US20190078401A1 - Tool joint positioning - Google Patents
Tool joint positioning Download PDFInfo
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- US20190078401A1 US20190078401A1 US16/129,153 US201816129153A US2019078401A1 US 20190078401 A1 US20190078401 A1 US 20190078401A1 US 201816129153 A US201816129153 A US 201816129153A US 2019078401 A1 US2019078401 A1 US 2019078401A1
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Images
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/10—Slips; Spiders ; Catching devices
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B15/00—Supports for the drilling machine, e.g. derricks or masts
- E21B15/02—Supports for the drilling machine, e.g. derricks or masts specially adapted for underwater drilling
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/16—Connecting or disconnecting pipe couplings or joints
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/16—Connecting or disconnecting pipe couplings or joints
- E21B19/165—Control or monitoring arrangements therefor
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
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Definitions
- tripping-in may include lowering drill pipe into a well (e.g., running in the hole or RIH) 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.
- a seam e.g., a break point between pipe segments
- FIG. 1 illustrates an example of an offshore platform having a riser coupled to a blowout preventer (BOP), in accordance with an embodiment
- FIG. 2 illustrates a front view a drilling rig as illustratively presented in FIG. 1 , in accordance with an embodiment
- FIG. 2A illustrates a front view of the tripping apparatus of FIG. 2 , in accordance with an embodiment
- FIG. 3 illustrates a block diagram of a computing system of FIG. 2 , in accordance with an embodiment
- FIG. 4 illustrates a flow chart used in conjunction with a tubular string detection system, in accordance with an embodiment.
- FIG. 5 illustrates a front view a second drilling rig as illustratively presented in FIG. 1 , in accordance with an embodiment
- FIG. 6 illustrates an isometric view of a movable platform of FIG. 5 , in accordance with an embodiment
- FIG. 7 illustrates a front view of a system inclusive of the tripping apparatus of FIG. 5 , in accordance with an embodiment.
- 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.
- 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).
- hardware components e.g., one or more processors and sensors
- 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).
- 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).
- 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.
- FIG. 1 illustrates an offshore platform 10 as a drillship.
- 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.
- 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.
- 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).
- 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
- 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-vert
- 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 .
- 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.
- 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.
- the riser string 12 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 .
- a drilling rig 22 e.g., a drilling package or the like
- 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 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 ).
- 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.
- drilling line 37 e.g., wire cable
- 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
- a travelling block e.g., a vertically movable set of one or more pulleys or sheaves through which the drilling line 37 is threaded
- 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.
- 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.
- a storage location 43 e.g., a pipe stand
- 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.
- 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.
- 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.
- the roughneck 54 may include one or more of fixed jaws 56 , makeup/breakout jaws 58 , and a spinner 60 .
- the fixed jaws 56 may be positioned to engage and hold the second (lower) tubular segment 46 below a threaded joint 62 thereof.
- 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 ).
- the spinner 60 and the makeup/breakout jaws 58 may provide rotational torque.
- 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 .
- 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 .
- 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 .
- 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 .
- 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.
- 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 .
- 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).
- moving of the tripping apparatus 24 into position 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 .
- 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 .
- 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.
- the computing system may be a portion of the main control system 72 (e.g., the control system present in the driller's cabin).
- FIG. 3 illustrates the computing system 70 .
- 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 .
- 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 .
- 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.
- ASICs application specific integrated circuits
- 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.
- 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 carry or store desired program code in the form of machine-executable instructions or data structures and which can be accessed by the processing device 74 .
- 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.
- 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 main control system 72 e.g., to be utilized in the control of the tripping apparatus 24 , the roughneck 54 , the fixed jaws
- 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.
- 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 .
- information e.g., signals or data
- tubular characteristics e.g., lengths or similar measurements
- 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 .
- a make-up or break-out e.g., tripping
- 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 .
- GUI graphical user interface
- 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 .
- 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 .
- 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.
- 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.
- a Bluetooth interface e.g., 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
- 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 .
- 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.
- 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).
- ESD electrostatic discharge
- EMC electromagnetic compatibility
- 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).
- one or more sensors 84 and 86 may be provided in conjunction with the drilling rig 22 .
- 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.
- a make-up e.g., a tripping-in
- a break-out e.g., a tripping-out
- both sets of sensors 84 and 86 may be utilized together in conjunction with either or both tripping operations.
- the sensors 84 and 86 may include, but are not limited to, cameras (e.g., high frame rate cameras), lasers (e.g., multi-dimensional 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.
- cameras e.g., high frame rate cameras
- lasers e.g., multi-dimensional 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 e.g., metallurgical detection sensors, or the like.
- 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.
- 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
- This may be accomplished via
- 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.
- 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).
- 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).
- 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).
- 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
- the computer system 70 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
- 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 .
- 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.
- 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.
- 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 .
- 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 ).
- 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 .
- 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 .
- 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 .
- 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 .
- 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).
- 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 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.
- the computer system 70 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 .
