WO2021097414A1 - Commande de la vitesse de pénétration par l'intermédiaire d'une pluralité de couches de commande - Google Patents

Commande de la vitesse de pénétration par l'intermédiaire d'une pluralité de couches de commande Download PDF

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Publication number
WO2021097414A1
WO2021097414A1 PCT/US2020/060701 US2020060701W WO2021097414A1 WO 2021097414 A1 WO2021097414 A1 WO 2021097414A1 US 2020060701 W US2020060701 W US 2020060701W WO 2021097414 A1 WO2021097414 A1 WO 2021097414A1
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WO
WIPO (PCT)
Prior art keywords
drilling
control
rop
contextual
control parameters
Prior art date
Application number
PCT/US2020/060701
Other languages
English (en)
Inventor
Nathaniel Wicks
Richard Harmer
Ginger HILDEBRAND
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
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Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2021097414A1 publication Critical patent/WO2021097414A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B44/02—Automatic control of the tool feed

Definitions

  • Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other materials that are trapped in subterranean formations.
  • Well construction operations e.g ., drilling operations
  • a well construction system i.e ., a drill rig
  • various automated surface and subterranean well construction equipment operating in a coordinated manner.
  • a drive mechanism such as a top drive or a rotary table located at a wellsite surface, may be utilized to rotate and advance a drill string into a subterranean formation to drill a wellbore.
  • the drill string may include a plurality of drill pipes coupled together and terminating with a drill bit.
  • the length of the drill string is increased by adding additional drill pipes while the depth of the wellbore increases.
  • a drilling fluid i.e., drilling mud
  • the drilling fluid lubricates and cools the drill bit, and carries drill cuttings from the wellbore back to the wellsite surface.
  • the drilling fluid returning to the surface may then be cleaned and again pumped through the drill string.
  • Success of well construction operations may depend on many factors, including the cost of drilling a well.
  • the costs associated with drilling a well are primarily time dependent. Accordingly, the faster a target well depth is achieved, the lower the cost for drilling the well.
  • cost and time associated with well construction may increase substantially if a wellbore becomes unstable during drilling operations. Accordingly, successful drilling operations depend on achieving a target well depth as fast as possible, but within safety limits defined for the drilling operations.
  • a target well depth may be achieved in a shortest amount of time by drilling through subterranean formations at an optimal rate of penetration (ROP).
  • An optimal ROP that is achieved during drilling operations depends on various drilling parameters, including geological composition of the formation being drilled, geometry and material of the drill bit, rotational speed (RPM) of the drill bit, amount of torque applied to the drill bit, pressure and flow rate of drilling fluid being pumped through the drill string, and axial force applied at the drill bit, which may be known in the industry as the weight on bit (WOB).
  • ROP generally increases with increasing WOB, until a maximum beneficial WOB is reached, thereafter decreasing the ROP with further increase of the WOB.
  • an optimal WOB exists that will achieve an optimal ROP.
  • an optimal ROP for one set of drilling parameters may not be optimal for another set of drilling parameters.
  • the present disclosure introduces an apparatus including a control system that controls ROP through a subterranean formation via drilling equipment to drill a wellbore.
  • the control system includes sensors for operational measurements indicative of operational performance of the drilling equipment.
  • the control system also includes control devices each comprising a processor and a memory storing a computer program code, which when executed, causes the control devices to collectively perform a first control layer, a second control layer, and a third control layer.
  • the first control layer receives contextual drilling information.
  • the second control layer receives the operational measurements and determines drilling control parameters based on the contextual drilling information.
  • the third control layer determines an ROP control command indicative of an intended ROP based on the drilling control parameters and the operational measurements.
  • the ROP control command is to be received by a drawworks.
  • the present disclosure also introduces a method that includes commencing operation of a control system for controlling ROP through a subterranean formation via drilling equipment to drill a wellbore.
  • Commencing the operation of the control system causes control devices to collectively perform a first control layer, a second control layer, and a third control layer.
  • the first control layer receives contextual drilling information indicative of at least one of properties of the subterranean formation, specifications of the drilling equipment, and nominal operating setpoints of the drilling equipment.
  • the second control layer receives operational measurements and determines drilling control parameters based on the contextual drilling information.
  • the third control layer determines an ROP control command indicative of an intended ROP based on the drilling control parameters and the operational measurements.
  • the present disclosure also introduces a computer program product that includes a non-transitory, computer-readable medium containing a computer program code executable by processors of control devices of a control system for controlling ROP through a subterranean formation via drilling equipment to drill a wellbore.
  • the computer program code when executed by the processors, causes the control devices to collectively perform a first control layer, a second control layer, and a third control layer.
  • the first control layer receives contextual drilling information indicative of at least one of properties of the subterranean formation, specifications of the drilling equipment, and nominal operating setpoints of the drilling equipment.
  • the second control layer receives operational measurements and determines drilling control parameters based on the contextual drilling information.
  • the third control layer determines an ROP control command indicative of an intended ROP based on the drilling control parameters and the operational measurements.
  • FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 4 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 5 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 6 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 7 is a schematic view of at least a portion of an example implementation of a user interface according to one or more aspects of the present disclosure.
  • FIG. 8 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. 9 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.
  • FIG. l is a schematic view of at least a portion of an example implementation of a well construction system 100 according to one or more aspects of the present disclosure.
  • the well construction system 100 represents an example environment in which one or more aspects of the present disclosure described below may be implemented.
  • the well construction system 100 may be or comprise a drilling rig and associated equipment.
  • the well construction system 100 is depicted as an onshore implementation, the aspects described below are also applicable to offshore implementations.
  • the well construction system 100 is depicted in relation to a wellbore 102 formed by rotary and/or directional drilling from a wellsite surface 104 and extending into a subterranean formation 106.
  • the well construction system 100 comprises well construction equipment, such as surface equipment 110 located at the wellsite surface 104 and a drill string 120 suspended within the wellbore 102.
  • the surface equipment 110 may include a mast, a derrick, and/or another support structure 112 disposed over a rig floor 114.
  • the drill string 120 may be suspended within the wellbore 102 from the support structure 112.
  • the support structure 112 and the rig floor 114 are collectively supported over the wellbore 102 by legs and/or other support structures (not shown).
  • Certain pieces of surface equipment 110 may be manually operated (e.g ., by hand, via a local control panel, etc.) by rig personnel 195 (e.g, a roughneck or another human rig operator) located at various portions (e.g, rig floor 114) of the well construction system 100.
  • rig personnel 195 e.g, a roughneck or another human rig operator located at various portions (e.g, rig floor 114) of the well construction system 100.
  • the drill string 120 may comprise a bottom -hole assembly (BHA) 124 and means 122 for conveying the BHA 124 within the wellbore 102.
  • the conveyance means 122 may comprise drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, and/or other means for conveying the BHA 124 within the wellbore 102.
  • a downhole end of the BHA 124 may include or be coupled to a drill bit 126. Rotation of the drill bit 126 and the weight of the drill string 120 collectively operate to form the wellbore 102.
  • the drill bit 126 may be rotated via operation of a top drive 116 at the wellsite surface 104 and/or via operation of a downhole mud motor 182 operatively connected with the drill bit 126.
  • a top drive 116 at the wellsite surface 104
  • a downhole mud motor 182 may rotate the drill bit 126.
  • the resulting average drill bit rotational rate is equal to the rotational rate of the top drive 116.
  • both the top drive 116 and the mud motor 182 rotate the drill bit 126, the resulting average drill bit rotational rate is equal to the sum of the rotational rates of the top drive 116 and the mud motor 182.
  • the drill string 120 may also or instead be rotated by a rotary table (not shown) that is rotatably supported on the rig floor 114.
  • Drilling torque applied to the drill string 120 by the top drive 116 or the rotary table to rotate the drill string 120 may be known in the industry as rotary torque.
  • Drilling torque applied to the drill bit 126 may be known in the industry as torque on bit (TOB).
  • the BHA 124 may also include one or more downhole tools 180, 181 connected above and/or below the mud motor 182.
  • One or more of the downhole tools 180, 181 may be or comprise a directional drilling tool, such as a bent sub operable to facilitate slide drilling or a rotary steerable system (RSS) operable to facilitate directional drilling while continuously rotating the drill string 120 from the surface ( e.g ., via the top drive 116).
  • a directional drilling tool such as a bent sub operable to facilitate slide drilling or a rotary steerable system (RSS) operable to facilitate directional drilling while continuously rotating the drill string 120 from the surface ( e.g ., via the top drive 116).
  • RSS rotary steerable system
  • One or more of the downhole tools 180, 181 may be or comprise a power generating sub having a mud-powered turbine operable to generate electrical power to energize one or more of the electrical devices of the BHA 124.
  • One or more of the downhole tools 180, 181 may be or comprise a measurement- while-drilling (MWD) or logging-while-drilling (LWD) tools comprising downhole sensors 184 operable for the acquisition of measurement data pertaining to the BHA 124, the wellbore 102, and/or the formation 106.
  • MWD measurement- while-drilling
  • LWD logging-while-drilling
  • the downhole sensors 184 may comprise an inclination sensor, a rotational position sensor, and/or a rotational speed sensor, which may include one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for determining the orientation, position, and/or speed of one or more portions of the BHA 124 (e.g, the drill bit 126, the downhole tools 180, 181, and/or the mud motor 182) and/or other portions of the drill string 120 relative to the wellbore 102 and/or the wellsite surface 104.
  • MEMS micro-electro-mechanical system
  • the downhole sensors 184 may comprise a depth correlation sensor utilized to determine and/or log position (i.e., depth) of one or more portions of the BHA 124 and/or other portions of the drill string 120 within the wellbore 102 and/or with respect to the wellsite surface 104.
  • the downhole sensors 184 may comprise one or more pressure sensors operable to facilitate pressure data (i.e., pressure measurements) indicative of internal pressure of the drilling fluid while flowing 158 within the internal passage 121 and/or indicative of external pressure of the drilling fluid while flowing 159 within the annulus 108 of the wellbore 102.
  • the downhole sensors 184 may comprise an axial load sensor operable to facilitate axial load data (i.e., axial load measurements) indicative of axial load (i.e., weight) applied to the drill bit 126 by the drill string 120.
  • the axial load data may thus comprise or otherwise be indicative of WOB (i.e., downhole WOB) that is applied by the drill bit 126 to the formation 106 during drilling operations.
  • WOB downhole WOB
  • the axial load sensor may thus be operable to output or otherwise facilitate WOB data (i.e., WOB measurements) and be referred to as a WOB sensor.
  • the downhole sensors 184 may further comprise a torque sensor operable to facilitate torque data (i.e., torque measurements) indicative of TOB applied by the top drive 116 and/or mud motor 182 to the drill bit 126 during drilling operations.
  • the torque data may thus comprise or otherwise be indicative of drilling torque applied by the drill bit 126 to the formation 106 during drilling operations.
  • the torque sensor may thus be operable to output or otherwise facilitate TOB data (i.e., TOB measurements) and be referred to as a TOB sensor.
  • the drilling torque output by the mud motor 182 may be calculated based on the pressure data indicative of differential pressure of the drilling fluid across the mud motor 182 and operational ( e.g ., structural) specifications of the mud motor 182.
  • One or more of the downhole tools 180, 181 may comprise a downhole telemetry device 186 operable to communicate with the surface equipment 110, such as via mud-pulse telemetry, electromagnetic telemetry, and/or other telemetry means.
  • One or more of the downhole tools 180, 181 and/or other portion(s) of the BHA 124 may comprise a downhole controller 188 operable to receive, process, and/or store data received from the surface equipment 110, the downhole sensors 184, and/or other portions of the BHA 124.
  • the controller 188 may also store executable computer programs (e.g., program code instructions), including for implementing one or more aspects of the operations described herein.
  • the support structure 112 may support the top drive 116, operable to connect with an upper end of the drill string 120, and to impart rotary motion 117 and vertical motion 135 to the drill string 120, including the drill bit 126.
  • another driver such as a kelly and a rotary table (neither shown), may be utilized in addition to or instead of the top drive 116 to impart the rotary motion 117 to the drill string 120.
  • the top drive 116 may be suspended from (i.e., supported by) the support structure
  • the hoisting system may comprise a traveling block 113, a crown block 115, and a drawworks 118 storing a flexible line 123 (e.g, a cable, a wire rope, etc.).
  • the crown block 115 may be connected to and supported by the support structure
  • the traveling block 113 may be connected to and support the top drive 116.
