Blowout Preventer Control
An apparatus and method for blowout preventer (BOP) control. The apparatus may include a first control station communicatively connected with and operable to control BOP equipment for controlling pressure within a wellbore at an oil and gas wellsite, and a second control station communicatively connected with and operable to control drilling rig equipment for drilling the wellbore within a subterranean formation at the oil and gas wellsite. The second control station may be communicatively connected with the first control station and operable to control the BOP equipment via the first control station.
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. Such wells are drilled into the subterranean formations at wellsites utilizing a well construction system having various surface and subterranean wellsite equipment operating in a coordinated manner. The wellsite equipment may be grouped into various subsystems, wherein each subsystem performs a different operation controlled by a corresponding controller and/or a central controller operable to execute processes associated with the corresponding subsystem(s). The subsystems may include a rig control system, a fluid control system, a managed pressure drilling control system, a gas monitoring system, a closed-circuit television system, a choke pressure control system, and a well pressure control system, among other examples.
The wellsite equipment is monitored and controlled from a control center located at the wellsite. A typical control center contains a wellsite control station utilized by a human wellsite operator to monitor and control the various subsystems of the well construction system. However, safety regulations specify that certain subsystems are to be controlled by a designated control station constructed pursuant to corresponding safety standards. For example, safety regulations specify that blowout preventer (BOP) equipment of the well pressure control system is to be controlled by a designated BOP control station constructed pursuant to safety standards for use in designated areas or zones of the wellsite. Safety regulations further specify that the BOP control station is to be enclosed within an intrinsically safe, weatherproof, waterproof, or another cabinet or enclosure, such as may permit the control station to be utilized within safe areas, hazardous areas, or other areas or zones of the wellsite.
Because the well pressure control system comprises a designated BOP control station, the wellsite control station may not be utilized by the wellsite operator (e.g., driller) to monitor and control the BOP equipment of the well pressure control system, requiring the wellsite operator to walk or otherwise move about the control center between the wellsite and BOP control stations to control the BOP equipment and other subsystems of the well construction system, such as the rig control system. Furthermore, because there is no communication between the wellsite and BOP control stations, interactions or coordination between the BOP equipment of the well pressure control system and other subsystems are typically initiated by the wellsite operators. For example, the wellsite operators may monitor the subsystems to identify operational and safety events and manually initiate processes to counteract such events. Accordingly, a typical control center may be manned by multiple wellsite operators who monitor and control the BOP equipment and other wellsite equipment. Utilizing multiple workstations and relying on multiple wellsite operators to perform such operations increases cost and limits speed, efficiency, and safety of well construction operations.
SUMMARY OF THE DISCLOSUREThis summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.
Some embodiments herein relate to an apparatus including a first control station communicatively connected with and operable to control blowout preventer (BOP) equipment for controlling pressure within a wellbore at an oil and gas wellsite; and a second control station communicatively connected with and operable to control drilling rig equipment for drilling the wellbore within a subterranean formation at the oil and gas wellsite, wherein the second control station is communicatively connected with the first control station and operable to control the BOP equipment via the first control station.
Some embodiments herein relate to a method including receiving, by a first control station at an oil and gas wellsite, first information indicative of operational status of drilling rig equipment at an oil and gas wellsite, wherein the first control station is manually and/or automatically operable to control the drilling rig equipment; receiving, by the first control station, second information indicative of operational status of blowout preventer (BOP) equipment at the oil and gas wellsite, wherein the drilling rig equipment does not include the BOP equipment; the second information is received from a second control station at the oil and gas wellsite; and the second control station is operable to control the BOP equipment but not the drilling rig equipment; transmitting first control commands from the first control station to the second control station for transmission to the BOP equipment to control the BOP equipment; and transmitting second control commands from the first control station to the drilling rig equipment to control the drilling rig equipment to drill a wellbore within a subterranean formation at the oil and gas wellsite.
These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.
The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.
It is to be understood that the following disclosure describes many example implementations for different aspects introduced herein. Specific examples of components and arrangements are described below to simplify the present disclosure. These are merely examples, and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various implementations described herein. Moreover, the formation of a first feature over or on a second feature in the description that follows may include implementations in which the first and second features are formed in direct contact, and may also include implementations in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
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 includes 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 wellsite structure 112 disposed over a rig floor 114. The drill string 120 may be suspended within the wellbore 102 from the wellsite structure 112. The wellsite structure 112 and the rig floor 114 are collectively supported over the wellbore 102 by legs and/or other support structures 113.
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, coiled tubing, 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 from the wellsite surface 104 and/or via a downhole mud motor (not shown) connected with the drill bit 126.
The BHA 124 may also include various downhole tools 180, 182, 184. One or more of such downhole tools 180, 182, 184 may be or comprise an acoustic tool, a density tool, a directional drilling tool, an electromagnetic (EM) tool, a formation sampling tool, a formation testing tool, a gravity tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a sampling while drilling (SWD) tool, a seismic tool, a surveying tool, and/or other measuring-while-drilling (MWD) or logging-while-drilling (LWD) tools.
One or more of the downhole tools 180, 182, 184 may be or comprise an MWD or LWD tool comprising a sensor package 186 operable for the acquisition of measurement data pertaining to the BHA 124, the wellbore 102, and/or the formation 106. One or more of the downhole tools 180, 182, 184 and/or another portion of the BHA 124 may also comprise a telemetry device 187 operable for communication with the surface equipment 110, such as via mud-pulse telemetry. One or more of the downhole tools 180, 182, 184 and/or another portion of the BHA 124 may also comprise a downhole processing device 188 operable to receive, process, and/or store information received from the surface equipment 110, the sensor package 186, and/or other portions of the BHA 124. The processing device 188 may also store executable programs and/or instructions, including for implementing one or more aspects of the operations described herein.
The wellsite structure 112 may support a top drive 116 operable to connect (perhaps indirectly) with an uphole end of the conveyance means 122, and to impart rotary motion 117 and vertical motion 135 to the drill string 120 and the drill bit 126. However, a kelly and rotary table (neither shown) may be utilized instead of or in addition to the top drive 116 to impart the rotary motion 117. The top drive 116 and the connected drill string 120 may be suspended from the wellsite structure 112 via hoisting equipment, which may include a traveling block 118, a crown block (not shown), and a drawworks 119 storing a support cable or line 123. The crown block may be connected to or otherwise supported by the wellsite structure 112, and the traveling block 118 may be coupled with the top drive 116, such as via a hook. The drawworks 119 may be mounted on or otherwise supported by the rig floor 114. The crown block and traveling block 118 comprise pulleys or sheaves around which the support line 123 is reeved to operatively connect the crown block, the traveling block 118, and the drawworks 119 (and perhaps an anchor). The drawworks 119 may thus selectively impart tension to the support line 123 to lift and lower the top drive 116, resulting in the vertical motion 135. The drawworks 119 may comprise a drum, a frame, and a prime mover (e.g., an engine or motor) (not shown) operable to drive the drum to rotate and reel in the support line 123, causing the traveling block 118 and the top drive 116 to move upward. The drawworks 119 may be operable to release the support line 123 via a controlled rotation of the drum, causing the traveling block 118 and the top drive 116 to move downward.
The top drive 116 may comprise a grabber, a swivel (neither shown), a tubular handling assembly 127 terminating with an elevator 129, and a drive shaft 125 operatively connected with a prime mover (not shown), such as via a gear box or transmission (not shown). The drill string 120 may be mechanically coupled to the drive shaft 125 with or without a sub saver between the drill string 120 and the drive shaft 125. The prime mover may be selectively operated to rotate the drive shaft 125 and the drill string 120 coupled with the drive shaft 125. Hence, during drilling operations, the top drive 116 in conjunction with operation of the drawworks 119 may advance the drill string 120 into the formation 106 and form the wellbore 102. The tubular handling assembly 127 and the elevator 129 of the top drive 116 may handle tubulars (e.g., drill pipes, drill collars, casing joints, and the like) that are not mechanically coupled to the drive shaft 125. For example, when the drill string 120 is being tripped into or out of the wellbore 102, 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. The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft 125. The top drive 116 may have a guide system (not shown), such as rollers that track up and down a guide rail on the wellsite structure 112. The guide system may aid in keeping the top drive 116 aligned with the wellbore 102, and in preventing the top drive 116 from rotating during drilling by transferring reactive torque to the wellsite structure 112.
The well construction system 100 may further include a well control system for maintaining well pressure control. For example, the drill string 120 may be conveyed within the wellbore 102 through various blowout preventer (BOP) equipment disposed at the wellsite surface 104 on top of the wellbore 102 and perhaps below the rig floor 114. The BOP equipment may be operable to control pressure within the wellbore 102 via a series of pressure barriers (e.g., rams) between the wellbore 102 and the wellsite surface 104. The BOP equipment may include a BOP stack 130 and an annular fluid control device 132 (e.g., an annular preventer and/or a rotating control device (RCD)). The BOP equipment 130, 132 may be mounted on top of a wellhead 134. The well control system may further include a BOP control unit 137 (i.e., a BOP closing unit) operatively connected with the BOP equipment 130, 132 and operable to actuate, drive, or otherwise operate the BOP equipment 130, 132 to control the BOP equipment 130, 132. The BOP control unit 137 may be or comprise a hydraulic fluid power unit fluidly connected with the BOP equipment 130, 132 and selectively operable to hydraulically drive various portions (e.g., rams, valves) of the BOP equipment 130, 132. The well control system may further include a BOP control station (e.g., a BOP control station 370 shown in
The well construction system 100 may further include a drilling fluid circulation system operable to circulate fluids between the surface equipment 110 and the drill bit 126 during drilling and other operations. For example, 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 drilling fluid 140, and a pump 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 146 extending from the pump 144 to the top drive 116 and an internal passage extending through the top drive 116. The fluid conduit 146 may comprise one or more of a pump discharge line, a stand pipe, a rotary hose, and a gooseneck (not shown) connected with a fluid inlet of the top drive 116. The pump 144 and the container 142 may be fluidly connected by a fluid conduit 148, such as a suction line.
A flow rate sensor 150 may be operatively connected along the fluid conduit 146 to measure flow rate of the drilling fluid 140 being pumped downhole. The flow rate sensor 150 may be operable to measure volumetric and/or mass flow rate of the drilling fluid 140. The flow rate sensor 150 may be an electrical flow rate sensor operable to generate an electrical signal and/or information indicative of the measured flow rate. The flow rate sensor 150 may be a Coriolis flowmeter, a turbine flowmeter, or an acoustic flowmeter, among other examples.
A fluid level sensor 152 may be mounted or otherwise disposed in association with the container 142, and may be operable to measure the level of the drilling fluid 140 within the container 142. The fluid level sensor 152 may be an electrical fluid level sensor operable to generate signals or information indicative of the amount (e.g., level, volume) of drilling fluid 140 within the container 142. The fluid level sensor 152 may comprise conductive, capacitive, vibrating, electromechanical, ultrasonic, microwave, nucleonic, and/or other example sensors. A flow check valve 154 may be connected downstream from the pump 144 to prevent the drilling or other fluids from backing up through the pump 144.
