Compensating rig floor

Abstract

A system (92) includes a first structure (106) configured to be coupled to a tubular column extending to a seafloor (14), whereby the first structure (106) includes a rig floor (26). The system also includes a second structure (96) configured to provide a lateral force to the first structure (106) while allowing vertical movement between the first structure (106) and the second structure (96) relative to the seafloor (14).

Description

[0001] Cross-references to related applications

[0002] This application is a non-provisional application claiming priority to U.S. Provisional Patent Application No. 62 / 893,741, filed August 29, 2019, entitled “Offshore Platform,” which is incorporated herein by reference. Background Technology

[0003] This section is intended to introduce the reader to various aspects of the technology that may be related to the following descriptions and / or the claimed aspects of this disclosure. This discussion is intended to help provide the reader with background information to facilitate a better understanding of the various aspects of this disclosure. Therefore, it should be understood that these statements are to be understood from this perspective, and not as an admission of prior art.

[0004] Advances in the oil industry have enabled access to oil and gas drilling locations and reservoirs that were previously inaccessible due to technological limitations. For example, technological advancements have allowed for drilling offshore wells in increasingly deeper waters and harsher environments, enabling oil and gas resource owners to successfully drill for energy resources that were previously unavailable. Similarly, drilling advancements have allowed for greater access to onshore reservoirs.

[0005] However, offshore drilling and production facilities (e.g., offshore platforms) may encounter problems not typically found in land-based drilling and production facilities. For example, when operating in water, lateral positioning techniques and systems (e.g., thrusters or similar devices) can be used to counteract lateral movement caused by currents, waves, etc. Furthermore, maintaining the stability of offshore platforms is also crucial. One technique for maintaining the stability of offshore platforms is to design the platform with sufficient waterline area (e.g., the enclosed area of ​​the facility hull at the waterline) to allow for stability. However, while increasing the waterline area of ​​an offshore platform can increase its stability (e.g., its ability to resist roll (lateral / left-right movement) and surge (longitudinal / backward movement) caused by ocean conditions), it can also increase its sensitivity to undulations (e.g., vertical / up-down movement). Solutions addressing undulations in offshore platforms and / or their impact on components are therefore necessary. Attached Figure Description

[0006] Figure 1 An example of an offshore platform having a riser connected to a blowout preventer (BOP) according to an embodiment is shown;

[0007] Figure 2 Examples of embodiments are shown. Figure 1 A schematic front view of a first embodiment of the drilling rig;

[0008] Figure 3 a drilling rig according to an embodiment is shown; Figure 2 a front view of a tripping device according to an embodiment is shown;

[0009] Figure 4 a front view of a drilling rig according to an embodiment is shown; Figure 1 a front view of a second embodiment of a drilling rig schematically presented according to an embodiment is shown;

[0010] Figure 5 a block diagram of a computing system according to an embodiment is shown; Figure 2

[0011] Figure 6 a front view of a third embodiment of a drilling rig according to an embodiment is shown; Figure 1 an isometric view of a third embodiment of a drilling rig schematically presented according to an embodiment is shown;

[0012] Figure 7 a side view of a third embodiment of a drilling rig according to an embodiment is shown; and Figure 6

[0013] Figure 8 a flowchart of an actuation system of a drilling rig according to an embodiment is shown; Figure 6 7 a flowchart of an actuation system of a drilling rig according to an embodiment is shown. DETAILED DESCRIPTION

[0014] One or more specific embodiments will be described below. To provide a context for the various embodiments, Figure 1 shows, in simplified form, a diagram of a drilling rig 100 according to an embodiment. In order to provide a concise description of these embodiments, all features of an actual implementation can not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which can vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0015] When introducing elements of various embodiments, the articles "a," "an," "the," and "said" are intended to mean that there are one or more of the elements. The terms "comprising," "including," and "having" are intended to be inclusive and mean that there can be additional elements other than the listed elements.

[0016] ​​​Systems and techniques for stabilizing a drill floor of an offshore platform (e.g., a semi-submersible platform, a drillship, a jack-up platform, a floating production system, etc.) are set forth below. The offshore platform can include a drill floor suspended above a deck of the offshore platform. The drill floor can be limited in horizontal movement relative to the deck of the offshore platform, and the drill floor can be vertically moved in a controlled manner toward and away from the deck of the offshore platform to counteract heave (e.g., vertical / up-and-down motion) relative to the seafloor. In some embodiments, an actuation system, which can include one or more drawworks, for example, can be used to effect control of the vertical movement of the drill floor relative to the deck of the offshore platform.

[0017] With the above in mind, Figure 1 The offshore platform 10 is shown as a drillship. Although the current illustrated embodiment of the offshore platform 10 is a drillship (e.g., a vessel equipped with a drilling system and engaged in offshore oil and gas exploration and / or well maintenance or completion work, including but not limited to casing and tubing installations, subsea Christmas tree installations, and well caps), other offshore platforms 10 such as semi-submersible platforms, jack-up drilling platforms, jack-up platforms, floating production systems, etc. can be substituted for the drillship. Indeed, while the techniques and systems described below are described in connection with a drillship, these techniques and systems are intended to cover at least the additional offshore platforms 10 described above. These techniques can also be applicable at least to vertical drilling (or drilling) or production operations (e.g., having a rig in a predominantly vertical orientation drilling or producing from a substantially vertical well) and / or directional drilling or production operations (e.g., having a rig in a predominantly vertical orientation drilling or producing from a substantially non-vertical or deviated well and / or orienting the rig at an angle from vertical to drill or produce from a substantially non-vertical or deviated well).

[0018] As Figure 1 shown, the offshore platform 10 includes a riser string 12 extending therefrom. The riser string 12 can include a pipe or series of pipes that connect the offshore platform 10 to the seafloor 14 through a BOP 16 coupled to a wellhead 18 on the seafloor 14, for example. In some embodiments, the riser string 12 can transport produced hydrocarbons and / or production materials between the offshore platform 10 and the wellhead 18, and the BOP 16 can include at least one BOP stack having at least one valve with a sealing element for controlling drilling hole fluid flow. In some embodiments, the riser string 12 can pass through (or pass) an opening (e.g., moonpool) in the offshore platform 10 and can be coupled to drilling equipment of the offshore platform 10. As Figure 1 shown, it can be desirable to position the riser string 12 in a vertical orientation between the wellhead 18 and the offshore platform 10 to allow a drill string composed of drill pipe 20 to pass from the offshore platform 10 through the BOP 16 and the wellhead 18 and into a drilling hole below the wellhead 18. Figure 1Also shown is a rig 22 (e.g., a drilling rig, etc.) that can be used for drilling and / or servicing of a wellbore below the wellhead 18.

[0019] Figure 2 Components of the rig 22 are shown in more detail, as are additional components used in various operations (e.g., tripping operations). As shown, a tripping device 24 is positioned on a rig floor 26 in the rig 22 above a platform 28. The rig 22 can include one or more of, for example, the tripping device 24, a kelly block 30 positioned in a rotary table 32, a drawworks 34, a crown block 35, a traveling block 36, a top drive 38, an elevator 40, and a tubular handling device 42. The tripping device 24 can operate to trip tubular sections (e.g., to and from the drill string), while the kelly block 30 can operate to grip and hold the drill string 20 and / or thread into the wellbore. The rotary table 32 can be a rotatable portion of the rig floor 26 that can operate as a primary or backup rotary system (e.g., a backup to the top drive 38) to impart rotation to the drill string.

