity to distribute the BOP 27 weight down to a skidding structure (not shown) on which the frame 20c is stacked. It will 28 be appreciated that for operations that do not require a BOP such as casing tubular 29 removal or installation the BOP frame may be removed. The BOP weight may be transferred to the well head or through the frame to the platform structure which may be 31 sitting on a skidding substructure for offshore purposes.

33 The hydraulic cylinders 26, 36 in this example, have at least an 8m stroke, which is longer 34 than hydraulic cylinders used in conventional jacking systems. The provision of the hollow columns 25, 35 provides structural and guidance to the longer hydraulic cylinders as they 1 move between retracted and extended conditions. By assembling the upper and lower 2 jacking modules so that they extend in opposing directions enables the hydraulic cylinders 3 to support each other for alignment and reduces total assembly height.

In the lower and upper jacking modules, the hydraulic cylinders 26, 36 are located 6 between the static platforms 22, 32 and the moving platforms24, 34 respectively illustrating 7 various elevation heights in Figure 1A and 1B. Actuation of the hydraulic cylinders moves 8 the moving platforms 24, 34 in the vertical axis. The static platforms 22,32 of the upper 9 and lower jacking modules may be equipped with an assembly to hold the weight of the drill string or tubular when pulling out of the hole or run in the hole. The moving platforms 11 24, 34 of the upper and lower jacking modules may be equipped with rotary systems. The 12 moving platform 24 of the lower jacking module may comprise a power tong system 13 configured to make and/or break the tubular. In this example, the moving platform 34 of 14 the upper jacking module is a load beam and may comprise a top drive with an optional elevator system to tilt the tubular from or to the well center allowing for pick up or lowering 16 of the tubular from or to a laydown area.

18 The disconnected tubular segments from the tubular string are transported in single 19 tubular segments by a tiltable elevator system from, or to, a buffer zone area, where the tubulars are temporarily located before either the crane picks them up in bundles, or they 21 are stored in a fingerboard system. The top drive assembly 40 may be connected to a 22 swivel for mud circulation through a connected drill string. The modular arrangement of 23 Figure 1A facilitates rapid tripping capacity beyond existing conventional tripping speeds 24 and simplifies current pipe handling operations compared to conventional hydraulic tubular handling and workover units. The columns 25,35 may provide counter torque support for 26 the top drive. The frames 20a, 20b and 20c of the modules may be designed to be 27 reversibly and/or removably connected and/or mounted to one another. This may allow the 28 different modules to be connected to one another in different configurations.

Figures 3A to 3F show sequential movement of the modular tubular handling and lifting 31 system of Figure 1A during the stages of pulling out a tubular 90 from a well; the BOP has 32 been removed for clarity. Figure 3A shows the hydraulic cylinders 26 connected to the 33 moving platform 24 and the static platform 22 of the lower jacking module in a partially 34 retracted position. The slip assembly 30 on the lower jacking module is actuated to grip an upper end of the drill string 90. The hydraulic cylinders 36 are connected to the moving 1 platform 34 and the static platform 32 of the upper jacking module 16 and connected to the 2 base structure of the hollow cylinders sitting on the lower structure 22. The upper jacking 3 module 16 is in a partially extended position where the moving platform (load beam) 34 is 4 located at a mid-stroke length of the hydraulic cylinders.

6 Figure 3B shows the moving platform 24 of the lower jacking module and the moving 7 platform (load beam) 34 of the upper jacking module approaching a handover position.

8 The hydraulic cylinders 26 are actuated to a partially extended condition as shown in 9 Figure 3B. The moving platform 24 is moved in a substantially vertical upward direction as shown as arrow "A" in Figure 3B. As the moving platform 24 of the lower jacking module is 11 moved to partially extended condition the tubular 90 is pulled out of the well. The hydraulic 12 cylinders 36 are actuated to a partially retracted condition to move the moving platform 13 (load beam) 34 of the upper jacking module to approach a handover position as shown in 14 Figure 3B. The moving platform 34 is moved in a substantially vertical downward direction as shown as arrow B in Figure 3B.

17 Figure 30 shows the moving platform 24 of the lower jacking module and the moving 18 platform (load beam) 34 of the upper jacking module at a handover position. The hydraulic 19 cylinders 26 are actuated to a fully extended condition as shown in Figure 30. The moving platform 24 is moved in a substantially vertical upward direction as shown as arrow "C" in 21 Figure 3C. As the moving platform 24 of the lower jacking module is moved to fully 22 extended condition the tubular 90 is pulled out of the well to a first distance, which in this 23 example is at least the half the length of a single tubular member length. The hydraulic 24 cylinders 36 are actuated to a fully retracted condition to move the moving platform 34 of the upper jacking module to the handover position as shown in Figure 3C. The moving 26 platform 34 is moved in a substantially vertical downward direction as shown as arrow "D" 27 in Figure 30. In the fully retracted condition, the moving platform 34 of the upper jacking 28 module is brought in close proximity to the moving platform 24 of the lower jacking module.

29 The top drive assembly 40 on the moving platform 34 of the upper jacking module is actuated to grip the tubular and the slip joint assembly 30 on the lower jacking module is 31 actuated to release the tubular. In this example, the minimum stroke of each of the 32 hydraulic cylinders 26, 36 of the lower jacking module and upper jacking module is at least 33 8m. For continuous tripping, there is an overlap of 1m over which handover can take 34 place. This may increase the stroke length of 1m for each jacking module. In this example, the minimum stroke of each of the lower jacking module and upper jacking 1 module is at least 8m. For continuous tripping, there is an overlap of 1m over which 2 handover can take place. This may increase the stroke length of lm for each jacking 3 module.