- the lengths of the tubular members e.g., tubular segments 44 and 46
- 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
- the lengths of the tubular members e.g., tubular segments 44 and 46
- 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
- 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 .
- 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.
- a connection point e.g., a seam of a tool joint or a connection point for a tubular member such as tubular segment 44
- the determined location of a connection point may be utilized to generate an output signal from the computer system 70 .
- 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.
- 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.
- 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.
- the output signal generated by the computer system 70 may be applied by the computer system 70 .
- 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
- 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 where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation.
- 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.
- 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.
- 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.
- position e.g., tool joint recognition
- 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.
- 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.
- 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 ).
- the tripping apparatus 24 may be moved towards and away from the drill floor 26 during a tripping operation.
- 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.
- a primary or a backup rotation system e.g., a backup to the top drive 38
- tubular segments e.g., tubular segment 46
- 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.
- 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.
- 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.
- 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.
- a storage location e.g., a pipe stand
- 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.
- the tripping apparatus 24 may operate as discussed in conjunction with FIG. 2A above during a tripping operation.
- continuous tripping operations may be facilitated and/or accelerated through the inclusion of the movable platform 102 .
- 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 .
- a cable and sheave arrangement e.g., similar to the block and tackle system for movement of the top drive 38
- 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.
- a line e.g., a wire cable
- a crown block e.g., a stationary set of one or more pulleys or sheaves through which the line 37 is threaded
- a travelling block e.g., a movable set of one or more pulleys or sheaves through which the line 37 is threaded
- 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 .
- 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 .
- one or more lateral supports 104 may be used to couple the movable platform 102 to the support element 68 .
- 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.
- 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 .
- a support element 68 e.g., guide tracks, such as top drive dolly tracks
- 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).
- a tripping operation e.g., a continuous tripping operation
- 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 ).
- 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 .
- 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.
- tripping operations involving singular tubular members has been discussed with respect to FIGS. 2-6 .
- a stand 110 of tubular segments 44 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 .
- 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.
- 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
- 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 .
- 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 .
- 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 .
- a seam e.g., a tool joint seam
- a connection point for tubular stands 110 e.g., a connection point for tubular stands 110 .
- 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).
- 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
- 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 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.
- the computer system 70 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 .
- tubular characteristics e.g., lengths or similar measurements
- 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 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.
- 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
- the determined location of a connection point may be utilized to generate an output signal from the computer system 70 .
- 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 .
- 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.
- 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.
- the output signal generated by the computer system 70 may be applied by the computer system 70 .
- 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
- 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 where and when to move the tripping apparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation.
- 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.
- 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.
- position e.g., tool joint recognition
Abstract
Techniques and systems to provide automatic positioning of a tripping apparatus. A system may include a sensor configured to detect an object in proximity of the sensor and generate a signal indicative of detected object. The system may also include a processing device configured to process the signal indicative of the detected object to determine a location of the detected object, retrieve information related to a physical characteristic of a tubular segment, and calculate an indication of the location of a connection point of the tubular segment based upon the location of the detected object and the physical characteristic of the tubular segment.
Description
- This application is a Non-Provisional application claiming priority to U.S. Provisional Patent Application No. 62/558,758, entitled “Tool Joint Positioning”, filed Sep. 14, 2017, which is herein incorporated by reference.
- 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.
- 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.
- Much of the time spent in drilling to reach these reservoirs is wasted “non-productive 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 RIH) 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.
-
FIG. 1 illustrates an example of an offshore platform having a riser coupled to a blowout preventer (BOP), in accordance with an embodiment; -
FIG. 2 illustrates a front view a drilling rig as illustratively presented inFIG. 1 , in accordance with an embodiment; -
FIG. 2A illustrates a front view of the tripping apparatus ofFIG. 2 , in accordance with an embodiment; -
FIG. 3 illustrates a block diagram of a computing system ofFIG. 2 , in accordance with an embodiment; and -
FIG. 4 illustrates a flow chart used in conjunction with a tubular string detection system, in accordance with an embodiment. -
FIG. 5 illustrates a front view a second drilling rig as illustratively presented inFIG. 1 , in accordance with an embodiment; -
FIG. 6 illustrates an isometric view of a movable platform ofFIG. 5 , in accordance with an embodiment; and -
FIG. 7 illustrates a front view of a system inclusive of the tripping apparatus ofFIG. 5 , in accordance with an embodiment. - 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.
- 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.
- 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.
- 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.