[0020] The drawworks 34 can be a large spool that is powered to reel in and out a line 37 (e.g., a wireline or drill line) over the crown block 35 (e.g., a set of one or more pulleys or a block of rope 37 that passes therethrough that is vertically stationary) and the traveling block 36 (e.g., a set of one or more pulleys or a block of rope 37 that passes therethrough that is vertically movable) as a pulley block system for moving the top drive 38, the elevator 40, and any tubular members (e.g., drill pipe 20) coupled therewith. The top drive 38 can be a device that provides torque (e.g., rotates the drill string) to the drill string as an alternative to the rotary table 32, and the elevator 40 can be a mechanism that can close around the drill pipe 20 or other tubular member (or similar component) to grip and hold the drill pipe 20 or other tubular member as it is moved vertically (e.g., as it is lowered into or raised out of the wellbore). The tubular handling device 42 can operate to retrieve tubular members from a storage location 43 (e.g., a pipe rack) and position the tubular members during tripping in to help add the tubular members to the tubular string. Likewise, the tubular handling device 42 can operate to retrieve tubular members from the tubular string during tripping out and transfer the tubular members to the storage location 43 (e.g., a pipe rack) to remove the tubular members from the tubular string.

[0021] For example, during a tripping in operation, the tubular handling device 42 can position a first tubular section 44 (e.g., a first drill pipe 20) such that the tubular section 44 can be grasped by the elevator 40. The elevator 40 can be lowered, e.g., by the pulley block system, toward the tripping device 24 to be coupled to a second tubular section 46 (e.g., a second drill pipe 20) that is part of the drill string. As shown, the tripping device 24 can be positioned to receive the second tubular section 46 from the elevator 40 and to couple the second tubular section 46 to the first tubular section 44. The tripping device 24 can then be operated to lower the second tubular section 46 into the wellbore, e.g., by the pulley block system, and the first tubular section 44 can be removed from the elevator 40 and placed in the storage location 43 (e.g., a pipe rack). Figure 3As shown, the pipe running device 24 can be or can include a racker that can operate to selectively make and break threaded connections between tubular sections 44 and 46 in the tubular string. In some embodiments, the pipe running device 24 can include one or more of a stationary jaw 48, a make / break jaw 50, and a spinner 52. In some embodiments, the stationary jaw 48 can be positioned to engage and hold the second (lower) tubular section 46 below its threaded joint 54. In this manner, when the first (upper) tubular section 44 is positioned coaxially with the second tubular section 46 in the pipe running device 24, the second tubular section 46 can be held in a stationary position to allow for connection of the first and second tubular sections (e.g., by connection of the threaded joint 54 of the second tubular section 46 and the threaded joint 56 of the first tubular section 44, as shown). Figure 2

[0022] To facilitate such connection, Figure 3 The spinner 52 and make / break jaw 50, as shown in FIG. 4, can provide rotational torque. For example, in making the connection, the spinner 52 can engage and provide relatively high speed, low torque rotation to the first tubular section 44 to connect the first tubular section 44 to the second tubular section 46. Likewise, the make / break jaw 50 can engage and provide relatively low speed, high torque rotation to the first tubular section 44 to provide, for example, a rigid connection between the tubular section 44 and the tubular section 46. Further, in breaking the connection, the make / break jaw 50 can engage and exert relatively low speed, high torque rotation on the first tubular section 44 to break the rigid connection. Thereafter, the spinner 52 can provide relatively high speed, low torque rotation to the first tubular section 44 to break the first tubular section 44 from the second section 46.

[0023] In some embodiments, the pipe running device 24 can also include a mud bucket 58 that can operate to capture drilling fluid that can otherwise be released during, for example, a break-out operation. In this manner, the mud bucket 58 can operate to prevent drilling fluid from spilling onto the rig floor 26. In some embodiments, the mud bucket 58 can include one or more seals that facilitate fluidly sealing the mud bucket 58 as well as a discharge line that operates to allow drilling fluid contained within the mud bucket 58 to be returned to a drilling fluid reservoir.

[0024] Returning to Figure 2 ​In some embodiments, one or more sensors 60 can be used in conjunction with make-up (e.g., tripping in) and break-out (e.g., tripping out) operations. In one embodiment, one or more sensors 60 can include, but are not limited to, cameras (e.g., high frame rate cameras), lasers (e.g., multi-dimensional lasers), transducers (e.g., ultrasonic transducers), electrical and / or magnetic property sensors (e.g., sensors that can measure / infer capacitance, inductance, magnetism, etc.), chemical sensors, metallurgical detection sensors, etc. In some embodiments, one or more sensors 60 can also be proximity sensors or other sensors (e.g., rotational sensors such as optical encoders, magnetic speed sensors, reflective sensors, Hall effect sensors, load cells such as inline load cells) to detect operating characteristics of drawworks 34 (e.g., rotation of the drum, speed of the drum, tension on the rope 37, etc.) can include or be coupled to a transmitter. In some embodiments, one or more sensors 60 can generate a signal indicative of the operating characteristics of drawworks 34 and can transmit the signal indicative of the operating characteristics of drawworks 34 (wirelessly or through a physical connection) to computer system 62, either by itself or through a transmitter coupled thereto. This signal can be used by computer system 62 to determine the position of an object (e.g., drill pipe 20, top drive 38, elevator 40, threaded joint 54 of drill pipe 20, or threaded joint 56 of drill pipe 20) as the position of the object will be directly related to the operation of drawworks 34 (e.g., the tension of rope 37 or the amount of rotation of the drum that extends rope 37 from drawworks 34, which defines the position of the object suspended from the catenary system). The determined position of the object can be used, for example, to determine and / or control the position and timing of moving tripping apparatus 24 into position (e.g., tool joint identification) to perform tripping operations. Likewise, computer system 62 can monitor the tension value of rope 37 and cause the tension to be maintained at a particular value or range of values to help maintain a desired tension of rope 37.

[0025] In some embodiments, computing system 62 can be communicatively coupled to a separate main control system, e.g., a control system in the driller’s cabin, which can provide a centralized control system for drilling control, automated pipe handling control, etc. In other embodiments, computing system 62 can be part of the main control system (e.g., present in the control system in the driller’s cabin).