A pressure sensor 156 may be connected along the fluid conduit 146, such as to measure the pressure of the drilling fluid 140 being pumped downhole. The pressure sensor 156 may be connected close to the top drive 116, such as may permit the pressure sensor 156 to measure the pressure within the drill string 120 at the top of the internal passage 121 or otherwise proximate the wellsite surface 104. The pressure sensor 156 may be an electrical sensor operable to generate electric signals and/or other information indicative of the measured pressure.
During drilling operations, the drilling fluid may continue to flow downhole through the internal passage 121 of the drill string 120, as indicated in
The drilling fluid exiting the annulus 108 via the ported adapter 136 may be directed into a fluid conduit 160, and may pass through various equipment fluidly connected along the conduit 160 prior to being returned to the container 142 for recirculation. For example, the drilling fluid may pass through a choke manifold 162 connected along the conduit 160. The choke manifold 162 may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through and out of the choke manifold 162. Backpressure may be applied to the annulus 108 by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold 162. The greater the restriction to flow through the choke manifold 162, the greater the backpressure applied to the annulus 108. Thus, downhole pressure (e.g., pressure at the bottom of the wellbore 102 around the BHA 124 or at a selected depth along the wellbore 102) may be regulated by varying the backpressure at an upper (i.e., uphole) end (e.g., within an upper portion) of the annulus 108 proximate the wellsite surface 104. Pressure maintained at the upper end of the annulus 108 may be measured via a pressure sensor 164 connected along the conduit 160 between the ported adapter 136 and the choke manifold 162. A fluid valve 166 may be connected along the conduit 160 to selectively fluidly isolate the annulus 108 from the choke manifold 162 and/or other surface equipment 110 fluidly connected with the conduit 160. The fluid valve 166 may be or comprise one or more fluid shut-off valves, such as ball valves, globe valves, and/or other types of fluid valves, which may be selectively opened and closed to permit and prevent fluid flow therethrough. The fluid valve 166 may be actuated remotely by a corresponding actuator operatively coupled with the fluid valve 166. The actuator may be or comprise an electric actuator, such as a solenoid or motor, or a fluid actuator, such as pneumatic or hydraulic cylinder or rotary actuator. The fluid valve 166 may also or instead be actuated manually, such as by a corresponding lever. A flow rate sensor 168 may be connected along the fluid conduit 160 to monitor the flow rate of the returning drilling fluid or another fluid being discharged from the wellbore 102.
Before being returned to the container 142, the drilling fluid may be cleaned and/or reconditioned by solids and gas control equipment 170, which may include one or more of shakers, separators, centrifuges, and other drilling fluid cleaning devices. The solids control equipment 170 may be operable for separating and removing solid particles 141 (e.g., drill cuttings) from the drilling fluid returning to the surface 104. The solids and gas control equipment 170 may also comprise fluid reconditioning equipment, such as may remove gas and/or finer formation cuttings 143 from the drilling fluid. The fluid reconditioning equipment may include a desilter, a desander, a degasser 172, and/or the like. The degasser 172 may form or be mounted in association with one or more portions of the solids and gas control equipment 170. The degasser 172 may be operable for releasing and/or capturing formation gasses entrained in the drilling fluid discharged from the wellbore 102. Intermediate tanks/containers (not shown) may be utilized to hold the drilling fluid 140 between the various portions of the solids and gas control equipment 170.
The degasser 172 may be fluidly connected with one or more gas sensors 174 (e.g., gas detectors and/or analyzers) via a conduit 176, such as may permit the formation gasses released and/or captured by the degasser 172 to be directed to and analyzed by the gas sensors 174. The gas sensors 174 may be operable for generating signals or information indicative of the presence and/or quantity of formation gasses released and/or captured by the degasser 172. The gas sensors 174 may be or comprise qualitative gas analyzers, which may be utilized for safety purposes, such as to detect presence of hazardous gases entrained within the returning drilling fluid. The gas sensors 174 may also or instead be or comprise quantitative gas analyzers, which may be utilized to detect levels or quantities of certain formation gasses, such as to perform formation evaluation.
The cleaned/reconditioned drilling fluid may be transferred to the fluid container 142, and the solid particles 141 removed from the fluid may be transferred to a solids container 143 (e.g., a reserve pit). The container 142 may include an agitator (not shown) to maintain uniformity of the drilling fluid 140 therein. A hopper (not shown) may be connected with or along the fluid conduit 148 to introduce chemical additives, such as caustic soda, into the drilling fluid 140 being pumped into the wellbore 102.
The surface equipment 110 may include tubular handling equipment operable to store, move, connect, and disconnect tubulars to assemble and disassemble the conveyance means 122 of the drill string 120 during drilling operations. For example, a catwalk 131 may be utilized to convey tubulars from a ground level, such as along the wellsite surface 104, to the rig floor 114, permitting the tubular handling assembly 127 to grab and lift the tubulars above the wellbore 102 for connection with previously deployed tubulars. The catwalk 131 may have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor 114. The catwalk 131 may comprise a skate 133 movable along a groove (not shown) extending longitudinally along the horizontal and inclined portions of the catwalk 131. The skate 133 may be operable to convey (e.g., push) the tubulars along the catwalk 131 to the rig floor 114. The skate 133 may be driven along the groove by a drive system (not shown), such as a pulley system or a hydraulic system, among other examples. Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk 131. The racks may have a spinner unit for transferring tubulars to the groove of the catwalk 131.
An iron roughneck 151 may be positioned on the rig floor 114. The iron roughneck 151 may comprise a torqueing portion 153, such as may include a spinner and a torque wrench comprising a lower tong and an upper tong. The torqueing portion 153 of the iron roughneck 151 may be moveable toward and at least partially around the drill string 120, such as may permit the iron roughneck 151 to make up and break out connections of the drill string 120. The torqueing portion 153 may also be moveable away from the drill string 120, such as may permit the iron roughneck 151 to move clear of the drill string 120 during drilling operations. The spinner of the iron roughneck 151 may be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string 120, and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections.
A reciprocating slip 161 may be located on the rig floor 114, such as may accommodate therethrough the conveyance means 122 during make up and break out operations and during the drilling operations. The reciprocating slip 161 may be in an open position during drilling operations to permit advancement of the drill string 120 therethrough, and in a closed position to clamp an upper end of the conveyance means 122 (e.g., assembled tubulars) to thereby suspend and prevent advancement of the drill string 120 within the wellbore 102, such as during the make up and break out operations.
During drilling operations, the hoisting equipment lowers the drill string 120 while the top drive 116 rotates the drill string 120 to advance the drill string 120 downward within the wellbore 102 and into the formation 106. During the advancement of the drill string 120, the reciprocating slip 161 is in an open position, and the iron roughneck 151 is moved away or is otherwise clear of the drill string 120. When the upper portion of the tubular in the drill string 120 that is made up to the drive shaft 125 is near the reciprocating slip 161 and/or the rig floor 114, the top drive 116 ceases rotating and the reciprocating slip 161 closes to clamp the tubular made up to the drive shaft 125. The grabber of the top drive 116 then clamps the upper portion of the tubular made up to the drive shaft 125, and the drive shaft 125 rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft 125 and the made up tubular. The grabber of the top drive 116 may then release the tubular of the drill string 120.
Multiple tubulars may be loaded on the rack of the catwalk 131 and individual tubulars (or stands of two or three tubulars) may be transferred from the rack to the groove in the catwalk 131, such as by the spinner unit. The tubular positioned in the groove may be conveyed along the groove by the skate 133 until an end of the tubular projects above the rig floor 114. The elevator 129 of the top drive 116 then grasps the protruding end, and the drawworks 119 is operated to lift the top drive 116, the elevator 129, and the new tubular.
The hoisting equipment then raises the top drive 116, the elevator 129, and the tubular until the tubular is aligned with the upper portion of the drill string 120 clamped by the slip 161. The iron roughneck 151 is moved toward the drill string 120, and the lower tong of the torqueing portion 153 clamps onto the upper portion of the drill string 120. The spinning system rotates the new tubular (e.g., a threaded male end) into the upper portion of the drill string 120 (e.g., a threaded female end). The upper tong then clamps onto the new tubular and rotates with high torque to complete making up the connection with the drill string 120. In this manner, the new tubular becomes part of the drill string 120. The iron roughneck 151 then releases and moves clear of the drill string 120.
The grabber of the top drive 116 may then clamp onto the drill string 120. The drive shaft 125 (e.g., a threaded male end) is brought into contact with the drill string 120 (e.g., a threaded female end) and rotated to make up a connection between the drill string 120 and the drive shaft 125. The grabber then releases the drill string 120, and the reciprocating slip 161 is moved to the open position. The drilling operations may then resume.
The tubular handling equipment may further include a tubular handling manipulator (PHM) 163 disposed in association with a fingerboard 165. Although the PHM 163 and the fingerboard 165 are shown supported on the rig floor 114, one or both of the PHM 163 and fingerboard 165 may be located on the wellsite surface 104 or another area of the well construction system 100. The fingerboard 165 provides storage (e.g., temporary storage) of tubulars (or stands of two or three tubulars) 111 during various operations, such as during and between tripping out and tripping in the drill string 120. The PHM 163 may be operable to transfer the tubulars 111 between the fingerboard 165 and the drill string 120 (i.e., space above the suspended drill string 120). For example, the PHM 163 may include arms 167 terminating with clamps 169, such as may be operable to grasp and/or clamp onto one of the tubulars 111. The arms 167 of the PHM 163 may extend and retract, and/or at least a portion of the PHM 163 may be rotatable and/or movable toward and away from the drill string 120, such as may permit the PHM 163 to transfer the tubular 111 between the fingerboard 165 and the drill string 120.
To trip out the drill string 120, the top drive 116 is raised, the reciprocating slip 161 is closed around the drill string 120, and the elevator 129 is closed around the drill string 120. The grabber of the top drive 116 clamps the upper portion of the tubular made up to the drive shaft 125. The drive shaft 125 then rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft 125 and the drill string 120. The grabber of the top drive 116 then releases the tubular of the drill string 120, and the drill string 120 is suspended by (at least in part) the elevator 129. The iron roughneck 151 is moved toward the drill string 120. The lower tong clamps onto a lower tubular below a connection of the drill string 120, and the upper tong clamps onto an upper tubular above that connection. The upper tong then rotates the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars. The spinning system then rotates the upper tubular to separate the upper and lower tubulars, such that the upper tubular is suspended above the rig floor 114 by the elevator 129. The iron roughneck 151 then releases the drill string 120 and moves clear of the drill string 120.
The PHM 163 may then move toward the tool string 120 to grasp the tubular suspended from the elevator 129. The elevator 129 then opens to release the tubular. The PHM 163 then moves away from the tool string 120 while grasping the tubular with the clamps 169, places the tubular in the fingerboard 165, and releases the tubular for storage in the fingerboard 165. This process is repeated until the intended length of drill string 120 is removed from the wellbore 102.
The well construction system 100 may also comprise a plurality of fire and gas sensors 178 located at different locations (e.g., the rig floor 114, the wellsite structure 112) of the well construction system 100. The fire and gas sensors 178 may each be operable to generate signals indicative of fire and/or smoke. The fire and gas sensors 178 may also be or comprise qualitative gas analyzers operable to generate signals indicative of flammable and/or other hazardous gasses being released from the wellbore 102 or otherwise present at the well construction system 100.