As shown in Figure 3D, after handover, the hydraulic cylinders 36 are actuated to a fully 6 extended condition to move the moving platform 34 of the upper jacking module. The 7 moving platform 34 is moved in a substantially vertical upward direction as shown as arrow 8 "E" in Figure 3D. In the fully extended condition, the moving platform 34 of the upper 9 jacking module is brought to upper end of the frame (not shown) and pulls the tubular 90 out of the well exposing a connection joint 92 of the tubular. As shown in Figure 3E, the 11 hydraulic cylinders 26 are actuated to a fully retracted condition to move the moving 12 platform 24 of the lower jacking module in a substantial vertical downward direction as 13 shown as arrow "F" in Figure 2E. As shown in Figure 2E the lower jacking module is 14 brought into close proximity with the connection joint 92 of the tubular. The power tongs 31 on the lower jacking module engages the connection joint and breaks the joint to allow the 16 upper tubular section to be removed from the tubular string 90. The disconnected pipe 17 section is moved to a storage area optional by an elevator system and/or a crane system 18 (not shown) or any other pipe handling system such as pipe racker unit. As shown in 19 Figure 3F, with the pipe section 91 removed the hydraulic cylinders 26 and 36 are actuated to move the moving platform 34 of the upper jacking module and the moving 21 platform 24 of the lower jacking module back to a starting position ready to engage and 22 pull another section of the tubular from the well. Although the above example in Figure 3A 23 to 3F describes the operation of the system to pull a tubular from a well, it will be 24 appreciated that the operation may be reversed or partially reversed to run in a tubular, into the well. It will also be appreciated that the movement of the moving platforms 24 and 26 34 and components of the upper and lower lifting modules may be sequential, 27 synchronised, alternating, overlapping and/or staggered.

29 The operation of two moving platforms of the lifting modules in opposite vertical directions facilitates sequential gripping and pushing and/or pulling of the tubular. While the lower 31 lifting module grips and pulls the tubular a first distance out of the well the upper lifting 32 module is repositioned to a handover position to take over gripping the tubular before the 33 slip assembly holding the drill string in the lower lifting module is opened to release the 34 lower lifting module from the drill string. While the upper lifting module takes over gripping the drill string and pulls and/or pushes the drill string a second distance out of the well, the 1 lower lifting module is repositioned to a disconnect position to engage the connection point 2 on the drill string and breaks and/or makes the pipe. This system may mitigate waiting time 3 of the top drive once the maximum hoisting length is reached and in return may increase 4 the tripping speed and may facilitate a continuous tripping operation. Optionally, a rotary system may be provided on both moving platforms 24 and 34. The rotary system may be 6 used for drilling, milling, making and/or breaking operations. Optionally the rotary system 7 may be positioned off-centre. Optionally the rotary system removed or moved temporarily 8 from the well centre.

For continuous tripping mode the top drive assembly may be moved out of the well centre 11 to facilitate a pipe racker to pick up the disconnected tubular section, while the remaining 12 tubular string is gripped and pulled by the slip assembly on the moving platform of the 13 lower lifting module. Once the tubular is removed out of well centre, the top drive assembly 14 may be moved back to its original position to pick up the string again from the approaching lower platform of the lower lifting module to pull it up at its full stroke. During a drilling 16 operation, the drill string may be connected to the top drive assembly allowing mud to 17 circulate through the borehole. Alternatively, or additionally, the tubular may be only 18 rotated through a rotary system on the lower lifting module.

Although the examples above describes the lower lifting system as breaking and/or 21 making the tubular string, it will be appreciated that the lower lifting module and/or the 22 upper lifting module system may have the capability to rotate or break and/or make the 23 tubular string while the system is operating.

Figure 4 schematically shows features of tubular handling system 100 in accordance with 26 an embodiment of the invention. The tubular handling system 100 is similar to the system 27 10 described in Figure 1A and will be understood from the description of Figure 1A.

28 However, the system 100 described in Figure 4 includes a titling elevator system 160.

29 The system 100 has an intermediate buffer zone 162 such as a slide 164 attached to the intermediate platform 142, or such as a mousehole in vertical position. The elevator 31 system 160 is able to tilt to facilitate the lowering or pick-up of pipe sections at the 32 intermediate buffer zone 162, which may comprise a basket, slide or fingerboard. The 33 correct height of the intermediate platform allows a safe handover of pipe lengths 27 to 30 34 ft long (API Range 2 pipes) to or from the elevator 160. Longer pipes of 38 to 45 ft lengths (such as API Range 3 pipes) are handled from the static platform 132 of the upper jacking 1 module 116. The slide 164 has a slot 166 in an upper slide section 168 dimensioned to 2 allow a pipe section to pass through the upper section of the slide.

4 Figure 5 shows an optional crane module system 200 comprising a frame 20d. In this example the frame 20d is configured to be removably or reversibly mounted above the 6 frame 20a of the upper lifting system. However, as the modules are interconnectable the 7 crane module may be connectable to other module types. As an example, Figure 9 below 8 describes a crane module attached to frame 20b of the lower lifting system. Figure 5 9 shows the crane module 200 comprises a bridge crane 270 travelling on rails 272. The crane system may be equipped with a winch or pipe gripper system to assist the 11 transportation of the pipes. In this example the crane system has pipe gripper module 274.

12 The pipe gripper module comprises grippers 275 configured to grip and move sections of 13 pipe. The crane system may alternatively or additionally be configured to assist in the 14 transportation of tubulars and wireline equipment. The crane system 200 may enhance the tripping sequence in automated mode without any manual handling involved.

17 Figure 6 schematically shows features of modular tubular lifting and handling system 300 18 in accordance with an embodiment the invention. The tubular lifting and handling system 19 300 is similar to the system 10 described in Figure 1A and will be understood from the description of Figure 1A. However, the system 300 described in Figure 6 includes a titling 21 elevator system 160 as described and understood from Figure 4 and the crane system 200 22 as described and understood from Figure 5 above. The system 300 comprises an optional 23 removable pipe storage system 377 for storage of pipe sections. The grippers 275 of the 24 pipe gripper module 274 are configured to pick up pipes to or from a vertical modular rack in the pipe storage system 377. In a pull-out operation, once the box is full, it can be 26 disconnected and replaced by a new box enabling a continuous tripping sequence 27 independently of the racking capacity. This may also reduce the total amount of required 28 lifts. The removable pipe storage system 377 may be connected to the frame 20. The 29 crane module system 200 is reversibly or removably mounted on top of the upper lifting module. The pipe gripper module 274 comprises pipe grippers 275 which moves with the 31 moving platform 34 while the rotary system breaks and/or makes the tubular connection.