[0026] Figure 4A computing system 62 is shown. It should be noted that the computing system 62 can be a standalone unit (e.g., a control monitor) that can operate to generate output control signals (e.g., to form a control system). Likewise, the computing system 62 can be configured to operate in conjunction with one or more of the following: the tripping device 24; the drawworks 34, the top drive 38, and the elevator 40; and / or the tubular handling device 42. The computing system 62 can be a general or special purpose computer that includes a processing device 64, such as one or more application specific integrated circuits (ASICs), one or more processors, or another processing device that interacts with one or more tangible, non-transitory machine-readable media (e.g., a memory 66) of the computing system 62 that is operable to collectively store instructions that are executable by the processing device 64 to perform the methods and actions described herein. By way of example, such machine-readable media can include RAM, ROM, EPROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to carry or store desired program codes in the form of machine-executable instructions or data structures and that can be accessed by the processing device 64. In some embodiments, the instructions executable by the processing device 64 are used to generate control signals that are to be sent to, for example, one or more of the following: the tripping device 24 (e.g., one or more of the stationary jaws 48, the make / break jaws 50, and the spinner 52), the tubular handling device 42, the drawworks 34, the top drive 38, and the elevator 40 or controllers thereof, and / or a main control system (e.g., to control one or more of the tripping device 24, the stationary jaws 48, the make / break jaws 50, the spinner 52, the drawworks 34, the top drive 38, the elevator 40, and / or the tubular handling device 42) in the manner described herein.

[0027] The computing system 62 can operate in conjunction with a software system implemented as computer-executable instructions stored in a non-transitory machine readable medium (e.g., memory 66, a hard drive, or other short and / or long term storage device) of the computing system 62. In particular, the processing device 64 can operate in conjunction with a software system implemented as computer-executable instructions (e.g., code) stored in a non-transitory machine readable medium (e.g., memory 66) of the computing system 62 that can be executed to receive information (e.g., signals or data) related to the sensitivity of surge and / or swabbing pressure characteristics and well pressure characteristics. This information can be used by the computing system 62 (e.g., by the processing device 64 executing the computer-executable instructions stored in the memory 66) to generate or otherwise calculate a trip plan that can be used to limit trip-out operations speeds to predetermined levels at predetermined times and / or well depths. Moreover, this determined trip plan can be used to initiate or control movement and / or operation of the tripping device 24 and / or associated tripping elements (e.g., drawworks 34, top drive 38, elevator 40, and / or tubular handling device 42) to facilitate make-up or break-out (e.g., tripping) operations by the computing system 62, the main control system, or by local controllers of the tripping device 24 and / or associated tripping elements (e.g., drawworks 34, top drive 38, elevator 40, and / or tubular handling device 42).

[0028] In some embodiments, the computing system 62 can also include one or more input structures 68 (e.g., one or more of a keyboard, a mouse, a touchpad, a touchscreen, one or more switches, buttons, etc.) to allow a user to interact with the computing system 62, for example, to initiate, control, or operate a graphical user interface (GUI) or an application running on the computing system 62 and / or to initiate, control, or operate the tripping device 24 (e.g., one or more of the fixed jaws 48, the make-up / break-out jaws 50, and the spinner 52), the tubular handling device 42, and / or additional systems of the rig 22. Additionally, the computing system 62 can include a display 70, which can be a liquid crystal display (LCD) or another type of display that allows a user to view images generated by the computing system 62. The display 70 can include a touchscreen, which can allow a user to interact with a GUI of the computing system 62. Likewise, the computing system 62 can additionally and / or alternatively send images to a display of the main control system, which itself can also include a processing device 64, a non-transitory machine readable medium (e.g., memory 66), one or more input structures 68, a display 70, and / or a network interface 72.

[0029] Returning to the computing system 62, it can be appreciated that the GUI can be a type of user interface that allows a user to interact with the computer system 62 and / or one or more sensors that send data to the computing system 62 through, for example, graphical icons, visual indicators, and the like. Further, the computer system 62 can include a network interface 72 to allow the computer system 62 to interface with various other devices, such as electronic devices. The network interface 72 can include one or more of a Bluetooth interface, a local area network (LAN) or wireless local area network (WLAN) interface, an Ethernet or Ethernet-based interface (e.g., Modbus TCP, EtherCAT, and / or ProfiNET interface), a fieldbus communication interface (e.g., Profibus), and / or other industrial protocol interfaces that can be coupled to a wireless network, a wired network, or a combination thereof, which can use, for example, a multi-drop and / or star topology, with each network leg being multi-connected to a reduced number of nodes.

[0030] In some embodiments, the tripping device 24 (and / or a controller or control system associated therewith), the tubular handling device 42 (and / or a controller or control system associated therewith), associated tripping elements (e.g., the drawworks 34, the top drive 38, the elevator 40, and / or the tubular handling device 42), and / or the main control system can each be devices that can be coupled to the network interface 72. In some embodiments, the network formed by the interconnection of one or more of the above-described devices should operate to provide sufficient bandwidth and sufficiently low latency to exchange all needed data within a time period consistent with all control sequencing and closed loop control function dynamic response requirements of the network and / or devices associated therewith. It can also be advantageous for the network to allow for deterministic sequencing response times and closed loop performance, and the network components should allow for use in an oilfield / drilling vessel environment (e.g., should allow for robust physical and electrical characteristics consistent with their respective operating environments, including but not limited to withstanding electrostatic discharge (ESD) events and other threats, and meeting any electromagnetic compatibility (EMC) requirements of the respective environments in which the network components are disposed). The network used can also provide sufficient data protection and / or data redundancy to ensure that the operation of the network is not compromised, for example, by data corruption (e.g., by using error detection and correction or error control techniques to avoid or reduce errors in transmitted network signals and / or data).

[0031] The computing system 62 can operate in conjunction with additional embodiments of a drilling rig. For example, Figure 5 Another embodiment of a drilling rig 84 is shown that can be used in operations, such as tripping operations consistent with embodiments of the present disclosure, and can operate in conjunction with Figure 5 the computing system 62. As Figure 5As shown, the pipe running device 24 is positioned above the drill floor 26 in the rig 84. However, as will be discussed in greater detail below, the pipe running device 24 can be moved toward and away from the drill floor 26 during pipe running operations. As shown, the rig 84 can include one or more of, for example, the pipe running device 24, the movable platform 86 (which can include the drill floor slips 30 positioned in the rotary table 32, as shown), the drawworks 34, the crown block 35, the traveling block 36, the top drive 38, the elevators 40, and the tubular handling device 42. The pipe running device 24 is operable to couple and decouple tubular sections (e.g., to couple and decouple the drill pipe 20 to and from the drill string), while the drill floor slips 30 can be operable to grip and hold the drill pipe 20 and / or the drill string being run into the wellbore. The rotary table 32 can be a rotatable section that can be locked into position co-planar with and / or above the drill floor 26. For example, the rotary table 32 can operate as a primary or backup rotary system (e.g., backup to the top drive 38) to impart rotation to the drill string and to support tubular sections with its drill floor slips 30, for example, during pipe running operations, or can be a dummy rotary table that does not impart rotation to the drill string while still allowing tubular sections to be supported with its drill floor slips 30. Figure 5 As shown, the pipe running device 24 is positioned above the drill floor 26 in the rig 84. However, as will be discussed in greater detail below, the pipe running device 24 can be moved toward and away from the drill floor 26 during pipe running operations. As shown, the rig 84 can include one or more of, for example, the pipe running device 24, the movable platform 86 (which can include the drill floor slips 30 positioned in the rotary table 32, as shown), the drawworks 34, the crown block 35, the traveling block 36, the top drive 38, the elevators 40, and the tubular handling device 42. The pipe running device 24 is operable to couple and decouple tubular sections (e.g., to couple and decouple the drill pipe 20 to and from the drill string), while the drill floor slips 30 can be operable to grip and hold the drill pipe 20 and / or the drill string being run into the wellbore. The rotary table 32 can be a rotatable section that can be locked into position co-planar with and / or above the drill floor 26. For example, the rotary table 32 can operate as a primary or backup rotary system (e.g., backup to the top drive 38) to impart rotation to the drill string and to support tubular sections with its drill floor slips 30, for example, during pipe running operations, or can be a dummy rotary table that does not impart rotation to the drill string while still allowing tubular sections to be supported with its drill floor slips 30.

