CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application is a Non-Provisional Application claiming priority to U.S.

Provisional Patent Application No. 62/558,758, entitled "Tool Joint Positioning", filed September 14, 2017, which is herein incorporated by reference.

BACKGROUND

[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.

[0002] Advances in the petroleum industry have allowed access to oil and gas drilling locations and reservoirs that were previously inaccessible due to technological limitations. For example, technological advances have allowed drilling of offshore wells at increasing water depths and in increasingly harsh environments, permitting oil and gas resource owners to successfully drill for otherwise inaccessible energy resources. Likewise, drilling advances have allowed for increased access to land based reservoirs.

[0003] Much of the time spent in drilling to reach these reservoirs is wasted "nonproductive time" (NPT) that is spent in doing activities which do not increase well depth, yet may account for a significant portion of costs. For example, when drill pipe is pulled out of or lowered into a previously drilled section of well it is generally referred to as "tripping."

Accordingly, tripping-in may include lowering drill pipe into a well (e.g., running in the hole or PJH) while tripping-out may include pulling a drill pipe out of the well (pulling out of the hole or POOH). Tripping operations may be performed to, for example, install new casing, change a drill bit as it wears out, clean and/or treat the drill pipe and/or the wellbore to allow more efficient drilling, run in various tools that perform specific jobs required at certain times in the oil well construction plan, etc. Additionally, tripping operations may require a large number of threaded pipe joints to be disconnected (broken-out) or connected (made-up). Currently, this process involves visual inspection by a human operator to locate a seam (e.g., a break point between pipe segments) and may further include human fine tuning of the position of the seam into an appropriate location so that the tripping operation may be undertaken.

BRIEF DESCRIPTION OF DRAWINGS

[0004] FIG. 1 illustrates an example of an offshore platform having a riser coupled to a blowout preventer (BOP), in accordance with an embodiment;

[0005] FIG. 2 illustrates a front view a drilling rig as illustratively presented in FIG. 1, in accordance with an embodiment;

[0006] FIG. 2 A illustrates a front view of the tripping apparatus of FIG. 2, in accordance with an embodiment;

[0007] FIG. 3 illustrates a block diagram of a computing system of FIG. 2, in accordance with an embodiment; and

[0008] FIG. 4 illustrates a flow chart used in conjunction with a tubular string detection system, in accordance with an embodiment.

[0009] FIG. 5 illustrates a front view a second drilling rig as illustratively presented in

FIG. 1, in accordance with an embodiment;

[0010] FIG. 6 illustrates an isometric view of a movable platform of FIG. 5, in accordance with an embodiment; and

[0011] FIG. 7 illustrates a front view of a system inclusive of the tripping apparatus of

FIG. 5, in accordance with an embodiment. DETAILED DESCRIPTION

[0012] One or more specific embodiments will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may 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 may 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.

[0013] 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 may be additional elements other than the listed elements.

[0014] Present embodiments are directed to components, systems, and techniques (e.g., a position determination system) utilized in the detection of connection points between individual tubular segments, such as those used in oil and gas applications. The detection of connection points may be accomplished through the use of a hardware suite of one or more sensors and processors, as well as a suite of one or more software programs (e.g., instructions configured to be executed by a processor, whereby the instructions are stored on a tangible, non-transitory computer-readable medium such as memory) that may operate in conjunction to determine the precise position of the connection point between tubular segments.

[0015] Additionally, in some embodiments, the software program(s) may be utilized, for example, in conjunction with hardware components (e.g., one or more processors and sensors) to access stored information relating to the tubulars to generate a position of a connection point between two tubular segments (e.g., a tool joint connection typically having a larger diameter than the respective tubulars and including a male pin connector of one tubular connectable to a female box connector on the other tubular). For example, a tool joint seam (e.g., a location of the connection of the pin connector and the box connector) may be calculated using stored information about the tubular segments (e.g., the length of the respective tubular segments) and the current position of a tubular string including the tubular segments, as determined through one or more indirect measurements of the tubular segment positions (e.g., through measurements of a portion of drawworks supporting the tubular string). In some embodiments, activation of one or more slips to secure one of the tubular segments may be controlled based upon the calculated tool joint seam to allow for attachment or detachment of the tubular segments. By calculating the correct position of the connection point between tubular segments, continuous tripping procedures may be facilitated, since hunt and peck methods for the connection point can be avoided.

[0016] With the foregoing in mind, FIG. 1 illustrates an offshore platform 10 as a drillship. Although the presently illustrated embodiment of an offshore platform 10 is a drillship (e.g., a ship 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 installation, subsea tree installations, and well capping), other offshore platforms 10 such as a semi-submersible platform, a jack up drilling platform, a spar platform, a floating production system, or the like may be substituted for the drillship. Indeed, while the techniques and systems described below are described in conjunction with a drillship, the techniques and systems are intended to cover at least the additional offshore platforms 10 described above. Likewise, while an offshore platform 10 is illustrated and described in FIG. 1, the techniques and systems described herein may also be applied to and utilized in onshore (e.g., land based) drilling activities. These techniques may also apply to at least vertical drilling or production operations (e.g., having a rig in a primarily vertical orientation drill or produce from a substantially vertical well) and/or directional drilling or production operations (e.g., having a rig in a primarily vertical orientation drill or produce from a substantially non-vertical or slanted well or having the rig oriented at an angle from a vertical alignment to drill or produce from a substantially non- vertical or slanted well).