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 the top drive 116, the hoisting system, the tubular handling system, the drilling fluid circulation system, the well control system, the BHA 124, and the fire and gas sensors 178, among other examples, may be monitored and controlled. 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, etc.) containing a control workstation 197, which may be operated by a human wellsite operator 195 to monitor and control various wellsite equipment or portions of the well construction system 100. The control workstation 197 may comprise or be communicatively connected with a processing device 192 (e.g., a controller, 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. For example, the processing device 192 may be communicatively connected with the various surface and downhole equipment described herein, and may be operable to receive signals from and transmit signals to such equipment to perform various operations described herein. The processing device 192 may store executable programs, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of the operations described herein. The processing device 192 may be located within and/or outside of the facility 191.
The control workstation 197 may be operable for entering or otherwise communicating commands to the processing device 192 by the wellsite operator 195, and for displaying or otherwise communicating information from the processing device 192 to the wellsite operator 195. The control workstation 197 may comprise a plurality of human-machine interface (HMI) devices, including one or more input devices 194 (e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices 196 (e.g., a video monitor, a printer, audio speakers, etc.). Communication between the control center 190, the processing device 192, the input and output devices 194, 196, and the various wellsite equipment may be via wired and/or wireless communication means. However, for clarity and ease of understanding, 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.
The well construction system 100 also includes stationary and/or mobile video cameras 198 disposed or utilized at various locations within the well construction system 100. The video cameras 198 capture videos of various portions, equipment, or subsystems of the well construction system 100, and perhaps the wellsite operators 195 and the actions they perform, during or otherwise in association with the wellsite operations, including while performing repairs to the well construction system 100 during a breakdown. For example, the video cameras 198 may capture videos of the entire well construction system 100 and/or specific portions of the well construction system 100, such as the top drive 116, the iron roughneck 151, the PHM 163, the fingerboard 165, and/or the catwalk 131, among other examples. The video cameras 198 generate corresponding video signals (i.e., video feeds) comprising or otherwise indicative of the captured videos. The video cameras 198 may be in signal communication with the processing device 192, such as may permit the video signals to be processed and transmitted to the control workstation 197 and, thus, permit the wellsite operators 195 to view various portions or components of the well construction system 100 on one or more of the output devices 196. The processing device 192 or another portion of the control workstation 197 may be operable to record the video signals generated by the video cameras 198.
Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in
The control system 200 may be utilized to monitor and control various portions, components, and equipment of the well construction system 100 described herein, which 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 rig control (RC) system 211, a fluid control (FC) system 212, a managed pressure drilling control (MPDC) system 213, a fire and gas monitoring (FGM) system 214, a closed-circuit television (CCTV) system 215, a choke pressure control (CPC) system 216, and a well pressure control (WC) system 217. The control workstation 197 may be utilized to monitor, configure, control, and/or otherwise operate one or more of the subsystems 211-217.
The RC system 211 may include the wellsite structure 112, the drill string hoisting system or equipment (e.g., the drawworks 119 and the top drive 116), drill string rotation system or equipment (e.g., the top drive 116 and/or the rotary table and kelly), the reciprocating slip 161, the drill pipe handling system or equipment (e.g., the catwalk 131, the PHM 163, the fingerboard 165, and the iron roughneck 151), electrical generators, and other equipment. Accordingly, the RC system 211 may perform power generation and drill pipe handling, hoisting, and rotation operations. The RC system 211 may also serve as a support platform for drilling equipment and staging ground for rig operations, such as connection make up and break out operations described above. The FC system 212 may include the drilling fluid 140, the pumps 144, valves 166, drilling fluid loading equipment, the solids and gas treatment equipment 170, and/or other fluid control equipment. Accordingly, the FC system 212 may perform fluid operations of the well construction system 100. The MPDC system 213 may include the choke manifold 162, the downhole pressure sensors 186, and/or other equipment. The FGM system 214 may comprise the gas sensors 174, the fire and gas sensors 178, and/or other equipment. The CCTV system 215 may include the video cameras 198, one or more other input devices 194 (e.g., a keyboard, a touchscreen, etc.), one or more video output devices 196 (e.g., video monitors), various communication equipment (e.g., modems, network interface cards, etc.), and/or other equipment. The CCTV system 215 may be utilized to capture real-time video of various portions or subsystems 211-217 of the well construction system 100 and display video signals from the video cameras 198 on the video output devices to display in real-time the various portions or subsystems 211-217 of the well construction system 100. The CPC system 216 may comprise the choke manifold 162 and/or other equipment, and the WC system 217 may comprise the BOP equipment 130, 132, the BOP control unit 137, and the BOP control station (e.g., BOP control station 370 shown in
The control system 200 may include a wellsite computing resource environment 205, which may be located at the wellsite 104 as part of the well construction system 100, and a remote computing resource environment 206, which may be located offsite (i.e., not at the wellsite 104). The control system 200 may also include various local controllers (e.g., controllers 241-247 shown in
The control system 200 may be in real-time communication with the various components of the well construction system 100. For example, the local controllers may be in communication with various sensors and actuators of the corresponding subsystems 211-217 via local communication networks (not shown) and the wellsite computing resource environment 205 may be in communication with the subsystems 211-217 via a data bus or network 209. As described below, data or sensor signals generated by the sensors of the subsystems 211-217 may be made available for use by processes (e.g., processes 274, 275 shown in
The remote computing resource environment 206, the wellsite computing resource environment 205, and the subsystems 211-217 of the well construction system 100 may be communicatively connected with each other via a network connection, such as via a wide-area-network (WAN), a local-area-network (LAN), and/or other networks also within the scope of the present disclosure. A “cloud” computing environment is one example of a remote computing resource environment 206. The wellsite computing resource environment 205 may be or form at least a portion of the processing device 192 and, thus, may form a portion of or be communicatively connected with the control workstation 197.
An example implementation of the well construction system 100 may include one or more onsite user devices 202 communicatively connected with the wellsite computing resource environment 205. The onsite user devices 202 may be or comprise stationary user devices intended to be stationed at the well construction system 100 and/or portable user devices. For example, the onsite user devices 202 may include a desktop, a laptop, a smartphone, a personal digital assistant (PDA), a tablet component, a wearable computer, or other suitable devices. The onsite user devices 202 may be operable to communicate with the wellsite computing resource environment 205 of the well construction system 100 and/or the remote computing resource environment 206. The onsite user device 202 may be or comprise at least a portion of the control workstation 197 shown in
The wellsite computing resource environment 205 and/or other portions of the well construction system 100 may further comprise an information technology (IT) system 219 operable to communicatively connect various portions of the wellsite computing resource environment 205 and/or communicatively connect the wellsite computing resource environment 205 with other portions of the well construction system 100. The IT system 219 may include communication conduits, software, computers, and other IT equipment facilitating communication between one or more portions of the wellsite computing resource environment 205 and/or between the wellsite computing resource environment 205 and another portion of the well construction system 100, such as the remote computing resource environment 206, the onsite user device 202, and the subsystems 211-217.
The control system 200 may include (or otherwise be utilized in conjunction with) one or more offsite user devices 203. The offsite user devices 203 may be or comprise a desktop computer, a laptop computer, a smartphone and/or other portable smart device, a PDA, a tablet/touchscreen computer, a wearable computer, and/or other devices. The offsite user devices 203 may be operable to receive and/or transmit information (e.g., for monitoring functionality) from and/or to the well construction system 100, such as by communication with the wellsite computing resource environment 205 via the network 208. The offsite user devices 203 may be utilized for monitoring functions, but may also provide control processes for controlling operation of the various subsystems 211-217 of the well construction system 100. The offsite user devices 203 and/or the wellsite computing resource environment 205 may also be operable to communicate with the remote computing resource environment 206 via the network 208. The network 208 may be a WAN, such as the internet, a cellular network, a satellite network, other WANs, and/or combinations thereof.
The subsystems 211-217 of the well construction system 100 may include sensors 221-227, actuators 231-237, and local controllers 241-247. The controllers 241-247 may be programmable logic controllers (PLCs) and/or other controllers having aspects similar to the example processing device 700 shown in
The sensors 221-227 may include sensors utilized for operation of the various subsystems 211-217 of the well construction system 100. For example, the sensors 221-227 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 sensors 221-227 may be operable to provide sensor data to the wellsite computing resource environment 205, such as to the coordinated control device 204. For example, the sensors 221-227 may provide sensor data 251-257, respectively. The sensor data 251-257 may include signals or information indicative of equipment operation status (e.g., on or off, up or down, set or release, 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 251-257 may include or be associated with a timestamp (e.g., date and/or time) indicative of when the sensor data 251-257 was acquired. The sensor data 251-257 may also or instead be aligned with a depth or other drilling parameter.
Acquiring the sensor data 251-257 at the coordinated control device 204 may facilitate measurement of the same physical properties at different locations of the well construction system 100, wherein the sensor data 251-257 may be utilized for measurement redundancy to permit continued well construction operations. Measurements of the same physical properties at different locations may also be utilized for detecting equipment conditions among different physical locations at the wellsite surface 104 or within the wellbore 102. Variation in measurements at different wellsite locations over time may be utilized to determine equipment performance, system performance, scheduled maintenance due dates, and the like. For example, slip status (e.g., set or unset) may be acquired from the sensors 221 and communicated to the wellsite computing resource environment 205. Acquisition of fluid samples may be measured by a sensor, such as the sensors 186, 223, and related with bit depth and time measured by other sensors. Acquisition of data from the video cameras 198, 225 may facilitate detection of arrival and/or installation of materials or equipment at the well construction system 100. The time of arrival and/or installation of materials or equipment may be utilized to evaluate degradation of material, scheduled maintenance of equipment, and other evaluations.
The coordinated control device 204 may facilitate control of one or more of the subsystems 211-217 at the level of each individual subsystem 211-217. For example, in the FC system 212, sensor data 252 may be fed into the controller 242, which may respond to control the actuators 232. However, for control operations that involve multiple systems, the control may be coordinated through the coordinated control device 204. For example, coordinated control operations may include the control of downhole pressure during tripping. The downhole pressure may be affected by both the FC system 212 (e.g., pump rate), the MPDC 213 (e.g., choke position of the MPDC), and the RC system 211 (e.g., tripping speed). Thus, when it is intended to maintain certain downhole pressure during tripping, the coordinated control device 204 may be utilized to direct the appropriate control commands to two or more (or each) of the participating subsystems.
Control of the subsystems 211-217 of the well construction system 100 may be provided via a three-tier control system that includes a first tier of the local controllers 241-247, a second tier of the coordinated control device 204, and a third tier of the supervisory control system 207. Coordinated control may also be provided by one or more controllers 241-247 of one or more of the subsystems 211-217 without the use of a coordinated control device 204. In such implementations of the control system 200, the wellsite computing resource environment 205 may provide control processes directly to these controllers 241-247 for coordinated control.
The sensor data 251-257 may be received by the coordinated control device 204 and utilized for control of the subsystems 211-217. The sensor data 251-257 may be encrypted to produce encrypted sensor data 271. For example, the wellsite computing resource environment 205 may encrypt sensor data from different types of sensors and systems to produce a set of encrypted sensor data 271. Thus, the encrypted sensor data 271 may not be viewable by unauthorized user devices (either offsite user devices 203 or onsite user devices 202) if such devices gain access to one or more networks of the well construction system 100. The encrypted sensor data 271 may include a timestamp and an aligned drilling parameter (e.g., depth), as described above. The encrypted sensor data 271 may be communicated to the remote computing resource environment 206 via the network 208 and stored as encrypted sensor data 272.