- With the foregoing in mind,
FIG. 1 illustrates anoffshore platform 10 as a drillship. Although the presently illustrated embodiment of anoffshore 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), otheroffshore 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 additionaloffshore platforms 10 described above. Likewise, while anoffshore platform 10 is illustrated and described inFIG. 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). - As illustrated in
FIG. 1 , theoffshore platform 10 includes ariser string 12 extending therefrom. Theriser string 12 may include a pipe or a series of pipes that connect theoffshore platform 10 to theseafloor 14 via, for example, aBOP 16 that is coupled to awellhead 18 on theseafloor 14. In some embodiments, theriser string 12 may transport produced hydrocarbons and/or production materials between theoffshore platform 10 and thewellhead 18, while theBOP 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, theriser string 12 may pass through an opening (e.g., a moonpool) in theoffshore platform 10 and may be coupled to drilling equipment of theoffshore platform 10. As illustrated inFIG. 1 , it may be desirable to have theriser string 12 positioned in a vertical orientation between thewellhead 18 and theoffshore platform 10 to allow a drill string made up ofdrill pipes 20 to pass from theoffshore platform 10 through theBOP 16 and thewellhead 18 and into a wellbore below thewellhead 18. Also illustrated inFIG. 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 thewellhead 18. - In a tripping-in operation consistent with embodiments of the present disclosure, as depicted in
FIG. 2 , atripping apparatus 24 is positioned ondrilling floor 26 in thedrilling rig 22 above the wellbore 28 (e.g., the drilled hole or borehole of a well which may be, as illustrated inFIG. 2 , proximate to thedrilling floor 26 in land based drilling operations or which may be, in conjunction withFIG. 1 , below the wellhead 18). Thedrilling rig 22 may include one or more of, for example, thetripping apparatus 24,floor slips 30 positioned in rotary table 32,drawworks 34, acrown block 35, atravelling block 36, atop drive 38, anelevator 40, and atubular handling apparatus 42. Thetripping apparatus 24 may operate to couple and decouple tubular segments (e.g.,drill pipe 20 to and from a drill string) while thefloor slips 30 may operate to close upon and hold adrill pipe 20 and/or the drill string passing into thewellbore 28. The rotary table 32 may be a rotatable portion of thedrilling 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). - 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 thedrilling line 37 is threaded) to operate as a block and tackle system for movement of thetop drive 38, theelevator 40, and any tubular member (e.g., drill pipe 20) coupled thereto. Thetop 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 theelevator 40 may be a mechanism that may be closed around adrill pipe 20 or other tubular members (or similar components) to grip and hold thedrill pipe 20 or other tubular members while those members are moving vertically (e.g., while being lowered into or raised from the wellbore 28). Thetubular 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, thetubular 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. - During a tripping-in operation, the
tubular handling apparatus 42 may position a first tubular segment 44 (e.g., afirst drill pipe 20 or another tubular member) so that thesegment 44 may be grasped by theelevator 40.Elevator 40 may be lowered, for example, via the block and tackle system towards thetripping 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 inFIG. 2A , thetripping apparatus 24 may includetripping slips 48 inclusive ofslip jaws 50 that engage and hold thesegment 46 as well as a forcingring 52 that operates to provide force to actuate theslip jaws 50. Thetripping 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. Thetripping slips 48 may be actuated hydraulically, electrically, pneumatically, or via any similar technique. - The
tripping apparatus 24 may further include a roughneck 54 that may operate to selectively make-up and break-out a threaded connection betweentubular segments jaws 56, makeup/breakout jaws 58, and aspinner 60. In some embodiments, the fixedjaws 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 thesecond tubular segment 46 in the trippingapparatus 24, thesecond tubular segment 46 may be held in a stationary position to allow for the connection of thefirst tubular segment 44 and the second tubular segment 46 (e.g., through connection of the threaded joint 62 of thesecond tubular segment 46 and a threaded joint 64 of the first tubular segment 44). - To facilitate this connection, the
spinner 60 and the makeup/breakout jaws 58 may provide rotational torque. For example, in making up the connection, thespinner 60 may engage thefirst tubular segment 44 and provide a relatively high-speed, low-torque rotation to thefirst tubular segment 44 to connect thefirst segment 44 to thesecond segment 46. Likewise, the makeup/breakout jaws 58 may engage thefirst segment 44 and may provide a relatively low-speed, high-torque rotation to thefirst tubular segment 44 to provide, for example, a rigid connection between thetubular segment breakout jaws 58 may engage thefirst tubular segment 44 and impart a relatively low-speed, high-torque rotation on thefirst tubular segment 44 to break the rigid connection. Thereafter, thespinner 60 may provide a relatively high-speed, low-torque rotation to thefirst tubular segment 44 to disconnect thefirst segment 44 from thesecond segment 46. - In some embodiments, the
roughneck 54 may further include amud bucket 66 that may operate to capture drilling fluid, which might otherwise be released during, for example, the break-out operation. In this manner, themud bucket 66 may operate to prevent drilling fluid from spilling ontodrill floor 26. In some embodiments, themud bucket 66 may include one or more seals that aid in fluidly sealing themud bucket 66 as well as a drain line that operates to allow drilling fluid contained withinmud bucket 66 to return to a drilling fluid reservoir. - Returning to
FIG. 2 , the trippingapparatus 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 trippingapparatus 24 can be moved along the direction of the rig towards and away from thedrilling 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 trippingapparatus 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 ormore support elements 68. This movement may be beneficial to aid in proper location of theroughneck 54 during a make-up or break-out operation (e.g., during a tripping-in or tripping-out operation). - In some embodiments, moving of the tripping