[0017] As illustrated in FIG. 1, the offshore platform 10 includes a riser string 12 extending therefrom. The riser string 12 may include a pipe or a series of pipes that connect the offshore platform 10 to the seafloor 14 via, for example, a BOP 16 that is coupled to a wellhead 18 on the seafloor 14. In some embodiments, the riser string 12 may transport produced hydrocarbons and/or production materials between the offshore platform 10 and the wellhead 18, while the BOP 16 may include at least one BOP stack having at least one valve with a sealing element to control wellbore fluid flows. In some embodiments, the riser string 12 may pass through an opening (e.g., a moonpool) in the offshore platform 10 and may be coupled to drilling equipment of the offshore platform 10. As illustrated in FIG. 1, it may be desirable to have the riser string 12 positioned in a vertical orientation between the wellhead 18 and the offshore platform 10 to allow a drill string made up of drill pipes 20 to pass from the offshore platform 10 through the BOP 16 and the wellhead 18 and into a wellbore below the wellhead 18. Also illustrated in FIG. 1 is a drilling rig 22 (e.g., a drilling package or the like) that may be utilized in the drilling and/or servicing of a wellbore below the wellhead 18.

[0018] In a tripping-in operation consistent with embodiments of the present disclosure, as depicted in FIG. 2, a tripping apparatus 24 is positioned on drilling floor 26 in the drilling rig 22 above the wellbore 28 (e.g., the drilled hole or borehole of a well which may be, as illustrated in FIG. 2, proximate to the drilling floor 26 in land based drilling operations or which may be, in conjunction with FIG. 1, below the wellhead 18). The drilling rig 22 may include one or more of, for example, the tripping apparatus 24, floor slips 30 positioned in rotary table 32, drawworks 34, a crown block 35, a travelling block 36, a top drive 38, an elevator 40, and a tubular handling apparatus 42. The tripping apparatus 24 may operate to couple and decouple tubular segments (e.g., drill pipe 20 to and from a drill string) while the floor slips 30 may operate to close upon and hold a drill pipe 20 and/or the drill string passing into the wellbore 28. The rotary table 32 may be a rotatable portion of the drilling floor 26 that may operate to impart rotation to the drill string either as a primary or a backup rotation system (e.g., a backup to the top drive 38).

[0019] The drawworks 34 may be a large spool that is powered to retract and extend drilling line 37 (e.g., wire cable) over a crown block 35 (e.g., a vertically stationary set of one or more pulleys or sheaves through which the drilling line 37 is threaded) and a travelling block (e.g., a vertically movable set of one or more pulleys or sheaves through which the drilling line 37 is threaded) to operate as a block and tackle system for movement of the top drive 38, the elevator 40, and any tubular member (e.g., drill pipe 20) coupled thereto. The top drive 38 may be a device that provides torque to (e.g., rotates) the drill string as an alternative to the rotary table 32 and the elevator 40 may be a mechanism that may be closed around a drill pipe 20 or other tubular members (or similar components) to grip and hold the drill pipe 20 or other tubular members while those members are moving vertically (e.g., while being lowered into or raised from the wellbore 28). The tubular handling apparatus 42 may operate to retrieve a tubular member from a storage location 43 (e.g., a pipe stand) and position the tubular member during tripping-in to assist in adding a tubular member to a tubular string. Likewise, the tubular handling apparatus 42 may operate to retrieve a tubular member from a tubular string and transfer the tubular member to a storage location 43 (e.g., a pipe stand) during tripping-out to remove the tubular member from the tubular string.

[0020] During a tripping-in operation, the tubular handling apparatus 42 may position a first tubular segment 44 (e.g., a first drill pipe 20 or another tubular member) so that the segment 44 may be grasped by the elevator 40. Elevator 40 may be lowered, for example, via the block and tackle system towards the tripping apparatus 24 to be coupled to a second tubular segment 46 (e.g., a second drill pipe 20) as part of a drill string. As illustrated in FIG. 2A, the tripping apparatus 24 may include tripping slips 48 inclusive of slip jaws 50 that engage and hold the segment 46 as well as a forcing ring 52 that operates to provide force to actuate the slip jaws 50. The tripping slips 48 may, thus, be activated to grasp and support the segment, and, accordingly, an associated tubular string (e.g., drill string) when the tubular string is disconnected from the block and tackle system. The tripping slips 48 may be actuated hydraulically, electrically, pneumatically, or via any similar technique.

[0021] The tripping apparatus 24 may further include a roughneck 54 that may operate to selectively make-up and break-out a threaded connection between tubular segments 44 and 46 in a tubular string. In some embodiments, the roughneck 54 may include one or more of fixed jaws 56, makeup/breakout jaws 58, and a spinner 60. In some embodiments, the fixed jaws 56 may be positioned to engage and hold the second (lower) tubular segment 46 below a threaded joint 62 thereof. In this manner, when the first (upper) tubular segment 44 is positioned coaxially with the second tubular segment 46 in the tripping apparatus 24, the second tubular segment 46 may be held in a stationary position to allow for the connection of the first tubular segment 44 and the second tubular segment 46 (e.g., through connection of the threaded joint 62 of the second tubular segment 46 and a threaded joint 64 of the first tubular segment 44). [0022] To facilitate this connection, the spinner 60 and the makeup/breakout jaws 58 may provide rotational torque. For example, in making up the connection, the spinner 60 may engage the first tubular segment 44 and provide a relatively high-speed, low-torque rotation to the first tubular segment 44 to connect the first segment 44 to the second segment 46. Likewise, the makeup/breakout jaws 58 may engage the first segment 44 and may provide a relatively low- speed, high-torque rotation to the first tubular segment 44 to provide, for example, a rigid connection between the tubular segment 44 and 46. Furthermore, in breaking-out the connection, the makeup/breakout jaws 58 may engage the first tubular segment 44 and impart a relatively low-speed, high-torque rotation on the first tubular segment 44 to break the rigid connection. Thereafter, the spinner 60 may provide a relatively high-speed, low-torque rotation to the first tubular segment 44 to disconnect the first segment 44 from the second segment 46.