32 Once the tubular is disconnected from or connected to the string and handed over to the 33 gripper 274 the upper rotary system can be positioned to the well center to allow full 34 rotation of the string towards the modular pipe storage system 377. Additionally, or alternatively, the pipe gripper module 274 may have the capacity to move horizontally in 1 both directions and in vertical directions. The system 300 also comprises an optional stair 2 tower 379 for easy access to static platforms. Each moving platform may be equipped with 3 a rotary system comprising at least one rotary drive for drilling, milling, making, and 4 breaking operations.

6 The arrangement of the upper lifting module, lower lifting module, crane module and tilting 7 elevator module may speed up the tripping speed and reduce overall manual labor 8 handling in transporting the pipes to a laydown area, or to a dedicated racking system. The 9 optional removable pipe box 377 of the racking system may be removed once full or emptied to support an uninterrupted tripping or drilling operation, reducing the overall 11 number of total lifts and total crane occupation. Equipped with a tiltable elevator system on 12 a top drive assembly in combination with tubular storage may reduce the crane occupation 13 and manual pipe handling compared to conventional rig-less solutions. A rotary system is 14 connected to the moving platform of the lower lifting module to facilitate rotation of the tubular/pipe at high speeds and/or high torque while performing an operation such as 16 tripping, drilling and/or milling. The rotary system may also be used to make and break the 17 tubular. A slip assembly is connected to a bearing system to support the rotation of the 18 string. The top drive may be removed automatically from the well center as shown in 19 Figure 6, while the pipe is located in the slip assembly in the moving platform of the lower lifting module. By moving the top drive from the well center, the tubular/pipe may be 21 rotated and lifted above the height of the top drive. The sequential actuation of the upper 22 lifting module, lower lifting module, and ability to lift the tubular/pipe past the top drive 23 enables and/or simplifies continuous tripping. The system 300 may allow automated or 24 semi-automated mode. The system 300 in combination with an automated racking system or semi-automated racking system may allow refilling or emptying the setback area in 26 assistance with a crane during operations. The presence of the multi direction vertical 27 racker system may allow continuous tripping mode. The removable pipe racking system, 28 the stair tower to access all static platform levels, and the rotary system which has the 29 additional mechanism to rotate the pipe body at high-speed rates for continuous drilling mode are all optional modules.

32 Figure 7 shows an alternative modular tubular lifting and handling system 400. The 33 modular tubular lifting and handling system 400 is similar to the system 10 described in 34 Figure 1A and will be understood from the description of Figure 1A. However, the system 400 described in the example shown in Figure 7 is configured for workover wireline 1 operations. In a wireline operation setup shown in Figure 7, the upper lifting module is 2 removed and the crane 470 does not comprise a pipe handler module. The system 400 3 has a lubricator 480, a lubricator support frame 482 and two intermediate platforms 427 4 and 442, of which one is not required for short lubricator length. The system has a wireline BOP module 484 mounted on the moving platform 424 of the lower lifting module 414. The 6 system also has a setback area 486 for a wireline tool bottom hole assembly (BHA) to be 7 exchanged. In wireline operation setup shown in Figure 7 the cylinders 426 are configured 8 to extend and lift the moving platform 424 holding the wireline BOP gate system to the 9 same height as the static intermediate platform 427 with a V-door to access the BHA lay down area. The lubricator 480 hangs down on a hook from bridge crane 471 of the crane 11 system 470. However, this setup is also possible with the moving platform at the static 12 platform height of the lower module 22. At the lower level, the wireline BOP 484 is 13 connected to a support frame integrated to the moving platform 424. The overhead crane 14 system 470 is used to lower the lubricator 480 to the laydown area or to support a BHA change.

17 Figure 8 shows a modular tubular handling system 500 in a wireline bottom hole assembly 18 change mode operation setup in accordance with another embodiment of the invention.

19 The modular tubular handling system 500 is similar to the system 400 described in Figure 7 and will be understood from the description of Figure 7. However, Figure 8 shows the 21 lubricator support frame 582 in tilt mode. A lubricator support frame 582 has a mechanism 22 588 to push up the lubricator 580 from the wireline BOP 584 and to tilt the assembly 23 towards the laydown area in front of the BOP for simpler wireline BHA change.

Figure 9 shows a modular tubular handling system 600 in a conductor handling operation 26 setup in accordance with another embodiment of the invention. The modular tubular 27 handling system 600 is similar to the system 400 described in Figure 7 and will be 28 understood from the description of Figure 7. However, Figure 9 shows the system 29 comprises a crane module 670 mounted on a lower lifting module 614. It is also understood that this setup may also function without the upper crane module 670.

31 The lower lifting module 614 comprise a frame 20b a static platform 622 and a moving 32 platform 624. In Figure 9 the moving platform is shown in a fully retracted condition. A 33 plurality of hydraulic cylinders 626, four are shown in this example, which are connected to 34 the static platform 622 and moving platform 624. However, it will be appreciated that more or less than four cylinders 626 may be used. The cylinders 626 when actuated control the 1 lifting or lowering the moving platform 624 relative to the static platform 622. The movable 2 platform is configured to grip a conductor. Actuation of the hydraulic cylinders 626 to move 3 the moving platform to an extended position, lifts and pulls the conductor in a substantially 4 upward direction to remove or partially remove the conductor from the wellbore in assistant with a slip system sitting in the moving table 24 and below in the static frame 622. The 6 conductor is cut, and the cut conductor sections transported by the crane module from the 7 wellbore to a basket or slide. Optionally a pipe gripper system similar to the system 8 described in relation to Figure 5 may be used in the crane module.

Figures 10A and 10B show profile and front views of modular tubular lifting and handling 11 system 700 respectively. The system 700 has a base frame 721. The system 700 12 comprises a lifting module (best shown in Figures 11A to 110); an upper support module 13 which in this example is an upper mast module 716 (best shown in Figures 12A to 120) 14 with an optional top drive. The arrangement of Figure 10A differs from the arrangement of Figure 1A in that only one lifting module is used in which the upper and lower hoisting 16 cylinders are integrated to the lower lifting module 714.

18 Figure 10A shows an example setup of modular tubular handling system 700 where the 19 lower lifting module is mounted on the base frame 721 and the upper support module 716 is mounted on the lower lifting module. In this example jacking mechanisms or hydraulic 21 cylinders are used as the lifting mechanisms in the lower lifting module. Alternatively, or 22 additionally different lifting mechanisms may be used. The lifting module 714 comprises a 23 frame 720b, a static platform 722, a moving platform 724 and a support mast 780.