[0032] The drawworks 34 can be a large spool that is powered to reel in and out of the crown block 35 (e.g., a set of one or more stationary pulleys or a block of rope 37 that the rope 37 passes over) and the traveling block 36 (e.g., a set of one or more vertically movable pulleys or a block of rope 37 that the rope 37 passes over) to operate as a pulley block system for moving the top drive 38, the elevators 40, and any tubular members (e.g., drill pipe 20) coupled thereto. In some embodiments, the top drive 38 and / or the elevators 40 can be referred to as a tubular support system, or the tubular support system can additionally include the pulley block system described above.

[0033] The top drive 38 can be a device that provides torque to the drill string (e.g., rotates the drill string) as an alternative to the rotary table 32, and the elevators 40 can be mechanisms that can close around the drill pipe 20 or other tubular sections (or similar components) to grip and hold the drill pipe 20 or other tubular sections as they are moved vertically (e.g., as they are lowered into or raised out of the wellbore) or directionally (e.g., during directional drilling). The tubular handling device 42 is operable to retrieve tubular sections from a storage location 43 (e.g., a pipe rack) and position the tubular sections during pipe running in to assist in adding the tubular sections to the tubular string. Likewise, the tubular handling device 42 is operable to retrieve tubular sections from the tubular string during pipe running out and transfer the tubular sections to a storage location (e.g., a pipe rack) to remove the tubular sections from the tubular string.

[0034] During a trip-in operation, the tubular handling device 42 can position the tubular section 44 (e.g., drill pipe 20) so that the section 44 can be grasped by the elevator 40. The elevator 40 can be lowered, e.g., by a block and tackle system, toward the tripping device 24 to be coupled to the tubular section 46 (e.g., drill pipe 20) that is part of the drill string. In some embodiments, the tripping device 24 can operate as discussed above in connection with the trip-out operation during the trip-in operation. However, while the trip-in operation has been discussed in connection with the tripping of a single tubular section 44 and 46 (e.g., drill pipe 20), it is contemplated that a stand of tubular sections 44, 46 (e.g., two, three, or more tubular sections 44, 46 coupled together) can be tripped in or out. Moreover, by including the movable platform 86, continuous tripping operations (tripping of tubular sections without stopping the movement of the pipe string at a fixed location) can be facilitated and / or expedited. Figure 3 Figure 2-5 However, while the trip-in operation has been discussed in connection with the tripping of a single tubular section 44 and 46 (e.g., drill pipe 20), it is contemplated that a stand of tubular sections 44, 46 (e.g., two, three, or more tubular sections 44, 46 coupled together) can be tripped in or out. Moreover, by including the movable platform 86, continuous tripping operations (tripping of tubular sections without stopping the movement of the pipe string at a fixed location) can be facilitated and / or expedited.

[0035] The movable platform 86 can be raised and lowered by a cable and tackle wheel arrangement (e.g., similar to the block and tackle system used to move the top drive 38), which can include a winch or other drawworks element located on the drilling floor 26 or other location on the offshore platform 10 or rig 22. The winch or other drawworks element can be a spool that is powered to take in and extend a line (e.g., a wireline) over a crown block (e.g., a stationary set of one or more sheaves or tackle wheels through which the line 37 passes) and a traveling block (e.g., a movable set of one or more sheaves or tackle wheels through which the line 37 passes) to operate as a block and tackle system for moving the movable platform 86, and thus the rotary table 32 therein and the tripping device 24 thereon. Additionally and / or alternatively, one or more direct acting cylinders, pendant winches and cable systems, or other internal or external actuation systems can be used to move the movable platform 86 along the one or more supports 88.

[0036] ​In some embodiments, the one or more supports 88 can be one or more guide mechanisms (e.g., rails, such as top drive skid tracks) that provide support (e.g., lateral support) to the movable platform 86 while allowing movement toward and away from the rig floor 26. One or more lateral supports of the movable platform 86 can be used to couple the movable platform 86 to the one or more supports 88. For example, the one or more lateral supports of the movable platform 86 can be pads, for example, that can be made of Teflon-graphite material or another low-friction material (e.g., a composite material) that allows the movable platform 86 to move with reduced frictional characteristics relative to the rig floor 26 and / or the tubular segment support system. Other lateral supports of the movable platform 86 can be used in addition to or instead of the pads described above, including bearing or roller-type supports (e.g., steel or other metal or composite rollers and / or roller bearings). The lateral supports of the movable platform 86 can allow the movable platform 86 to interface with a guide (e.g., a rail, such as a top drive skid track) such that the movable platform 86 is movably coupled to the one or more supports 88. Thus, the movable platform 86 can be movably coupled to the one or more supports 88 to allow the movable platform 86 to move (e.g., toward and away from the rig floor 26 and / or the tubular segment support system while maintaining contact with the rail or other guide) during a tripping operation (e.g., a continuous tripping operation).

[0037] Figure 6An embodiment is shown in which a rig 90 similar to the rigs described above can be used. For example, the rig 90 can be substantially similar to the rig 22 or the rig 84 as described above. However, as described herein, the rig 90 can include an active heave compensation system 92. The active heave compensation system 92 includes, for example, one or more active heave winches 94 and a fixed frame 96 that encloses at least one of the rig floor 26 and the derrick 98. In some embodiments, the one or more active heave winches 94 can be defined as the actuation system and / or the actuation system can employ other hoisting components in place of or in addition to the one or more active heave winches 94. The one or more active heave winches 94 can be large spools that are powered to take in and extend a rope 37 (e.g., a wireline or drill line) over a set of one or more sheaves or rope 37 passing through a cathead. The set of one or more sheaves or catheads can be a cable and cathead arrangement similar to the sheave block system described above, and the rope 37 can be a single cable that is routed from a first active heave winch 94 through the cable and cathead arrangement to a second active heave winch 94 in a manner described below. Likewise, the rope 37 can be a single cable that is routed from the first active heave winch 94 through the cable and cathead arrangement to a connector (e.g., an anchor bolt, a ring bolt, an eye, an eye plate, or other connector) coupled to, on, or in the deck 28 that operates as an anchor point in a manner described below. In other embodiments, the active heave and compensation system 92 can include an actuation system that includes elements operating in parallel, for example, a first rope 37 that is a single cable that is routed from a first active heave winch 94 through the cable and cathead arrangement to a second active heave winch 94 in a manner described below; and a second rope 37 that is a second single cable that is routed from a third active heave winch 94 through a cable and cathead arrangement (or a second cable and cathead arrangement) to a fourth active heave winch 94 in a manner described below. Likewise, the rope 37 can be a single cable that is routed from the first active heave winch 94 through the cable and cathead arrangement to a connector (e.g., an anchor bolt, a ring bolt, an eye, an eye plate, or other connector) coupled to, on, or in the deck 28 that operates as an anchor point in a manner described below, and the second rope 37 can be a second single cable that is routed from the second active heave winch 94 through the cable and cathead arrangement (or the second cable and cathead arrangement) to a second connector (or the first connector) coupled to, on, or in the deck 28 that operates as an anchor point in a manner described below. In this manner, the actuation system can be operated in parallel. Further, the active heave compensation system 92 can include a cable and cathead arrangement (e.g., a set of one or more sheaves or catheads).