[0023] In some embodiments, the roughneck 54 may further include a mud bucket 66 that may operate to capture drilling fluid, which might otherwise be released during, for example, the break-out operation. In this manner, the mud bucket 66 may operate to prevent drilling fluid from spilling onto drill floor 26. In some embodiments, the mud bucket 66 may include one or more seals that aid in fluidly sealing the mud bucket 66 as well as a drain line that operates to allow drilling fluid contained within mud bucket 66 to return to a drilling fluid reservoir.

[0024] Returning to FIG. 2, the tripping apparatus 24 may be movable with respect to the drill floor 26 (e.g., towards and away from the drill floor 26) and, in some embodiments, relative to the tripping slips 48. In other embodiments, the tripping apparatus 24 can be moved along the direction of the rig towards and away from the drilling floor 26 in conjunction with slanted well operations when the rig is oriented at an angle from a vertical alignment to respectively drill or produce from a substantially non-vertical or slanted well. Movement of the tripping apparatus 24 may be accomplished through the use of hydraulic pistons, jackscrews, racks and pinions, cable and pulley, a linear actuator, or the like along one or more support elements 68. This movement may be beneficial to aid in proper location of the roughneck 54 during a make-up or break-out operation (e.g., during a tripping-in or tripping-out operation).

[0025] In some embodiments, moving of the tripping apparatus 24 into position (whether in conjunction with a continuous tripping operation in which the tubular segments 44 and 46 are moving towards or away from the drill floor 26 while being made-up or broken-out or in conjunction with a static tripping operation in which the tubular segments 44 and 46 remain in a static position relative to the drill floor 26 while being made-up or broken-out) may require hunt and peck techniques to find a seam between the tubular segments 44 and 46 or the connection point thereof so as to allow the roughneck 54 to trip the tubular segments 44 and 46. However, it may be advantageous to instead utilize techniques and one or more systems to determine the location of a seam or a connection point for tubular segments 44 and 46 so that the tripping apparatus 24 can be moved into a correct position to facilitate a make-up or break-out (e.g., tripping) operation.

[0026] To facilitate this determination of where and when to move the tripping apparatus

24 into position (e.g., tool joint recognition), a computing system 70 may be present and may operate to control the timing when the tripping apparatus 24 moves into position to perform a tripping operation based on, for example, a determined or calculated location of a seam or a connection point for tubular segments 44 and 46. In some embodiments, the computing system 70 may be communicatively coupled to a separate main control system 72, for example, a control system in a driller's cabin that may provide a centralized control system for drilling controls, automated pipe handling controls, and the like. In other embodiments, the computing system may be a portion of the main control system 72 (e.g., the control system present in the driller's cabin).

[0027] FIG. 3 illustrates the computing system 70. It should be noted that the computing system 70 may be a standalone unit (e.g., a control monitor) that operates in conjunction with one or more sensors (e.g., to form a control system) that may operate to provide inputs used, for example, by the computing system to determine a position of a seam or a connection point for tubular segments 44 and 46. Likewise, the computing system 70 may be configured to operate in conjunction with one or more of the tripping apparatus 24 and/or the tubular handling apparatus 42.

[0028] The computing system 70 may be a general purpose or a special purpose computer that includes a processing device 74, 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., memory 76) of the computing system 70, which may operate to collectively store instructions executable by the processing device 74 to perform the methods and actions described herein. By way of example, such machine-readable media can comprise RAM, ROM, EPROM, EEPROM, CD-ROM: or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to cany or store desired program code in the form of machine- executable instructions or data stnictures and which can be accessed by the processing device 74. In some embodiment, the instructions executable by the processing device 74 are used to generate, for example, control signals to be transmitted to, for example, one or more of the tripping apparatus 24 (e.g., the roughneck 54 and/or one or more of the fixed jaws 56, the makeup/breakout jaws 58, and the spinner 60), the tubular handling apparatus 42, and/or the main control system 72 (e.g., to be utilized in the control of the tripping apparatus 24, the roughneck 54, the fixed jaws 56, the makeup/breakout jaws 58, the spinner 60, and/or the tubular handling apparatus 42) to operate in a manner described herein.