24 The moving platform 724 as best shown in Figures 13A and 13B is supported by four hydraulic cylinders 726. The four cylinders 726 are connected between the static platform 26 722 and the moving platform 724. It will be appreciated that more or fewer than four 27 hydraulic cylinders may be used. The cylinders 726 when actuated control the lifting or 28 lowering of the moving platform 724 relative to the static platform 722. The lifting module 29 714 also comprises two hydraulic cylinders 736 configured to lift and lower a top drive assembly on a second moving platform 734 movable mounted on the upper support 31 module. In this example the second moving platform is a load beam. The cylinders 736 32 when actuated control the lifting or lowering of the load beam relative to the static platform 33 722. In this example the cylinder housings are facing upwards and only the piston side is 34 connected to the lower static platform 722.

1 In this example the hydraulic cylinders 726 are connected to the moving platform 724 via 2 pinned connections which may allow for horizontal rotation degrees of freedom release on 3 each cylinder. Slip assemblies may allow for horizontal translation movement to release 4 degrees of freedom on each cylinder. Plate springs or a separately mounted guidance system may be used to keep the moving platform centralised. In this example the moving 6 platform comprises a frame 724a and rollers 782 which act as guidance rollers which are 7 configured to move along tracks 784 in the support/guidance mast 780 to prevent 8 horizontal or vertical rotation of the platform relative to the support/guidance mast.

As best shown in Figure 14 the hydraulic cylinders 726, 736 also may comprise a frame 11 783 and rollers 782a at selected positions along their length which are configured to 12 provide support and act as guidance rollers to move along tracks 784 in the 13 support/guidance mast 780 to prevent horizontal or vertical rotation to of the hydraulic 14 cylinders relative to the guidance mast as the hydraulic cylinders move between extended and retracted conditions. The moving platform 724 may support a slip assembly and a 16 power tong. The power tong may be configured for making/ breaking or rotating a 17 connected pipe string. The upper support module 716 comprises a frame 720a, a moving 18 platform 734 in this example the moving platform is a load beam. The load beam as best 19 seen in Figure 15A has a telescopic function, guided on tracks by a roller guidance assembly and is connectable through a pin connection for free rotation to the two hydraulic 21 cylinders 736 mounted on the lifting module 714. In this example the hydraulic cylinders 22 736 are connected to the load beam 734 via pinned connections which may allow for 23 horizontal rotation degrees of freedom release on each cylinder. Slip assemblies may 24 allow for horizontal translation movement to release degrees of freedom on each cylinder.

In this example the load beam comprises rollers 792 which act as guidance rollers which 26 are configured to move along tracks 784 in the support/guidance mast 780 to prevent 27 horizontal or vertical rotation of the platform relative to the support/guidance mast. In this 28 example the load beam 734 comprises lugs 735 its underside to provide connection to the 29 top drive assembly. This may allow a top drive assembly to be connected (or disconnected) for drilling operations.

32 In this example, the top drive assembly module 800 comprises a dolly 810 comprises a 33 frame 811 and two bails 812 as shown in Figure 158. The bails are capable of tilting to the 34 front and rear and potentially able to rotate up to 360 degree movement. The elevator system is configured to tilt out from well centre from the bails. Hooks 814 are provided to 1 connect to lugs on the load beam. The hooks provide the top drive assembly with easy 2 connection/disconnection for drilling operations. In this example the top drive assembly 3 module 800 comprises rollers 816 which act as guidance rollers which are configured to 4 move along tracks 784 in the support/guidance mast 780 to prevent horizontal/vertical rotation and/or translation of the top drive assembly module 800 relative to the guidance 6 mast. In this example, the top drive assembly module 800 comprises feet 818 to allow the 7 top drive assembly to be handed over to the moving table in drilling operations. The 8 frames 720a and 720b of the lower lifting module and upper support module are designed 9 to be reversibly and/or removably connected and mounted to one another. This may allow the different modules to be connected to one another in different configurations.

12 Figures 16A to 16E show sequential movement of the modular tubular handling system 13 during the stages of the drilling operation. A first stage is to actuate the hydraulic cylinders 14 726 connected to the moving platform 724 to a retracted position to locate the moving platform 724 to a low position on the lower lifting module and actuate the hydraulic 16 cylinders 736 connected to the load beam 734 to an extended position to locate the load 17 beam and attached top drive to a high position on the upper support module as shown in 18 Figure 16A. In this condition the drilling operation continues through the stroke length of 19 the hydraulic cylinders 736.

21 During drilling operation, the top drive assembly is moved in a substantially downward 22 direction as the hydraulic cylinders 736 retract moving drill string 793 in a downward 23 direction into the wellbore. Once the hydraulic cylinders 736 has retracted to a handover 24 position, the support of the top drive assembly is transferred from the upper support module to the lower lifting module as shown in Figure 16B.

27 The system comprises sensors which detect the position and/or load on the top drive 28 assembly and moving platform. When the handover procedure is initiated the hydraulic 29 cylinders 726 are actuated to an extended position to locate the moving platform 724 to a handover position on the lower lifting module. In this example positional sensors control 31 the movement of the bails and top drive assembly to move from well centre either front or 32 rear. A load cell located at the load beam acts as a safety release. The load cell measures 33 the loads acting on the load beam and the handover sequence may be initiated if the 34 measured load is below a specific load limit. The hydraulic cylinders 736 are further retracted to move the top drive assembly downwards until the feet of the top drive dolly 1 contact the moving platform 724 and a load cell located at the moving platform is 2 configured to measure if the load has been transferred to the moving platform 724. Once 3 the load cell on the moving platform has confirmed the load transfer, hhydraulic pins 4 located in the feet of the dolly system are actuated to lock inside the landing area of the moving platform.