The wellsite computing resource environment 205 may provide the encrypted sensor data 271, 272 available for viewing and processing offsite, such as via the offsite user devices 203. Access to the encrypted sensor data 271, 272 may be restricted via access control implemented in the wellsite computing resource environment 205. The encrypted sensor data 271, 272 may be provided in real-time to offsite user devices 203 such that offsite personnel may view real-time status of the well construction system 100 and provide feedback based on the real-time sensor data. For example, different portions of the encrypted sensor data 271, 272 may be sent to the offsite user devices 203. The encrypted sensor data 271, 272 may be decrypted by the wellsite computing resource environment 205 before transmission, and/or decrypted on the offsite user device 203 after encrypted sensor data is received. The offsite user device 203 may include a thin client (not shown) configured to display data received from the wellsite computing resource environment 205 and/or the remote computing resource environment 206. For example, multiple types of thin clients (e.g., devices with display capability and minimal processing capability) may be utilized for certain functions or for viewing various sensor data 251-257.
The wellsite computing resource environment 205 may include various computing resources utilized for monitoring and controlling operations, such as one or more computers having a processor and a memory. For example, the coordinated control device 204 may include a processing device (e.g., processing device 700 shown in
The coordinated control device 204 may intermediate between the supervisory control system 207 and the local controllers 241-247 of the subsystems 211-217, such as may permit the supervisory control system 207 to control the subsystems 211-217. The supervisory control system 207 may include, for example, devices for entering control commands to perform operations of the subsystems 211-217. The coordinated control device 204 may receive commands from the supervisory control system 207, process such commands according to a rule (e.g., an algorithm based upon the laws of physics for drilling operations), and provide control data to one or more subsystems 211-217. The supervisory control system 207 may be provided by the wellsite operator 195 and/or process monitoring and control program. In such implementations, the coordinated control device 204 may coordinate control between discrete supervisory control systems and the subsystems 211-217 while utilizing control data 261-267 that may be generated based on the sensor data 251-257 received from the subsystems 211-217 and analyzed via the wellsite computing resource environment 205. The coordinated control device 204 may receive the control data 251-257 and then dispatch control data 261, including interlock commands, to each subsystem 211-217. The coordinated control device 204 may also or instead just listen to the control data 251-257 being dispatched to each subsystem 221-227 and then initiate the machine interlock commands to the relevant local controller 241-247.
The coordinated control device 204 may run with different levels of autonomy. For example, the coordinated control device 204 may operate in an advice mode to inform the wellsite operators 195 to perform a specific task or take specific corrective action based on sensor data 251-257 received from the various subsystems 211-217. While in the advice mode, the coordinated control device 204 may, for example, advise or instruct the wellsite operator 195 to perform a standard work sequence when gas is detected on the rig floor 114, such as to close the annular BOP 132. Furthermore, if the wellbore 102 is gaining or losing drilling fluid 140, the coordinated control device 204 may, for example, advise or instruct the wellsite operator 195 to modify the density of the drilling fluid 140, modify the pumping rate of the drilling fluid 140, and/or modify the pressure of the drilling fluid within the wellbore 102.
The coordinated control device 204 may also operate in a system/equipment interlock mode, whereby certain operations or operational sequences are prevented based on the received sensor data 251-257. While operating in the interlock mode, the coordinated control device 204 may manage interlock operations among the various equipment of the subsystems 211-217. For example, if a pipe ram of the BOP stack 130 is activated, the coordinated control device 204 may issue an interlock command to the RC system controller 241 to stop the drawworks 119 from moving the drill string 120. However, if a shear ram of the BOP stack 130 is activated, the coordinated control device 204 may issue an interlock command to the controller 241 to operate the drawworks 119 to adjust the position of the drill string 120 within the BOP stack 130 before activating the shear ram, so that the shear ram does not align with a shoulder of the tubulars forming the drill string 120.
The coordinated control device 204 may also operate in an automated sequence mode, whereby certain operations or operational sequences are automatically performed based on the received sensor data 251-257. For example, the coordinated control device 204 may activate an alarm and/or stop or reduce operating speed of the pipe handling equipment when a wellsite operator 195 is detected close to a moving iron roughneck 151, the PHM 163, or the catwalk 131. As another example, if the wellbore pressure increases rapidly, the coordinated control device 204 may close the annular BOP 132, close one or more rams of the BOP stack 130, and/or adjust the choke manifold 162.
The wellsite computing resource environment 205 may comprise or execute a monitoring process 274 (e.g., an event detection process) that may utilize the sensor data 251-257 to determine information about status of the well construction system 100 and automatically initiate an operational action, a process, and/or a sequence of one or more of the subsystems 211-217. The monitoring process 274 may initiate the operational action to be caused by the coordinated control device 204. Depending on the type and range of the sensor data 251-257 received, the operational actions may be executed in the advice mode, the interlock mode, or the automated sequence mode.
For example, the monitoring process 274 may determine a drilling state, equipment health, system health, a maintenance schedule, or combination thereof, and initiate an advice to be generated. The monitoring process 274 may also detect abnormal drilling events, such as a wellbore fluid loss and gain, a wellbore washout, a fluid quality issue, or an equipment event based on job design and execution parameters (e.g., wellbore, drilling fluid, and drill string parameters), current drilling state, and real-time sensor information from the surface equipment 110 (e.g., presence of hazardous gas at the rig floor, presence of wellsite operators in close proximity to moving pipe handling equipment, etc.) and the BHA 124, initiating an operational action in the automated mode. The monitoring process 274 may be connected to the real-time communication network 209. The coordinated control device 204 may initiate a counteractive measure (e.g., a predetermined action, process, or operation) based on the events detected by the monitoring process 274.
The term “event” as used herein may include, but not be limited to, an operational and safety related event described herein and/or another operational and safety related event that can take place at a well construction system. The events described herein may be detected by the monitoring process 274 based on the sensor data 251-257 (e.g., sensor signals or information) received and analyzed by the monitoring process 274.
The wellsite computing resource environment 205 may also comprise or execute a control process 275 that may utilize the sensor data 251-257 to optimize drilling operations, such as the control of drilling equipment to improve drilling efficiency, equipment reliability, and the like. For example, the acquired sensor data 252 may be utilized to derive a noise cancellation scheme to improve electromagnetic and mud pulse telemetry signal processing. The remote computing resource environment 206 may comprise or execute a control process 276 substantially similar to the control process 275 that may be provided to the wellsite computing resource environment 205. The monitoring and control processes 274, 275, 276 may be implemented via, for example, a control algorithm, a computer program, firmware, or other hardware and/or software.
The wellsite computing resource environment 205 may include various computing resources, such as a single computer or multiple computers. The wellsite computing resource environment 205 may further include a virtual computer system and a virtual database or other virtual structure for collected data, such as may include one or more resource interfaces (e.g., web interfaces) that facilitate the submission of application programming interface (API) calls to the various resources through a request. In addition, each of the resources may include one or more resource interfaces that facilitate the resources to access each other (e.g., to facilitate a virtual computer system of the computing resource environment to store data in or retrieve data from the database or other structure for collected data). The virtual computer system may include a collection of computing resources configured to instantiate virtual machine instances. A wellsite operator 195 may interface with the virtual computer system via the offsite user device 203 or the onsite user device 202. Other computer systems or computer system services may be utilized in the wellsite computing resource environment 205, such as a computer system or computer system service that provides computing resources on dedicated or shared computers/servers and/or other physical devices. The wellsite computing resource environment 205 may include a single server (in a discrete hardware component or as a virtual server) or multiple servers (e.g., web servers, application servers, or other servers). The servers may be, for example, computers arranged in physical and/or virtual configuration.
The wellsite computing resource environment 205 may also include a database that may be or comprise a collection of computing resources that run one or more data collections. Such data collections may be operated and managed by utilizing API calls. The data collections, such as the sensor data 251-257, may be made available to other resources in the wellsite computing resource environment 205, or to user devices (e.g., onsite user device 202 and/or offsite user device 203) accessing the wellsite computing resource environment 205. The remote computing resource environment 206 may include computing resources similar to those described above, such as a single computer or multiple computers (in discrete hardware components or virtual computer systems).
The control center 300 comprises a facility 305 (e.g., a room, a cabin, a trailer, etc.) containing various control devices for monitoring and controlling the subsystems 211-217 and other portions of the well construction system 100. The facility 305 may comprise a front side 301, which may be directed toward or located closest to the drill string 120 being constructed by the well construction system 100 and a rear side 303, which may be directed away from the drill string 120. The facility 305 may comprise a floor 302, a front wall 304, a left wall 306, a right wall 308, a rear wall 310, and a roof 312. The facility 305 may also have a side door 314, a rear door 316, and a plurality of windows 321-328 in one or more of the walls 304, 306, 308, 310 and/or the roof 312. Each of the windows 321-328 may be surrounded by structural framing 330 connected with the walls and supporting window safety guards 332 (e.g., bars, grills) in front of or along the windows 321-328.
The facility 305 may have an observation area 340 at the front side 301 of the facility 305 from which a wellsite operator 195 will have an optimal or otherwise improved view of the drill string 120, the rig floor 114, and/or other portions of the well construction system 100. The observation area 340 may be surrounded or defined by windows 323-328 on several sides to increase wellsite operator's 195 horizontal and vertical angle of view of the well constriction system 100. A portion 342 of the observation area 340 (e.g., windows 323-327) may protrude or extend out past other portions of the facility 305 (e.g., front wall 304) to facilitate the optimal view of the well construction system 100 by the wellsite operators 195. The observation area 340 may be located on a side of the facility 305. The observation area 318 may be surrounded by or at least partially defined by a front window 324 permitting the wellsite operator 195 to look forward, two side windows 323, 325 permitting the wellsite operator 195 to look sideways (i.e., left and right), a lower window 326 permitting the wellsite operator 195 to look downwards, and one or more upper windows 327, 328 permitting the wellsite operator 195 to look upwards. The lower window 326 and/or at least one upper window 327 may extend diagonally with respect to the front window 324.
The control center 300 may comprise one or more wellsite operator control workstations within the facility 305. The workstations may be utilized by the wellsite operators 195 to monitor and control the subsystems 211-217 and other portions of the well construction system 100. For example, the observation area 340 may contain a first control workstation 350 located adjacent the windows 323, 324, 325, 326, 328 and at least partially within the extended portion 342 of the observation area 340, such as may permit the wellsite operator 195 utilizing the control workstation 350 to have an unobstructed or otherwise optimal view of the drill string 120, the rig floor 114, and/or other portions of the well construction system 100. The observation area 340 may also contain a second control workstation 352 located adjacent (e.g., behind) the first control workstation 350 and adjacent the window 325, but not within the extended portion 342 of the observation area 340. The control workstation 352 may be elevated at least partially above the control workstation 350 to reduce the obstruction of view caused by the control workstation 350 and, thus, permit the wellsite operator 195 utilizing the control workstation 352 to view the drill string 120, the rig floor 114, and/or other portions of the well construction system 100 over the control workstation 350 via the front window 324. The control center 300 may also comprise a third control workstation 354 located adjacent the control workstations 350, 352 and adjacent the windows 321, 322, but not within the observation area 340.