[0029] The computing system 70 may operate in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium of computing system 70, such as memory 76, a hard disk drive, or other short term and/or long term storage. Particularly, the processing device 74 may operate in conjunction with software systems implemented as computer executable instructions (e.g., code) stored in a non- transitory machine readable medium of computing system 70, such as memory 76, that may be executed to receive information (e.g., signals or data) related to one or more of tubular characteristics (e.g., lengths or similar measurements) as well as receive tubular locations or positions when involved in a tripping operation, attributes of a portion of the drawworks 34, operational parameters of the drawworks 34, and/or location and/or position information of the travelling block 36, the top drive 38, and/or the elevator 40. This information can be used by the computing system 70 (e.g., by the processing device 74 executing computer executable instructions stored in memory 76) to generate or otherwise calculate a determined position of a seam or a connection point for tubular segments 44 and 46. Additionally, this determined position can be used to initiate or control movement of the tripping apparatus 24 into position to facilitate a make-up or break-out (e.g., tripping) operation by the computing system 70, the main control system 72, or by another local controller of the tripping apparatus 24.

[0030] In some embodiments, the computing system 70 may also include one or more input structures 78 (e.g., one or more of a keypad, mouse, touchpad, touchscreen, one or more switches, buttons, or the like) to allow a user to interact with the computing system 70, for example, to start, control, or operate a graphical user interface (GUI) or applications running on the computing system 70 and/or to start, control, or operate the tripping apparatus 24 (e.g., the roughneck 54 and/or one or more of the fixed jaws 56, the makeup/breakout jaws 58, and the spinner 60), the tubular handling apparatus 42, or additional systems of the drilling rig 22.

Additionally, the computing system 70 may include a display 80 that may be a liquid crystal display (LCD) or another type of display that allows users to view images generated by the computing system 70. The display 80 may include a touch screen, which may allow users to interact with the GUI of the computing system 70. Likewise, the computing system 70 may additionally and/or alternatively transmit images to a display of the main control system 72, which itself may also include a processing device 74, a non-transitory machine readable medium, such as memory 76, one or more input structures 78, a display 80, and/or a network interface 82.

[0031] Returning to the computing system 70, as may be appreciated, the GUI may be a type of user interface that allows a user to interact with the computer system 70 and/or the computer system 70 and one or more sensors that transmit data to the computing system through, for example, graphical icons, visual indicators, and the like. Additionally, the computer system 70 may include network interface 82 to allow the computer system 70 to interface with various other devices (e.g., electronic devices). The network interface 82 may 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., a Modbus TCP, EtherCAT, and/or ProfiNET interface), a field bus communication interface (e.g., Profibus), a/or other industrial protocol interfaces that may be coupled to a wireless network, a wired network, or a combination thereof that may use, for example, a multi-drop and/or a star topology with each network spur being multi-dropped to a reduced number of nodes. [0032] In some embodiments, one or more of the tripping apparatus 24 (and/or a controller or control system associated therewith), the tubular handling apparatus 42 (and/or a controller or control system associated therewith), sensors of the drilling rig 22, and/or the main control system 72 may each be a device that can be coupled to the network interface 82. In some embodiments, the network formed via the interconnection of one or more of the aforementioned devices should operate to provide sufficient bandwidth as well as low enough latency to exchange all required data within time periods consistent with any dynamic response

requirements of all control sequences and closed-loop control functions of the network and/or associated devices therein. It may also be advantageous for the network to allow for sequence response times and closed-loop performances to be ascertained, the network components should allow for use in oilfield/drillship environments (e.g., should allow for rugged physical and electrical characteristics consistent with their respective environment of operation inclusive of but not limited to withstanding electrostatic discharge (ESD) events and other threats as well as meeting any electromagnetic compatibility (EMC) requirements for the respective environment in which the network components are disposed). The network utilized may also provide adequate data protection and/or data redundancy to ensure operation of the network is not compromised, for example, by data corruption (e.g., through the use of error detection and correction or error control techniques to obviate or reduce errors in transmitted network signals and/or data).

[0033] Returning to FIG. 2, one or more sensors 84 and 86 may be provided in conjunction with the drilling rig 22. In some embodiments, the one or more sensors 84 or 86 may be utilized in conjunction with a make-up (e.g., a tripping-in) and a break-out (e.g., a tripping-out) operation. Alternatively, both sets of sensors 84 and 86 may be utilized together in conjunction with either or both tripping operations. In one embodiment, the sensors 84 and 86 may include, but are not limited to, cameras (e.g., high frame rate cameras), lasers (e.g., multidimensional lasers), transducers (e.g., ultrasound transducers), electrical and or magnetic characteristic sensors (e.g., sensors that can measure/infer capacitance, inductance, magnetism, or the like), chemical sensors, metallurgical detection sensors, or the like. In some embodiments, the one or more sensors 84 may be proximity sensors (e.g., inductive, magnetic, optical, ultrasonic, etc.) to detect the presence of an object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) without physical contact with the object. This may be accomplished via emission of an electromagnetic signal as well as monitoring for a return signal or emitting an electromagnetic field and monitoring for changes in the electronic field. As illustrated, the sensors 84 may be disposed on a derrick 87 of the drilling rig 22 while the sensors 86 may be disposed internal to or adjacent to the drawworks 34. However, alternative locations on the drilling rig 22 may be employed.

[0034] In some embodiments, a sensor 84 may generate a signal indicative of the detection of the object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) as the object passes the sensor 84 and the sensor 84 may transmit (wirelessly or via a physical connection) the signal indicative of the detection of the object to the computer system 70. This signal may be used to determine the location of the object by the computer system 70, as the location of the sensor 84 may be stored in the computer system 70 and the location of the object may be calculated based on its being detected.