[0038] In some embodiments, the cable and pulley arrangement (e.g., one or more sets of pulleys or sheaves) coupled to the one or more active heave winches 94 can include one or more upper sheaves 100 disposed, for example, on an upper portion or topmost portion of the fixed frame 96. In one embodiment, a first upper sheave 100 is disposed on a topmost beam of the fixed frame 96 at a first corner of an upper portion of the fixed frame 96 and a second upper sheave 100 is disposed on the topmost beam of the fixed frame 96 at a second corner of the upper portion of the fixed frame 96. In some embodiments, there is an upper sheave 100 corresponding to each active heave winch 94. Each of the one or more upper sheaves 100 can be disposed at a respective corner of the upper portion or topmost portion of the fixed frame 96 (e.g., a first upper sheave 100 is disposed at a first upper corner of the fixed frame 96 and a second upper sheave 100 is disposed at a second upper corner of the fixed frame 96), whereby the first and second upper corners of the fixed frame 96 on which the upper sheaves 100 are disposed are adjacent to the active heave winches 94 (or the physical connection or anchor point). The one or more upper sheaves 100 can receive the rope 37 directly from their respective active heave winches 94 (or from the physical connection or anchor point).

[0039] In addition, the cable and pulley arrangement (e.g., one or more sets of pulleys or sheaves) can also include one or more lower sheaves 102 and one or more lower sheaves 104. The one or more lower sheaves 102 can be coupled to a lower side of the upper portion or topmost portion of the fixed frame 96. In this manner, the one or more lower sheaves 102 can be disposed generally below (toward the deck 28) the one or more upper sheaves 100. For example, the one or more lower sheaves 102 can be disposed below (on a lower side toward the deck 28) a beam or other support on which the one or more upper sheaves 100 are disposed. In some embodiments, one or more (e.g., two, three, or more) sheaves of the one or more lower sheaves 102 can be disposed below each of the one or more upper sheaves 100. For example, the one or more lower sheaves 102 can be disposed at respective corners of the upper portion or topmost portion of the fixed frame 96 (e.g., a first one or more lower sheaves 102 can be disposed at a first upper corner of the fixed frame 96 below a beam or other support on which a first upper sheave 100 is disposed, i.e., below the first upper sheave 100, and a second one or more lower sheaves 102 can be disposed at a second upper corner of the fixed frame 96 below a beam or other support on which a second upper sheave 100 is disposed, i.e., below the second upper sheave 100), whereby the first and second upper corners of the fixed frame 96 on which the lower sheaves 102 are disposed are adjacent to the active heave winches 94 (or the physical connection or anchor point).

[0040] Similarly, one or more lower trolley wheels 104 can be coupled to the underside of the upper portion or topmost portion of the fixed frame 96. In some embodiments, one or more (e.g., two, three, or more) trolley wheels, such as one or more lower trolley wheels 104, can be disposed along the underside of the upper portion or topmost portion of the fixed frame 96. The one or more lower trolley wheels 104 can also be disposed generally below (toward the deck 28) the one or more upper trolley wheels 100. For example, the one or more lower trolley wheels 104 can be disposed below (on the underside toward the deck 28) the beam or other support on which the one or more upper trolley wheels 100 are disposed. However, the one or more lower trolley wheels 104 can also be spaced apart from the one or more upper trolley wheels 100 along the length of the fixed frame 96.

[0041] For example, the first one or more lower trolley wheels 104 can be disposed at a respective corner of the upper portion or topmost portion of the fixed frame 96 (e.g., the first one or more lower trolley wheels 104 can be disposed at the third upper corner of the fixed frame 96 below the beam or other support on which the first upper trolley wheel 100 is disposed, i.e., below the first upper trolley wheel 100 and at a distance along the length of the fixed frame 96 from the first upper trolley wheel 100). Likewise, for example, the second one or more lower trolley wheels 104 can be disposed at a separate respective corner of the upper portion or topmost portion of the fixed frame 96 (e.g., the second one or more lower trolley wheels 104 can be disposed at the fourth upper corner of the fixed frame 96 below the beam or other support on which the first upper trolley wheel 100 is disposed, i.e., below the second upper trolley wheel 100 and at a distance along the length of the fixed frame 96 from the second upper trolley wheel 100). Thus, the first one or more lower trolley wheels 102 and the first one or more lower trolley wheels 104 can be disposed on or coupled to the underside of the upper portion or topmost portion of the fixed frame 96 at a distance along the length of the fixed frame 96 such that each of the first one or more lower trolley wheels 102 and the first one or more lower trolley wheels 104 is disposed in a respective upper corner of the fixed frame 96. Likewise, the second one or more lower trolley wheels 102 and the second one or more lower trolley wheels 104 can be disposed on or coupled to the underside of the upper portion or topmost portion of the fixed frame 96 at a distance along the length of the fixed frame 96 such that each of the first one or more lower trolley wheels 102 and the first one or more lower trolley wheels 104 is disposed in a respective upper corner of the fixed frame 96. Thus, in one embodiment, each upper corner of the fixed frame 96 can have a set of one or more lower trolley wheels 102 or one or more lower trolley wheels 104 disposed thereat.

[0042] The active heave compensation system 92 also includes, for example, a heave compensation frame 106. The heave compensation frame 106 can be a structure that includes the drill floor 26 as a base, one or more structural beams 108 disposed, for example, along edges of the drill floor 26 and / or at corners and extending vertically (e.g., perpendicularly) away from the drill floor 26, and one or more upper beams 110 extending horizontally (e.g., perpendicular to the one or more structural beams 108) and coupled to the structural beams 108. The heave compensation frame 106 can be coupled to a tubular column that extends to the seafloor 14 and / or into a wellbore below the seafloor 14. For example, a drill string composed of the drill pipe 20 can be held by the drill floor slips 30 of the drill floor 26, whereby the drill string extends to the seafloor 14 and / or into a wellbore below the seafloor 14. In some embodiments, the derrick 98 is disposed on the one or more upper beams 110. The heave compensation frame 106 is sized to fit within the stationary frame 96. The heave compensation frame 106 can be slidably coupled to the stationary frame 96 such that the heave compensation frame 106 can move toward and away from the deck 28 while the stationary frame 96 remains stationary relative to the deck 28. The stationary frame 96 can also limit lateral movement (e.g., movement in a horizontal direction along the deck 28) of the heave compensation frame 106. In this manner, the heave compensation frame 106 is slidably coupled to the stationary frame 96 (e.g., the heave compensation frame 106 is able to move in one plane relative to the stationary frame 96 while being restricted from moving in a second plane relative to the stationary frame).