  • the drawworks 118 may be mounted to the rig floor 114.
  • the 113 comprise pulleys or sheaves around which the flexible line 123 is reeved to operatively connect the crown block 115, the traveling block 113, and the drawworks 118.
  • the drawworks 118 may comprise a drum and an electric motor (not shown) operatively connected with and operable to rotate the drum.
  • the drawworks 118 may selectively impart tension to the flexible line 123 to lift and lower the top drive 116, resulting in the vertical movement 135 of the top drive 116 and the drill string 120 (when connected with the top drive 116).
  • the drawworks 118 may be operable to reel in the flexible line 123, causing the traveling block 113 and the top drive 116 to move upward.
  • the drawworks 118 may be further operable to reel out the flexible line 123, causing the traveling block 113 and the top drive 116 to move downward.
  • the hoisting system may further comprise a weight sensor 119 operable to output or otherwise facilitate weight data ⁇ i.e., weight measurements) indicative of weight of the drill string 120 at the surface.
  • the weight sensor 119 may be disposed or installed in association with a top drive link, the elevator links 127, the elevator 129, a deadline anchor (not shown), and/or other portions of the hoisting system.
  • the weight sensor 119 may be or comprise a load sensor (e.g ., a force sensor, a load cell, a strain gauge, etc.) operable to output or otherwise facilitate weight data indicative of load ⁇ i.e., weight) applied by the drill string 120 to the hoisting system at the surface.
  • the weight data of the drill string 120 may comprise or be indicative of hook load, which is the portion of the weight of the drill string 120 supported by the hoisting system from the travelling block 113.
  • the weight sensor 119 may thus be operable to output or otherwise facilitate hook load data ⁇ i.e., hook load measurements) and be referred to as a hook load sensor.
  • the weight of the drill string 120 may be greater than an optimal or otherwise intended WOB.
  • part of the weight of the drill string 120 may be supported by the hoisting system ⁇ e.g., the drawworks 118). Therefore, the drill string 120 may be maintained in tension over some ⁇ e.g, most) of its length above the BHA 124.
  • the drill string 120 may also exhibit buoyancy when submerged in the drilling fluid in the wellbore 102. Therefore, WOB ⁇ i.e., surface WOB) may be calculated (or estimated) to be equal to the weight of the drill string 120 in the drilling mud, minus the hook load.
  • the WOB may be further offset ⁇ e.g, increased or decreased) by friction between the drill string 120 and the sidewall of the wellbore 102.
  • the drill string hoisting system may further comprise a position sensor 131 operable to output or otherwise facilitate position data ⁇ i.e., position measurements) indicative of position of a predetermined portion of the hoisting system.
  • the position sensor 131 may be or comprise a rotational position sensor disposed or installed in association with, for example, the drum of the drawworks 118.
  • the position sensor 131 may thus be operable to output or otherwise facilitate position data indicative of rotational position of the drum.
  • the position data may be indicative of block position, which may be or comprise position of the traveling block 113 or another portion of the drill string hoisting system ( e.g ., top drive 116) supported by the traveling block 113.
  • the position data may be further indicative of rotational speed of the drum, and thus indicative of linear speed of the traveling block 113 and the drill string 120.
  • the position data may be further indicative of rotational acceleration of the drum, and thus linear acceleration of the traveling block 113 and the drill string 120.
  • the position sensor 131 may be or comprise, for example, an encoder, a rotary potentiometer, or a rotary variable-differential transformers (RVDTs).
  • the top drive 116 may comprise a grabber, a swivel (neither shown), elevator links 127 terminating with an elevator 129, and a drive shaft 125 operatively connected with a motor (e.g., an electric motor) (not shown) of the top drive 116.
  • the drive shaft 125 may be selectively coupled with the upper end of the drill string 120 and the prime mover may be selectively operated to rotate the drive shaft 125 and the drill string 120 coupled with the drive shaft 125.
  • the elevator links 127 and the elevator 129 of the top drive 116 may handle tubulars (e.g, joints and/or stands of drillpipe, drill collars, casing, etc.) that are not mechanically coupled to the drive shaft 125.
  • tubulars e.g, joints and/or stands of drillpipe, drill collars, casing, etc.
  • the elevator 129 may grasp the tubulars of the drill string 120 such that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive 116.
  • a rotation sensor 132 may be operatively connected with and/or disposed in association with the top drive 116.
  • the rotation sensor 132 may be operable to output or otherwise facilitate rotational data (i.e., rotational measurements) indicative of rotational position of a drive shaft 125 of the top drive 116.
  • the rotation sensor 132 may be disposed or installed in association with, for example, an electric motor of the top drive 116 to monitor rotational position of the electric motor, and thus the drive shaft 125.
  • the rotation sensor 132 may be disposed or installed in association with, for example, the drive shaft 125 to monitor rotational position of the drive shaft 125.
  • the rotational measurements may be further indicative of rotational distance, rotational speed, and rotational acceleration of the drive shaft 125 of the top drive 116.
  • the rotation sensor 132 may be or comprise, for example, at least one of an encoder, a rotary potentiometer, and an RVDT.
  • a torque sensor 128 (e.g, a torque sub) may be mechanically connected or otherwise disposed between an upper end of the drill string 120 and the drive shaft 125, such as may permit the torque sensor to transfer and measure torque output by the top drive 116.
  • the torque sensor 128 may be operable to output or otherwise facilitate torque data (i.e., torque measurements) indicative of torque applied by the top drive 116 to the drill string 120.
  • the torque sensor 128 may also facilitate determination of rotational position, rotational distance, rotational speed, and/or rotational acceleration of the drive shaft 125.
  • a top drive controller (e.g ., a VFD) may also operate as a torque sensor operable to determine torque output by the top drive 116 to the drill string 120, such as based on the electrical power (e.g., current, voltage, frequency, etc.) delivered to the electric motor of the top drive 116.
  • the electrical power e.g., current, voltage, frequency, etc.
  • the well construction system 100 may further include a drilling fluid circulation system or equipment operable to circulate fluids between the surface equipment 110 and the drill bit 126 during drilling and other operations.
  • the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surface 104 into the wellbore 102 via an internal fluid passage 121 extending longitudinally through the drill string 120.
  • the drilling fluid circulation system may comprise a pit, a tank, and/or other fluid container 142 holding the drilling fluid 140 (i.e., drilling mud), and one or more pumps 144 operable to move the drilling fluid 140 from the container 142 into the fluid passage 121 of the drill string 120 via a fluid conduit 145 (i.e., a standpipe) extending from the pump 144 to the top drive 116 and an internal passage extending through the top drive 116 (not shown).
  • a fluid conduit 145 i.e., a standpipe
  • a pressure sensor 147 may be connected along the fluid conduit 146 to measure pressure of the drilling fluid being pumped downhole.
  • the pressure sensor 147 may be operable to output or otherwise facilitate pressure data (i.e., pressure measurements) indicative of pressure of the drilling fluid at the wellsite surface 104 being pumped downhole via the drill string 120.
  • the pressure sensor 147 may be connected close to the top drive 116 or at an upper end of the conduit 145, such as may permit the pressure sensor 147 to measure the pressure within the drill string 120 at an upper end of the internal passage 121 of the drill string 120.
  • the pressure of the drilling fluid at the wellsite surface 104 being pumped downhole may be known in the industry as standpipe pressure.
  • the pressure sensor 147 may be used to determine differential pressure across the mud motor, by measuring the standpipe pressure while the drill bit 126 is on-bottom (i.e., contacting the bottom of the wellbore 102) during drilling operations, measuring the standpipe pressure while the drill bit 126 is off-bottom (i.e., not contacting the bottom of the wellbore 102) and the drilling fluid is being pumped downhole to rotate the drill bit 126 via the mud motor 182, and then calculating the difference between the two standpipe pressure measurements.
  • the differential pressure may be or comprise an increase in standpipe pressure while drilling relative to standpipe pressure while off-bottom.
  • the off-bottom standpipe pressure may be determined ( i.e ., taken) after each piece of drill pipe (or stand) is connected, before going on-bottom, but while rotating the drill 126 via the mud motor 182 and pumping drilling fluid at the nominal drilling flowrate.
  • the differential pressure may be known in the industry as DeltaP (or DR).
  • the pressure sensor 147 may thus be operable to output or otherwise facilitate DR measurements and be referred to as a DR sensor.
  • the drilling fluid may continue to flow downhole through the internal passage 121 of the drill string 120, as indicated by directional arrow 158.
  • the drilling fluid may exit the BHA 124 via ports in the mud motor 182 and/or drill bit 126 and then circulate uphole through an annular space 108 of the wellbore 102 defined between an exterior of the drill string 120 and the sidewall of the wellbore 102, such flow being indicated in FIG. 1 by directional arrows 159.
  • the drilling fluid lubricates the drill bit 126 and carries formation cuttings uphole to the wellsite surface 104.
  • the drilling fluid flowing downhole through the internal passage 121 may selectively actuate the mud motor 182 to rotate the drill bit 126 instead of or in addition to the rotation of the drill string 120 via the top drive 116. Accordingly, rotation of the drill bit 126 caused by the top drive 116 and/or mud motor 182, in conjunction with the weight-on-bit (WOB), may advance the drill string 120 through the formation 106 to form the wellbore 102.
  • WOB weight-on-bit
  • the well construction system 100 may further include fluid control equipment 130 for maintaining well pressure control and for controlling fluid being discharged from the wellbore 102.
  • the fluid control equipment 130 may be mounted on top of a wellhead 134.
  • the drilling fluid flowing uphole 159 toward the wellsite surface 104 may exit the annulus 108 of the wellbore 102 via one or more components of the fluid control equipment 130, such as a bell nipple, a rotating control device (RCD), and/or a ported adapter (e.g, a spool, a cross adapter, a wing valve, etc.).
  • the drilling fluid may then pass through one or more fluid conduits 151 into drilling fluid reconditioning equipment 170 to be cleaned and reconditioned before returning to the fluid container 142.
  • the drilling fluid reconditioning equipment 170 may also separate drill cuttings 146 from the drilling fluid into a cuttings container 148.
  • a pressure sensor 153 may be connected along one or more of the fluid conduits 151 to measure pressure of the drilling fluid exiting the annulus 108 via one or more components of the fluid control equipment 130.
  • the pressure sensor 153 may be operable to output or otherwise facilitate pressure data (i.e., pressure measurements) indicative of the pressure of the drilling fluid exiting the annulus 108.
  • the pressure sensor 153 may be connected close to the fluid control equipment 130, such as may permit the pressure sensor 153 to measure the pressure of the drilling fluid at an upper end of the annulus 108 proximate the wellsite surface 104.
  • Monitoring annular pressure may aid in diagnosing condition of the wellbore 102 and help prevent or otherwise avoid potentially dangerous well control issues.
  • Monitoring annular pressure during drilling operations, when used in conjunction with measuring and controlling other drilling parameters may improve steering performance and aid in detection of abnormal events, such as sticking, hanging or balling stabilizers, drilling fluid problems, and cuttings build-up.
  • the surface equipment 110 of the well construction system 100 may also comprise a control center 190 from which various portions of the well construction system 100, such as a drill string rotation system (e.g ., the top drive 116), a hoisting system (e.g, the drawworks 118 and the blocks 113, 115), a drilling fluid circulation system (e.g, the mud pump 144 and the fluid conduit 145), a drilling fluid cleaning and reconditioning system (e.g, the drilling fluid reconditioning equipment 170 and the containers 142, 148), the well control system (e.g, a BOP stack, a choke manifold, and/or other components of the fluid control equipment 130), and the BHA 124, among other examples, may be monitored and controlled.
  • a drill string rotation system e.g ., the top drive 116
  • a hoisting system e.g, the drawworks 118 and the blocks 113, 115
  • a drilling fluid circulation system e.g, the mud pump 144 and the fluid
  • the control center 190 may be located on the rig floor 114 or another location of the well construction system 100, such as the wellsite surface 104.
  • the control center 190 may comprise a facility 191 (e.g, a room, a cabin, a trailer, a truck or other service vehicle, etc.) containing a control workstation 197, which may be operated by rig personnel 195 (e.g, a driller or other human rig operator(s)) to monitor and control various wellsite equipment and/or portions of the well construction system 100.
  • rig personnel 195 e.g, a driller or other human rig operator(s)
  • the control workstation 197 may be communicatively connected with a central (or surface) controller 192 (e.g, a processing device, a computer, etc.), such as may be operable to receive, process, and output information to monitor operations of and provide control to one or more portions of the well construction system 100.