[0035] One or more additional sensors 84 may generate respective signals indicative of the detection of the object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) as the one or more additional sensors 84 is passed by the object. The one or more additional sensors 84 may each transmit (wirelessly or via a physical connection) a respective signal indicative of the detection of the object to the computer system 70. This signal may be used to determine the location of the object by the computer system 70, as the location of the sensor 84 transmitting the signal may be stored in the computer system 70 and the location of the object may be calculated based on its being detected (e.g., based on the received signal from a particular sensor 84). Additionally, the computer system 70 may be able to calculate the velocity of the object based on the one or more location calculations as related to time (e.g., the computer system 70 may be able to calculate velocity of the object based on its calculated location at a first time and its calculated location at a second time). [0036] In some embodiments, one or more sensors 86 may also be proximity sensors

(e.g., a rotational sensor such as an optical encoder, magnetic speed sensor, a reflective sensor, or a hall effect sensor) to detect operational characteristics of the drawworks 34 (e.g., rotation of a drum, speed of a drum or the like). In some embodiments, the one or more sensors 86 may generate a signal indicative of operational characteristics of the drawworks 34 and may transmit (wirelessly or via a physical connection) the signal indicative of operational characteristic of the drawworks 34 to the computer system 70. This signal may be used to determine the location of an object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) by the computer system 70, as the location of an object may be directly related to the operation of the drawworks 34 (e.g., an amount of rotation of a drum causing drilling line 37 to be extended from the drawworks 34, which defines the location of the object suspended from the block and tackle system). The determined location of an object may be useful, for example, to determine and/or control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation based on, for example, a determined or calculated location of a seam or a connection point for tubular segments 44 and 46.

[0037] FIG. 4 illustrates a flow chart 88 detailing the operation of a detection system, which may include the use of the computing system 70 operating in conjunction with one or more of the sensors 84 and 86. It will be noted that the operation will be discussed as utilizing one or more sensors 84. However, this operation may instead utilize one or more sensors 84 and 86 or one or more sensors 86 depending on, for example, a tripping operation being undertaken, the type of deviation in the tubular string to be detected, and/or based on additional factors.

[0038] In step 90, initial information may be received and/or calculated regarding the tubular members (e.g., drill pipes 20) to be used in formation of a tubular string (e.g., a drill string). This initial information may include tubular member characteristics, such as

measurements of an overall length of each respective tubular member, a measurement of the length of a pin connector and/or a box connector of each respective tubular member, and/or an order in which the respective tubular members are to be connected and/or disconnected to form or break down the tubular string. In some embodiments, the initial information regarding the tubular members may be calculated by the computing system 70 based upon inputs (received signals) from one or more sensors (e.g., optical sensor or the like) adjacent to the storage location 43 (e.g., a pipe stand) transmitted to the computing system 70. In other embodiments, the measurements and/or order of the tubular members may be directly input to the computing system. The initial information may also include information related to a distance between a bottom portion of, for example, the elevator 40 and a connection portion of a tubular segment (e.g., tubular segment 44 or 46).

[0039] In step 92, the one or more sensors 84 may generate a signal indicative of detection of an object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) as the object passes the one or more sensors 84 and the one or more sensors 84 may transmit the signal indicative of the detection of the object for receipt by the computer system 70. Additionally or alternatively in step 92, one or more sensors 86 may generate a signal indicative of operational characteristics of the drawworks 34 (e.g., an amount of rotation of a drum causing drilling line 37 to be extended from the drawworks 34) and may transmit the signal indicative of operational characteristic of the drawworks 34 for receipt by the computer system 70.

[0040] In step 94, the signal(s) received in step 92 may be utilized in conjunction with the initial information from step 90 to calculate a location of a seam (e.g., a tool joint seam) or a connection point for tubular segments 44 and 46. For example, the signal(s) received in step 92 may be used to determine the location of an object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) by the computer system 70 based upon location information of the sensor 84 used to generate the signal and/or based upon operational information of the drawworks 34 (e.g., an amount of rotation of a drum causing drilling line 37 to be extended from the drawworks 34, which defines the location of the object suspended from the block and tackle system). For the purposes of discussion, the object will be the elevator 40, but it is appreciated that the object could be any one of a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, the threaded joint 64 of a drill pipe 20, or other related physical characteristics of the tubular members or their associated positioning equipment. [0041] In step 94, the computer system 70 (e.g., the processing device 74 or the processing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium of computing system 70, such as memory 76, that may be executed) may apply the initial information related to one or more of tubular characteristics (e.g., lengths or similar measurements) with the location of the elevator 40. In some embodiments, the lengths of the tubular members (e.g., tubular segments 44 and 46) and/or the lengths of the connection portions of the tubular members (e.g., the lengths of a pin connector and/or a box connector of each respective tubular member and, thus, the location of the tool joint and its respective seam) may vary. The processing device 74 or the processing device 74 operating in conjunction with a software system may retrieve a known physical attribute (e.g., a measured characteristic such as a length) of the tubular member (e.g., tubular segment 44) being supported by the elevator 40, based upon its order to be

attached/detached from the tubular string. The processing device 74 or the processing device 74 operating in conjunction with a software system may also retrieve and/or calculate the location of an object (e.g., the elevator 40) based upon information received in step 92. In this manner, the processing device 74 or the processing device 74 operating in conjunction with a software system may utilize the location of the object (e.g., the elevator 40) in conjunction with the physical attribute to determine a precise location of a connection point (e.g., a seam of a tool joint or a connection point for a tubular member such as tubular segment 44) without direct measurement or sensing of the connection point.