The control center 300 may further comprise a processing device 356 (e.g., a controller, a computer, a server, etc.) operable to provide control to one or more portions of the well construction system 100 and/or operable to monitor operations of one or more portions of the well construction system 100. For example, the processing device 356 may be communicatively connected with the various surface and downhole equipment described herein and operable to receive signals from and transmit signals to such equipment to perform various operations described herein. The processing device 356 may store executable programs, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of the operations described herein. The processing device 356 may be communicatively connected with the control workstations 350, 352, 354. Although the processing device 356 is shown located within the facility 305, the processing device 356 may be located outside of the facility 305. Furthermore, although the processing device 356 is shown as a single device that is separate and distinct from the control workstations 350, 352, 354, one or more of the control workstation 350, 352, 354 may comprise a corresponding processing device 356 disposed in association with or forming at least a portion of such corresponding processing device 356.
The control workstations 350, 352, 354 may be operable to enter or otherwise communicate commands to the processing device 356 by the wellsite operator 195 and to display or otherwise communicate information from the processing device 356 to the wellsite operator 195. One or more of the control workstations 350, 352, 354 may comprise an operator chair 360 and an HMI system comprising one or more input devices 362 (e.g., a keyboard, a mouse, a joystick, a touchscreen, a microphone, etc.) and one or more output devices 364 (e.g., a video monitor, a printer, audio speakers, a touchscreen, etc.). The input and output devices 362, 364 may be disposed in association with and/or integrated with the operator chair 360 to permit the wellsite operator 195 to enter commands or other information to the processing device 356 and receive information from the processing device 356 and other portions of the well construction system 100. One or more of the control workstations 350, 352, 354 may be or form at least a portion of the control workstation 197 shown in
The control center 300 may further contain a BOP control station 370 (e.g., control panel) of the WC system 217 operable to monitor and control one or more portions of the WC system 217. For example, the BOP control station 370 may be communicatively connected with the BOP control unit 137 and the BOP equipment 130, 132, and operable to monitor and control operations of the BOP control unit 137 and the BOP equipment 130, 132.
The BOP control station 370 may be operable communicate to the BOP control unit 137 control commands entered by the wellsite operator 195 for controlling the BOP equipment 130, 132 and to display or otherwise communicate information indicative of operational status of the BOP equipment 130, 132 and the BOP control unit 137 to the wellsite operator 195. The BOP control station 370 may comprise a processing device (e.g., processing device 700 shown in
The BOP control station 370 and the BOP control unit 137 may be operatively connected via electrical, pneumatic, and/or hydraulic means. For example, control commands entered by the wellsite operator 195 via the input devices 372 may be transmitted from the BOP control station 370 in the form of electrical, pneumatic, and/or hydraulic control signals to operate various portions (e.g., valves) of the BOP control unit 137 to control the BOP equipment 130, 132. Feedback information indicative of operational status of the BOP control unit 137 and the BOP equipment 130, 132 may be transmitted in the form of electrical, pneumatic, and/or hydraulic feedback signals from various sensors of the BOP control unit 137 and the BOP equipment 130, 132. The feedback information may be displayed to the wellsite operator 195 via the output devices 374 of the BOP control station 370. The BOP control station 370 may comprise an intrinsically safe construction, an explosion proof construction (e.g., Class 1 rating), a weatherproof construction, a dust and/or water proof construction (e.g., IP66 rating, IP55 rating), and/or may be certified for use in Zone 1, Zone 2, hazardous, and/or safe areas of the wellsite. Although the BOP control station 370 is shown located within the facility 305, the BOP control station 370 may be located outside of the facility 305, such as on the rig floor 114 or the wellsite surface 104.
The BOP control unit 370 may be communicatively connected with one or more of the control workstations 350, 352, 354, such as may permit monitoring and control of one or more portions of the WC system 217 via the control workstations 350, 352, 354. For example, one or more of the control workstations 350, 352, 354 or the processing device 356 may be communicatively connected directly with the processing device of the BOP control station 370 or indirectly, such as via the input and output devices 372, 374 of the BOP control station 370. Such connection may permit the control workstations 350, 352, 354 to receive information indicative of operational status of the BOP control unit 137 and the BOP equipment 130, 132 via the BOP control station 370. Such connection may further permit the control workstations 350, 352, 354 to transmit control commands to the BOP control unit 137 and the BOP equipment 130, 132 via the BOP control station 370. Such connection may also or instead facilitate control of the BOP control station 370 via the control workstations 350, 352, 354, such as may cause the BOP control station 370 to control the BOP control unit 137 and the BOP equipment 130, 132 as directed by or from the control workstations 350, 352, 354.
The control workstations 350, 352, 354 may be operable to display the information indicative of operational status of the BOP control unit 137 and the BOP equipment 130, 132 to the wellsite operator 195 via the output devices 364 to permit the wellsite operator to monitor the operational status of the BOP control unit 137 and the BOP equipment 130, 132 while sitting in the corresponding operator chair 360. The control workstations 350, 352, 354 may be further operable to receive the control commands from the wellsite operator 195 via the input devices 362 while sitting in the corresponding operator chair 360 for transmission to the BOP control station 370 to control the BOP control unit 137 and the BOP equipment 130, 132.
The control workstation 400 comprises an operator chair 402 (e.g., driller's chair) and an HMI system comprising a plurality of input and output devices integrated with, supported by, or otherwise disposed in association with the operator chair 402. The input devices permit the wellsite operator 195 to enter commands or other information to the processing device 192, such as to control the actuators of a selected one of the wellsite equipment of the well construction system 100, and the output devices permit the wellsite operator to receive information from the processing device 192 and other wellsite equipment. The operator chair 402 may include a seat 404, a left armrest 406, and a right armrest 408.
The input devices of the control workstation 400 may include a plurality of physical controls, such as a left joystick 410, a right joystick 412, and/or other physical controls 414, 415, 416, 418, 420, such as buttons, switches, knobs, dials, slider bars, a mouse, a keyboard, and a microphone. One or more of the joysticks 410, 412 and/or the physical controls 414, 415, 416 may be integrated into or otherwise supported by the corresponding armrests 406, 408 of the operator chair 402 to permit the wellsite operator 195 to operate these input devices from the operator chair 404. Furthermore, one or more of the physical controls 418, 420 may be integrated into the corresponding joysticks 410, 412 to permit the wellsite operator 195 to operate these physical controls 418, 420 while operating the joysticks 410, 412. The physical controls may comprise emergency stop (E-stop) buttons 415, which may be electrically connected to E-stop relays of one or more pieces of wellsite equipment (e.g., the iron roughneck 151, the PHM 163, the drawworks 119, the top drive 116, etc.), such that the wellsite operator 195 can shut down the wellsite equipment during emergencies and other situations.
The output devices of the control workstation 400 may include one or more video output devices 426 (e.g., video monitors), printers, speakers, and other output devices disposed in association with the operator chair 404 and operable to display to the wellsite operator 195 information from the processing device 192 and other portions of the well construction system 100. The video output devices may be implemented as one or more LCD displays, LED displays, plasma displays, cathode ray tube (CRT) displays, and/or other types of displays.
The video output devices 426 may be disposed in front of or otherwise adjacent the operator chair 402. The video output devices 426 may include a plurality of video output devices 432, 434, 436, each dedicated to displaying predetermined information in a predetermined (e.g., programmed) manner. Although the video output devices 426 are shown comprising three video output devices 432, 434, 436, the video output devices 426 may be or comprise one, two, four, or more video output devices. As described below, different portions of the video output devices 432, 434, 436 may be dedicated to displaying predetermined information in a predetermined manner.
One or more of the video output devices 426 may be operated as both input and output devices. For example, the video output devices 434, 436 may display information related to the control and monitoring of the various subsystems 211-217 of the well construction system 100. The video output devices 434, 436 may further display sensor signals or information 440 generated by the various sensors 221-227 of the well construction system 100 to permit the wellsite operator 195 to monitor operational status of the subsystems 211-217. The video output devices 434, 436 may also display a plurality of software (e.g., virtual, computer generated) buttons, icons, selection menus, switches, knobs, slide bars, dials, or other software controls 442 displayed on the video output devices 434, 436 to permit the wellsite operator 195 to control the various actuators 231-237 or other portions of the subsystems 211-217. The software controls 442 may be operated by the physical controls 414, 416, the joysticks 410, 412, or other input devices of the control workstation 400.
One or more of the video output devices 426 may be configured to display the video signals (i.e., video feeds) generated by one or more of the video cameras 198. For example, the video output device 432 may operate purely as an output device dedicated for displaying the video signals generated by one or more of the video cameras 198. When displaying the video signals from multiple video cameras 198, the display screen of the video output device 432 may be divided into or comprise multiple video windows, each displaying a corresponding video signal. One or more of the other video output devices 434, 436 may display an integrated display screen displaying the sensor information 440, the software controls 442, and the video signals from one or more of the video cameras 198. For example, one or both of the display screens of the video output devices 434, 436 may include one or more picture-in-picture (PIP) video windows 444, each displaying a video signal from a corresponding one of the video cameras 198. The PIP video windows 444 may be embedded or inset on the corresponding display screens along or adjacent the sensor information 440 and the software controls 442. Sourcing (i.e., selection) of the video cameras 198 whose video signals are to be displayed on the display screens may be automated based on operational events (e.g., drilling events, drilling operation processes, etc.) at the well construction system 100, such that video signals relevant to an event currently taking place are displayed.
The control workstation 400 may further comprise combination devices operable as both input and output devices to display information to the wellsite operator 195 and receive commands or information from the wellsite operator 195. Such devices may be or comprise touchscreens 422, 424 (i.e., touchpads) operable to display a plurality of software buttons, switches, knobs, dials, icons, and/or other software controls 428, 430 permitting the wellsite operator 195 to operate (e.g., click, selected, move) the software controls 428, 430 via finger contact with the touchscreens 422, 424. The software controls 428, 430 and/or other features displayed on the touchscreens 422, 424 may also display operational settings, set-points, and/or status of selected subsystems 211-217 for viewing by the wellsite operator 195. For example, the software controls 428, 430 may change color, move in position or direction, and/or display the set-points or operational values (e.g., temperature, pressure, position). The touchscreens 422, 424 may be disposed on or integrated into the armrests 406, 408 or other parts of the operator chair 404 to permit the wellsite operator 195 to operate the software controls 428, 430 displayed on the touchscreens 422, 424 from the operator chair 404.
Selected sensor data may be shown to the wellsite operator 195 via multiple display screens (i.e., an integrated display system) displayed on the video output devices 426 and/or the touchscreens 422, 424. Each display screen may display information related to one or more of the subsystems 211-217. Each display screen may integrate the software controls 428, 430, 442, selected sensor data 251-257, 440 from the corresponding subsystems 211-217, and information from the monitoring process 274, the control process 275, and/or the control data 261-267, 273 generated by the processing devices/controllers 192, 205, 241-247 for the wellsite operator 195. Accordingly, each display screen may be utilized to control operation of the subsystems 211-217 associated with the display screen. The display screens may be shown or displayed alternately on one or more of the video output devices 426 and/or the touchscreens 422, 424 or simultaneously on one or more of these devices. The display screens intended to be displayed on the video output devices 426 and/or the touchscreens 422, 424 may be selected by the wellsite operator 195 via the physical 414, 416, 418, 420 and/or software controls 428, 430, 442. The display screen intended to be displayed on the video output devices 426 and/or the touchscreens 422, 424 may also or instead be selected automatically by the monitoring process 274 based on operational events detected or planned at the well construction system 100 (e.g., a drilling process or event), such that information relevant to an event currently taking place is displayed.