  • the controller 192 may be communicatively connected with the surface equipment 110 and downhole equipment 120 described herein, and may be operable to receive signals (e.g, sensor data, sensor measurements, etc.) from and transmit signals (e.g, control data, control signals, control commands, etc.) to the equipment to perform various operations described herein.
  • the controller 192 may store executable program code, instructions, and/or operational parameters or setpoints, including for implementing one or more aspects of methods and operations described herein.
  • the controller 192 may be located within and/or outside of the facility 191.
  • Communication i.e., telemetry
  • the BHA 124 and the controller 192 may be via mud-pulse telemetry (i.e., pressure pulses) sent through the drilling fluid flowing within a fluid passage 121 of the drill string 120.
  • the downhole telemetry device 186 may comprise a modulator selectively operable to modulate the pressure (i.e., cause pressure changes, pulsations, and/or fluctuations) of the drilling fluid flowing within the fluid passage 121 of the downhole tool 189 to transmit downhole data (i.e., downhole measurements) received from the downhole controller 188, the downhole sensors 184, and/or other portions of the BHA 124 in the form of pressure pulses.
  • downhole data i.e., downhole measurements
  • the modulated pressure pulses travel uphole along the drilling fluid through the fluid passage 121, the top drive 116, and the fluid conduit 145 to be detected by an uphole telemetry device 149.
  • the uphole telemetry device 149 may comprise a pressure transducer or sensor in contact with the drilling fluid being pumped downhole.
  • the uphole telemetry device 149 may thus be disposed along or in connection with the fluid conduit 145, the top drive 116, and/or another conduit or device transferring or in contact with the drilling fluid being pumped downhole.
  • the uphole telemetry device 149 may be operable to detect the modulated pressure pulses, convert the pressure pulses to electrical signals, and communicate the electrical signals to the controller 192.
  • the controller 192 may be operable to interpret the electrical signals to reconstruct the downhole data transmitted by the downhole telemetry device 186.
  • the pressure sensor 147 and the uphole telemetry device 149 may be or form the same device.
  • the control workstation 197 may be operable for entering or otherwise communicating control commands to the controller 192 by the rig personnel 195, and for displaying or otherwise communicating information from the controller 192 to the rig personnel 195.
  • the control workstation 197 may comprise one or more input devices 194 (e.g., one or more keyboards, mouse devices, joysticks, touchscreens, etc.) and one or more output devices 196 (e.g, one or more video monitors, touchscreens, printers, audio speakers, etc.).
  • Communication between the controller 192, the input and output devices 194, 196, and various sensors 119, 128, 131, 147, 149 of the well construction system 100 may be via wired and/or wireless communication means.
  • such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.
  • Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in FIG. 1. Additionally, various equipment and/or subsystems of the well construction system 100 shown in FIG. 1 may include more or fewer components than as described above and depicted in FIG. 1. For example, various engines, motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system 100 and are within the scope of the present disclosure.
  • FIG. 2 is a schematic view of at least a portion of an example implementation of a drilling rig control system 200 (hereinafter “rig control system”) for monitoring and controlling various equipment, portions, and subsystems of the well construction system 100 shown in FIG. 1.
  • the rig control system 200 may comprise one or more features of the well construction system 100, including where indicated by the same reference numerals. Accordingly, the following description refers to FIGS. 1 and 2, collectively.
  • the rig control system 200 depicted in FIG. 2, as well as other implementations of rig control systems also within the scope of the present disclosure may also be applicable or readily adapted for utilization with other implementations of well construction systems also within the scope of the present disclosure.
  • the various pieces of well construction equipment described above and shown in FIGS. 1 and 2 may each comprise one or more actuators (e.g ., combustion, hydraulic, and/or electric), which when operated may cause the corresponding well construction equipment to perform intended actions (e.g., work, tasks, movements, operations, etc.).
  • Each piece of well construction equipment may further carry or comprise one or more sensors disposed in association with a corresponding actuator or another portion of the piece of equipment.
  • Each sensor may be communicatively connected with a corresponding control device and operable to generate sensor data (e.g, electrical sensor signals or measurements) indicative of an operational (e.g, mechanical or physical) status of the corresponding actuator or component, thereby permitting the operational status of the actuator to be monitored by the control device.
  • the sensor data may be utilized by the control device as feedback data, permitting operational control of the piece of well construction equipment and coordination with other well construction equipment.
  • Such sensor data may be indicative of performance of each individual actuator and, collectively, of the entire piece of well construction equipment.
  • the rig control system 200 may be in real-time communication with one or more components, subsystems, systems, and/or other equipment of the well construction system 100 that are monitored and/or controlled by the rig control system 200.
  • the equipment of the well construction system 100 may be grouped into several subsystems, each operable to perform a corresponding operation and/or a portion of the well construction operations described herein.
  • the subsystems may include a drill string rotation system 211 (e.g ., the top drive 116), a hoisting system 212 (e.g, the drawworks 118 and the blocks 113, 115), a drilling fluid circulation system 213 (e.g, the mud pump 144 and the fluid conduit 145), a drilling fluid cleaning and reconditioning (DFCR) system 214 (e.g, the drilling fluid reconditioning equipment 170 and the containers 142, 148), a well control system 215 (e.g, a BOP stack, a choke manifold, and/or other components of the fluid control equipment 130), and the BHA 124 (designated in FIG. 2 by reference number 216), among other examples.
  • the control workstation 197 may be utilized by rig personnel to monitor, configure, control, and/or otherwise operate one or more of the subsystems 211-216.
  • Each of the well construction subsystems 211-216 may further comprise various communication equipment (e.g, modems, network interface cards, etc.) and communication conductors (e.g, cables) communicatively connecting the equipment (e.g, sensors and actuators) of each subsystem 211-216 with the control workstation 197 and/or other equipment.
  • various communication equipment e.g, modems, network interface cards, etc.
  • communication conductors e.g, cables
  • One or more of the subsystems 211-216 may include one or more local controllers 221-226, each operable to control various well construction equipment of the corresponding subsystem 211-216 and/or an individual piece of well construction equipment of the corresponding subsystem 211-216.
  • Each well construction subsystem 211-216 includes various well construction equipment comprising corresponding actuators 241-246 for performing operations of the well construction system 100.
  • One or more of the subsystems 211-216 may include various sensors 231-236 operable to output or otherwise facilitate sensor data (e.g, signals, information, measurements, etc.) indicative of operational status of the well construction equipment of the corresponding subsystem 211-216.
  • Each local controller 221-226 may output or otherwise facilitate control data (i.e., control commands, signals, and/or information) to one or more actuators 241-246 to perform corresponding actions of a piece of equipment of the corresponding subsystem 211-216.
  • control data i.e., control commands, signals, and/or information
  • One or more of the local controllers 221-226 may receive sensor data generated by one or more corresponding sensors 231-236 indicative of operational status of an actuator or another portion of a piece of equipment of the corresponding subsystem 211-216.
  • the local controllers 221-226, the sensors 231-236, and the actuators 241-246 are each shown as a single block, it is to be understood that each local controller 221-226, sensor 231-236, and actuator 241-246 may illustratively represent a plurality of local controllers, sensors, and actuators.
  • the sensors 231-236 may include sensors utilized for operation of the various subsystems 211-216 of the well construction system 100.
  • the sensors 231-236 may include cameras, position sensors, pressure sensors, temperature sensors, flow rate sensors, vibration sensors, current sensors, voltage sensors, resistance sensors, gesture detection sensors or devices, voice actuated or recognition devices or sensors, and/or other examples.
  • the sensor data may include signals, information, and/or measurements indicative of equipment operational status ( e.g ., on or off, up or down, set or released, etc.), drilling parameters (e.g, depth, hook load, torque, etc.), auxiliary parameters (e.g, vibration data of a pump), flow rate, temperature, operational speed, position, and pressure, among other examples.
  • the acquired sensor data may include or be associated with a timestamp (e.g, date and/or time) indicative of when the sensor data was acquired.
  • the sensor data may also or instead be aligned with a depth or other drilling parameter.
  • the sensors 231 may comprise one or more rotation sensors (e.g, the torque sub 128 and/or the rotation sensor 132) operable to output or otherwise facilitate rotational position, rotational speed, and/or rotational acceleration measurements of the top drive 116 (e.g, the drive shaft 125) indicative of rotational position, rotational speed, and/or rotational acceleration of the upper end of the drill string 120 connected to the top drive 116.
  • the sensors 231 may also comprise one or more torque sensors (e.g, the torque sub 128) operable to facilitate torque measurements indicative of torque output by the top drive 116 to the upper end of the drill string 120.
  • the torque sensors may also or instead be or comprise a variable frequency drive (VFD) supplying electrical power to the top drive 116, whereby torque output by the top drive 116 to the drill string 120 may be measured or otherwise determined based on measurements of electrical current transmitted to the top drive 116 by the VFD.
  • the sensors 232 may comprise one or more rotation sensors (e.g ., the sensor 131) operable to output or otherwise facilitate rotational position, rotational speed, and/or rotational acceleration measurements of the drawworks 118 indicative of vertical position, vertical speed, and/or vertical acceleration of the traveling block 113 and the drill string 120 (including the BHA 124) connected to the travelling block 113 via the top drive 116.
  • the sensors 232 may comprise one or more weight sensors (e.g., the weight sensor 119) operable to output weight data (i.e., weight measurements) indicative of weight of the drill string 120 at the surface.
  • the sensors 233 may comprise one or more pressure sensors (e.g, the sensors 147, 153) operable to facilitate pressure measurements indicative of pressure of the drilling fluid being pumped downhole by the mud pumps 144 via the internal fluid passage 121 of the drill string 120.
  • the pressure sensors may be disposed at the outlets of the pumps 144 and/or along the fluid conduits 145, 151.
  • the sensors 236 may comprise the sensors 184 implemented as one or more of axial load sensors, torque sensors, pressure sensors, position sensors disposed downhole within or as part of the BHA 216 (e.g, the BHA 124).
  • the local controllers 221-226, the sensors 231-236, and the actuators 241-246 may be communicatively connected with a central controller 192.
  • the local controllers 221-226 may be in communication with the sensors 231-236 and actuators 241-246 of the corresponding subsystems 211-216 via local communication networks (e.g, field buses) (not shown) and the central controller 192 may be in communication with the subsystems 211-216 via a central communication network 209 (e.g, a data bus, a field bus, a wide-area-network (WAN), a local-area-network (LAN), etc.).
  • a central communication network 209 e.g, a data bus, a field bus, a wide-area-network (WAN), a local-area-network (LAN), etc.
  • the sensor data generated by the sensors 231-236 of the subsystems 211-216 may be made available for use by the central controller 192 and/or the local controllers 221-226.
  • control data i.e., control commands, signals, and/or information
  • output by the central controller 192 and/or the local controllers 221-226 may be automatically communicated to the various actuators 241-246 of the subsystems 211-216, perhaps pursuant to predetermined programming, such as to facilitate well construction operations and/or other operations described herein.
  • the central controller 192 is shown as a single device (i.e., a discrete hardware component), it is to be understood that the central controller 192 may be or comprise a plurality of control devices and/or other electronic devices collectively operable to perform operations (i.e., computational processes or methods) described herein.
  • the sensors 231-236 and actuators 241-246 may be monitored and/or controlled by corresponding local controllers 221-226 and/or the central controller 192.
  • the central controller 192 may be operable to receive sensor data from the sensors 231-236 of the subsystems 211-216 in real-time, and to output real-time control data directly to the actuators 241-246 of the subsystems 211-216 based on the received sensor data.
  • actuators 241-246 of one or more of the subsystems 211-216 may be controlled by a corresponding local controller 221-226, which may control the actuators 241-246 based on sensor data received from the sensors 231-236 of the corresponding subsystem 211-216 and/or based on control data received from the central controller 192.
  • the rig control system 200 may be a tiered control system, wherein control of the subsystems 211-216 of the well construction system 100 may be provided via a first tier of the local controllers 221-226 and a second tier of the central controller 192.
  • the central controller 192 may facilitate control of one or more of the subsystems 211-216 at the level of each individual subsystem 211-216.
  • sensor data may be fed into the local controller 242, which may respond to control the actuators 232.
  • the control may be coordinated through the central controller 192 operable to coordinate control of well construction equipment of two, three, four, or more (each) of the subsystems 211-216.