[0042] In step 96, the determined location of a connection point (e.g., a seam of a tool joint or a connection point for a tubular member such as tubular segment 44) may be utilized to generate an output signal from the computer system 70. In some embodiments, this output signal may be an indication of the location of the connection point to be used by a controller external to the computing system 70 and may be used to determine and/or control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation. Additionally or alternatively, the generated output signal may be utilized as a control signal for the activation of one or more slips 30 and/or 48 to secure one of the tubular segments (e.g., tubular segment 44) so that a calculated tool joint seam location thereof will be at an appropriate height for the tripping apparatus 24 to operate on. In some embodiments, the output signal generated may cause display of an image, for example, on display 80 in conjunction with and/or separate from activation of one or more slips 30 and/or 48 and/or determining and/or controlling where and when to move the tripping apparatus 24 into position for a tripping operation.

[0043] In step 98, the output signal generated by the computer system 70 may be applied by the computer system 70. For example, the computer system 70 (e.g., the processing device 74 or the processing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium of computing system 70, such as memory 76, that may be executed) may operate as a control system itself so as to transmit a control signal based upon the output signal of step 96 or as the output signal of step 96 to control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation. Additionally or

alternatively, the computer system 70 may operate as a control system itself so as to transmit a control signal based upon the output signal of step 96 or as the output signal of step 96 to control the activation of one or more slips 30 and/or 48 to secure one of the tubular segments (e.g., tubular segment 44) so that a calculated tool joint seam location thereof will be at an appropriate height for the tripping apparatus 24 to perform a tripping operation. Likewise, external control systems may instead receive the output signal of step 96 from the computer system 70 and use the output signal to control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation and/or control the activation of one or more slips 30 and/or 48 to secure one of the tubular segments (e.g., tubular segment 44) so that a calculated tool joint seam location thereof will be at an appropriate height for the tripping apparatus 24 to perform a tripping operation.

[0044] FIG. 5 illustrates another embodiment of a drilling rig 100 that may be utilized in a tripping operation consistent with embodiments of the present disclosure. As illustrated, the tripping apparatus 24 is illustrated as being positioned above drill floor 26 in the drilling rig 100 above the wellbore (e.g., the drilled hole or borehole of a well which may be proximate to the drill floor 26 or which may be, in conjunction with FIG. 1, below the wellhead 18). However, as will be discussed in greater detail below, the tripping apparatus 24 may be moved towards and away from the drill floor 26 during a tripping operation. As illustrated, the drilling rig 100 may include one or more of, for example, the tripping apparatus 24, a movable platform 102 (that may include floor slips 30 positioned in rotary table 32, as illustrated in FIG. 6), drawworks 34, a crown block 35, a travelling block 36, a top drive 38, an elevator 40, and a tubular handling apparatus 42. The tripping apparatus 24 may operate to couple and decouple tubular segments 44 and 46 (e.g., couple and decouple drill pipe 20 to and from a drill string) while the floor slips 30 may operate to close upon and hold a drill pipe 20 and/or the drill string passing into the wellbore. The rotary table 32 may be a rotatable portion that can be locked into positon co- planar with the drill floor 26 and/or above the drill floor 26. The rotary table 32 can, for example, operate to impart rotation to the drill string either as a primary or a backup rotation system (e.g., a backup to the top drive 38) as well as utilize its floor slips 30 to support tubular segments (e.g., tubular segment 46), for example, during a tripping operation.

[0045] The drawworks 34 may be a large spool that is powered to retract and extend drilling line 37 (e.g., wire cable) over a crown block 35 (e.g., a vertically stationary set of one or more pulleys or sheaves through which the drilling line 37 is threaded) and a travelling block (e.g., a vertically movable set of one or more pulleys or sheaves through which the drilling line 37 is threaded) to operate as a block and tackle system for movement of the top drive 38, the elevator 40, and any tubular segment (e.g., drill pipe 20) coupled thereto. In some embodiments, the top drive 38 and/or the elevator 40 may be referred to as a tubular support system or the tubular support system may also include the block and tackle system described above.

[0046] The top drive 38 may be a device that provides torque to (e.g., rotates) the drill string as an alternative to the rotary table 32 and the elevator 40 may be a mechanism that may be closed around a drill pipe 20 or other tubular segments 44 and 46 (or similar components) to grip and hold the drill pipe 20 or other tubular segments 44 and 46 while those segments are moving vertically (e.g., while being lowered into or raised from a wellbore) or directionally (e.g., during slant drilling). The tubular handling apparatus 42 may operate to retrieve a tubular segment 44 from a storage location 43 (e.g., a pipe stand) and position the tubular segment 44 during tripping-in to assist in adding a tubular segment 44 to a tubular string. Likewise, the tubular handling apparatus 42 may operate to retrieve a tubular segment 44 from a tubular string and transfer the tubular segment 44 to a storage location (e.g., a pipe stand) during tripping-out to remove the tubular segment 44 from the tubular string. [0047] During a tripping-in operation, the tubular handling apparatus 42 may position a tubular segment 44 (e.g., a drill pipe 20) so that the segment 44 may be grasped by the elevator 40. Elevator 40 may be lowered, for example, via the block and tackle system towards the tripping apparatus 24 to be coupled to tubular segment 46 (e.g., a drill pipe 20) as part of a drill string. In some embodiments, the tripping apparatus 24 may operate as discussed in conjunction with FIG. 2A above during a tripping operation. However, in addition to the operation of the tripping apparatus 24, continuous tripping operations (tripping tubular segments 44 and 46 without halting the movement of the tubular string at a fixed position) may be facilitated and/or accelerated through the inclusion of the movable platform 102.