7 Both the hydraulic cylinders 726 and hydraulic cylinders 736 move at the same velocity to 8 allow for continuous drilling. If the load cells on the moving platform and the load beam 9 detect a successful load distribution through the moving platform the top drive assembly is disengaged from the load beam. To disengage from the load beam, the hydraulic cylinders 11 736 moves in a downward direction at a faster velocity than the hydraulic cylinders 726, 12 until it reaches a hook unlock position which in this example is approximately 100mm. The 13 top drive dolly hooks are now dis-engaged from the load beam and full control of the top 14 drive assembly support is now transferred to the moving platform 724. As shown in Figure 16C once the top drive is released from the load beam the hydraulic cylinders 726 and 16 moving platform 724 support the further downward movement of the top drive assembly.

17 The top drive assembly continues in a downward direction until the hydraulic cylinders 726 18 are in a fully retracted position where a static hydraulic slip located in the base frame 721 19 takes the drill pipe and the top drive assembly is repositioned to accept a new drill pipe section. The hydraulic cylinders 726 are actuated to an extended position to locate the 21 moving platform 724 and supported top drive assembly to the handover position on the 22 lower lifting module. At the handover position the hooks on the top drive assembly engage, 23 the load beam, the hydraulic pins on the dolly feet unlock to the landing area of the moving 24 platform and the load is transferred to the load beam. The hydraulic cylinders 726 and 736 are actuated to move the moving platform 724 and load beam to the first stage as shown 26 in Figure 16E.

28 Figures 17A to 17E show sequential movement of the modular tubular handling system 29 700 during the stages of the tubular removal process operation. A first stage is to actuate the hydraulic cylinders 726 connected to the moving platform 724 to a retracted position to 31 locate the moving platform 724 to a low position on the lower lifting module where a slip 32 assembly on the moving platform 724 is actuated to grip an upper end of the drill string 90.

33 Hydraulic cylinders 736 connected to the load beam 734 are actuated to an extended 34 position to locate the load beam and attached top drive to a high position on the upper support module as shown in Figure 17A. The hydraulic cylinders 726 are actuated to an 1 extended condition as shown in Figure 17B. The moving platform 724 is moved in a 2 substantially vertical upward direction as shown as arrow "A" in Figure 17B. As the moving 3 platform 724 is raised the tubular 90 is pulled out of the well a first distance as shown in 4 Figure 17B. The hydraulic cylinders 736 are actuated to a retracted condition as shown in Figure 17B to reach a handover position. The top drive assembly 800 is moved in a 6 substantially downward direction as the hydraulic cylinders 736 retract. Once the hydraulic 7 cylinders 736 has retracted to a handover position, elevator clamps on the top drive take 8 hold of the drill pipe.

The moving platform 724 and top drive assembly both move momentarily in an upward 11 direction as shown in Figure 170 to ensure a safe handover, which is confirmed by load 12 sensors on the moving platform and load beam. The hydraulic slip on the moving platform 13 724 is actuated to release the pipe. The hydraulic cylinders 726 are actuated to a 14 retracted condition as shown in Figure 170 to move the moving platform 724 in a substantially vertical downward direction until it returned to a pipe gripping position as 16 shown in Figure 17D. The hydraulic cylinders 736 are actuated to an extended condition 17 as shown in Figure 170 to move the top drive assembly and connected pipe in a 18 substantially vertical upward direction to pull the pipe out of the well a second distance as 19 shown in Figure 17D. The pipe section is removed as shown in Figure 17E. The above steps are repeated until the tubular is removed from the well. Although the above example 21 in Figure 17A to 17E describes the operation of the system to pull a tubular from a well, it 22 will be appreciated that the operation may be reversed or partially reversed to run in a 23 tubular into the well. It will also be appreciated that the movement of the moving platform 24 724 and load beam 734 and components of the lower lifting module and/or upper support modules may be sequential, synchronised, alternating, overlapping and/or staggered.

27 Figures 18A to 180 show sequential movement of the modular tubular handling system 28 1100 during the stages of the removal of the outer completion tubing. The tubular handling 29 system 1100 comprises a lifting module 1014 similar to the lifting module 714 described in Figures 10A to 16 and will be understood from the description of Figures 10A to 16.

31 However, the system 1100 described in Figure 18A to 180 includes a diamond cutter 32 module 1160 instead of a tubular making and breaking system. A first stage is to actuate 33 the hydraulic cylinders 1126 connected to the moving platform 1124 to a retracted position 34 to locate the moving platform 1124 to a low position on the lifting module where a slip 1 assembly on the moving platform 1124 is actuated to grip an upper end of the conductor 2 pipe 1191.

4 The hydraulic cylinders 1126 are actuated to an extended condition as shown in Figure 18B. The moving platform 1124 is moved in a substantially vertical upward direction as 6 shown as arrow "A" in Figure 18B. As the moving platform 1124 is raised the conductor 7 pipe 1191 is pulled out of the well a first distance as shown in Figure 18B. Hydraulic slips 8 on the lower transverse structure 1121 are actuated to grip the conductor pipe. Hydraulic 9 slips on the moving platform 1124 actuated to release the conductor pipe. The hydraulic cylinders 1126 are actuated to a retracted condition as shown in Figure 18C to move the 11 moving platform 1124 in a substantially vertical downward direction until it returned to a 12 pipe gripping position as shown in Figure 18C. The pipe gripping position being located 13 below the position of the diamond cutter module 1160. The diamond cutter module is 14 actuated to cut the pipe. The section of cut conductor pipe is removed. The process is repeated until the conductor pipe 1191 is removed from the wellbore. This process can be 16 supported by the two modular jib cranes 1131 mounted to the mast structure.

18 Figures 19A to 19C show sequential movement of the modular tubular handling system 19 1200 configured for workover wireline operations during the stages of a wireline operation.

The modular tubular handling system 1200 is similar to the modular tubular handling 21 system 700 described in Figure 10A and will be understood from the description of Figures 22 10A. However, the system 1200 described in Figure 19A to 19C includes a lubricator 23 module 1280, a lubricator support frame 1281, a wireline BOP module 1284, a monkey 24 arm module 1286, a jib crane module 1288, a closed platform front 1292 and a wireline assembly module 1290. A first stage is the monkey arm module 1286 is actuated to 26 position it rearward of the well centre. The wireline assembly module is lifted into well- 27 centre via the modular jib crane 1131 as shown in Figure 19A. For changing the Bottom 28 Hole Assemblies (BHA) the wireline BOP assembly is disconnected from the lubricator 29 package. The monkey arm is configured to automatically move out the wireline lubricator assembly to an appropriate handling position. The wireline tool is then changed on the 31 wireline assembly and plugged into position as shown in Figure 19C. The wireline 32 assembly is then re-positioned over the well-centre via automatic movement by the 33 monkey arm. The wireline assembly is now able to continue its operations in the well.