  • the downhole controller 188, the central controller 192, the local controllers 221-226, and/or other controllers or processing devices (individually or collectively referred to hereinafter as a “control device”) of the rig control system 200 may each or collectively be operable to receive and store machine-readable and executable program code instructions (e.g ., computer program code, algorithms, programmed processes or operations, etc.) on a memory device (e.g., a memory chip) and then execute the program code instructions to run, operate, or perform a process for monitoring and/or controlling the well construction equipment of the well construction system 100.
  • machine-readable and executable program code instructions e.g ., computer program code, algorithms, programmed processes or operations, etc.
  • a memory device e.g., a memory chip
  • Control devices 188, 192, 221-226 within the scope of the present disclosure can include, for example, programmable logic controllers (PLCs), industrial computers (IPCs), personal computers (PCs), soft PLCs, variable frequency drives (VFDs), and/or other controllers or processing devices operable to store and execute program code instructions, receive sensor data, and output control data (i.e., control commands, signals, and/or information) to cause operation of the well construction equipment based on the program code instructions, sensor data, and/or control data.
  • PLCs programmable logic controllers
  • IPCs industrial computers
  • PCs personal computers
  • VFDs variable frequency drives
  • a control workstation 197 may be communicatively connected with the central controller 192 and/or the local controllers 221-226 via the communication network 209, such as to receive sensor data from the sensors 231-236 and transmit control data to the central controller 192 and/or the local controllers 221-226 to control the actuators 241-246. Accordingly, the control workstation 197 may be utilized by rig personnel ( e.g ., a driller) to monitor and control the actuators 241-246 and other portions of the subsystems 211-216 via the central controller 192 and/or local controllers 221-226.
  • rig personnel e.g ., a driller
  • the central controller 192 may be operable to receive and store machine-readable and executable program code instructions on a memory device and then execute such program code instructions to run, operate, or perform a control process 250 (e.g., a coordinated control process or anther computer process).
  • Each local controller 221-226 may execute a corresponding control process (e.g, a local control process or another computer processor) (not shown). Two or more of the local controllers 221-226 may execute their local control processes to collectively coordinate operations between well construction equipment of two or more of the subsystems 211-216.
  • the control process 250 of the central controller 192 may operate as a mechanization manager of the rig control system 190, such as by coordinating operational sequences of the well construction equipment of the well construction system 100.
  • each local controller 221-226 may facilitate a lower (e.g, basic) level of control within the rig control system 200 to operate a corresponding piece of well construction equipment or a plurality of pieces of well construction equipment of a corresponding subsystem 211-216.
  • Such control process may facilitate, for example, starting, stopping, and setting or maintaining an operating speed of a piece of well construction equipment.
  • Each control process being executed by a control device of the rig control system 200 may receive and process (i.e., analyze) sensor data (i.e., sensor measurements) from one or more of the sensors 231-236 according to the program code instructions, and generate control data (i.e., control commands) to operate or otherwise control one or more of the actuators 241-246 of the well construction equipment.
  • the control process 250 of the central controller 192 may output control data directly to the actuators 241-246 to control the well construction operations.
  • the control process 250 may also or instead output control data to the control process of one or more local controllers 221-226, wherein each control process of the local controllers 221-226 may then output control data to the actuators 241-246 of the corresponding subsystem 211-216 to control a portion of the well construction operations performed by that subsystem 211-216.
  • control processes of control devices e.g ., the central controller 192 and/or the local controllers 221-226
  • the program code instructions forming the basis for the control processes described herein may comprise rules (e.g., algorithms) based upon the laws of physics for drilling and other well construction operations.
  • the central controller 192 may also or instead be operable to receive and store machine-readable and executable program code instructions on a memory device and then execute such program code instructions to run, operate, or perform an automatic drilling control process 252 (hereinafter an “autodriller”) to automatically control predetermined drilling operations performed by the drawworks 118.
  • the autodriller 252 may be executed by the central controller 190 and/or the autodriller 252 may be executed by a separate controller (i.e., a processing device) that includes hardware and/or software with functionality for controlling the drawworks 118.
  • the autodriller 252 may also or instead be executed by a local controller 222 for controlling the drawworks 118.
  • the autodriller 252 may receive and process (i.e., analyze) sensor data (i.e., sensor measurements) from one or more of the sensors 231, 232, 233, 236 according to the program code instructions, and generate control data (i.e., control commands) to operate or otherwise control one or more of the actuators 242 (e.g, drawworks 118) of the hoisting system 212 to control at least a portion of the drilling operations (e.g, ROP).
  • the autodriller 252 may output control data directly to the actuators 242 to control the drilling operations.
  • the autodriller 252 may also or instead output control data to one or more local controllers 222, which may then output control data to the actuators 242.
  • the autodriller 252 may automatically control predetermined drilling operations based on various operational measurements (i.e., sensor data), including WOB, drilling torque, and DR (or standpipe pressure).
  • the autodriller 252 may then output ROP control commands (i.e., control data) indicative of intended ROP based on such operational measurements.
  • the ROP control commands may then be received by the drawworks 118 to control downward speed of the travelling block 113 and thus control downward speed of the drill string 120 to achieve an intended (e.g, optimal) ROP.
  • the autodriller 252 may be operable to cause the drawworks 118 to achieve the intended ROP and/or to maintain intended setpoints of WOB, drilling torque, and/or DR.
  • the intended setpoints of WOB, drilling torque, and DR may be selected by rig personnel or automatically by the autodriller 252.
  • FIGS. 3-6 are schematic views of example implementations of control systems 301, 302, 303, 304, respectively, each operable to execute program code instructions to run, operate, or perform the autodriller 252 shown in FIG. 2.
  • Each control system 301, 302, 303, 304 may be implemented by or form at least a portion of one or more of the central controller 192 and/or the local controllers 221, 222, 223, 226 shown in FIGS. 1 and 2. Accordingly, the following description refers to FIGS. 1-6, collectively.
  • FIG. 3 shows an example implementation of the control system 301, which may comprise a WOB controller 310, a drilling torque controller 320, a DR controller 330, and an ROP controller 340.
  • the ROP controller 340 may be operable to receive information (e.g ., control data) from the WOB controller 310, the drilling torque controller 320, and the DR controller 330 and output an ROP output 345 (i.e., a control command).
  • the WOB controller 310 may output a normalized WOB output 315 in response to a WOB input (i.e.,
  • WOB measurements from a WOB sensor 184. While the WOB output 315 is shown transmitted from the WOB controller 310 to the ROP controller 340 as normalized WOB output 315, it is to be understood that normalization of data from the WOB sensor 184 of the WOB controller 310 may be performed either by the WOB controller 310, the ROP controller 340, or an external normalization unit (not shown) located between the WOB controller 310 and the ROP controller 340. Furthermore, although the term “normalized” may refer to any scheme and scale for normalizing output across multiple data sources, selected implementations of the present disclosure are operable to normalize the WOB output 315 to a range between zero (0) and one (1) .
  • the drilling torque controller 320 is operable to communicate with the ROP controller 340.
  • the drilling torque controller 320 may receive a drilling torque input (i.e ., drilling torque measurements) from a downhole torque sensor 184 and convert the drilling torque input to a normalized TOB output 325 to be received by the ROP controller 340.
  • the torque sensor 184 in communication with drilling torque controller 320 may be operable to measure torque (i.e., TOB) applied to the drill bit 126.
  • the drilling torque controller 320 may also or instead be operable to receive rotary torque input from a surface torque sensor 128 operable to measure torque applied to the drill string 120 at the surface by the top drive 116 or rotary table.
  • the drilling torque controller 320 may receive and process the rotary drilling torque applied to the drill string 120 at the surface as an approximation of the TOB. Regardless of which drilling torque input the drilling torque controller 320 receives, the drilling torque controller 320 may be operable to convert the drilling torque input to the normalized TOB output 325 for use by the ROP controller 340.
  • the DR controller 330 may be operable to communicate with ROP controller 340. As such, the DR controller 330 may be operable to receive DR input (i.e., DR measurements) from the pressure sensor 147 and convert that input to a normalized DR output 335 for communication to the ROP controller 340. Depending on the type and configuration of the well construction equipment of the well construction system 100, the DR inputs may be of various types and configurations. For example, the DR controller 330 may receive two separate pressure inputs and calculate the DR input internally.
  • the DR controller 330 may receive the first pressure input from the pressure sensor 147 while the drill bit 126 is off-bottom and being rotated by the mud motor 182 and a second pressure input while the drill bit 126 is on-bottom and being rotated by the mud motor 182 to perform the drilling operations.
  • the DR controller 330 may also or instead receive the DR input from an external device that calculates a non- normalized DR input and transmits it to the DR controller 330.
  • one or more of the controllers 310, 320, 330 may be operable to generate more than one output. Furthermore, the controllers 310, 320, 330 may be toggled on and off by a user ( e.g ., rig personnel) and therefore, at predetermined times, not provide a normalized output 315, 325, 335 to the ROP controller 340.
  • a user e.g ., rig personnel
  • the ROP controller 340 may be further operable to receive an ROP setpoint 342, which may be or comprise an intended or target ROP for the control system 301.
  • the ROP setpoint 342 may be selected through one of many methods known to one of ordinary skill in the art.
  • the ROP setpoint 342 may be an estimated maximum ROP for the formation 106 the drill bit 126 is expected to be drilling through or the ROP setpoint 342 may be a value selected based on experience with similar formations 106 in the same region.
  • the ROP setpoint 342 may be a value that, absent the control system 301, controls the ROP of the drill string 120 into the formation 106. Such control may come in the form of varying the hook load of a hoisting system 212 or varying the amount of thrust or lift applied to the top drive 116.
  • the ROP setpoint 342 may represent a maximum ROP for the control system 100, with the controllers 310, 320, 330 operating to retard the maximum ROP as intended.
  • the ROP setpoint 342 may be entered into the ROP controller 340 by a user ( e.g ., rig personnel) or automatically by another controller.
  • the ROP controller 340 may receive the normalized outputs 315, 325, 335 and ROP setpoint 342 as inputs, and generate the ROP output 345 based on the received normalized outputs 315, 325, 335 and ROP setpoint 342.
  • the ROP controller 340 may determine (i.e., calculate) the ROP output 345 by taking a product of (i.e., multiplying) the ROP setpoint 342 and the normalized outputs 315, 325, 335.
  • the controller outputs 315, 325, 335 may be normalized to be between zero (0) and one (1), such that their product will also be calculated to be between zero (0) and one (1).
  • the product of the normalized outputs 315, 325, 335 and the ROP setpoint 342, and thus the ROP output 345, will also be between zero (0) and the value of the ROP setpoint 342.
  • the inputs to the controllers 310, 320, 330 may be normalized, such that their corresponding normalized outputs 315, 325, 335 may be “scaled” while maximum and/or minimum permissive values for WOB, TOB, and DR are reached.
  • the WOB controller 310 may generate a normalized WOB output 315 of zero (0) when the WOB input is eighty (80) and above, and a normalized WOB output 315 of one (1) when the WOB input is less than thirty (30).
  • the normalized WOB output 315 may be scaled between zero (0) and one (1) for the WOB input ranging between thirty (30) and eighty (80), depending on how critical the WOB input is to the success of drilling operations.
  • the normalized TOB output 325 and the normalized DR output 335 may be similarly scaled to reflect their effect on the ROP output 345.
  • FIG. 4 show an example implementation of the control system 302, which may include controllers 310, 320, 330 operable to receive predetermined inputs 311, 312, 321, 322, 331, 332 and generate corresponding normalized outputs 315, 325, 335 based on such inputs 311, 312, 321, 322, 331, 332.
  • the WOB controller 310 may be operable to receive a WOB setpoint 311, which may be defined by a user (e.g., rig personnel), and a measured WOB input 312, which may be received from the WOB sensor 184 installed along the drill string 120.
  • the user-defined WOB setpoint 311 may be selected by a driller, a project engineer, or a programming engineer.
  • the user-defined WOB setpoint 311 may also or instead be received from a computer simulation, a database of historical drilling records, or a computer having artificial intelligence (AI) capabilities.
  • the drilling torque controller 320 may be operable to receive a drilling torque setpoint 321, which may be defined by a user, and a measured drilling torque input 322, which may be received from the torque sensors 128, 184 installed along the drill string 120 or in association with the top drive 116.
  • the DR controller 330 may be operable to receive a DR setpoint 331, which may be defined by a user, and a measured DR input 332, which may be received from the pressure sensor 147.
  • the normalized WOB output 315, the normalized TOB output 325, and the normalized DR output 335 may be normalized to fall between zero (0) and one (1).