The control workstation 400 may also be utilized by the wellsite operator 195 to control the subsystems 211-217 or other wellsite equipment of the well construction system 100. For example, the control workstation 400 may display on one or more of the video output devices 426 and/or the touchscreens 422, 424 one or more configuration display screens or menus (i.e., computer programs), which may be utilized to set, adjust, configure or otherwise control the subsystems 211-217 or other wellsite equipment. The configuration display screens or menus may be displayed on the touchscreens 422, 424 to permit the wellsite operator 195 to operate the displayed software controls 428, 430 via finger contact with the touchscreens 422, 424 from the operator chair 404.
The software controls 452 may be or comprise software buttons, which may be operated to increase, decrease, change, or otherwise enter different operational parameters, set-points, and/or instructions for controlling one or more portions of the well construction system 100 associated with the software controls 452. The software controls 454 may be or comprise a list or menu of items (e.g., equipment, processes, operational stages, equipment subsystems, etc.) related to one or more aspects of the well construction system 100, which may be operated to select one or more items on the list. The selected items may be highlighted, differently colored, or otherwise indicated, such as via a checkmark, a circle, or a dot appearing in association with the selected item. The software controls 456 may be or comprise a combination of different software controls, which may be operated to increase, decrease, change, or otherwise enter different operational parameters, set-points, and/or instructions for controlling one or more portions of the well construction system 100 associated with the software controls 456, such as a pump of the well construction system 100. The software controls 456 may include a slider bar 453, which may be moved or otherwise operated to increase, decrease, or otherwise change pump speed or another operational parameter associated with the slider bar 453. The entered pump speed may be shown in a display window 455. The software controls 456 may also include software buttons 457, such as may be operated to start, pause, and stop operation of the pump or another portion of the well construction system 100 associated with the software buttons 457.
The display screens, including the display screens 502, 504, may comprise a wellsite subsystem selector/indicator window or area 506, which may be utilized to switch between or select which one or more of the display screens are being displayed on the video output device. The selector/indicator area 506 may be continuously displayed regardless of which display screen is being shown on the video output device. The area 506 may comprise a subsystem selection menu 508, such as a plurality of indicator bars, tabs, or buttons, each listing a subsystem 211-217 of the well construction system 100. The wellsite operator 195 may operate (e.g., click on, touch, highlight, and/or otherwise select) one of the buttons to select and view the display screen and the associated subsystem information. The button associated with the selected subsystem 211-217 may light up, change color, and/or otherwise indicate which display screen and, thus, subsystem 211-217, is being shown. The selector/indicator area 506 may also include a SAFETY button, which may be selected to show the display screen with status of various safety equipment of the well construction system 100. Although the subsystem selection menu 508 is shown as a list that is permanently maintained on the display screens 502, 504, the subsystem selection menu 508 may be implemented as a dropdown or pop-up menu, displaying a list of subsystems 211-217 when clicked on or otherwise operated.
The selector/indicator area 506 may also include a plurality of alarms or event indicators 510 (e.g., lights), each associated with a corresponding subsystem selection button. The monitoring process 274 may activate (e.g., light up, change color, etc.) one or more of the event indicators 510 to show or alarm the wellsite operator 195 of an operational event at or associated with a corresponding subsystem 211-217 that may be associated with a predetermined corrective action or another action by the wellsite operator 195. Responsive to the event indicator 510 being activated, the wellsite operator 195 may switch to a display screen corresponding to the activated event indicator to assess the event and/or implement appropriate counteractive measures or actions. Instead of manually changing between the display screens, the processing device 192 may automatically change the display screen to show the display screen corresponding to a subsystem 211-217 experiencing the event.
The display screens, including the display screens 502, 504, may further comprise a driller information window or area 512 displaying selected sensor data 251-257 or information related to status of drilling operations. For example, the area 512 may include selected sensor data 251 from the RC system 211, selected sensor data 252 from the FC system 212, and/or selected sensor data from the WC system 217. The area 512 may display information such as hook load, traveling block position, drill bit depth, wellbore depth, number of stands or tubulars in the wellbore, standpipe pressure, top drive dolly location, inside BOP position, top drive pipe connection status, elevator status, stickup connection status, and slips status. The area 512 may be continuously displayed regardless of which display screen is being shown on the video output device.
Each display screen, including the display screens 502, 504, may further comprise a corresponding subsystem information window or area 514, 518, respectively, displaying selected sensor data 251-257 or information related to a subsystem 211-217 being shown on the display screen. The information displayed in the area 514, 518 may switch when the wellsite operator 195 or the processing device 192 switches between the display screens of the integrated display.
As described above, the control station 370 may be communicatively connected with and operable to control the BOP control unit 137 and the BOP equipment 130, 132. The operator control workstation 400 may be communicatively connected with the BOP control station 370, such as may permit the operator control workstation 400 to receive information from and transmit control commands to the BOP control station 370, which in turn receives information from and transmits corresponding control commands to the BOP control unit 137 and the BOP equipment 130, 132, facilitating control of the BOP control unit 137 and the BOP equipment 130, 132 from the operator control workstation 400.
For example, when the wellsite operator 195 operates in the subsystem selection menu 508 a software button marked with “WC” associated with the WC system 217, the subsystem information area 514 may display selected information related to the WC system 217. The information area 514 may display a schematic view 515 of the BOP equipment 130, 132 and a plurality of status bars 516 indicative of status of corresponding portions of the BOP equipment 130, 132. The status bars 516 may display sensor data 257 showing operational parameters of the BOP equipment 130, 132, such as pressure, temperature, and position (e.g., open, closed). The information area 514 may further show the sensor data 257 of the WC system 217 in table or list form. One or more operational parameters (e.g., preventer position) of the WC system 217 may be changed, for example, by entering in the status bars 516 or on the list 257 the intended values of the one or more operational parameters, causing the processing device 356 to transmit corresponding control data 267 to the BOP control station 370 (e.g., controller 247) of the WC system 217 to change the operational parameters as intended. The sensor data 257 generated by the BOP control unit 137 and the BOP equipment 130, 132 may be transmitted from the BOP control station 370 to the operator control workstation 400 for display on the display screen 502.
The operator control workstation 400 may be further operable to receive and display different information from the BOP control station 370 or display different display screens (not shown) containing different information from the BOP control station 370, such as may permit the wellsite operator 154 to monitor and control other aspects of the WC system 217. For example, the operator control workstation 400 may display in the subsystem information area 514 different information related to the WC system 217, such as information related to a riser/diverter, pod controls, pod regulators, analog sensor values, BOP event alarm signals, and inclination sensors of the WC system 217. The operator control workstation 400 may be further operable to receive and display on one or more of the video output devices 426 or the touchscreens 422, 424 the same information displayed on the output devices 374 of the BOP control station 370. The operator control workstation 400 may also or instead be operable to mirror or otherwise duplicate on one or more of the video output devices 426 or the touchscreens 422, 424 the actual display screen(s) displayed on the output devices 374 of the BOP control station 370.
When the wellsite operator 195 operates in the subsystem selection menu 508 a software button marked with “CPC” associated with the CPC system 216, the subsystem information area 518 may display selected information related to the CPC system 216. The subsystem information area 518 may display a schematic view 519 of the choke manifold 162 and a plurality of status bars 520 indicative of status of corresponding portions of the choke manifold 162. The status bars 520 may display sensor data 256 showing operational parameters of the CPC system 216, such as flow, pressure, temperature, and position. The area 518 may further show the sensor data 256 of the CPC system 216 in table or list form. One or more operational parameters of the CPC system 216 may be changed, for example, by entering in the status bars 520 or on the list the intended values of the one or more operational parameters, causing the coordinated control device 204 to transmit corresponding control data 266 to the controller 246 of the CPC system 216 to change the operational parameters as intended.
Each display screen, including the display screens 502, 504, may further include one or more PIP video windows 522, each displaying in real-time a video signal from a predetermined video camera 198 to display a predetermined portion of the well construction system 100, a predetermined one of the subsystems 211-217, and/or predetermined wellsite equipment associated with the subsystem 211-217 selected in the subsystem selection menu 508 and/or associated with the information shown in the subsystem information area 514, 518. The PIP video windows 522 may be embedded or inset on the corresponding display screens 502, 504 along or adjacent the sensor information and the software controls displayed on the display screens 502, 504. The view shown in the PIP video window 522 may be switched between different video cameras 198. For example, the PIP video window 522 of the display screen 502 may show a real-time view of the BOP stack 130 and the PIP video window 522 of the display screen 504 may show a real-time view of the choke manifold 162.
Each display screen, including the display screens 502, 504, may also comprise an event description window or area 524 listing and/or describing one or more operational events taking place at the well construction system 100. The event description area 524 may also list and/or describe one or more counteractive measures (e.g., corrective actions, operational sequences) related to the event that may be performed or otherwise implemented in response to the event. Depending on the event and/or mode (e.g., advice, interlock, automated) in which the coordinated control device 204 is operating, the processing device 192 may just describe the corrective action within the event description area 524, and the wellsite operator 195 may implement such corrective action. However, the processing device 192 may automatically implement the corrective action, or cause the corrective action to be automatically implemented, such as by transmitting predetermined control data 261-267 to the controller 241-247 of the corresponding subsystem 211-217.
The information displayed in the area 524 may just display events and/or corrective actions related to the display screen and the subsystem 211-217 being viewed and, thus, change when switching between the display screens of the integrated display. However, the information displayed in the area 524 may not change when switching between the display screens, and may list events and/or corrective actions related to each subsystem 211-217, such as in chronological order or in the order of importance. As described above, the coordinated control device 204 or another portion of the processing device 192 may automatically change the display screen to show the subsystem 211-217 experiencing the event and the corresponding description and/or corrective action related to the event.
Each display screen, including the display screens 502, 504, may be adjusted or otherwise configured by the wellsite operator 195 to display one or more of the various information windows or areas in an intended position on each display screen. For example, the selector/indicator area 506 may be displayed at the bottom of the display screens 502, 504, the event description area 524 may be displayed at the top of the display screens 502, 504, and the driller information area 512 may be displayed on the left side of the display screens 502, 504. Furthermore, the location and/or size (i.e., dimensions) of the PIP video windows 522 displayed on each display screen, including the display screens 502, 504, may also be adjusted or otherwise selected. The placement of the various information windows or areas and the PIP video windows 522 on the display screens may be moved or selected, for example, via one or more of the physical controls physical controls 414, 416, 418, 420, such as by entering an intended location of the information areas and PIP video windows 522 or by dragging the information areas and PIP video windows 522 to an intended location on the display screens.
The wellsite control system 600 may comprise a wellsite control station 602 (e.g., operator control workstation 197, 350, 352, 354, 400) communicatively connected with and operable to control drilling rig equipment 604 (e.g., subsystems 211-216) of the wellsite construction system 100 to drill a wellbore 102 within a subterranean formation 106 at an oil and gas wellsite 104. The wellsite control station 602 may be in communication with various sensors (e.g., sensors 221-226), actuators (e.g., actuators 231-236), controllers (e.g., local controllers 241-246), and other devices of the subsystems 211-216 to control operations associated with the subsystems 211-216.