apparatus 24 into position (whether in conjunction with a continuous tripping operation in which thetubular segments drill floor 26 while being made-up or broken-out or in conjunction with a static tripping operation in which thetubular segments drill floor 26 while being made-up or broken-out) may require hunt and peck techniques to find a seam between thetubular segments roughneck 54 to trip thetubular segments tubular segments apparatus 24 can be moved into a correct position to facilitate a make-up or break-out (e.g., tripping) operation. - To facilitate this determination of where and when to move the tripping
apparatus 24 into position (e.g., tool joint recognition), acomputing system 70 may be present and may operate to control the timing when the trippingapparatus 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 fortubular segments computing system 70 may be communicatively coupled to a separatemain 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). -
FIG. 3 illustrates thecomputing system 70. It should be noted that thecomputing 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 fortubular segments computing system 70 may be configured to operate in conjunction with one or more of the trippingapparatus 24 and/or thetubular handling apparatus 42. - The
computing system 70 may be a general purpose or a special purpose computer that includes aprocessing 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 thecomputing system 70, which may operate to collectively store instructions executable by theprocessing 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 carry or store desired program code in the form of machine-executable instructions or data structures and which can be accessed by theprocessing device 74. In some embodiment, the instructions executable by theprocessing 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., theroughneck 54 and/or one or more of the fixedjaws 56, the makeup/breakout jaws 58, and the spinner 60), thetubular handling apparatus 42, and/or the main control system 72 (e.g., to be utilized in the control of the trippingapparatus 24, theroughneck 54, the fixedjaws 56, the makeup/breakout jaws 58, thespinner 60, and/or the tubular handling apparatus 42) to operate in a manner described herein. - The
computing system 70 may operate in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium ofcomputing system 70, such asmemory 76, a hard disk drive, or other short term and/or long term storage. Particularly, theprocessing 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 ofcomputing system 70, such asmemory 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 thedrawworks 34, operational parameters of thedrawworks 34, and/or location and/or position information of the travellingblock 36, thetop drive 38, and/or theelevator 40. This information can be used by the computing system 70 (e.g., by theprocessing 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 fortubular segments apparatus 24 into position to facilitate a make-up or break-out (e.g., tripping) operation by thecomputing system 70, themain control system 72, or by another local controller of the trippingapparatus 24. - 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 thecomputing system 70, for example, to start, control, or operate a graphical user interface (GUI) or applications running on thecomputing system 70 and/or to start, control, or operate the tripping apparatus 24 (e.g., theroughneck 54 and/or one or more of the fixedjaws 56, the makeup/breakout jaws 58, and the spinner 60), thetubular handling apparatus 42, or additional systems of thedrilling rig 22. Additionally, thecomputing system 70 may include adisplay 80 that may be a liquid crystal display (LCD) or another type of display that allows users to view images generated by thecomputing system 70. Thedisplay 80 may include a touch screen, which may allow users to interact with the GUI of thecomputing system 70. Likewise, thecomputing system 70 may additionally and/or alternatively transmit images to a display of themain control system 72, which itself may also include aprocessing device 74, a non-transitory machine readable medium, such asmemory 76, one ormore input structures 78, adisplay 80, and/or anetwork interface 82. - 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 thecomputer system 70 and/or thecomputer 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, thecomputer system 70 may includenetwork interface 82 to allow thecomputer system 70 to interface with various other devices (e.g., electronic devices). Thenetwork 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. - 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 themain control system 72 may each be a device that can be coupled to thenetwork 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). - Returning to
FIG. 2 , one ormore sensors drilling rig 22. In some embodiments, the one ormore sensors sensors sensors more sensors 84 may be proximity sensors (e.g., inductive, magnetic, optical, ultrasonic, etc.) to detect the presence of an object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill 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, thesensors 84 may be disposed on aderrick 87 of thedrilling rig 22 while thesensors 86 may be disposed internal to or adjacent to thedrawworks 34. However, alternative locations on thedrilling rig 22 may be employed. - In some embodiments, a
sensor 84 may generate a signal indicative of the detection of the object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, or the threaded joint 64 of a drill pipe 20) as the object passes thesensor 84 and thesensor 84 may transmit (wirelessly or via a physical connection) the signal indicative of the detection of the object to thecomputer system 70. This signal may be used to determine the location of the object by thecomputer system 70, as the location of thesensor 84 may be stored in thecomputer system 70 and the location of the object may be calculated based on its being detected. - One or more