  • Such normalization of the outputs 315, 325, 335 (which are received as inputs by the ROP controller 340) between zero (0) and one (1) facilitates a simplified process in which decimal numbers may be viewed or interpreted as percentages. For example, a normalized value of 0.453 may be interpreted as 45.3%, which can then be scaled and manipulated for use by the control system 302.
  • the normalized values may fall between or within other numerical ranges.
  • the normalized values may be normalized between zero (0) and three (3) or zero (0) and one hundred (100), and so on.
  • FIG. 5 shows an example implementation of the control system 303, which may include controllers 310, 320, 330 operable to execute predetermined internal processes to generate normalized outputs 315, 325, 335.
  • a WOB controller 310 may compare 317 a measured WOB input 312 (i.e., WOB present value or “Pv”) with a WOB setpoint 311 (“Sp”).
  • the difference may be received by a PI control 314 to calculate a new value for the normalized WOB output 315 (“Kl”) to be input to an ROP controller 340, which may cause the ROP controller 340 to change the drilling operations (e.g ., drawworks operations) such that the measured WOB input 312 is equal to or approaches the WOB setpoint 311.
  • a control gain setpoint 313 (“GainSp”) may be input to the PI control 314 to provide a constant used to change (e.g., increase) the new value for the normalized WOB output 315 generated by the PI control 314. It is to be understood that PID control may be used in addition to or instead of the PI control 314.
  • the new value for the normalized WOB output 315 generated by the PI control 314 may be a value representing a percent change (up or down) used by the control system 303.
  • the output 315 is shown as a percentage (i.e., between zero (0) and one (1))
  • the output 315 may instead be represented in other ways.
  • the output 315 may be a numerical value specifically representative of the shift needed to correct the error signal.
  • an absolute value of the output 315 may be taken and then normalized to fall between zero (0) and one (1).
  • Such operations may be executed by the WOB controller 310, by a separate or external normalization unit (not shown), or by the ROP controller 340.
  • a similar process may be executed by the drilling torque controller 320 to generate a new normalized TOB output 325 (“K2”) via a corresponding PI control 324 based on a comparison 327, 337 (i.e., a difference) between a measured drilling torque input 322 (present value or “Pv”) and the drilling torque setpoint 321 (“Sp”).
  • the new normalized TOB output 325 may also be changed by a corresponding control gain setpoint 323 (“GainSp”).
  • a similar process may be executed by the DR controller 330 to generate a new normalized DR output 335 (“K3”) via a corresponding PI control 334 based on a difference between a measured DR input 332 (present value or “Pv”) and the DR setpoint 331 (“Sp”).
  • the new normalized DR output 335 may also be changed by a corresponding control gain setpoint 333 (“GainSp”).
  • the ROP controller 340 may comprise a direction generator 341 operable to calculate a direction indicator 343 (“K4”) for the ROP output 345. Although the calculation for the direction indicator 343 for the ROP output 345 is shown calculated by the ROP controller 340, such calculations may be performed externally, such as by one or more of the controllers 310, 320, 330, and incorporated into the normalized outputs 315, 325, 335.
  • the direction generator 341 may permit the control system 303 to control the rate of release of the drill string 120 by the drawworks 118 and, in certain circumstances, to raise the drill string 120 by the drawworks 118.
  • the direction generator 341 may output a positive indicator 343 or a negative indicator 343, wherein a positive indicator 343 indicates that the drill string 120 is being released (i.e., lowered) and a negative indicator 343 indicates that the drill string 120 is being taken up (i.e., raised). Accordingly, the direction generator 341 may be operable to output a positive indicator 343 during normal drilling operations and output a negative indicator 343 during extraordinary or otherwise abnormal circumstances. For example, the direction generator 341 may be operable to output a negative indicator 343 when a measured input 312, 322, 332 falls outside a predetermined tolerance value or when a normalized output 315, 325, 335 is assigned a negative value by a corresponding controller 310, 320, 330.
  • the normalized outputs 315, 325, 335, the direction indicator 343, and the ROP setpoint 342 may be received by ROP controller 340, such values may be multiplied together to generate the ROP output 345.
  • the order in which the values are multiplied together does not matter and may therefore occur in any order.
  • One or more of the normalized outputs 315, 325, 335 may be omitted and other inputs indicative of other drilling factors may be input to the ROP controller 340 in any order. Because the normalized outputs 315, 325, 335 range between zero (0) and one (1), other normalized outputs to be received by the ROP controller 340 may be added or removed without affecting the scale of the remaining normalized outputs 315, 325, 335.
  • Each controller 310, 320, 330 may comprise a corresponding switch 316, 326, 336 operable to permit the corresponding controllers 310, 320, 330 to be turned on or off with respect to the ROP controller 340.
  • each corresponding controller 310, 320, 330 may output a default value of one (1) as the normalized output 315, 325, 335 to the ROP controller 340. Because multiplying a value of one (1) has no effect on a mathematical product (i.e., solution for multiplication), a normalized output 315, 325, 335 having a value of one (1) has the same effect as turning off a controller 310, 320, 330. Nonetheless, a product of the normalized outputs 315, 325, 335 produces the ROP output 345, which may be known in the industry as a block velocity setpoint.
  • Each control system 301, 302, 303 may generate a normalized WOB output 315, a normalized TOB output 325, and a normalized DR output 330, respectively, which may then be multiplied together by a constant ROP setpoint 342 to generate an ROP output 345 (i.e., a drawworks control command).
  • the ROP setpoint 342 may operate as a multiplicative control gain, which can be input and/or adjusted by rig personnel.
  • an improperly selected (e.g ., too large) ROP setpoint 342 may result in unintended control performance, such as drilling instability and/or large fluctuations of WOB, TOB, and/or DR.
  • the constant ROP setpoint 342 may be replaced with an automatically changing (i.e., variable) ROP setpoint that adopts to, follows, or otherwise changes with the changing drilling parameters, such as changing well conditions and/or changed drilling setpoints 311, 321, 331.
  • FIG. 6 shows an example implementation of the control system 304, which may include controllers 360, 370, 380 operable to execute predetermined internal processes to generate outputs 365, 375, 385, respectively.
  • the controllers 360, 370, 380 may comprise one or more features and/or modes of operation of the controllers 310, 320, 330, described above in association with FIGS. 3-5, including where indicated by the same reference numerals.
  • the WOB controller 360 may comprise a comparator 317 operable to compare a measured WOB input 312 (i.e., WOB present value or “Pv”) with a WOB setpoint 311 (“Sp”). The difference (i.e., an error signal) may be received by a PI control 314 to calculate a new value for the WOB output 365 (“Kl”) to be input to an ROP controller 390, which may cause the ROP controller 390 to change the drilling operations (e.g ., drawworks operations) such that the measured WOB input 312 is equal to or approaches the WOB setpoint 311.
  • a PI control 314 operable to compare a measured WOB input 312 (i.e., WOB present value or “Pv”) with a WOB setpoint 311 (“Sp”).
  • the difference i.e., an error signal
  • Kl new value for the WOB output 365
  • ROP controller 390 may cause the ROP controller 390 to change the drilling operations (e.g ., drawworks
  • One or more control gain setpoints 313 may be generated or received by the WOB controller 360 and input to the PI control 314 to provide one or more constants used to change (e.g., increase) the WOB output 365 generated by the PI control 314. It is to be understood that a PID control may be used in addition to or instead of the PI control 314. As such, additional control inputs or constants may be used.
  • the control gain setpoints 313 may include a proportional (P) control gain setpoint and an integral (I) control gain setpoint.
  • the error signal output by the comparator 317 may have or comprise units of weight (e.g, pounds), the proportional control gain setpoint may have or comprise units of speed per unit of weight (e.g, feet per hour per pound), and the integral control gain setpoint may have or comprise units of speed per unit of weight per unit of time (e.g, feet per hour per pound per hour).
  • the WOB output 365 generated by the PI control 314 may have units of speed (e.g, feet per hour) and represent a shift in speed (i.e., ROP) of the drill string 120 to correct the weight error signal generated by the comparator 317.
  • a similar process may be executed by the drilling torque controller 370 to generate a new TOB output 375 (“K2”) via a corresponding PI control 324 based on a comparison 327 (i.e., a difference) between a measured drilling torque input 322 (present value or “Pv”) and the drilling torque setpoint 321 (“Sp”).
  • the TOB output 375 may also be changed by corresponding one or more (e.g, proportional and integral) control gain setpoints 323 (“GainSp”).
  • the control gain setpoints 323 may include a proportional control gain setpoint and an integral control gain setpoint.
  • the error signal output by the comparator 327 may have or comprise units of torque (e.g, foot pounds), the proportional control gain setpoint may have or comprise units of speed per unit of torque (e.g, feet per hour per foot pound), and the integral control gain setpoint may have or comprise units of speed per unit of torque per unit of time (e.g, feet per hour per foot pound per hour).
  • the TOB output 375 generated by the PI control 324 may have units of speed (e.g, feet per hour) and represent a shift in speed (i.e., ROP) of the drill string 120 to correct the torque error signal generated by the comparator 327.
  • a similar process may be executed by the DR controller 380 to generate a new DR output 385 (“K3”) via a corresponding PI control 334 based on a comparison 337 between a measured DR input 332 (present value or “Pv”) and the DR setpoint 331 (“Sp”).
  • the DR output 385 may also be changed by corresponding one or more (e.g ., proportional and integral) control gain setpoints 333 (“GainSp”).
  • the control gain setpoints 333 may include a proportional control gain setpoint and an integral control gain setpoint.
  • the error signal output by the comparator 337 may have or comprise units of pressure (e.g., pounds per square foot), the proportional control gain setpoint may have or comprise units of speed per unit of pressure (e.g, feet per hour per pound per square foot), and the integral control gain setpoint may have or comprise units of speed per unit of pressure per unit of time (e.g, feet per hour per pound per square foot per hour).
  • the value for the DR output 385 generated by the PI control 334 may have units of speed (e.g, feet per hour) and represent a shift in speed (i.e., ROP) of the drill string 120 to correct the pressure error signal generated by the comparator 337.
  • the ROP controller 390 may comprise an ROP output generator 392 operable to generate the ROP output 345 (i.e., block velocity setpoint) to control the rate of release (i.e., lowering) or take up (i.e., lifting or raising) of the drill string 120 by the drawworks 118.
  • the ROP output generator 392 may be operable to select a minimum value of the outputs 365, 375, 385 and the ROP setpoint 342 and output (i.e., transmit) such minimum value as the ROP output 345.
  • the ROP output 345 may be passed through a units converter 394 to convert the ROP output 345, for example, from units of feet per hour to units of feet per minute.
  • One or more of the controllers 360, 370, 380 may be turned off via a corresponding switch 316, 326, 336, and thus one or more of the outputs 365, 375, 385 may not be transmitted to the ROP controller 390.
  • the ROP controller 390 may select the minimum value from among the available (i.e., received) outputs 365, 375, 385 and the ROP setpoint 342.
  • FIG. 7 is an example user interface 350 (e.g, a display screen, a control panel, etc.) that may be displayed on a video output device, a touchscreen, or other output devices 196 of the workstation 197 or another workstation of the well construction system 100 and/or located remotely from the wellsite 104.
  • the user interface 350 may be used by a user (e.g, rig personnel) to monitor and control execution of the autodriller 252 by the central controller 190 and/or the local controllers 221-226 forming one or more of the control systems 301, 302, 303, 304.
  • the interface 350 may comprise an input panel 352 where the ROP setpoint 342 may be entered manually or via a corresponding slider arrow that may be dragged to an intended value of the ROP setpoint 342.
  • a measured ROP 346 may be shown graphically and/or numerically.
  • the WOB setpoint 311, the TOB setpoint 321, and the DR setpoint 331 may be entered and displayed on the input panel 352. Furthermore, the measured WOB 312, the measured drilling torque 322, and the measured DR 332 may be displayed in a similar fashion. Status of the switches 316, 326, 336 for selectively engaging and disengaging each controller 310, 320, 330, 360, 370, 380 to and from the ROP controller 340, 390 may also be indicated. Status of switch 347 for selectively turning on and off the ROP controller 240 may also be indicated.
  • the user interface 350 may include a response adjuster input panel 354 where the user may speed up or slow down control loops by adjusting the default loop control gains.
  • the user interface 350 may include a trend window 356 for displaying to the user response of the controllers 310, 320, 330, 360, 370, 380 (i.e., operation of the autodriller 252) over a defined period of time (e.g ., a few minutes, an hour, a few hours, etc.).