34 Once completed the wireline assembly is lifted back to a stored location via the jib crane 1131. It may be possible with this system arrangement to carry out maintenance and 1 pressure testing operations whilst in its stored location on the system to mitigate non- 2 productive time. It will be appreciated that the jib crane module may consist of a winch, 3 telescopic boom and/or pulley assembly and can be installed at various heights on the 4 lower or upper module 6 Figure 20 schematically shows features of an example tubular handling system 1300 in 7 accordance with an embodiment the present invention. The tubular handling system 1300 8 is similar to the system 700 described in Figures 10A and will be understood from the 9 description of Figures 10A. However, the system 1300 described in Figure 20 includes optional modules attached for various well operations including load beam 1334, top drive 11 assembly 1380, jib crane module 1331, fingerboard 1333, radial racker 1337, monkey arm 12 1335, sub base module 1339, working platform 1341, elevated platform 1343, drillers 13 cabin 1345 and iron roughneck 1347. It will be appreciated that one or more modules may 14 be added or removed. Additional modules may be selected from the group comprising lifting module, crane module, platform walkway, pipe deck, stairs, stair tower, transverse 16 substructure, trip tank, jacking frame, service containers, catwalk, slip assembly, elevator 17 assembly, lubricator system, mast; support mast; BOP module, base frame, diamond 18 cutter, skidding system, BOP substructure, motor control centre, bell nipple frame, pipe 19 handling module and/or tubular storage module. The platform may be an open or closed platform. The size and/or height of installation of the at least one platform may depend on 21 the operation. The platform may be a telescopic or extendable platform, The platform may 22 comprise a telescopic or extendable section at the front enabling access to the moving 23 platform.

Figure 21A to 210 show schematic figures of a valve arrangement in a hydraulic system 26 1400 that may be used to control components of the modular system of Figure 10A during 27 stages of a tubular pull out operation. Figure 21A shows the status of the hydraulic system 28 1400 which controls the actuation of the four hydraulic cylinders 726 which control the 29 movement of the moving platform (not shown) and the actuation of the two hydraulic cylinders 736 which control the movement of the load beam 734. In the figures arrows "A" 31 shown the direction of movement of the four hydraulic cylinders 726 and moving platform.

32 Arrows "B" shown the direction of movement of the two hydraulic cylinders 736 and load 33 beam. The other arrows in the Figures show the flow of hydraulic fluid through the valve 34 arrangement of the hydraulic system.

1 In this example the four cylinders are shown for clarity as two outer cylinders 726a and two 2 inner cylinders 726b it will be appreciated that the cylinders arrangement may be different.

3 In Figure 21A two hydraulic cylinders 736 are in an extended condition to locate the load 4 beam 734 at its upper position. The four hydraulic cylinders 726 are in a retracted condition to locate the moving platform 724 at its lowest position with the pipe to be 6 removed from the well gripped by the hydraulic slip assembly. Figure 21A shows the 7 upper cylinders 736 are in a differential acting mode where valves V1 and V2 are open 8 between upper cylinder volume 736 and inner lower cylinder volume 726b.

Valves V3 and V4 between the lower cylinders 726 and the hydraulic storage tank 1420 11 are closed. Valves V5, V6 and V7 between the outer lower cylinders 726a and the 12 hydraulic pump 1410 are opened. The pumped hydraulic fluid in the lower outer cylinders 13 726a move the cylinders to an extended condition. Valves V9 and V10 between the upper 14 cylinders 736 and outer lower cylinder 726a are closed. Valves V1 and V2 between the upper cylinders 736 and inner lower cylinders 726b is opened and the hydraulic fluid 16 passes from the upper cylinders 736 to the inner lower cylinders 726b. The load beam 734 17 and top drive assembly (not shown) move in a generally downward direction shown by 18 arrow "B" towards the handover position with the retraction of the upper cylinders 736.

19 The moving platform 724 and attached pipe are moved in a generally upward direction shown by arrow "A" to the handover position with the extension of the lower cylinders 726 21 as shown in Figure 21B.

23 At the handover position shown in Figure 21B, the tubular is gripped by the top drive and 24 released by the hydraulic slip assembly on the moving platform. Valves V1, V2 and V11 open between the upper cylinders 736 and the pump 1410 which moves the upper 26 cylinders 736 to an extended position as shown in Figure 21C. The load beam 734 and 27 top drive assembly move in a generally upward direction pulling the tubular further out of 28 the well. Valves V6, V7, V12, V13 and V3 between the lower cylinder 726 and the 29 hydraulic storage tank open while valve V5 closes to the hydraulic pumps and the lower cylinder 726 retracts lowering the moving platform. The procedure is repeated to pull 31 further sections of the tubular from the well.

33 Figure 22A to 22D show schematic figures of a valve arrangement in a hydraulic system 34 1400 that may be used to control components of the modular system of Figure 10A during stages of a tubular run in operation. The hydraulic system 1400 is similar to the system 1 described in Figures 21A to 22D and will be understood from the description of Figures 2 21A to 22D. Figure 22A shows an initial condition where the two upper cylinders 736 in an 3 extended condition and the load beam 734 is at its upper position with the pipe to be run in 4 gripped by the top drive assembly. The four hydraulic cylinders 726 are in a retracted condition to locate the moving platform 724 at its lowest position. Figure 22B show the 6 upper cylinders 736 are in differential acting mode where valves V1 and V2 are open 7 between upper cylinder volume 736 and inner lower cylinder volume 726b.

9 Valves V3 and V4 between the lower cylinders 726 and the hydraulic storage tank are closed. Valves V5, V6 and V7 between the outer lower cylinder 726a and the hydraulic 11 pump 1410 are opened and the pumped hydraulic fluid in the outer lower cylinder 726a 12 actuates the lower cylinder arrangement 726 to an extended condition. Valves V1 and V2 13 between the upper cylinders 736 and inner lower cylinders 726b are opened and the 14 hydraulic fluid passes from the upper cylinders 736 to the inner lower cylinders 726b.