additional sensors 84 may generate respective signals indicative of the detection of the object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, or the threaded joint 64 of a drill pipe 20) as the one or moreadditional sensors 84 is passed by the object. The one or moreadditional sensors 84 may each transmit (wirelessly or via a physical connection) a respective signal indicative of the detection of the object to thecomputer system 70. This signal may be used to determine the location of the object by thecomputer system 70, as the location of thesensor 84 transmitting the signal may be stored in thecomputer 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, thecomputer 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., thecomputer 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). - 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 ormore sensors 86 may generate a signal indicative of operational characteristics of thedrawworks 34 and may transmit (wirelessly or via a physical connection) the signal indicative of operational characteristic of thedrawworks 34 to thecomputer system 70. This signal may be used to determine the location of an object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, or the threaded joint 64 of a drill pipe 20) by thecomputer 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 causingdrilling line 37 to be extended from thedrawworks 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 trippingapparatus 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 fortubular segments -
FIG. 4 illustrates aflow chart 88 detailing the operation of a detection system, which may include the use of thecomputing system 70 operating in conjunction with one or more of thesensors more sensors 84. However, this operation may instead utilize one ormore sensors 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. - 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 thecomputing 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 thecomputing 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, theelevator 40 and a connection portion of a tubular segment (e.g.,tubular segment 44 or 46). - In
step 92, the one ormore sensors 84 may generate a signal indicative of detection of an object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, or the threaded joint 64 of a drill pipe 20) as the object passes the one ormore sensors 84 and the one ormore sensors 84 may transmit the signal indicative of the detection of the object for receipt by thecomputer system 70. Additionally or alternatively instep 92, one ormore sensors 86 may generate a signal indicative of operational characteristics of the drawworks 34 (e.g., an amount of rotation of a drum causingdrilling line 37 to be extended from the drawworks 34) and may transmit the signal indicative of operational characteristic of thedrawworks 34 for receipt by thecomputer system 70. - In
step 94, the signal(s) received instep 92 may be utilized in conjunction with the initial information fromstep 90 to calculate a location of a seam (e.g., a tool joint seam) or a connection point fortubular segments step 92 may be used to determine the location of an object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, or the threaded joint 64 of a drill pipe 20) by thecomputer system 70 based upon location information of thesensor 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 causingdrilling line 37 to be extended from thedrawworks 34, which defines the location of the object suspended from the block and tackle system). For the purposes of discussion, the object will be theelevator 40, but it is appreciated that the object could be any one of adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, the threaded joint 64 of adrill pipe 20, or other related physical characteristics of the tubular members or their associated positioning equipment. - In
step 94, the computer system 70 (e.g., theprocessing device 74 or theprocessing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium ofcomputing system 70, such asmemory 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 theelevator 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. Theprocessing device 74 or theprocessing 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 theelevator 40, based upon its order to be attached/detached from the tubular string. Theprocessing device 74 or theprocessing 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 instep 92. In this manner, theprocessing device 74 or theprocessing 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. - 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 thecomputer 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 thecomputing system 70 and may be used to determine and/or control where and when to move the trippingapparatus 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 ormore 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 trippingapparatus 24 to operate on. In some embodiments, the output signal generated may cause display of an image, for example, ondisplay 80 in conjunction with and/or separate from activation of one ormore slips 30 and/or 48 and/or determining and/or controlling where and when to move the trippingapparatus 24 into position for a tripping operation. - In
step 98, the output signal generated by thecomputer system 70 may be applied by thecomputer system 70. For example, the computer system 70 (e.g., theprocessing device 74 or theprocessing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium ofcomputing system 70, such asmemory 76, that may be executed) may operate as a control system itself so as to transmit a control signal based upon the output signal ofstep 96 or as the output signal ofstep 96 to control where and when to move the trippingapparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation. Additionally or alternatively, thecomputer system 70 may operate as a control system itself so as to transmit a control signal based upon the output signal ofstep 96 or as the output signal ofstep 96 to control the activation of one ormore 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 trippingapparatus 24 to perform a tripping operation. Likewise, external control systems may instead receive the output signal ofstep 96 from thecomputer system 70 and use the output signal to control where and when to move the trippingapparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation and/or control the activation of one ormore 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 trippingapparatus 24 to perform a tripping operation. -