  • a trend window 356 for displaying to the user response of the controllers 310, 320, 330, 360, 370, 380 (i.e., operation of the autodriller 252) over a defined period of time (e.g ., a few minutes, an hour, a few hours, etc.).
  • FIG. 8 is a schematic view of at least a portion of an example implementation of a control system 400 operable to monitor operational status of selected drilling equipment and control operation of a drawworks 118 to control axial motion of a drill string 120 to thereby control ROP of the drill string 120.
  • the control system 400 may form a portion of or operate in conjunction with the well construction system 100 and/or the rig control system 200 shown in FIGS. 1 and 2, and thus may comprise one or more features of the well construction system 100 and/or the rig control system 200, including where indicated by the same reference numerals.
  • the control system 400 may comprise a plurality of control devices 402 collectively operable to control the axial motion of the drill string 120.
  • the control devices 402 may be implemented by or form at least a portion of the central controller 192 and/or the local controllers 221, 222, 223, 226 shown in FIGS. 1 and 2, respectively.
  • the control devices 402 may be or comprise the controllers 310, 320, 330, 340, 360, 370, 380, 390 shown in FIGS. 3-6. Accordingly, the following description refers to FIGS. 1-6 and 8, collectively.
  • Control of the axial motion of the drill string 120 performed by the control devices 402 may be separated or distributed into a plurality of hierarchical control layers 412, 414, 416 (i.e., levels or packets), with each layer handling a different aspect of control of the axial motion of the drill string 120.
  • the control layers 412, 414, 416 may be collectively operable to perform or facilitate performance of the autodriller 252 shown in FIG. 2 to determine an ROP command 410 for controlling the ROP.
  • the control layers 412, 414, 416 may also or instead be collectively operable to perform or facilitate performance of the controllers 310, 320, 330, 340, 360, 370, 380, 390 shown in FIGS.
  • the control devices 402 may be operable to execute computer program code instructions 422, 424, 426 to run, operate, or perform the control layers 412, 414, 416.
  • the control system 400 may further comprise various sensors operable to output or otherwise facilitate operational measurements 404 (i.e., drilling measurements) indicative of operational status of various well construction equipment 116, 118, 144.
  • the sensors may be communicatively connected with one or more of the control devices 402, such as may permit the control devices 402 to receive and process the operational measurements 404.
  • the control devices 402 may be further operable to receive and process various contextual drilling information 406.
  • the control devices 402 may then output the ROP control command 410 (i.e., a drawworks command) at least partially based on the operational measurements 404 and/or the contextual drilling information 406.
  • the control devices 402 may output (i.e., transmit) the ROP command 410 to a drawworks controller 430 (e.g., a drawworks VFD), which may then power or otherwise cause an electrical motor 432 to rotate a drum 434 and thereby cause the drawworks 118 to lower the drill string 120 axially into and through the formation 106 at an intended speed and thus intended ROP.
  • the output ROP control command 410 may be interpreted by the drawworks controller 430 as a travelling block downward speed control command.
  • the control system 400 may comprise a pressure sensor 147 disposed along a standpipe 145 fluidly connected with mud pumps 144.
  • the pressure sensor 147 may be or comprise a DR sensor operable to output or otherwise facilitate DR measurements.
  • the control system 400 may further comprise a torque sensor 128 connected between the drive shaft 125 and an upper end of the drill string 120.
  • the torque sensor 128 may be operable to output or otherwise facilitate surface torque measurements.
  • the control system 400 may further comprise a position sensor 131 connected in association with the drawworks 118.
  • the position sensor 131 may be or comprise an ROP sensor operable to output or otherwise facilitate ROP measurements.
  • the control system 400 may further comprise a weight sensor 119 connected in association with a drill string hoisting system.
  • the weight sensor 119 may be or comprise a hook load sensor operable to output or otherwise facilitate hook load measurements.
  • the hook load measurements may be used to calculate surface WOB measurements.
  • the position sensor 131 may be or comprise an ROP sensor operable to output or otherwise facilitate ROP measurements.
  • the control system 400 may further comprise an axial load sensor 184 disposed within or forming a portion of a BHA 124 of the drill string 120.
  • the control system 400 may also comprise a torque sensor 184 disposed within or forming a portion of the BHA 124.
  • the torque sensor 184 may be or comprise a TOB sensor operable to output or otherwise facilitate TOB measurements.
  • Communication between the downhole sensors 184 and the control devices 402 may be via mud-pulse telemetry 237 sent by a downhole telemetry device 186 to a surface telemetry device 149 through the drilling fluid flowing within the drill string 120.
  • Communication between the control devices 402, the drawworks controller 430, the surface telemetry device 149, and the sensors 119, 128, 131, 147, may be via wired and/or wireless communication means 436.
  • a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.
  • the control devices 402 may be or comprise computing and/or information processing devices, such as, for example, programmable logic controllers (PLCs), computers (PCs), industrial computers (IPC), or other control devices furnished with control logic.
  • PLCs programmable logic controllers
  • PCs computers
  • IPC industrial computers
  • One or more of the control devices 402 may be in real-time communication with the drawworks controller 430, the surface telemetry device 149, and the sensors 119, 128, 131, 147, such as may permit the control devices 402 to receive the operational measurements 404 and control the drawworks 118 in real-time.
  • the control devices 402 may collectively run, operate, perform, or otherwise implement the control layers 412, 414, 416.
  • the control devices 402 may implement a low control layer 412, a middle control layer 414, and a high control layer 416.
  • Each control layer 412, 414, 416 may control the drilling operations in a different manner and based on different type of information.
  • Each control layer 412, 414, 416 may be implemented by corresponding hardware and/or computer program code instructions operable to receive and process information and output information (e.g ., control parameters) to one or more of the other control layers 412, 414, 416.
  • Each control layer 412, 414, 416 may serve a higher control layer 412, 414, 416 and be served by a lower control layer 412, 414, 416.
  • each control layer 412, 414, 416 is shown as a separate and distinct element, it is to be understood that each control layer 412, 414, 416 may be implemented by ( e.g ., installed on or performed by) a separate and distinct control device (i.e., hardware), or two of the control layers 412, 414, 416 may be implemented by a single control device.
  • the middle control layer 414 and the high control layer 416 may be implemented by the same control device, with each control layer 414, 416 having different tasks and responsibilities.
  • the high control layer 416 may be implemented by a control device located at the wellsite or the high control layer 416 may be implemented by a control device (e.g., a cloud-based server) located at a distant location from the wellsite.
  • the high control layer 416 (a first control layer) may be or comprise a supervisory control layer operable to receive and then communicate contextual drilling information to the middle control layer 414 (a second control layer).
  • the high control layer 416 may be implemented via one or more of the control devices 402 operable to execute the computer program code 426.
  • the contextual drilling information 406 may comprise properties of the subterranean formation 106 through which the wellbore 102 is being drilled and/or is planned to be drilled, including, for example, composition of the formation 106, hardness or strength of the formation 106, density of the formation 106, and/or friction factor of the formation 106.
  • the contextual drilling information 406 may comprise properties of subterranean formations of offset wellbores previously drilled.
  • the contextual drilling information 406 may comprise specifications of the drilling equipment.
  • Specifications of the drilling equipment may comprise specifications (e.g, geometry, material properties, weight, expected performance, etc.) of the drill string 120, including the drill bit 126, the mud motor 182, the BHA 124, and/or the drill pipe 122.
  • the specifications of the drilling equipment may further comprise actual drill bit aggressively (downhole weight vs. downhole torque response) within the present formation 106.
  • Specifications of the drilling equipment may also comprise specifications of the drawworks 118, the mud pumps 144, and/or the top drive 116.
  • the contextual drilling information 406 may comprise nominal (or average) operating setpoints of the drilling equipment, including, for example, nominal flow rate of the drilling fluid pumped by the mud pumps 144, nominal torque setpoint of the mud motor 182, nominal torque setpoint of the top drive 116, and/or nominal rotational speed of the top drive 116.
  • the middle control layer 414 may be or comprise a mid-speed control layer configured to operate at a medium speed (i.e., frequency) ranging, for example, between about one (1) Hz and about 50 Hz.
  • the middle control layer 414 may be operable to receive and analyze (i.e., process) the contextual drilling information from the high control layer 416.
  • the middle control layer 414 may be further operable to receive and analyze the operational measurements 404 indicative of present (i.e., real-time) operational performance (i.e., status) of the drilling equipment or otherwise characterizing the drilling operations.
  • the operational measurements 404 may be or comprise one or more of, for example, WOB measurements, hook load measurements, TOB measurements, surface drilling torque measurements (i.e., torque output by the top drive 116 to the drill string 120), DR measurements, standpipe pressure measurements, ROP measurements, and/or wellbore depth (i.e., drill bit depth) measurements.
  • the middle control layer 414 may also or instead output predetermined ones (e.g., some or all) of the operational measurements 404 to the low control layer 412 (a third control layer).
  • the middle control layer 414 may be further operable to determine drilling control parameters 408 based at least partially on the operational measurements 404 and/or the contextual drilling information 406.
  • the middle control layer 414 may be implemented via one or more of the control devices 402 operable to execute the computer program code 424 to analyze the operational measurements 404 and/or determine the drilling control parameters 408. After the drilling control parameters 408 are determined, the middle control layer 414 may output the drilling control parameters 408 for use by the low control layer 412. The drilling control parameters 408 received from the middle control layer 414 may enable, permit, or otherwise facilitate the low control layer 412 to determine the ROP control command 410.
  • the drilling control parameters 408 may comprise operational setpoints (or limits) indicative of intended operational performance (i.e., status) of selected drilling equipment, which may be used by the low control layer 412 to determine the ROP control command 410.
  • Operational setpoints may comprise, for example, an intended WOB (e.g, the WOB setpoint 311), an intended TOB or surface torque (e.g, the drilling torque setpoint 321), an intended DR (e.g, the DR setpoint 331), and/or an initial or internal ROP command (e.g., the ROP setpoint 342).
  • the drilling control parameters 408 may also or instead comprise control gain setpoints (or limits) indicative of intended control gains for achieving the operational setpoints.
  • the control gain setpoints may be used by the low control layer 412 to change (e.g, increase or amplify) control outputs (or signals) used to determine the (final) ROP control command 410.
  • the control gain setpoints may be or comprise proportional and/or integral control gains.
  • the control gain setpoints may comprise, for example, a control gain for achieving the intended WOB (e.g, the WOB gain 313), a control gain for achieving the intended TOB or surface torque (e.g, the drilling torque gain 323), and a control gain for achieving the intended DR (e.g ., the DR gain 333).
  • the drilling control parameters 408 may also or instead comprise parameters that define how the autodriller algorithm within the computer program code 422 is to transition from one operational setpoint to a different operational setpoint.
  • the drilling control parameters 408 may also or instead comprise signal filter setpoints (or constants) that define the manner in which the electrical signals (i.e., operational measurements 404) generated by the various sensors of the control system 400 are filtered before being used by the low control layer 412.
  • the drilling control parameters 408 may also or instead comprise signal filter setpoints that define the manner in which the operational setpoints are filtered before being used by the low control layer 412.
  • the drilling control parameters 408 may also or instead comprise signal filter setpoints that define the manner in which internal (i.e., intermediate or provisional) control outputs generated by the low control layer 412 are filtered.
  • the signal filter setpoints may be or comprise signal filtering frequency ranges.
  • the low control layer 412 may be or comprise a fast-loop control layer configured to operate at a fast or ultra-fast speed (i.e., frequency) ranging, for example, between about 20 Hz and about 1,000 Hz.
  • the low control layer 412 may be implemented via one or more of the control devices 402 (e.g., PLCs) operable to execute the computer program code 422 comprising an autodriller algorithm to run, operate, or perform an autodriller process (e.g, the autodriller 252) operable to determine the ROP control command 410.
  • the autodriller algorithm may be referred to as an ROP control algorithm.
  • the low control layer 412 may receive the operational measurements 404 and the drilling control parameters 408 from the middle control layer 414.
  • the low control layer 412 may then incorporate (i.e., insert into) the operational measurements 404 and/or the drilling control parameters 408 into the autodriller algorithm to thereby configure (i.e., complete) the autodriller algorithm with the operational measurements 404 and/or the drilling control parameters 408, and then execute the autodriller algorithm to determine the ROP control command 410.