[0043] In some embodiments, one or more guides (e.g., rails, etc.) can be used to couple the heave compensation frame 106 to the fixed frame 96. For example, upper guides 112 can be disposed along each vertical support column of the fixed frame 96 at a location below the upper guides 112 (e.g., toward the deck 28) and lower guides 114 can be disposed along each vertical support column of the fixed frame 96. In some embodiments, there can be one or more guides (e.g., upper guides 112 and lower guides 114) corresponding to each structural beam 108 of the heave compensation frame 106. In some embodiments, one or more lateral supports can be coupled to one or more drill floors 26, one or more structural beams 108, and / or one or more upper beams 110 to couple the heave compensation frame 106 to the fixed frame. In some embodiments, the one or more guides and the one or more lateral supports can be male-female connectors or other types of connectors. For example, the one or more lateral supports can be, for example, pads that can be made of Teflon-graphite material or another low-friction material (e.g., composite material) that allows the heave compensation frame 106 to move with reduced frictional characteristics relative to the drill floor 26. Other lateral supports can be used in addition to or instead of the pads described above, including bearing or roller-type supports (e.g., steel or other metal or composite rollers and / or roller bearings) to allow for horizontal load transfer between the heave compensation frame 106 and the fixed frame 96 with minimal resistance to vertical movement. The one or more lateral supports can allow the heave compensation frame 106 to engage with the one or more guides such that the heave compensation frame 106 is movably coupled to the fixed frame 96. In this way, the heave compensation frame 106 can be movably coupled to the fixed frame 96 to allow for movement of the heave compensation frame 106 (e.g., toward and away from the drill floor 26 while maintaining contact with the guide rails or other support elements of the fixed frame).

[0044] In some embodiments, the heave compensation frame 106 can be raised and lowered by the one or more active heave winches 94 by means of cables and pulley wheels. One technique for connecting the cables and pulley wheels is described below; however, it should be understood that alternative configurations are also contemplated. In one embodiment, a rope 37 can be directed from a first one of the one or more active heave winches 94 directly to a first one of the one or more upper pulley wheels 100 and passed to a connector (e.g., an anchor bolt, a carabiner bolt, an eyelet, an eye plate, a pulley, or other connector) coupled to the heave compensation frame 106 (e.g., to one of the one or more upper beams 110 at a first upper beam location) or to a pulley wheel coupled to the connector that is coupled to the heave compensation frame 106. The rope 37 can then be directed at a first location (e.g., a first upper corner) of the fixed frame 96 to a first one of the one or more lower pulley wheels 102 and passed back to the connector (or pulley wheel coupled to the connector) of the heave compensation frame 106 if another one of the one or more lower pulley wheels 102 is present at the first location. When a second one of the one or more lower pulley wheels 102 is present at the first location (e.g., a first upper corner) of the fixed frame 96, the rope 37 can then be directed at the first location (e.g., a first upper corner) of the fixed frame 96 to the second one of the one or more lower pulley wheels 102. When the second one of the one or more lower pulley wheels 102 is present at the first location (e.g., a first upper corner) of the fixed frame 96, the rope 37 can be directed at a second location (e.g., a second upper corner) of the fixed frame 96 from the second one of the one or more lower pulley wheels 102 to a first one of the one or more lower pulley wheels 104. Alternatively, when the second one of the one or more lower pulley wheels 102 is not present at the first location (e.g., a first upper corner) of the fixed frame 96, the rope 37 can be directed at the second location (e.g., a second upper corner) of the fixed frame 96 from the first one of the one or more lower pulley wheels 102 to the first one of the one or more lower pulley wheels 104.

[0045] The rope 37 can be directed from a first of the one or more lower trolley wheels 104 at the second location (e.g., the second upper corner) of the fixed frame 96 to a second connector (e.g., an anchor, a carabiner bolt, an eyelet, an eye plate, a pulley, or other connector) coupled to the heave compensation frame 106 (e.g., to one of the one or more upper beams 110 at the second upper beam location) or passed to a trolley wheel coupled to the second connector. Then, if another of the one or more lower trolley wheels 104 is present at the second location (e.g., the second upper corner) of the fixed frame 96, the rope 37 can be directed from the second connector (or the trolley wheel coupled to the second connector) to the second of the one or more lower trolley wheels 104 at the second location (e.g., the second upper corner) of the fixed frame 96. When the second of the one or more lower trolley wheels 104 is present at the second location (e.g., the second upper corner) of the fixed frame 96, the rope 37 can be directed from the second of the one or more lower trolley wheels 104 to a first of the one or more lower trolley wheels 104 at a third location (e.g., a third upper corner) of the fixed frame 96. Alternatively, when the second of the one or more lower trolley wheels 102 is not present at the second location (e.g., the second upper corner) of the fixed frame 96, the rope 37 can be directed from the second connector back to the first of the one or more lower trolley wheels 104 at the second location (e.g., the second upper corner) and then to the first of the one or more lower trolley wheels 104 at the third location (e.g., a third upper corner) of the fixed frame 96.

[0046] Rope 37 can be directed from a first of the one or more lower trolley wheels 104 at the third location (e.g., the third upper corner) of the fixed frame 96 to a third connector (e.g., an anchor, a carabiner bolt, an eyelet, an eye plate, a pulley, or other connector) coupled to the heave compensation frame 106 (e.g., to one of the one or more upper beams 110 at the third upper beam location) or passed to a trolley wheel coupled to the third connector. Then, if another of the one or more lower trolley wheels 104 is present at the third location (e.g., the third upper corner) of the fixed frame 96, rope 37 can be directed from the third connector (or the trolley wheel coupled to the third connector) to the second of the one or more lower trolley wheels 104 at the third location (e.g., the third upper corner) of the fixed frame 96. When the second of the one or more lower trolley wheels 104 is present at the third location (e.g., the third upper corner) of the fixed frame 96, rope 37 can be directed from the second of the one or more lower trolley wheels 104 to a first of the one or more lower trolley wheels 104 at the fourth location (e.g., the fourth upper corner) of the fixed frame 96. Alternatively, when the second of the one or more lower trolley wheels 102 is not present at the third location (e.g., the third upper corner) of the fixed frame 96, rope 37 can be directed from the third connector back to the first of the one or more lower trolley wheels 104 at the third location (e.g., the third upper corner) and then to the first of the one or more lower trolley wheels 104 at the fourth location (e.g., the fourth upper corner) of the fixed frame 96.