FIG. 5 illustrates another embodiment of adrilling rig 100 that may be utilized in a tripping operation consistent with embodiments of the present disclosure. As illustrated, the trippingapparatus 24 is illustrated as being positioned abovedrill floor 26 in thedrilling rig 100 above the wellbore (e.g., the drilled hole or borehole of a well which may be proximate to thedrill floor 26 or which may be, in conjunction withFIG. 1 , below the wellhead 18). However, as will be discussed in greater detail below, the trippingapparatus 24 may be moved towards and away from thedrill floor 26 during a tripping operation. As illustrated, thedrilling rig 100 may include one or more of, for example, the trippingapparatus 24, a movable platform 102 (that may include floor slips 30 positioned in rotary table 32, as illustrated inFIG. 6 ),drawworks 34, acrown block 35, a travellingblock 36, atop drive 38, anelevator 40, and atubular handling apparatus 42. The trippingapparatus 24 may operate to couple and decoupletubular segments 44 and 46 (e.g., couple and decoupledrill pipe 20 to and from a drill string) while the floor slips 30 may operate to close upon and hold adrill 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 thedrill floor 26 and/or above thedrill 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. - 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 thedrilling line 37 is threaded) and a travelling block (e.g., a vertically movable set of one or more pulleys or sheaves through which thedrilling line 37 is threaded) to operate as a block and tackle system for movement of thetop drive 38, theelevator 40, and any tubular segment (e.g., drill pipe 20) coupled thereto. In some embodiments, thetop drive 38 and/or theelevator 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. - 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 theelevator 40 may be a mechanism that may be closed around adrill pipe 20 or othertubular segments 44 and 46 (or similar components) to grip and hold thedrill pipe 20 or othertubular segments tubular handling apparatus 42 may operate to retrieve atubular segment 44 from a storage location 43 (e.g., a pipe stand) and position thetubular segment 44 during tripping-in to assist in adding atubular segment 44 to a tubular string. Likewise, thetubular handling apparatus 42 may operate to retrieve atubular segment 44 from a tubular string and transfer thetubular segment 44 to a storage location (e.g., a pipe stand) during tripping-out to remove thetubular segment 44 from the tubular string. - During a tripping-in operation, the
tubular handling apparatus 42 may position a tubular segment 44 (e.g., a drill pipe 20) so that thesegment 44 may be grasped by theelevator 40.Elevator 40 may be lowered, for example, via the block and tackle system towards the trippingapparatus 24 to be coupled to tubular segment 46 (e.g., a drill pipe 20) as part of a drill string. In some embodiments, the trippingapparatus 24 may operate as discussed in conjunction withFIG. 2A above during a tripping operation. However, in addition to the operation of the trippingapparatus 24, continuous tripping operations (trippingtubular segments movable platform 102. - 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 thedrill floor 26 or elsewhere on theoffshore platform 10 or thedrilling 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 theline 37 is threaded) and a travelling block (e.g., a movable set of one or more pulleys or sheaves through which theline 37 is threaded) to operate as a block and tackle system for movement of themovable platform 102 and, thus the rotary table 32 therein and the trippingapparatus 24 thereon. Additionally and/or alternatively, direct acting cylinders, a suspended winch and cable system mechanism disposed such that themovable platform 102 is between the suspended winch and cable system and thedrill floor 26, or similar internal or external actuation systems may be used to move themovable platform 102 alongsupport element 68. - 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 themovable platform 102 while allowing for movement towards and away from thedrill floor 26. Additionally, as illustrated inFIG. 6 , one or morelateral supports 104 may be used to couple themovable platform 102 to thesupport 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 themovable platform 102 relative to drillfloor 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 themovable platform 102 to interface with a support element 68 (e.g., guide tracks, such as top drive dolly tracks) so that themovable platform 102 is movably coupled to thesupport element 68. Accordingly, themovable platform 102 may be movably coupled to asupport element 68 to allow for movement of the movable platform 102 (e.g., towards and away from thedrill 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). - As further illustrated in
FIG. 6 , themovable platform 102 may haveguide 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 thedrill floor 26 or raised above the drill floor 26). Additionally, one ormore locking mechanisms 108 may be employed to affix themovable platform 102 into a desired position with respect to thedrill 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 thetop drive 38 and/or as a backup system to thetop drive 38. The lockingmechanisms 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 thedrill floor 26 and the movable platform 102). It is envisioned that the locking mechanisms will interface with thedrill floor 26 or an element beneath the drill floor (if themovable platform 102 is to be locked in a position planar with the drill floor 26). - Returning to
FIG. 5 , acomputing system 70 may be present and may operate in conjunction with one or more of the trippingapparatus 24, themovable platform 102, an actuating system used to move the trippingapparatus 24, and/or an actuating system used to move themovable platform 102. Thiscomputing system 70 may also operate to control one or more of the tubular segment support system and/or thetubular handling apparatus 42. It should be noted that thecomputing system 70 may be similar to the computing system ofFIG. 3 and may operate in a manner disclosed with respect toFIG. 4 , with the added aspects of control of themovable platform 102 and/or the floor slips 30 of themovable platform 102 in conjunction withsteps - Additionally, tripping operations involving singular tubular members (e.g., drill pipe 20) has been discussed with respect to
FIGS. 2-6 . However, as illustrated inFIG. 7 , it is envisioned that astand 110 of tubular segments 44 (e.g., two, three, or moretubular segments 44 coupled together) may be thetubular segments 44 being tripped-in or tripped-out. The operation including the steps described inFIG. 4 may apply to trippingstands 110 as illustrated inFIG. 7 . For example, when applyingstep 90 to the system ofFIG. 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 includetubular segment 44 characteristics of thestand 110, such as measurements of an overall length of eachrespective tubular segment 44, a measurement of the length of a pin connector and/or a box connector of eachrespective tubular segment 44, and/or an order in which therespective tubular segment 44 are to be connected and/or disconnected to form or break down the tubular string, measurements of an overall length of thestand 110, a measurement of the length of a pin connector and/or a box connector of eachrespective 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 thetubular segments 44 of thestand 110 and/or thestand 110 may be calculated by thecomputing 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 thecomputing system 70. In other embodiments, the measurements and/or order of thetubular segments 44 of thestand 110 and/or thestand 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, theelevator 40 and a connection portion of an uppermost and/or lowermosttubular segment 44 of thestand 110. - Likewise when applying