  • the low control layer 412 may perform the operations of one or more of the control systems 301-304 described above and shown in FIGS. 3-6, respectively, to determine the ROP control command 410. For example, the low control layer 412 may compare the operational setpoints to the operational measurements 404 (similarly to the comparisons 317, 327, 337 performed by the corresponding controllers 310, 320, 330, 360, 370, 380) to determine error signals.
  • the error signals may then be changed (e.g, increased or amplified) by the determined control gain setpoints (similarly to manner in which the error signals were amplified by the PI controls 314, 324, 334 based on corresponding gain setpoints 313, 323, 333 performed by the controllers 310, 320, 330, 360, 370, 380) to generate the internal control outputs ( e.g ., the outputs 315, 325, 335, 365, 375, 385), which may then be used to determine the ROP control command 410 (e.g., the ROP output 345).
  • the low control layer 412 may then output the ROP command 410 to the drawworks controller 430 to control axial velocity (i.e., vertical speed of the travelling block 113) of the drill string 120.
  • the drilling control parameters 408 determined by the middle control layer 414 may be or comprise optimal drilling control parameters that cause the low control layer 412 to output an optimal ROP control command 410 to the drawworks controller 430 to thereby cause the drawworks 118 to advance (i.e., lower) the drill string 120 into the formation 106 at an optimal (e.g, maximum) ROP.
  • the computer program code 424 of the middle control layer 414 may thus comprise one or more drilling control parameter selection programs (or algorithms), which when executed, may be operable to select or otherwise determine optimal drilling control parameters 408.
  • the computer program code 424 of the middle control layer 414 may comprise a drilling control parameter selection program, which when executed, may perform (i.e., run) a computer (i.e., virtual) simulation (i.e., a model) of drilling operations based on the contextual drilling information 406.
  • the computer simulation may include a computer simulation of the drill string 120 being rotated by the top drive 116 (or a rotary table) to drill the planned wellbore 102 through the subterranean formation 106.
  • the middle control layer 414 may be further operable to determine the drilling control parameters 408 based on the computer simulation.
  • the computer simulation may include a computer simulation of the drilling operations described herein using the drilling equipment described herein.
  • the computer simulation may output or comprise simulated operational setpoints used by a simulated control system for controlling simulated drilling equipment to drill a simulated wellbore. Such simulated operational setpoints may then be used as (actual) operational setpoints to be used by the autodriller algorithm within the computer program code 422.
  • the computer simulation may output or comprise simulated control gain setpoints used by the simulated control system for controlling the simulated drilling equipment to drill the simulated wellbore. Such simulated control gain setpoints may then be used as (actual) control gain setpoints to be used by the autodriller algorithm within the computer program code 422.
  • the computer simulation may comprise or utilize, for example, a numerical simulation (i.e., a mathematical model) of the drilling operations.
  • the computer simulation may also or instead comprise or utilize, for example, a physics-based analytic model of the drilling operations.
  • the middle control layer 414 may be performed by one or more of the control devices 402.
  • the computer simulation of the planned drilling operations may be performed by one or more of the control devices 402 (e.g ., a processing device 500 shown in FIG. 9) and a different one or more of the control devices 402 may then receive the drilling control parameters 408 (e.g., the operational setpoints and the control gain setpoints) and output the drilling control parameters 408 to the low control layer 412.
  • the drilling control parameters 408 e.g., the operational setpoints and the control gain setpoints
  • the computer program code 424 of the middle control layer 414 may also or instead comprise a drilling control parameter selection program (a drilling planning program), which when executed, may access an internal database (or library) and/or an external database, and select the drilling control parameters 408 (or parameter sets) that optimize the ROP from the internal database and/or the external database based on the contextual drilling information 406 and/or the operational measurements 404.
  • a drilling control parameter selection program a drilling planning program
  • the middle control layer 414 may contain the internal database of the drilling control parameters and/or the middle control layer 414 may be communicatively connected to the external database of the drilling control parameters.
  • the external and/or internal databases may store historical drilling control parameters in association with historical contextual drilling information and/or historical operational measurements.
  • the databases may store historical drilling control parameters for use with different types of formations or for mitigation of different drilling dysfunctions (e.g, stick-slip, axial vibrations, lateral vibrations, etc.).
  • the middle control layer 414 may compare the present contextual drilling information 406 to the historical contextual drilling information and/or compare the present operational measurements 404 to the historical operational measurements.
  • the middle control layer 414 may analyze the present contextual drilling information 406 and/or the present operational measurements 404 to detect formation changes and/or presence of drilling dysfunctions.
  • the middle control layer 414 may then select from the database the historical drilling control parameters that optimize ROP that are associated with the historical contextual drilling information that is similar to the present contextual drilling information and deem such historical drilling control parameters as the (present) determined drilling control parameters 408.
  • the middle control layer 414 may also or instead select from the database the historical drilling control parameters that optimize ROP that are associated with the historical operational measurements that are similar to the present operational measurements and deem such historical drilling control parameters as the (present) determined drilling control parameters 408.
  • the middle control layer 414 may be further operable to determine (i.e., monitor) performance of the autodriller algorithm contained within the computer program code 422 and thereby operate as a feedback controller.
  • the middle control layer 414 may monitor (i.e., receive and analyze) the operational measurements 404 to determine whether the drilling equipment 116, 118, 124, 144 is achieving the operational setpoints determined by the middle control layer 414 and measure operational lag and/or overshoot (e.g ., instability) between the operational setpoints and the measured operational performance (i.e., the operational measurements 404) of the drilling equipment 116, 118, 124, 144.
  • operational lag and/or overshoot e.g ., instability
  • the middle control layer 414 may assess performance of the drilling equipment 116, 118, 124, 144 based on either surface measurements and/or downhole measurements. The middle control layer 414 may then use the determined performance of the autodriller algorithm to determine (or select) the drilling control parameters 408 that improve performance of the autodriller algorithm, and thus performance of the drilling equipment 116, 118, 124, 144. Accordingly, the drilling control parameter selection program within the computer program code 424 of the middle control layer 414 may be or comprise an optimization program operable to determine (optimal) drilling control parameters 408 that optimize the ROP.
  • one or more of the control layers 412, 414, 416 may accept feedback indicative of the performance of the whole control system 400, such as via the operational measurements 404 and/or via information entered manually by a user (e.g., rig personnel, control engineer, etc.).
  • a user may provide feedback indicative of the performance of the control system 400 by describing and/or associating events that took place during the drilling operations to facilitate long term evolution and improvement of the control layers 412, 414, 416.
  • Additional operational measurements 404 e.g, high resolution downhole data
  • the event information may be fed to the control layers 412, 414, 416 after a portion of the drilling operations (i.e., post-run information) and analyzed to improve the drilling control parameter selection program and/or the autodriller algorithm.
  • surface WOB such as determined based on the hook load measurements facilitated by the hook load sensor 119
  • downhole WOB such as facilitated by the axial load sensor 184, may be analyzed after the drilling operations to tune or otherwise optimize the drilling control parameter selection program and/or the autodriller algorithm.
  • control system 400 may comprise or be communicatively connected with a user interface (e.g., the control workstation 197), which may permit one or more of the control layers 412, 414, 416 (i.e., one or more of the computer program codes 422, 424, 426) to be configured.
  • a user interface e.g., the control workstation 197
  • the user interface may be used to configure (i.e., personalize) the drilling control parameter selection program in the computer program code 424 and/or the autodriller algorithm contained in the computer program code 422 for a specific user (e.g, rig personnel, control engineer, etc.) or application (e.g, drilling equipment, subterranean formation, etc.).
  • a specific user e.g, rig personnel, control engineer, etc.
  • application e.g, drilling equipment, subterranean formation, etc.
  • Personalization may be for a specific customer (e.g, a company man), specific wellsite location, specific drilling equipment (e.g, drill string geometry or type), specific subterranean formation, and specific wellbore geometry, among other examples.
  • Personalization options may be configured using descriptive indicators depending on a user’s risk tolerance and drilling preferences.
  • the user interface may interact with the computer program code 424 of the middle control layer 414 in determining the drilling control parameters 408. That is, optimal drilling control parameters 408 may be determined at least partially based on, for example, user input for intended aggressiveness of the drilling operations. As such, an option for personalization may be configured to be “very aggressive,” which may cause the middle control layer 414 to output (i.e., yield) high control gain setpoints, resulting in strong (i.e., high or fast) response to changes in, for example, the subterranean formation 106, the operational setpoints, and determined error signals, while risking response overshoot and/or instability.
  • very aggressive which may cause the middle control layer 414 to output (i.e., yield) high control gain setpoints, resulting in strong (i.e., high or fast) response to changes in, for example, the subterranean formation 106, the operational setpoints, and determined error signals, while risking response overshoot and/or instability.
  • Another option for personalization may be configured to be “medium aggressive,” which may cause the middle control layer 414 to output medium control gain setpoints, resulting in medium response to changes in, for example, the subterranean formation 106, the operational setpoints, and determined error signals, while having a low risk of response overshoot and/or instability.
  • Still another option for personalization may be configured to be “less aggressive,” which may cause the middle control layer 414 to output low control gain setpoints, resulting in slow response to changes in, for example, the subterranean formation 106, the operational setpoints, and determined error signals, but also resulting in stable drilling operations.
  • FIGS. 9 is a schematic view of at least a portion of an example implementation of a processing device 500 (or system) according to one or more aspects of the present disclosure.
  • the processing device 500 may be or form at least a portion of one or more control devices and/or other electronic devices shown in one or more of the FIGS. 1-8. Accordingly, the following description refers to FIGS. 1-9, collectively.
  • the processing device 500 may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, PCs (e.g ., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, IPCs, PLCs, servers, internet appliances, and/or other types of computing devices.
  • One or more instances of the processing device 500 may be or form at least a portion of the rig control system 200 and/or the ROP control system 400.
  • one or more instances of the processing device 500 may be or form at least a portion of the downhole controller 188, the central controller 192, one or more of the local controllers 221-226, the control devices 402, and/or the control workstation 197.
  • One or more instances of the processing device 500 may be or form at least a portion of the control systems 301, 302, 303, 304, 400. Although it is possible that the entirety of the processing device 500 is implemented within one device, it is also contemplated that one or more components or functions of the processing device 500 may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite.
  • the processing device 500 may comprise a processor 512, such as a general-purpose programmable processor.
  • the processor 512 may comprise a local memory 514 and may execute machine-readable and executable program code instructions 532 (i.e., computer program code) present in the local memory 514 and/or another memory device.
  • the processor 512 may execute, among other things, the program code instructions 532 and/or other instructions and/or programs to implement the example methods and/or operations described herein.
  • the program code instructions 532 when executed by the processor 512 of the processing device 500, may cause one or more portions or pieces of well construction equipment within the scope of the present disclosure to perform the example methods and/or operations described herein.
  • the processor 512 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples.
  • Examples of the processor 512 include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, embedded soft/hard processors in one or more FPGAs.
  • the processor 512 may be in communication with a main memory 516, such as may include a volatile memory 518 and a non-volatile memory 520, perhaps via a bus 522 and/or other communication means.
  • the volatile memory 518 may be, comprise, or be implemented by random-access memory (RAM), static RAM (SRAM), dynamic RAM (DRAM), synchronous DRAM (SDRAM), RAMBUS DRAM (RDRAM), and/or other types of RAM devices.
  • the non volatile memory 520 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices.
  • One or more memory controllers may control access to the volatile memory 518 and/or non-volatile memory 520.
  • the processing device 500 may also comprise an interface circuit 524, which is in communication with the processor 512, such as via the bus 522.
  • the interface circuit 524 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third-generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others.
  • the interface circuit 524 may comprise a graphics driver card.
  • the interface circuit 524 may comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g ., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).
  • a network e.g ., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.
  • the processing device 500 may be in communication with various sensors, video cameras, actuators, processing devices, control devices, and other devices of the well construction system via the interface circuit 524.
  • the interface circuit 524 can facilitate communications between the processing device 500 and one or more devices by utilizing one or more communication protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, or the like), a proprietary communication protocol, and/or another communication protocol.
  • One or more input devices 526 may also be connected to the interface circuit 524.
  • the input devices 526 may permit rig personnel to enter the program code instructions 532, which may be or comprise control data, operational parameters, operational setpoints, a well construction drill plan, and/or database of operational sequences.
  • the program code instructions 532 may further comprise modeling or predictive routines, equations, algorithms, processes, applications, and/or other programs operable to perform example methods and/or operations described herein.
  • the input devices 526 may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.
  • One or more output devices 528 may also be connected to the interface circuit 524.