[0047] Rope 37 can be directed from a first of the one or more lower trolley wheels 102 at the fourth location (e.g., the fourth upper corner) of the fixed frame 96 to a fourth connector (anchor, eye bolt, screw eye, eye plate, pulley, or other connector) coupled to the heave compensation frame 106 (e.g., to one of the one or more upper beams 110 at the fourth upper beam location) or to a trolley wheel coupled to the fourth connector. Then, if another of the one or more lower trolley wheels 102 is present at the fourth location (e.g., the fourth upper corner) of the fixed frame 96, rope 37 can be directed from the fourth connector (or trolley wheel coupled to the fourth connector) to the second of the one or more lower trolley wheels 102 at the fourth location (e.g., the fourth upper corner) of the fixed frame 96. Rope 37 can be directed from the second of the one or more lower trolley wheels 102 to the fourth connector (or trolley wheel coupled to the fourth connector) and then to a second of the one or more upper trolley wheels 100 disposed at a second location on the fixed frame 96 at a distance approximately equal to the width of the fixed frame from the location of the first of the one or more upper trolley wheels 100. Alternatively, rope 37 can be directed from the second of the one or more lower trolley wheels 102 to the second of the one or more upper trolley wheels 100 disposed at the second location on the fixed frame 96. Further, when the second of the one or more lower trolley wheels 102 is not present at the fourth location (e.g., the fourth upper corner) of the fixed frame 96, after being directed from the first of the one or more lower trolley wheels 102 at the fourth location (e.g., the fourth upper corner) of the fixed frame 96 to the fourth connector, rope 37 can be directed to the second of the one or more upper trolley wheels 100 disposed at the second location on the fixed frame 96. Rope 37 can then be directed to a second of the one or more active heave winches 94 or to a connector (e.g., anchor, eye bolt, screw eye, eye plate, or other connector) coupled to, on, or in the deck 28 that operates as an anchor point (if the second of the one or more active heave winches 94 is not present or is not used).

[0048] Figure 7 A side view of the rig 90 described including the active heave compensation system 92 is shown. As shown, when a first of the one or more active heave winches 94 extends and retracts the rope 37 to compensate for heave, a second of the one or more active heave winches 94 can operate as an anchor (e.g., lock the rope 37 to limit its movement), as described below with respect to FIG. 6. Figure 8A second active heave winch 94 of the one or more active heave winches 94 can additionally and / or alternatively operate in conjunction with the first active heave winch 94 of the one or more active heave winches 94 to extend and retract the line 37 to compensate for heave, e.g., to increase the speed at which the line 37 can be extended and retracted. Further, a second active heave winch 94 of the one or more active heave winches 94 can be removed and a connector (e.g., an anchor, a clevis bolt, an eye, an eye plate, or other connector) coupled to, on, or in the deck 28 can be added to operate as an anchor point for the line 37. Likewise, additionally and / or alternatively, one or more direct acting cylinders or other internal or external actuation devices can be used to move the heave compensation frame 106 along the one or more guides (e.g., the upper guide 112 and the lower guide 114) in place of or in addition to the one or more active heave winches 94 as the actuation system.

[0049] Figure 7 The computing system 62 described previously is further shown. In some embodiments, the computing system 62 can operate to configure (i.e., set up) control of the one or more of the active heave winches 94, e.g., to initialize motor control of the active heave winches 94. Alternatively, the computing system 62 runs programs stored therein to control operation of the one or more active heave winches 94. Operation of the active heave compensation system 92 will be discussed below with respect to Figure 8 and 9.

[0050] Figure 8 A flowchart 116 is shown detailing operation of an actuation system according to an embodiment, e.g., the actuation system including one or more active heave winches 94. In step 118, operational values, e.g., one or more tension values and / or load values corresponding to allowable tension and / or load on the line 37, are sent to the one or more active heave winches 94. These operational values can correspond to, e.g., predetermined values of allowable tension and / or load on the line 37. Additionally or alternatively, the operational values can correspond to a predetermined range of values around predetermined values of allowable tension and / or load on the line 37. The operational values can be initially provided, e.g., by the computing system 62 or by input on the active heave winch 94, to, e.g., a motor controller or other controller of the one or more active heave winches 94.

[0051] In step 120, an operating characteristic of one or more components of the one or more active heave winches 94 is monitored. For example, one or more sensors in the one or more active heave winches 94 can determine tension on the line 37 and / or can monitor load on the line 37. The sensed operating characteristic can change during operation of the one or more active heave winches 94. For example, the offshore platform 10 can move vertically away from the seafloor 14 due to waves, wind, or other factors. This causes the deck 28 on which the one or more active heave winches 94 are disposed to move vertically away from the seafloor 14, causing tension and / or load on the line 37 to increase, which is monitored as the operating characteristic in step 120. Likewise, the offshore platform 10 can move vertically toward the seafloor 14 due to conditions or factors, causing the deck 28 on which the one or more active heave winches 94 are disposed to move vertically toward the seafloor 14, causing tension and / or load on the line 37 to decrease, which is monitored as the operating characteristic in step 120. In step 122, the operating characteristic monitored in step 120 is transmitted in step 122. The transmission can be from the one or more sensors in the one or more active heave winches 94, or from a transmitter that receives the operating characteristic from the one or more sensors.

[0052] The indication of the operating characteristic (e.g., by the transmitted signal) is received by a controller of the active heave winch 94, or in other embodiments, by the processing device 64 of the computing system 62. The controller of the active heave winch 94 or the processing device 64 of the computing system 62 determines in step 124 whether the indication of the sensed value (e.g., the operating characteristic) represents an increase, a decrease, or no change in tension and / or load on the line 37. For example, if the indication is determined to be the same as a predetermined value, approximately the same as a predetermined value (e.g., within a predetermined tolerance of the predetermined value), or within a predetermined range of a predetermined value (e.g., within a percentage of the predetermined value), the operating characteristic is deemed acceptable in step 124 and the process returns to step 120. It should be noted that the indication can be transmitted in step 122, and the determination in step 124 can be performed continuously (i.e., as an uninterrupted stream of data input and decision making), near continuously (i.e., as a stream of data input and decision making that is slowed only by data sensing time, transmission time, computation time, and other operational limiting characteristics, etc. factors), or on a schedule (e.g., approximately every five minutes, approximately every two minutes, approximately every minute, approximately twice a minute, approximately ten times a minute, approximately twenty times a minute, approximately thirty times a minute, approximately sixty times a minute, approximately a predetermined fraction of a second, or another time period).

[0053] Returning to step 124, if the controller of the active heave winch 94 or the processing device 64 of the computing system 62 determines, for example, that the indication is not approximately the same as the predetermined value (e.g., not within a predetermined tolerance of the predetermined value), or is not within a predetermined range of the predetermined value (e.g., not within a percentage of the predetermined value), at step 124, the operating characteristic is deemed unacceptable at step 124 and the process moves to step 126.

[0054] At step 126, the controller of the active heave winch 94 or the processing device 64 of the computing system 62 determines an adjustment amount for the one or more active heave winches 94 to restore the tension and / or load on the rope 37 to the predetermined value. For example, the adjustment amount can be an amount of rotation of the drum(s) of the one or more active heave winches 94 to extend or retract the rope 37 as needed to maintain the tension and / or load on the rope 37 at or within a predetermined range of the predetermined value. The adjustment amount is sent as a control signal by the controller of the active heave winch 94 or the computing system 62 to, for example, the motor control of the active heave winch 94.