step 94 to the system ofFIG. 7 , the signal(s) received instep 92 may be utilized in conjunction with the initial information fromstep 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 instep 92 may be used to determine the location of an object (e.g., adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, or the threaded joint 64 of a drill pipe 20) by thecomputer system 70 based upon location information of thesensor 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 causingdrilling line 37 to be extended from thedrawworks 34, which defines the location of the object suspended from the block and tackle system). For the purposes of discussion, the object will be theelevator 40, but it is appreciated that the object could be any one of adrill pipe 20, thetop drive 38, theelevator 40, the threaded joint 62 of adrill pipe 20, the threaded joint 64 of adrill pipe 20, or other related physical characteristics of the tubular stands 110 or their associated positioning equipment. - When further applying
step 94 to the system ofFIG. 7 , the computer system 70 (e.g., theprocessing device 74 or theprocessing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium ofcomputing system 70, such asmemory 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 theelevator 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 thetubular segments 44 of the tubular stands 110 (e.g., the lengths of a pin connector and/or a box connector of eachrespective tubular segment 44 of thestand 110 and, thus, the tool joint and its respective seam between stands 110) may vary. Theprocessing device 74 or theprocessing 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 theelevator 40, based upon its order to be attached/detached from the tubular string. Theprocessing device 74 or theprocessing 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 instep 92. In this manner, theprocessing device 74 or theprocessing 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 lowertubular segment 44 of the tubular stand 110) without direct measurement or sensing of the connection point. - When applying
step 96 to the system ofFIG. 7 , the determined location of a connection point (e.g., a seam of a tool joint or a connection point for arespective tubular segment 44 of thestand 110 and/or between two stands 110) may be utilized to generate an output signal from thecomputer 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 thecomputing system 70 and may be used to determine and/or control where and when to move the trippingapparatus 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 ormore slips 30 and/or 48 to secure one of thestands 110 so that a calculated tool joint seam location thereof will be at an appropriate height for the trippingapparatus 24 to operate on. In some embodiments, the output signal generated may cause display of an image, for example, ondisplay 80 in conjunction with and/or separate from activation of one ormore slips 30 and/or 48 and/or determining and/or controlling where and when to move the trippingapparatus 24 into position for a tripping operation. - In applying
step 98 to the system ofFIG. 7 , the output signal generated by thecomputer system 70 may be applied by thecomputer system 70. For example, the computer system 70 (e.g., theprocessing device 74 or theprocessing device 74 operating in conjunction with software systems implemented as computer executable instructions stored in a non-transitory machine readable medium ofcomputing system 70, such asmemory 76, that may be executed) may operate as a control system itself so as to transmit a control signal based upon the output signal ofstep 96 or as the output signal ofstep 96 to control where and when to move the trippingapparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation. Additionally or alternatively, thecomputer system 70 may operate as a control system itself so as to transmit a control signal based upon the output signal ofstep 96 or as the output signal ofstep 96 to control the activation of one ormore slips 30 and/or 48 to secure one of thestands 110 so that a calculated tool joint seam location thereof will be at an appropriate height for the trippingapparatus 24 to perform a tripping operation. Likewise, external control systems may instead receive the output signal ofstep 96 from thecomputer system 70 and use the output signal to control where and when to move the trippingapparatus 24 into position (e.g., tool joint recognition) to perform a tripping operation and/or control the activation of one ormore slips 30 and/or 48 to secure one of thestands 110 so that a calculated tool joint seam location thereof will be at an appropriate height for the trippingapparatus 24 to perform a tripping operation. - 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.
Claims (20)
1. A system, comprising:
a sensor configured to detect an object in proximity of the sensor and generate a signal indicative of detected object; and
a processing device configured to:
process the signal indicative of the detected object to determine a location of the detected object;
retrieve information related to a physical characteristic of a tubular segment; and
calculate an indication of the location of a connection point of the tubular segment based upon the location of the detected object and the physical characteristic of the tubular segment.
2. The system of claim 1 , wherein the processing device is configured to generate an output indicative of the indication of the location of the connection point of the tubular segment.
3. The system of claim 2 , wherein the processing device is configured to utilize the output to generate a control signal to control movement of a tripping apparatus used in conjunction with a tripping operation.
4. The system of claim 2 , wherein the processing device is configured to utilize the output to generate a control signal to control an operation of a tripping apparatus used in conjunction with a tripping operation.
5. The system of claim 2 , wherein the processing device is configured to transmit the output to a controller to control movement of a tripping apparatus used in conjunction with a tripping operation.
6. The system of claim 2 , wherein the processing device is configured to transmit the output to a controller to control an operation of a tripping apparatus used in conjunction with a tripping operation.