Valves V9 and V10 are closed between the upper cylinders 736 and the outer lower 16 cylinders 726a. The upper cylinders 736 moves to a retracted condition lowering the load 17 beam, top drive assembly and attached tubular in a generally downward direction towards 18 a handover position. The moving platform is moved in a generally upward direction shown 19 by arrow "A" in Figure 22B to the handover position with the extension of the lower cylinders 726.

22 At the handover position shown in Figure 22B the tubular is gripped by the hydraulic slip 23 assembly on the moving platform and released by the top drive assembly. All Valves V5 24 and V11 between the pump and all cylinders 736 and 726 are closed. Valves V1 and V2 between the inner lower cylinders 726b and upper cylinders 736 stay open and hydraulic 26 fluid passes from the inner lower cylinders 726b to upper cylinders 736. The upper 27 cylinders 736 are actuated to an extended position where the load beam and top drive 28 assembly are moved in a generally upward direction shown by arrow" B in Figure 22C to 29 receive another tubular section. Valve V3 between the outer lower cylinder 726a and the hydraulic storage tank 1420 are opened. The outer lower cylinders 726a are move to a 31 retracted position shown in Figure 22D. The moving platform is moved to a retracted 32 position pushing the tubular into the well. The procedure is repeated to run in further 33 sections of the tubular into the well.

1 Figures 23A to 23D show schematic figures of a valve arrangement in a hydraulic system 2 1400 that may be used to control components of the modular system of Figure 10A for 3 increased hoisting capability. Figure 23A and 23B show actuation of the hydraulic system 4 for increased hoisting load capacity. As shown in Figure 23A the upper cylinder 736 is in direct acting mode where the valves V9 and V10 are open between the annular volume of 6 the upper cylinders 736 and hydraulic pumps 1410. Valves Vi, V2, V14 and V15 between 7 the piston volume of the upper cylinders 736 with the inner lower cylinders 726b are 8 opened. To further increase the hoisting load capacity the valves are opened between all 9 lower cylinders 726 and the pumps 1410, which pressurized all of them for higher load capacity. Valve V1, V2 and V4 are opened to drain the fluid from the upper cylinders 736 11 to the storage tank 1420.

13 It will be appreciated that various valve positions and configurations are possible for other 14 operational sequences such as for drilling operations. The ability of the hydraulic cylinder volumes to be connected and selectively control flow of hydraulic fluid between the 16 hydraulic cylinders may reduce required flow rates from the pump, reduce actuation time 17 and/or increase hoisting load capacity. It will be appreciated that similar a hydraulic system 18 may be used for other hydraulic drive systems such as a hydraulic rack and pinion drive 19 system. The hydraulic connections and valve positions may allow the connection of an upper lifting system with a lower lifting system by switching the flow direction and 21 connecting certain motor groups with each other.

23 It will be appreciated that the embodiments described in Figures 1A to 23 may illustrate 24 different arrangements of modules of the system during the different phases of the life of the well. As an example, the system setup described in Figure 7 may be the setup for a 26 first phase to perform one or more wireline operations. Attaching the BOP module and an 27 upper jacking module may allow a smooth continuation to the next phase as shown in 28 Figure 1A for pipe installation and recovery. The setup using only the modular lower lifting 29 module 14 such as shown in Figure 2A, or Figure 9 or the lifting module shown in Figure 18B may be used for a last phase to recover casing during a decommissioning phase.

31 Optionally, in a casing jacking system the static platform is equipped with an additional slip 32 assembly, which is not necessary, if both jacking frames are mounted to each other. For 33 drilling operations beyond the maximum cylinder stroke both hydraulic slip assemblies may 34 be required.

1 Throughout the specification, unless the context demands otherwise, the terms 'comprise' 2 or 'include', or variations such as 'comprises' or 'comprising', 'includes' or 'including' will be 3 understood to imply the inclusion of a stated integer or group of integers, but not the 4 exclusion of any other integer or group of integers. Furthermore, relative terms such as", "horizontal" ,"vertical", upward, downward, upper, lower and the like are used herein to 6 indicate directions and locations as they apply to the appended drawings and will not be 7 construed as limiting the invention and features thereof to particular arrangements or 8 orientations. The foregoing description of the invention has been presented for the 9 purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and 11 described in order to best explain the principles of the invention and its practical 12 application to thereby enable others skilled in the art to best utilise the invention in various 13 embodiments and with various modifications as are suited to the particular use 14 contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention as defined by the appended claims.

17 The invention provides a modular system for lifting and/or lowering tubulars in wellbore 18 operations. The system comprises at least one module, wherein the at least one module 19 comprises a frame. The frame of at least one module is configured to be removably connected to a frame of at least one other module to form an integrated structure above a 21 wellbore.

23 Embodiments of the invention may facilitate movement of a first and second tubular lifting 24 in a simultaneously and/or synchronized manner such that a tubular may be pulled out or run into or out rapidly with minimal interruption. Providing two or more lifting modules may 26 provide a multiple redundancy hoisting system. Embodiments of the invention may provide 27 a modular tubular handling and lifting system which can be readily transported, 28 assembled and/or disassembled. The system comprises multiple individual modular 29 components which are compatible with each other and may be added or removed from the system depending on the requirement of a specific well operation, the phase of the well or 31 a condition of the well or rig. This may provide a system which is transfigurable and 32 dynamic capable of being adapted to add or remove modules depending on the 33 operational requirement with minimal downtime. Embodiments of the invention may 34 facilitate all forces acting on the system to be distributed and transferred to the base of hydraulic cylinders and/or to the base support frame. Embodiments of the invention may 1 facilitate the transfer of hydraulic fluid between one lifting system and another lifting 2 system thereby increasing energy efficiency between the lifting systems. By hydraulically 3 connecting the hydraulic cylinders of the lifting systems for specific operations may allow 4 recycling/ reusing and/or diverting hydraulic power instead of draining the hydraulic fluid to a storage tank.