[0055] At step 128, the motor controller(s) of the one or more active heave winches 94 rotate the drum(s) of the one or more active heave winches 94 based on the control signal received from the controller of the active heave winch 94 or the computing system 62. The control signal causes the amount and direction of rotation to be imparted to the drum(s) by the motor controller(s). This has the effect of maintaining the tension and / or load on the rope 37 relatively constant (i.e., at or within a predetermined range of the predetermined value), and as the rope 37 is extended from the one or more active heave winches 94 by rotation of the drum(s) in the one or more active heave winches 94, causes the heave compensation frame 106 (and the derrick 98 and including the drill floor 26) to move along the one or more guides (e.g., the upper guide 112 and the lower guide 114) toward the deck 28 as the deck 28 moves vertically away from the seafloor 14. Similarly, as the rope 37 is retracted into the one or more active heave winches 94 by rotation of the drum(s) in the one or more active heave winches 94, the control signal can cause the heave compensation frame 106 (and the derrick 98 and including the drill floor 26) to move along the one or more guides (e.g., the upper guide 112 and the lower guide 114) away from the deck 28 as the deck 28 moves vertically toward the seafloor 14. These respective operations due to the vertical movement of the offshore platform 10 relative to the seafloor 14 maintain the heave compensation frame 106 (and the derrick 98 and including the drill floor 26) at a constant or nearly constant distance from the seafloor 14, for example.

[0056] Operation of the active heave compensation system 92 allows the drilling floor 26 to move, for example, about 25 feet (e.g., plus or minus 12.5 feet relative to the hull of the offshore platform 10) to compensate for vertical movement of the offshore platform 10 relative to the sea floor 14. Use of two active heave winches 94 can provide redundancy (e.g., if only one active heave winch 94 is used in operation to adjust the tension of the rope 37, while the other is anchored) as well as enable faster adjustments (e.g., if both active heave winches 94 are used together to adjust the tension of the rope 37). Further, use of the active heave compensation system 92 can eliminate the use of a coiled tubing riser and passive heave compensation systems for the drill string, such as a crown or top-mounted compensator. Further, by utilizing the fixed frame 96 and heave compensation frame 106 as described herein, the impact on stability and wind loads can be minimized.

[0057] This written description uses examples to disclose the above-described description such that any person skilled in the art can practice the disclosure, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the disclosure is defined by the claims, and can include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. Thus, although the foregoing disclosed embodiments can be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the intention is not to limit the embodiments to the particular disclosed forms. On the contrary, the disclosed embodiments are intended to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the embodiments as defined by the following appended claims.

Claims

1. A system comprising: A first frame structure, configured to connect to a tubular column extending to the seabed, wherein the first frame structure includes a drill platform serving as the base of the first frame structure; and A second frame structure surrounds the first frame structure and is slidably connected to the first frame structure via at least one guide to provide lateral forces to the first frame structure, while allowing vertical movement relative to the seabed between the first frame structure, the offshore vessel's derrick, and the drill rig. The second frame structure includes at least one vertically arranged beam configured to be directly connected to the deck of the offshore vessel, wherein the at least one vertically arranged beam is directly connected to the at least one guide member, and The second frame structure surrounds the derrick of the offshore vessel.

2. The system according to claim 1, comprising an actuation system disposed near the second frame structure.

3. The system of claim 2, comprising an active undulating winch as at least part of the actuation system.

4. The system of claim 3, comprising a rope coupled to the active undulating winch and connected to the first frame structure.

5. The system according to claim 4, wherein, The active undulating winch includes: The drum, as part of the active undulating winch connected to the rope; and The controller, when the second frame structure moves vertically toward the seabed, controls the rotation of the drum to retract the rope around the drum.

6. The system according to claim 5, wherein, When the second frame structure moves vertically away from the seabed, the controller controls the rotation of the drum to extend the rope from the drum during operation.

7. The system according to claim 4, comprising an upper sliding wheel disposed on the second frame structure, wherein, The rope is transmitted along the upper pulley to the first frame structure.

8. The system according to claim 7, comprising a sliding wheel disposed on the second frame structure, wherein, The rope is transmitted from the first frame structure to the sliding wheel.

9. The system according to claim 8, wherein, The rope is connected to the anchor point after passing along the sliding wheel.

10. The system according to claim 8, wherein, After passing along the sliding wheel, the rope is connected to a second active undulating winch, which is the second part of the actuation system.

11. The system according to claim 10, wherein, The second active undulating winch includes: The second drum, as part of the second active undulating winch connected to the rope; and Second controller: Upon receiving a first control signal, the second controller, during operation, controls the rotation of the second drum to retract the rope around the second drum; and When a second control signal is received, the second controller controls the rotation of the second drum during operation to extend the rope from the second drum.

12. The system according to claim 11, wherein, The second controller locks the second roller during operation to generate an anchor point upon receiving a third control signal.

13. A system comprising: A first frame structure, the first frame structure comprising: The drilling platform serves as the bottom of the first frame structure; One or more beams are connected to the drill rig and disposed around the drill rig; and One or more upper beams directly connected to the one or more beams; The derrick directly connected to one or more of the upper beams; and A second frame structure, at least partially disposed around the first frame structure, contacts the first frame structure to provide lateral forces to it, while allowing vertical movement between the first frame structure and the derrick (including the drill platform and the second frame structure), while maintaining a predetermined distance between the first frame structure and the seabed. The second frame structure surrounds the derrick.

14. The system according to claim 13, wherein, The second frame structure includes one or more guides for engaging at least a portion of the first frame structure.

15. The system of claim 14, comprising a lateral support member that is a portion of the first frame structure.

16. The system according to claim 15, wherein, The lateral support includes roller bearings or pads.

17. The system of claim 13, further comprising an actuation system coupled to the first frame structure, wherein, in operation, the actuation system controls vertical movement between the first frame structure and the second frame structure to maintain a predetermined distance between the first frame structure and the seabed.

18. A tangible, non-transitory computer-readable medium having stored thereon computer-executable code, the computer-executable code comprising instructions that cause a processor to execute the following: Receive data related to the operational characteristics of a portion of the actuation system, wherein, The operating characteristics indicate the tension or load on the ropes connected to the first frame structure, the first frame structure including a drill rig as the bottom of the first frame structure, one or more beams connected to the drill rig and disposed around the drill rig, and one or more upper beams directly connected to the one or more beams, wherein the first frame structure moves vertically relative to a second frame structure, the second frame structure laterally supports the first frame structure, wherein the second frame structure includes at least one vertically arranged beam configured to be directly connected to the deck of the offshore vessel, wherein the at least one vertically arranged beam is directly connected to the first frame structure via at least one guide, and wherein the second frame structure surrounds the derrick of the offshore vessel; Determine whether the operating characteristics are acceptable; When the operating characteristics are determined to be unacceptable, an adjustment value is determined as a control signal; and The control signal is sent to control at least a portion of the actuation system to adjust the tension or load on the rope to maintain a predetermined distance between the first frame structure and the seabed as the first frame structure moves vertically relative to the second frame structure.

19. The tangible non-transitory computer-readable medium according to claim 18, wherein, The computer-executable code includes instructions for determining whether an operating characteristic is acceptable by comparing at least one of the operating characteristics with a predetermined value.

20. The tangible non-transitory computer-readable medium according to claim 18, wherein, The computer-executable code includes instructions for determining whether an operating characteristic is acceptable by comparing at least one of the operating characteristics with a predetermined value range.

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