The wellsite control station 602 may be communicatively connected with one or more portions of the WC system 217 to facilitate control of the WC system 217 via the wellsite control station 602. The WC system 217 may comprise a BOP control station 606 (e.g., BOP control station 370) communicatively connected with and operable to control other portions of the WC system 217, including a BOP control unit 608 (e.g., BOP control unit 137) and BOP equipment 610 (e.g., BOP equipment 130, 132) for controlling pressure within the wellbore 102. The BOP control unit 608 may be operatively (e.g., fluidly) connected with the BOP equipment 610, such as may permit the BOP control unit 608 to selectively actuate, drive, or otherwise power various portions of the BOP equipment 610. The BOP control station 606 may be in communication with various sensors (e.g., sensors 227), actuators (e.g., actuators 237), controllers (e.g., controllers 247), and other devices of the WC system 217 to monitor operational status of the WC system 217. For example, the BOP control station 606 may be communicatively connected with various actuators (e.g., valves) of the BOP control unit 608 to actuate or otherwise operate various actuators (e.g., hydraulic cylinders) of the BOP equipment 610 and, thus, control the BOP equipment 610. The BOP control station 606 may also be communicatively connected with various sensors of the BOP control unit 608 and the BOP equipment 610 to receive information indicative of operational status (e.g., position, pressure) of the BOP control unit 608 and the BOP equipment 610.
The wellsite control station 602 and the BOP control station 606 may be communicatively connected together, such as may permit the wellsite control station 602 to control the BOP control station 606 to control the BOP control unit 608 and BOP equipment 610. Such communicative connection may also or instead permit the wellsite control station 602 to communicate with and control the BOP control unit 608 and BOP equipment 610 via the BOP control station 606. Accordingly, the wellsite control station 602 may be operated by a wellsite operator 195 to control the drilling rig equipment 604 and the BOP equipment 610.
The wellsite control station 602 may be operable to receive sensor signals or information (e.g., sensor data 257) indicative of operational status of the BOP equipment 610 and BOP control unit 608 via the BOP control station 606 to monitor the BOP equipment 610 and BOP control unit 608, and to receive sensor signals or information (e.g., sensor data 251-256) indicative of operational status of the drilling rig equipment 604 to monitor the drilling rig equipment 604. The wellsite control station 602 may be further operable to transmit control commands (e.g., control data 267) to the BOP equipment 610 and BOP control unit 608 via the BOP control station 606 to control the BOP equipment 610 and BOP control unit 608, and transmit control commands (e.g., control data 261-266) to the drilling rig equipment 604 to control the drilling rig equipment 604.
The control commands transmitted to the BOP control unit 608 and the BOP equipment 610 via the BOP control station 606 may be based, at least in part, on the sensor signals or information indicative of operational status (e.g., events described above in association with
The BOP control station 606 may comprise one or more input devices 612 (e.g., input devices 372), such as may be utilized by the wellsite operator 195 to enter the control commands for controlling the BOP control unit 608 and the BOP equipment 610. The BOP control station 605 may further comprise one or more output devices 614 (e.g., output devices 374), such as may be operable to display to the wellsite operator 195 the sensor signals or information indicative of the operational status of the BOP control unit 608 and the BOP equipment 610.
The wellsite control station 602 may comprise one or more input devices 616 (e.g., input devices 194, 414, 416, 418, 422, 424), such as may be utilized by the wellsite operator 195 to enter the control commands for controlling the drilling rig equipment 604, the BOP control unit 608, and/or the BOP equipment 610. The wellsite control station 602 may further comprise one or more output devices 618 (e.g., output devices 196, 422, 424, 426), such as may be operable to display to the wellsite operator 195 the sensor signals or information indicative of the operational status of the drilling rig equipment 604, the BOP control unit 608, and/or the BOP equipment 610. The wellsite control station 602 may be operable to receive and display on the output device 618 the sensor signals or information displayed by the BOP control station 606 on the output device 612. The control commands for controlling the BOP control unit 608, the BOP equipment 610, and drilling rig equipment 604 may be entered into the well site control station 602 by the wellsite operator 195, for example, while operating the coordinated control device 204 of the wellsite control station 602 in the advice mode, as described above in association with
Instead of or in addition to receiving control commands from the wellsite operator 195 to control the drilling rig equipment 604, the BOP control unit 608, and/or the BOP equipment 610, the wellsite control station 602 may be operable to automatically generate control commands based on computer program code and the sensor signals or information indicative of the operational status of the drilling rig equipment 604, the BOP control unit 608, and/or the BOP equipment 610 to automatically control operations of one or more of the drilling rig equipment 604, the BOP control unit 608, and/or the BOP equipment 610. The control commands for controlling the BOP control unit 608, the BOP equipment 610, and drilling rig equipment 604 may be generated automatically by the wellsite control station 602, for example, while operating the coordinated control device 204 in the interlock mode or automated sequence mode, as described above in association with
The wellsite and BOP control stations 602, 606 may be disposed within or form at least a portion of a wellsite control center (e.g., control center 190, 300). The input and output devices 616, 618 of the wellsite control station 602 may be or comprise one or more touchscreens (e.g., touchscreens 422, 424) mounted to, carried by, or otherwise disposed in association with a driller's chair (e.g., chair 402) within the control center, such as may permit the wellsite operator 195 to control the drilling rig equipment 604, the BOP control unit 608, and/or the BOP equipment 610 while sitting in the driller's chair.
The processing device 700 may be in communication with various sensors, actuators, controllers, and other devices of the subsystems 211-217 and/or other portions of the well construction system 100. The processing device 700 may be operable to receive coded instructions 742 from the wellsite operators 195 via the wellsite control station 602 and the sensor data 251-257 generated by the sensors 221-227, process the coded instructions 742 and the sensor data 251-257, and communicate the control data 261-267 to the local controllers 241-247 and/or the actuators 231-237 of the subsystems 211-217 to execute the coded instructions 742 to implement at least a portion of one or more example methods and/or operations described herein, and/or to implement at least a portion of one or more of the example systems described herein.
The processing device 700 may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, internet appliances, and/or other types of computing devices. The processing device 700 may comprise a processor 712, such as a general-purpose programmable processor. The processor 712 may comprise a local memory 714, and may execute coded instructions 742 present in the local memory 714 and/or another memory device. The processor 712 may execute, among other things, the machine-readable coded instructions 742 and/or other instructions and/or programs to implement the example methods and/or operations described herein. The programs stored in the local memory 714 may include program instructions or computer program code that, when executed by the processor 712 of the processing device 700, may cause the subsystems 211-217 of the well construction system 100 to perform the example methods and/or operations described herein. The processor 712 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. Of course, other processors from other families are also appropriate.
The processor 712 may be in communication with a main memory 717, such as may include a volatile memory 718 and a non-volatile memory 720, perhaps via a bus 722 and/or other communication means. The volatile memory 718 may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 720 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 718 and/or non-volatile memory 720.
The processing device 700 may also comprise an interface circuit 724. The interface circuit 724 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 724 may also comprise a graphics driver card. The interface circuit 724 may also 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.). One or more of the local controllers 241-247, the sensors 221-227, and the actuators 231-237 may be connected with the processing device 700 via the interface circuit 724, such as may facilitate communication between the processing device 700 and the local controllers 241-247, the sensors 221-227, and/or the actuators 231-237.
One or more input devices 726 may also be connected to the interface circuit 724. The input devices 726 may permit the wellsite operators 195 to enter the coded instructions 742, such as control commands, processing routines, and/or operational settings and set-points. The input devices 726 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 728 may also be connected to the interface circuit 724. The output devices 728 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 processing device 700 may also communicate with one or more mass storage devices 740 and/or a removable storage medium 744, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.
The coded instructions 742 may be stored in the mass storage device 740, the main memory 717, the local memory 714, and/or the removable storage medium 744. Thus, the processing device 700 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 712. In the case of 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 (i.e., software or firmware) thereon for execution by the processor 712. The coded instructions 742 may include program instructions or computer program code that, when executed by the processor 712, may cause the various subsystems 211-217 of the well construction system 100 to perform intended methods, processes, and/or operations disclosed herein.
The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.
The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.
Claims
1. An apparatus comprising:
- a first control station communicatively connected with and operable to control blowout preventer (BOP) equipment for controlling pressure within a wellbore at an oil and gas wellsite; and
- a second control station communicatively connected with and operable to control drilling rig equipment for drilling the wellbore within a subterranean formation at the oil and gas wellsite, wherein the second control station is communicatively connected with the first control station and operable to control the BOP equipment via the first control station.
2. The apparatus of claim 1 wherein each of the first and second control stations comprises or is communicatively connected with a corresponding processor and a memory storing a computer program code.
3. The apparatus of claim 1 wherein the drilling rig equipment comprises one or more of:
- a drill pipe handling system operable to move drill pipe at the oil/gas wellsite;
- a drill string hoisting system operable to move a drill string within the wellbore;
- a drill string rotation system operable to rotate the drill string within the wellbore; and
- a fluid control system operable to pump drilling fluid into the drill string.
4. The apparatus of claim 1 wherein the BOP equipment is or comprises a BOP stack and/or a BOP control hydraulic power unit for actuating the BOP stack.
5. The apparatus of claim 1 wherein the second control station is operable to:
- receive first information from the BOP equipment via the first control station;
- receive second information from the drilling rig equipment; and
- transmit control commands to the drilling rig equipment.
6. The apparatus of claim 5 wherein the control commands are based, at least in part, on the first and/or second information.
7. The apparatus of claim 5 wherein the control commands are first control commands, and wherein the second control station is operable to transmit second control commands to the BOP equipment via the first control station.
8. The apparatus of claim 7 wherein the second control commands are based, at least in part, on the first and/or second information.
9. The apparatus of claim 1 wherein the second control station is operable to:
- receive first information indicative of operational status of the BOP equipment from the first control station;
- receive second information indicative of operational status of the drilling rig equipment from the drilling rig equipment; and
- transmit control commands to the drilling rig equipment to control the drilling rig equipment.
10. The apparatus of claim 9 wherein the control commands are based, at least in part, on the first and/or second information.
11. The apparatus of claim 9 wherein the control commands are first control commands, and wherein the second control station is operable to transmit second control commands to the first control station to control the BOP equipment.
12. The apparatus of claim 11 wherein the second control commands are based, at least in part, on the first and/or second information.
13. The apparatus of claim 11 wherein:
- the first information is generated by first sensors disposed in association with or forming at least a portion of the BOP equipment;
- the second information is generated by second sensors disposed in association with or forming at least a portion of the drilling rig equipment;
- the second control commands are transmitted to first actuators disposed in association with or forming at least a portion of the BOP equipment; and
- the first control commands are transmitted to second actuators disposed in association with or forming at least a portion of the drilling rig equipment.
14. The apparatus of claim 9 wherein the second control station comprises a video output device operable to display the first and second information.
15. The apparatus of claim 9 wherein the first control station comprises a first video output device operable to display the first information, and wherein the second control station comprises a second video output device operable to display the first and second information.