  • the output devices 528 may permit for visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data.
  • the output devices 528 may be, comprise, or be implemented by video output devices (e.g ., an LCD, an LED display, a CRT display, a touchscreen, etc.), printers, and/or speakers, among other examples.
  • the one or more input devices 526 and the one or more output devices 528 connected to the interface circuit 524 may, at least in part, facilitate the HMIs described herein.
  • the processing device 500 may comprise a mass storage device 530 for storing data and program code instructions 532.
  • the mass storage device 530 may be connected to the processor 512, such as via the bus 522.
  • the mass storage device 530 may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples.
  • the processing device 500 may be communicatively connected with an external storage medium 534 via the interface circuit 524.
  • the external storage medium 534 may be or comprise a removable storage medium (e.g., a CD or DVD), such as may be operable to store data and program code instructions 532.
  • the program code instructions 532 may be stored in the mass storage device 530, the main memory 516, the local memory 514, and/or the removable storage medium 534.
  • the processing device 500 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 512.
  • firmware or software the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code instructions 532 (i.e., software or firmware) thereon for execution by the processor 512.
  • the program code instructions 532 may include program instructions or computer program code that, when executed by the processor 512, may perform and/or cause performance of example methods, processes, and/or operations described herein.
  • the present disclosure is further directed to example methods (e.g, operations, processes, actions, etc.) for monitoring and controlling well construction equipment 110, 120 of a well construction system 100.
  • example methods e.g, operations, processes, actions, etc.
  • one or more descriptors and/or other references to such example methods may not be applicable to the entirety of one or more of the methods. That is, such references may instead be applicable to just one or more aspects of one or more of the methods.
  • references to “the example methods” are to be understood as being applicable to the entirety of one or more of the methods and/or one or more aspects of one or more of the methods.
  • the example methods may be performed utilizing or otherwise in conjunction with one or more implementations of one or more instances of one or more components of the apparatus shown in one or more of FIGS. 1-9 and/or otherwise within the scope of the present disclosure.
  • the example methods may be at least partially performed (and/or caused to be performed) by a processing device, such as the processing device 500 executing program code instructions according to one or more aspects of the present disclosure.
  • a processing device such as the processing device 500 executing program code instructions according to one or more aspects of the present disclosure.
  • the present disclosure is also directed to a non-transitory, computer-readable medium comprising computer program code that, when executed by the processing device, may cause such processing device to perform the example methods described herein.
  • the methods may also or instead be at least partially performed (or be caused to be performed) by a human user (e.g ., rig personnel) utilizing one or more implementations of one or more instances of one or more components of the apparatus shown in one or more of FIGS. 1-9 and/or otherwise within the scope of the present disclosure. Accordingly, the following description refers to apparatus shown in one or more of FIGS. 1-9 and example methods that may be performed by such apparatus. However, the example methods may also be performed in conjunction with implementations of apparatus other than those depicted in FIGS. 1-9 that are also within the scope of the present disclosure.
  • An example implementation of a method according to one or more aspects of the present disclosure may comprise commencing operation of a control system 400 for controlling ROP through a subterranean formation 106 by drilling equipment 116, 118, 124, 144 to drill a wellbore 102.
  • the control system 400 may comprise a plurality of sensors 119, 131, 149, 184 operable to facilitate operational measurements 404 indicative of operational performance of the drilling equipment 116, 118, 124, 144, and a plurality of control devices 402, each comprising a processor 512 and a memory 516 storing a computer program code 422, 424, 426.
  • control system 400 may cause the control devices 402 to collectively perform a high control layer 416 to receive contextual drilling information 406 indicative of at least one of properties of the subterranean formation 106, specifications of the drilling equipment 116, 118, 124, 144, and nominal operating setpoints of the drilling equipment 116, 118, 124,
  • a middle control layer 414 to receive the operational measurements 404 and determine drilling control parameters 408 based on the contextual drilling information 406, and a low control layer 412 to determine an ROP control command 410 indicative of an intended ROP based on the drilling control parameters 408 and the operational measurements 404.
  • the operational measurements 404 may comprise at least one of WOB, hook load, TOB, drilling torque output by the top drive 116, pressure differential across the mud motor 182, and present ROP.
  • the drilling control parameters 408 may comprise operational setpoints, wherein the operational setpoints may comprise at least one of an intended WOB, an intended TOB, an intended drilling torque output by the top drive 116, and an intended pressure differential across the mud motor 182.
  • the drilling control parameters 408 may further comprise control gain setpoints for achieving the operational setpoints.
  • the middle control layer 414 may determine the drilling control parameters 408 by generating a computer simulation of the drilling operations based on the contextual drilling information 406, and determining the drilling control parameters 408 based on the computer simulation.
  • the middle control layer 414 may determine the present drilling control parameters 408 by accessing a database storing historical drilling control parameters in association with historical contextual drilling information, comparing the present contextual drilling information 406 to the historical contextual drilling information, and selecting from the database the historical drilling control parameters that are associated with the historical contextual drilling information that is similar to the present contextual drilling information 406.
  • the middle control layer 414 may determine the drilling control parameters 408 also based on the operational measurements 404.
  • the computer program code 422 of at least one of the control devices 402 may comprise an ROP control algorithm.
  • the low control layer 412 may then determine the ROP control command 410 by incorporating the drilling control parameters 408 and the operational measurements 404 into the ROP control algorithm and executing the ROP control algorithm.
  • control system operable to control ROP through a subterranean formation by drilling equipment to drill a wellbore
  • the control system comprises: (A) a plurality of sensors operable to facilitate operational measurements indicative of operational performance of the drilling equipment; and (B) a plurality of control devices each comprising a processor and a memory storing a computer program code, which when executed, causes the control devices to collectively perform: (1) a first control layer operable to receive contextual drilling information; (2) a second control layer operable to: (a) receive the operational measurements; and (b) determine drilling control parameters based on the contextual drilling information; and (3) a third control layer operable to determine an ROP control command indicative of an intended ROP based on the drilling control parameters and the operational measurements, wherein the ROP control command is to be received by a drawworks.
  • the contextual drilling information may be indicative of at least one of properties of the subterranean formation, specifications of the drilling equipment, and nominal operating setpoints of the drilling equipment.
  • the operational measurements may comprise at least one of WOB, hook load, torque on bit, drilling torque output by a top drive, pressure differential across a mud motor, and present ROP.
  • the drilling control parameters may comprise operational setpoints and the operational setpoints may comprise at least one of an intended WOB, an intended torque on bit, an intended drilling torque output by a top drive, and an intended pressure differential across a mud motor.
  • the drilling control parameters may comprise proportional and/or integral control gain setpoints for achieving the operational setpoints.
  • the second control layer may be operable to determine the drilling control parameters by: generating a computer simulation of the drilling operations based on the contextual drilling information; and determining the drilling control parameters based on the computer simulation.
  • the contextual drilling information may be present contextual drilling information
  • the drilling control parameters may be present drilling control parameters
  • the second control layer may be operable to determine the present drilling control parameters by: accessing a database storing historical drilling control parameters in association with historical contextual drilling information; comparing the present contextual drilling information to the historical contextual drilling information; and selecting from the database the historical drilling control parameters that are associated with the historical contextual drilling information that is similar to the present contextual drilling information.
  • the second control layer may be operable to determine the drilling control parameters based also on the operational measurements.
  • the computer program code of at least one of the control devices may comprise an ROP control algorithm and the third control layer may be operable to determine the ROP control command by: incorporating the drilling control parameters and the operational measurements into the ROP control algorithm; and executing the ROP control algorithm.
  • the present disclosure also introduces a method comprising commencing operation of a control system for controlling ROP through a subterranean formation by drilling equipment to drill a wellbore, wherein commencing the operation of the control system causes a plurality of control devices to collectively perform: a first control layer to receive contextual drilling information indicative of at least one of properties of the subterranean formation, specifications of the drilling equipment, and nominal operating setpoints of the drilling equipment; a second control layer to receive operational measurements and determine drilling control parameters based on the contextual drilling information; and a third control layer to determine an ROP control command indicative of an intended ROP based on the drilling control parameters and the operational measurements.
  • the operational measurements may comprise at least one of WOB, hook load, torque on bit, drilling torque output by a top drive, pressure differential across a mud motor, and present ROP.
  • the drilling control parameters may comprise operational setpoints and the operational setpoints may comprise at least one of an intended WOB, an intended torque on bit, an intended drilling torque output by a top drive, and an intended pressure differential across a mud motor.
  • the drilling control parameters may comprise proportional and/or integral control gain setpoints for achieving the operational setpoints.
  • the second control layer may determine the drilling control parameters by: generating a computer simulation of the drilling operations based on the contextual drilling information; and determining the drilling control parameters based on the computer simulation.
  • the contextual drilling information may be present contextual drilling information
  • the drilling control parameters may be present drilling control parameters
  • the second control layer may determine the present drilling control parameters by: accessing a database storing historical drilling control parameters in association with historical contextual drilling information; comparing the present contextual drilling information to the historical contextual drilling information; and selecting from the database the historical drilling control parameters that are associated with the historical contextual drilling information that is similar to the present contextual drilling information.
  • the second control layer may determine the drilling control parameters based also on the operational measurements.
  • the computer program code of at least one of the control devices may comprise an ROP control algorithm and the third control layer may determine the ROP control command by: incorporating the drilling control parameters and the operational measurements into the ROP control algorithm; and executing the ROP control algorithm.
  • the present disclosure also introduces a computer program product comprising a non- transitory, computer-readable medium comprising a computer program code executable by processors of control devices of a control system for controlling ROP through a subterranean formation by drilling equipment to drill a wellbore, wherein the computer program code, when executed by the processors, causes the control devices to collectively perform: a first control layer to receive contextual drilling information indicative of at least one of properties of the subterranean formation, specifications of the drilling equipment, and nominal operating setpoints of the drilling equipment; a second control layer to receive operational measurements and determine drilling control parameters based on the contextual drilling information; and a third control layer to determine an ROP control command indicative of an intended ROP based on the drilling control parameters and the operational measurements.
  • the operational measurements may comprise at least one of WOB, hook load, torque on bit, drilling torque output by a top drive, pressure differential across a mud motor, and present ROP.
  • the drilling control parameters may comprise operational setpoints and the operational setpoints may comprise at least one of an intended WOB, an intended torque on bit, an intended drilling torque output by a top drive, and an intended pressure differential across a mud motor.
  • the drilling control parameters may comprise proportional and/or integral control gain setpoints for achieving the operational setpoints.
  • the second control layer may determine the drilling control parameters by: generating a computer simulation of the drilling operations based on the contextual drilling information; and determining the drilling control parameters based on the computer simulation.
  • the contextual drilling information may be present contextual drilling information
  • the drilling control parameters may be present drilling control parameters
  • the second control layer may determine the present drilling control parameters by: accessing a database storing historical drilling control parameters in association with historical contextual drilling information; comparing the present contextual drilling information to the historical contextual drilling information; and selecting from the database the historical drilling control parameters that are associated with the historical contextual drilling information that is similar to the present contextual drilling information.
  • the second control layer may determine the drilling control parameters based also on the operational measurements.
  • the computer program product may comprise an ROP control algorithm and the third control layer may determine the ROP control command by: incorporating the drilling control parameters and the operational measurements into the ROP control algorithm; and executing the ROP control algorithm.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
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Abstract

Appareil et procédés pour commander la vitesse de pénétration (ROP) à travers une formation souterraine par un équipement de forage pour forer un puits. Un appareil peut être un système de commande comprenant une pluralité de capteurs appropriés pour faciliter des mesures opérationnelles indiquant la performance opérationnelle de l'équipement de forage et une pluralité de dispositifs de commande comprenant chacun un processeur et une mémoire stockant un code de programme informatique. Le code de programme informatique, lorsqu'il est exécuté, amène les dispositifs de commande à réaliser collectivement une première couche de commande appropriée pour recevoir des informations de forage contextuelles, une deuxième couche de commande appropriée pour recevoir les mesures opérationnelles et déterminer des paramètres de commande de forage sur la base des informations de forage contextuelles, et une troisième couche de commande appropriée pour déterminer une instruction de commande de ROP indiquant une ROP souhaitée sur la base des paramètres de commande de forage et des mesures opérationnelles. L'instruction de commande de ROP peut être reçue par un treuil.
PCT/US2020/060701 2019-11-15 2020-11-16 Commande de la vitesse de pénétration par l'intermédiaire d'une pluralité de couches de commande WO2021097414A1 (fr)

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