7. The system of claim 2 , wherein the processing device is configured to utilize the output to generate a control signal to control movement of a movable platform configured to transport a tripping apparatus used in conjunction with a tripping operation.
8. The system of claim 2 , wherein the processing device is configured to utilize the output to generate a control signal to control an operation of a movable platform configured to transport a tripping apparatus used in conjunction with a tripping operation.
9. The system of claim 2 , wherein the processing device is configured to transmit the output to a controller to control movement of a movable platform configured to transport a tripping apparatus used in conjunction with a tripping operation.
10. The system of claim 2 , wherein the processing device is configured to transmit the output to a controller to control an operation of a movable platform configured to transport a tripping apparatus used in conjunction with a tripping operation.
11. A device, comprising:
an input configured to receive a signal indicative of a location of a detected object; and
a processor configured to:
calculate an indication of a location of a connection point of a tubular segment based upon the signal and a physical characteristic of the tubular segment to be used in conjunction with a tripping operation.
12. The device of claim 11 , wherein the signal comprises a second indication that the object has passed a sensor, wherein the sensor is configured to be coupled to the input and to generate the signal.
13. The device of claim 11 , wherein the signal comprises a second indication of an operational characteristic of a portion of a drawworks configured to support the tubular segment.
14. The device of claim 11 , wherein the input is configured to receive a second signal indicative of second location of the detected object, wherein the processor is configured to calculate a second indication of a location of the connection point of the tubular segment based upon the second signal and the physical characteristic of the tubular segment to be used in conjunction with a tripping operation.
15. The device of claim 14 , wherein the processor is configured to calculate a velocity of the detected object based upon the indication of the location of the connection point and the second indication of the location of the connection point.
16. The device of claim 11 , wherein the processor is configured to generate an output indicative of the indication of the location of the connection point of the tubular segment to control a tripping apparatus used in conjunction with the tripping operation.
17. A method, comprising:
receiving a signal indicative of a location of a detected object;
retrieving information related to a physical characteristic of a tubular segment;
calculating an indication of the location of a connection point of the tubular segment based upon the signal and the physical characteristic of the tubular segment;
generating an output indicative of the indication of the location of the connection point of the tubular segment; and
utilizing the output in conjunction with a tripping operation.
18. The method of claim 17 , wherein utilizing the output in conjunction with the tripping operation comprises generating a control signal to control movement of a tripping apparatus used in conjunction with the tripping operation.
19. The method of claim 17 , wherein utilizing the output in conjunction with the tripping operation comprises generating a control signal to control an operation of a tripping apparatus used in conjunction with the tripping operation.
20. The method of claim 17 , wherein utilizing the output in conjunction with the tripping operation comprises generating a control signal to an operation of a movable platform configured to transport a tripping apparatus used in conjunction with the tripping operation.
Priority Applications (9)
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US16/129,153 US20190078401A1 (en) | 2017-09-14 | 2018-09-12 | Tool joint positioning |
SG11202002275SA SG11202002275SA (en) | 2017-09-14 | 2018-09-13 | Tool joint positioning |
KR1020207010531A KR20200040933A (en) | 2017-09-14 | 2018-09-13 | Tool joint positioning |
PCT/US2018/050813 WO2019055606A1 (en) | 2017-09-14 | 2018-09-13 | Tool joint positioning |
EP18857211.9A EP3682082A4 (en) | 2017-09-14 | 2018-09-13 | Tool joint positioning |
CA3075671A CA3075671A1 (en) | 2017-09-14 | 2018-09-13 | Tool joint positioning |
AU2018332896A AU2018332896A1 (en) | 2017-09-14 | 2018-09-13 | Tool joint positioning |
CN201880073218.6A CN111373115A (en) | 2017-09-14 | 2018-09-13 | Drill tool joint positioning |
BR112020005058-0A BR112020005058A2 (en) | 2017-09-14 | 2018-09-13 | conical connection placement |
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US201762558758P | 2017-09-14 | 2017-09-14 | |
US16/129,153 US20190078401A1 (en) | 2017-09-14 | 2018-09-12 | Tool joint positioning |
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EP (1) | EP3682082A4 (en) |
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US20220074275A1 (en) * | 2020-09-04 | 2022-03-10 | Sichuan Honghua Petroleum Equipment Co., Ltd. | Methods for tripping a drilling rig or a workover rig |
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CN112554853A (en) * | 2020-12-11 | 2021-03-26 | 成都北方石油勘探开发技术有限公司 | Method and system for controlling water injection or gas injection |
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BR112020005058A2 (en) | 2020-09-15 |
EP3682082A4 (en) | 2021-06-02 |
CN111373115A (en) | 2020-07-03 |
EP3682082A1 (en) | 2020-07-22 |
SG11202002275SA (en) | 2020-04-29 |
KR20200040933A (en) | 2020-04-20 |
AU2018332896A1 (en) | 2020-04-09 |
WO2019055606A1 (en) | 2019-03-21 |
CA3075671A1 (en) | 2019-03-21 |
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