16. The apparatus of claim 1 wherein:
- the first control station is operable to: receive first information indicative of operational status of the BOP equipment from the BOP equipment; and transmit first control commands to the BOP equipment to control the BOP equipment; and
- the second control station is operable to: receive the first information from the first control station; receive second information indicative of operational status of the drilling rig equipment from the drilling rig equipment; receive the first control commands from a human wellsite operator; receive second control commands from the human wellsite operator; transmit the first control commands to the first control station to control the BOP equipment; and transmit the second control commands to the drilling rig equipment to control the drilling rig equipment.
17. The apparatus of claim 16 wherein the first control commands are based, at least in part, on the first and/or second information.
18. The apparatus of claim 16 wherein the second control station comprises:
- an input device operable to receive the first and second control commands from the human wellsite operator; and
- a video output device operable to display the first and second information.
19. The apparatus of claim 1 wherein:
- the first control station is operable to: receive information indicative of operational status of the BOP equipment from the BOP equipment; and transmit control commands to the BOP equipment to control the BOP equipment; and
- the second control station comprises a processor and a memory storing a computer program code, wherein the second control station is operable to: receive the information from the first control station; generate the control commands based on the computer program code and the information; and transmit the control commands to the first control station.
20. The apparatus of claim 1 wherein the first and second control stations are disposed within or form at least a portion of a wellsite control center.
21. The apparatus of claim 20 wherein the first control station comprises a touchscreen operable by a human wellsite operator sitting in a driller's chair within the wellsite control center to control the BOP equipment and the rig equipment.
22. The apparatus of claim 21 wherein the touchscreen is mounted to and/or otherwise carried with the driller's chair.
23. An apparatus comprising:
- a first control station communicatively connected with blowout preventer (BOP) equipment for controlling pressure within a wellbore at an oil and gas wellsite, wherein the first control station is operable to: receive information indicative of operational status of the BOP equipment from the BOP equipment; and control the BOP equipment to control the pressure within the wellbore; and
- a second control station communicatively connected with the first control station and operable to: receive the information from the first control station; receive control commands from a human wellsite operator; and transmit the control commands to the first control station for transmission by the first control station to the BOP equipment to control the BOP equipment.
24. The apparatus of claim 23 wherein each of the first and second control stations comprises or is communicatively connected with a corresponding processor and a memory storing a computer program code.
25. The apparatus of claim 23 wherein the BOP equipment is or comprises a BOP stack and/or a BOP control hydraulic power unit for actuating the BOP stack.
26. The apparatus of claim 23 wherein the second control station is communicatively connected with drilling rig equipment for drilling the wellbore within a subterranean formation at the oil and gas wellsite.
27. The apparatus of claim 26 wherein the drilling rig equipment comprises one or more of:
- a drill pipe handling system operable to move drill pipe at the oil/gas wellsite;
- a drill string hoisting system operable to move a drill string within the wellbore;
- a drill string rotation system operable to rotate the drill string within the wellbore; and
- a fluid control system operable to pump drilling fluid into the drill string.
28. The apparatus of claim 26 wherein the information is first information, and wherein the second control station is operable to receive second information indicative of operational status of the drilling rig equipment from the drilling rig equipment.
29. The apparatus of claim 28 wherein the control commands are based, at least in part, on the first and/or second information.
30. The apparatus of claim 28 wherein the second control station comprises a video output device operable to display the first and second information.
31. The apparatus of claim 28 wherein the first control station comprises a first video output device operable to display the first information, and wherein the second control station comprises a second video output device operable to display the first and second information.
32. The apparatus of claim 28 wherein the control commands are first control commands, and wherein the second control station is further operable to transmit second control commands to the drilling rig equipment to control the drilling rig equipment.
33. The apparatus of claim 32 wherein the second control commands are based, at least in part, on the first and/or second information.
34. The apparatus of claim 32 wherein:
- the first information is generated by first sensors disposed in association with or forming at least a portion of the BOP equipment;
- the second information is generated by second sensors disposed in association with or forming at least a portion of the drilling rig equipment;
- the first control commands are transmitted to first actuators disposed in association with or forming at least a portion of the BOP equipment; and
- the second control commands are transmitted to second actuators disposed in association with or forming at least a portion of the drilling rig equipment.
35. The apparatus of claim 32 the second control station is further operable to receive the first and second control commands from the human wellsite operator.
36. The apparatus of claim 35 wherein the second control commands are based, at least in part, on the first and/or second information.
37. The apparatus of claim 35 wherein the second control station comprises:
- an input device operable to receive the first and second control commands from the human wellsite operator; and
- a video output device operable to display the first and second information.
38. The apparatus of claim 23 wherein the second control station comprises a processor and a memory storing a computer program code, and wherein the second control station is operable to generate the control commands based on the computer program code and the information.
39. The apparatus of claim 23 wherein the first and second control stations are disposed within or form at least a portion of a wellsite control center.
40. The apparatus of claim 39 wherein the first control station comprises a touchscreen operable by the human wellsite operator sitting in a driller's chair within the wellsite control center to control the BOP equipment and the rig equipment.
41. The apparatus of claim 40 wherein the touchscreen is mounted to and/or otherwise carried with the driller's chair.
42. A method comprising:
- receiving, by a first control station at an oil and gas wellsite, first information indicative of operational status of drilling rig equipment at an oil and gas wellsite, wherein the first control station is manually and/or automatically operable to control the drilling rig equipment;
- receiving, by the first control station, second information indicative of operational status of blowout preventer (BOP) equipment at the oil and gas wellsite, wherein: the drilling rig equipment does not include the BOP equipment; the second information is received from a second control station at the oil and gas wellsite; and the second control station is operable to control the BOP equipment but not the drilling rig equipment;
- transmitting first control commands from the first control station to the second control station for transmission to the BOP equipment to control the BOP equipment; and
- transmitting second control commands from the first control station to the drilling rig equipment to control the drilling rig equipment to drill a wellbore within a subterranean formation at the oil and gas wellsite.
43. The method of claim 42 wherein the drilling rig equipment comprises one or more of:
- a drill pipe handling system operable to move drill pipe at the oil/gas wellsite;
- a drill string hoisting system operable to move a drill string within the wellbore;
- a drill string rotation system operable to rotate the drill string within the wellbore; and
- a fluid control system operable to pump drilling fluid into the drill string.
44. The method of claim 42 wherein the BOP equipment is or comprises a BOP stack and/or a BOP control hydraulic power unit for actuating the BOP stack.
45. The method of claim 42 further comprising transmitting from the second control station to the BOP equipment the first control commands to control the BOP equipment.
46. The method of claim 42 wherein the first control commands are based, at least in part, on the first and/or second information.
47. The method of claim 42 wherein the second control commands are based, at least in part, on the first and/or second information.
48. The method of claim 42 wherein:
- the first information is generated by first sensors disposed in association with or forming at least a portion of the drilling rig equipment;
- the second information is generated by second sensors disposed in association with or forming at least a portion of the BOP equipment;
- the second control commands are transmitted to first actuators disposed in association with or forming at least a portion of the drilling rig equipment; and
- the first control commands are transmitted to second actuators disposed in association with or forming at least a portion of the BOP equipment.
49. The method of claim 42 further comprising displaying the first and second information on a video output device of the first control station.
50. The method of claim 42 further comprising:
- displaying the first and second information on a first video output device of the first control station; and
- displaying the second information on a second video output device of the second control station.
51. The method of claim 42 further comprising receiving by the first control station the first and second control commands from a human wellsite operator.
52. The method of claim 51 wherein the second control commands are based, at least in part, on the first and/or second information.
53. The method of claim 42 further comprising automatically generating by the second control station the second control commands based, at least in part, on the first and/or second information.
54. The method of claim 42 wherein the first and second control stations are disposed within or forming at least a portion of a wellsite control center.
55. The method of claim 54 wherein the first control station comprises a touchscreen, and wherein the method further comprises operating the touchscreen by a human wellsite operator sitting in a driller's chair within the wellsite control center to enter the first and second commands.
56. The method of claim 55 wherein the touchscreen is mounted to and/or otherwise carried with the driller's chair.
57. A method comprising:
- controlling drilling rig equipment by operating a first control station in response to receipt, by the first control station, of first information indicative of operational status of the drilling rig equipment; and
- controlling blowout preventer (BOP) equipment by operating the first control station in response to receipt, by the first control station, of second information indicative of operational status of the BOP equipment, wherein the second information is received by the first control station from a second control station that is operable to control the BOP equipment but not the drilling rig equipment.
58. The method of claim 57 wherein controlling the drilling rig equipment causes the rig equipment to drill a wellbore within a subterranean formation at an oil and gas wellsite, and wherein controlling the BOP equipment causes the BOP equipment to control pressure within the wellbore at the oil and gas wellsite.
59. The method of claim 57 wherein the drilling rig equipment comprises one or more of:
- a drill pipe handling system operable to move drill pipe at the oil/gas wellsite;
- a drill string hoisting system operable to move a drill string within the wellbore;
- a drill string rotation system operable to rotate the drill string within the wellbore; and
- a fluid control system operable to pump drilling fluid into the drill string.
60. The method of claim 57 wherein the BOP equipment is or comprises a BOP stack and/or a BOP control hydraulic power unit for actuating the BOP stack.
61. The method of claim 57 wherein:
- controlling the BOP equipment by operating the first control station further comprises transmitting first control commands from the first control station to the second control station;
- controlling the drilling rig equipment by operating a first control station further comprises transmitting second control commands from the first control station to the drilling rig equipment to control the drilling rig equipment to drill a wellbore within a subterranean formation at the oil and gas wellsite; and
- the method further comprises transmitting the first control commands from the second control station to the BOP equipment to control the BOP equipment.
62. The method of claim 57 wherein the first control commands are based, at least in part, on the first and/or second information.
63. The method of claim 57 wherein the second control commands are based, at least in part, on the first and/or second information.
64. The method of claim 57 wherein:
- the first information is generated by first sensors disposed in association with or forming at least a portion of the drilling rig equipment;
- the second information is generated by second sensors disposed in association with or forming at least a portion of the BOP equipment;
- the second control commands are transmitted to first actuators disposed in association with or forming at least a portion of the drilling rig equipment; and
- the first control commands are transmitted to second actuators disposed in association with or forming at least a portion of the BOP equipment.
65. The method of claim 57 further comprising receiving by the first control station the first and second control commands from a human wellsite operator.
66. The method of claim 61 wherein the second control commands are based, at least in part, on the first and/or second information.
67. The method of claim 61 further comprising automatically generating by the second control station the second control commands based, at least in part, on the first and/or second information.
68. The method of claim 61 wherein the first and second control stations are disposed within or forming at least a portion of a wellsite control center.
69. The method of claim 68 wherein the first control station comprises a touchscreen, and wherein the method further comprises operating the touchscreen by the human wellsite operator sitting in a driller's chair within the wellsite control center to enter the first and second commands.
70. The method of claim 69 wherein the touchscreen is mounted to and/or otherwise carried with the driller's chair.
71. The method of claim 57 further comprising displaying the first and second information on a video output device of the first control station.
72. The method of claim 57 further comprising:
- displaying the first and second information on a first video output device of the first control station; and
- displaying the second information on a second video output device of the second control station.
Type: Application
Filed: Jun 4, 2018
Publication Date: Dec 5, 2019
Inventor: Anstein Jorud (Kristiansand)
Application Number: 15/997,414