7 Providing a modular system capable of adaptation for different well stage operations may 8 reduce the mobilization and assembly of operation specific equipment and/or increase 9 utilization of available equipment. As an example, after finishing a pulling and/or milling operations the upper jacking module and/or BOP module may be removed to use the 11 lower jacking module as a jacking system to pull the conductor.

13 The system may be suitable for a wide range of applications in offshore and/or onshore 14 environments on different rig types and sizes. The system may be compact, mobile and transfigurable to adapt to wide range of well operations and conditions. This may facilitate 16 an upgrade and/or downgrade of the systems operational envelope. Deploying only the 17 necessary modules for each well operation phase may increase available rig footprint, 18 reduce maintenance and reduce equipment and maintenance costs. The unused modules 19 may be utilised on another project site until required reducing costs further.

21 A further advantage of the system according to an embodiment of the invention is that by 22 providing two independently moving lifting modules tripping speed during run in or pull out 23 may be increased independent of the stroke length. Providing the lifting modules in a 24 stacked arrangement on top of each other may facilitate continuous tripping, drilling and/or milling operations. Another advantage of the system according to an embodiment of the 26 invention is that it may be configured to run in semi-automated or full-automated mode 27 depending on the operational requirements. This may enable continuous or semi- 28 continuous tubular recovery/tubular installation with minimal manual handling.

Various modifications to the above described embodiments may be made within the scope 31 of the invention herein intended.

Claims

Claims 1. A modular rig system, the system comprising: two or more modules wherein each module comprises at least one rig system component; wherein the two or more modules are configured to be connected or interconnected together so as to form an integrated structure.
2. The modular rig system according to claim 1 configured to be assembled, positioned and/or installed substantially above and/or adjacent to a wellbore.
3. The modular rig system according to claims 1 or 2 wherein the two or more modules comprise a frame wherein the frames of the two or more modules are assembled together to form the integrated structure.
4. The modular system according to any preceding claim wherein the two or more modules are configured to be assembled and/or arranged into a first configuration to perform one or more tasks in a first wellbore operation.
5. The modular system according to any preceding claim wherein the two or more modules are configured to be assembled and/or arranged into a second configuration to perform one or more tasks in a second wellbore operation.
6. The modular system according to any preceding claim wherein the two or more modules are configured to be arranged in a different configurations by adding to or removing at least one module from the integrated structure depending on the wellbore operation.
7. The modular system according to any preceding claim wherein the two or more modules are arranged in a vertical and/or horizontal stacked arrangement.
The modular rig system according to any preceding claim wherein the arrangement of the two or more modules in the integrated structure are configured to transfer loads acting on each of the two or more modules directly to a base support structure.
The modular system according to any preceding claim wherein the modular rig system is selected from the group comprising a tubular handling system, a tubular lifting system, a pipe removal system, a conductor pipe handling system, a drill system and/or a wireline system.
10. The modular system according to any preceding claim wherein the wellbore operation is selected from the group comprising running in, pulling out, drilling, milling, workover, completion and/or decommissioning operation.
11. The modular system according to any preceding claim wherein the two or more modules is selected from the group comprising lifting module, crane module, iron roughneck, platforms, slip assembly, top drive assembly, elevator assembly, lubricator system, mast; support mast; catwalk module, monkey arm, racker, radial racker, BOP module, base support module, lift support module, crane module, jib crane module, diamond cutter, skidding system, driller cabin, motor control centre, sub-structure, bell nipple frame, pipe handling module and/or tubular storage module.
12. The modular system according to claim 11 wherein at least one module comprises at least one lifting module.
13. The modular system according to claim 12 wherein the at least one lifting module comprises at least one lifting mechanism selected from the group comprising a jack system, screw jack, hydraulic cylinder, pulley system, rack and pinion system, linear motor or any other lifting device.
14. The modular system according to any preceding claim comprising two or more lifting mechanisms where a first lifting mechanism is configured to lift or lower a tubular a first distance and a second mechanism is configured to lift and/or lower a tubular a second distance.
15. The modular system according to claim 14 wherein the two or more lifting mechanisms are hydraulically connected and configured to transfer hydraulic fluids between the two or more lifting mechanisms.
16. The modular system according to any preceding claim wherein the two or more modules are configured for continuously and/or automatic tripping.
17. A method of configuring a modular rig system comprising: providing a modular rig system comprising two or more modules wherein each module comprising at least one rig system component; wherein the two or more modules are configured to be connected or interconnected together to form an integrated structure; assembling the two or more modules in a first configuration to form an integrated structure to perform a first well operation.
18. The method according to claim 17 comprising assembling the two more modules into at least a second configuration to perform at least a second well operation.
19. The method according to claim 17 or 18 wherein the first well operation and/or second well operation is selected from the group comprising a wellbore tubular lifting operation, a drilling operation, a pipe removal operation, a conductor jacking operation, completion operation and/or a wireline operation.
20. The method according to any of claims 17 to 19 comprising arranging the two or more modules in a stacked or connected arrangement to form an integrated structure.
21. The method according to claim comprising removing, adding and/or repositioning at least one module in the integrated structure to form the second configuration.
22. A method of operating a modular rig system comprising: providing a modular rig system comprising two or more modules each module comprising at least one rig system component; wherein the two or more modules are configured to be connected or interconnected together so as to form an integrated structure; assembling the two or more modules in a first configuration to form an integrated structure; performing a first well operation; reconfiguring the two or more module to form a second configuration-and performing a second well operation.
23. The method according to claim 22 wherein the first or second well operation is a tubular handling operation, wherein system comprises at least one lifting module comprising a lifting mechanism configured to lift and/or lower a tubular; and actuating the lifting mechanism to lift or lower a tubular section out from or into the wellbore.
24. The method according to claim 22 wherein the first or second well operation is a drilling operation, wherein system comprises at least one lifting module and a top drive module; wherein the at least one lifting module comprising two or more lifting mechanisms configured to support the load of the top drive module; moving a top drive module connected to a drill pipe member a first vertical distance using a first lifting mechanism; transferring the load of the top drive module to a second lifting mechanism and moving the top drive module a second vertical distance using the second lifting mechanism.
25. The method according to claim 22 wherein the first or second well operation is a wireline operation, wherein the system comprises at least a wireline assembly and a crane module; lifting the wireline assembly into position above the wellbore; passing a wireline into the well; and conducting the wireline operation.