[0048] The movable platform 102, may be raised and lowered with a cable and sheave arrangement (e.g., similar to the block and tackle system for movement of the top drive 38) that may include a winch or other drawworks element positioned on the drill floor 26 or elsewhere on the offshore platform 10 or the drilling rig 22. The winch or other drawworks element may be a spool that is powered to retract and extend a line (e.g., a wire cable) over a crown block (e.g., a stationary set of one or more pulleys or sheaves through which the line 37 is threaded) and a travelling block (e.g., a movable set of one or more pulleys or sheaves through which the line 37 is threaded) to operate as a block and tackle system for movement of the movable platform 102 and, thus the rotary table 32 therein and the tripping apparatus 24 thereon. Additionally and/or alternatively, direct acting cylinders, a suspended winch and cable system mechanism disposed such that the movable platform 102 is between the suspended winch and cable system and the drill floor 26, or similar internal or external actuation systems may be used to move the movable platform 102 along support element 68.

[0049] In some embodiments, the support element 68 may be one or more guide mechanisms (e.g., guide tracks, such as top drive dolly tracks) that provide support (e.g., lateral support) to the movable platform 102 while allowing for movement towards and away from the drill floor 26. Additionally, as illustrated in FIG. 6, one or more lateral supports 104 may be used to couple the movable platform 102 to the support element 68. For example, the lateral supports 104 may be, for example, pads that may be made of Teflon-graphite material or another low-friction material (e.g., a composite material) that allows for motion of the movable platform 102 relative to drill floor 26 and/or the tubular segment support system with reduced friction characteristics. In addition to, or in place of the aforementioned pads, other lateral supports 104 including bearing or roller type supports (e.g., steel or other metallic or composite rollers and/or bearings) may be utilized. The lateral supports 104 may allow the movable platform 102 to interface with a support element 68 (e.g., guide tracks, such as top drive dolly tracks) so that the movable platform 102 is movably coupled to the support element 68. Accordingly, the movable platform 102 may be movably coupled to a support element 68 to allow for movement of the movable platform 102 (e.g., towards and away from the drill floor 26 and/or the tubular segment support system while maintaining contact with the guide tracks or other support element 68) during a tripping operation (e.g., a continuous tripping operation).

[0050] As further illustrated in FIG. 6, the movable platform 102 may have guide pins

106 or similar devices to provide coarse and fine alignment when moving in and out of the drill floor 26 (e.g., into a planar position with the drill floor 26 or raised above the drill floor 26). Additionally, one or more locking mechanisms 108 may be employed to affix the movable platform 102 into a desired position with respect to the drill floor 26, for example, when a tripping operation is complete or not necessary. In this fixed position, the rotary table 32 may operate in conjunction with the top drive 38 and/or as a backup system to the top drive 38. The locking mechanisms 108 may be automatic (e.g., controllable) such that they can be actuated without human contact (e.g., a control signal may cause pins or other locking mechanisms to engage an aperture between the drill floor 26 and the movable platform 102). It is envisioned that the locking mechanisms will interface with the drill floor 26 or an element beneath the drill floor (if the movable platform 102 is to be locked in a position planar with the drill floor 26).

[0051] Returning to FIG. 5, a computing system 70 may be present and may operate in conjunction with one or more of the tripping apparatus 24, the movable platform 102, an actuating system used to move the tripping apparatus 24, and/or an actuating system used to move the movable platform 102. This computing system 70 may also operate to control one or more of the tubular segment support system and/or the tubular handling apparatus 42. It should be noted that the computing system 70 may be similar to the computing system of FIG. 3 and may operate in a manner disclosed with respect to FIG. 4, with the added aspects of control of the movable platform 102 and/or the floor slips 30 of the movable platform 102 in conjunction with steps 96 and 98 therein. [0052] Additionally, tripping operations involving singular tubular members (e.g., drill pipe 20) has been discussed with respect to FIGS. 2-6. However, as illustrated in FIG. 7, it is envisioned that a stand 110 of tubular segments 44 (e.g., two, three, or more tubular segments 44 coupled together) may be the tubular segments 44 being tripped-in or tripped-out. The operation including the steps described in FIG. 4 may apply to tripping stands 110 as illustrated in FIG. 7. For example, when applying step 90 to the system of FIG. 7, initial information may be received and/or calculated regarding the tubular segments 44 (e.g., drill pipes 20) to be used in formation of a tubular string (e.g., a drill string). This initial information may include tubular segment 44 characteristics of the stand 110, such as measurements of an overall length of each respective tubular segment 44, a measurement of the length of a pin connector and/or a box connector of each respective tubular segment 44, and/or an order in which the respective tubular segment 44 are to be connected and/or disconnected to form or break down the tubular string, measurements of an overall length of the stand 110, a measurement of the length of a pin connector and/or a box connector of each respective tubular segment 44 at a terminal end of the stand 110 (e.g., where a connection between stands 110 is made), and/or an order in which the respective stands 110 are to be connected and/or disconnected to form or break down the tubular string. In some embodiments, the initial information regarding the tubular segments 44 of the stand 110 and/or the stand 110 may be calculated by the computing system 70 based upon inputs (received signals) from one or more sensors (e.g., optical sensor or the like) adjacent to the storage location 43 (e.g., a pipe stand) transmitted to the computing system 70. In other embodiments, the measurements and/or order of the tubular segments 44 of the stand 110 and/or the stand 110 may be directly input to the computing system. The initial information may also include information related to a distance between a bottom portion of, for example, the elevator 40 and a connection portion of an uppermost and/or lowermost tubular segment 44 of the stand 110.

[0053] Likewise when applying step 94 to the system of FIG. 7, the signal(s) received in step 92 may be utilized in conjunction with the initial information from step 90 to calculate a location of a seam (e.g., a tool joint seam) or a connection point for tubular stands 110. For example, the signal(s) received in step 92 may be used to determine the location of an object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) by the computer system 70 based upon location information of the sensor 84 used to generate the signal and/or based upon operational information of the drawworks 34 (e.g., an amount of rotation of a drum causing drilling line 37 to be extended from the drawworks 34, which defines the location of the object suspended from the block and tackle system). For the purposes of discussion, the object will be the elevator 40, but it is appreciated that the object could be any one of a drill pipe 20, the top drive 38, the elevator 40, the threaded joint 62 of a drill pipe 20, the threaded joint 64 of a drill pipe 20, or other related physical characteristics of the tubular stands 110 or their associated positioning equipment.

[0054] When further applying step 94 to the system of FIG. 7, the computer system 70

(e.g., the processing device 74 or the processing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium of computing system 70, such as memory 76, that may be executed) may apply the initial information related to one or more of tubular characteristics (e.g., lengths or similar measurements) with the location of the elevator 40. In some embodiments, the lengths of the tubular members (e.g., tubular segments 44) or tubular stands 110 and/or the lengths of the connection portions of the tubular segments 44 of the tubular stands 110 (e.g., the lengths of a pin connector and/or a box connector of each respective tubular segment 44 of the stand 110 and, thus, the tool joint and its respective seam between stands 110) may vary. The processing device 74 or the processing device 74 operating in conjunction with a software system may retrieve a known physical attribute (e.g., a measured characteristic such as a length) of the tubular member (e.g., tubular segment 44) or stand 110 being supported by the elevator 40, based upon its order to be attached/detached from the tubular string. The processing device 74 or the processing device 74 operating in conjunction with a software system may also retrieve and/or calculate the location of an object (e.g., the elevator 40) based upon information received in step 92. In this manner, the processing device 74 or the processing device 74 operating in conjunction with a software system may utilize the location of the object (e.g., the elevator 40) in conjunction with the physical attribute to determine a precise location of a connection point (e.g., a seam of a tool joint or a connection point for an upper and/or lower tubular segment 44 of the tubular stand 110) without direct measurement or sensing of the connection point. [0055] When applying step 96 to the system of FIG. 7, the determined location of a connection point (e.g., a seam of a tool joint or a connection point for a respective tubular segment 44 of the stand 110 and/or between two stands 110) may be utilized to generate an output signal from the computer system 70. In some embodiments, this output signal may be an indication of the location of the connection point to be used by a controller external to the computing system 70 and may be used to determine and/or control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation between stands 110. Additionally or alternatively, the generated output signal may be utilized as a control signal for the activation of one or more slips 30 and/or 48 to secure one of the stands 110 so that a calculated tool joint seam location thereof will be at an appropriate height for the tripping apparatus 24 to operate on. In some embodiments, the output signal generated may cause display of an image, for example, on display 80 in conjunction with and/or separate from activation of one or more slips 30 and/or 48 and/or determining and/or controlling where and when to move the tripping apparatus 24 into position for a tripping operation.

[0056] In applying step 98 to the system of FIG. 7, the output signal generated by the computer system 70 may be applied by the computer system 70. For example, the computer system 70 (e.g., the processing device 74 or the processing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non- transitory machine readable medium of computing system 70, such as memory 76, that may be executed) may operate as a control system itself so as to transmit a control signal based upon the output signal of step 96 or as the output signal of step 96 to control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation. Additionally or alternatively, the computer system 70 may operate as a control system itself so as to transmit a control signal based upon the output signal of step 96 or as the output signal of step 96 to control the activation of one or more slips 30 and/or 48 to secure one of the stands 110 so that a calculated tool joint seam location thereof will be at an appropriate height for the tripping apparatus 24 to perform a tripping operation. Likewise, external control systems may instead receive the output signal of step 96 from the computer system 70 and use the output signal to control where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation and/or control the activation of one or more slips 30 and/or 48 to secure one of the stands 110 so that a calculated tool joint seam location thereof will be at an appropriate height for the tripping apparatus 24 to perform a tripping operation.

[0057] This written description uses examples to disclose the above description to enable any person skilled in the art to 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 may 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.

Accordingly, while the above disclosed embodiments may 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 embodiments are not intended to be limited to the particular forms disclosed. Rather, the disclosed embodiment are to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the embodiments as defined by the following appended claims.