TACHOMETER FOR A ROTATING CONTROL DEVICE
A rotating control device (RCD) includes: a tubular housing having a flange formed at each end thereof; a stripper seal for receiving and sealing against a tubular; a bearing for supporting rotation of the stripper seal relative to the housing; a retainer for connecting the stripper seal to the bearing; and a tachometer. The tachometer includes a probe connected to the retainer and including: a tilt sensor; an angular speed sensor; an angular acceleration sensor; a first wireless data coupling; and a microcontroller operable to receive measurements from the sensors and to transmit the measurements to a base using the first wireless data coupling. The tachometer further includes the base connected to the housing and including: a second wireless data coupling operable to receive the measurements; and an electronics package in communication with the second wireless data coupling and operable to relay the measurements to an offshore drilling unit.
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1. Field of the Disclosure
The present disclosure generally relates to a tachometer for a rotating control device.
2. Description of the Related Art
Drilling a wellbore for hydrocarbons requires significant expenditures of manpower and equipment. Thus, constant advances are being sought to reduce any downtime of equipment and expedite any repairs that become necessary. Rotating equipment is particularly prone to maintenance as the drilling environment produces abrasive cuttings detrimental to the longevity of rotating seals, bearings, and packing elements.
In a typical drilling operation, a drill bit is attached to a drill pipe. Thereafter, a drive unit rotates the drill pipe using a drive member as the drill pipe and drill bit are urged downward to form the wellbore. Several components are used to control the gas or fluid pressure. Typically, one or more blow out preventers (BOP) are used to seal the mouth of the wellbore. In many instances, a rotating control device is mounted above the BOP stack. An internal portion of the conventional rotating control device is designed to seal and rotate with the drill pipe. The internal portion typically includes an internal sealing element mounted on a plurality of bearings. Over time, the seal arrangement may leak (or fail) due to wear.
SUMMARY OF THE DISCLOSUREThe present disclosure generally relates to a tachometer for a rotating control device. In one embodiment, a rotating control device (RCD) for use with an offshore drilling unit includes: a tubular housing having a flange formed at each end thereof; a stripper seal for receiving and sealing against a tubular; a bearing for supporting rotation of the stripper seal relative to the housing; a retainer for connecting the stripper seal to the bearing; and a tachometer. The tachometer includes a probe connected to the retainer and including: a tilt sensor; an angular speed sensor; an angular acceleration sensor; a first wireless data coupling; and a microcontroller operable to receive measurements from the sensors and to transmit the measurements to a base using the first wireless data coupling. The tachometer further includes the base connected to the housing and including: a second wireless data coupling operable to receive the measurements; and an electronics package in communication with the second wireless data coupling and operable to relay the measurements to the offshore drilling unit.
So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.
Alternatively, the MODU 1m may be a drill ship. Alternatively, a fixed offshore drilling unit or a non-mobile floating offshore drilling unit may be used instead of the MODU 1m. Alternatively, the wellbore may be subsea having a wellhead located adjacent to the waterline and the drilling rig may be a located on a platform adjacent the wellhead. Alternatively, the wellbore may be subterranean and the drilling rig located on a terrestrial pad.
The drilling rig 1r may include a derrick 3, a floor 4, a top drive 5, and a hoist. The top drive 5 may include a motor for rotating 16 the drill string 10. The top drive motor may be electric or hydraulic. A frame of the top drive 5 may be linked to a rail (not shown) of the derrick 3 for preventing rotation thereof during rotation 16 of the drill string 10 and allowing for vertical movement of the top drive with a traveling block 6 of the hoist. The frame of the top drive 5 may be suspended from the derrick 3 by the traveling block 6. A Kelly valve 11 may be connected to a quill of a top drive 5. The quill may be torsionally driven by the top drive motor and supported from the frame by bearings. The top drive 5 may further have an inlet connected to the frame and in fluid communication with the quill.
The traveling block 6 may be supported by wire rope 7 connected at its upper end to a crown block 8. The wire rope 7 may be woven through sheaves of the blocks 6, 8 and extend to drawworks 9 for reeling thereof, thereby raising or lowering the traveling block 6 relative to the derrick 3. The drilling rig 1r may further include a drill string compensator (not shown) to account for heave of the MODU 1m. The drill string compensator may be disposed between the traveling block 6 and the top drive 5 (aka hook mounted) or between the crown block 8 and the derrick 3 (aka top mounted).
An upper end of the drill string 10 may be connected to the Kelly valve 11, such as by threaded couplings. The drill string 10 may include a bottomhole assembly (BHA) 10b and joints of drill pipe 10p connected together, such as by threaded couplings. The BHA 10b may be connected to the drill pipe 10p, such as by threaded couplings, and include a drill bit 15 and one or more drill collars 12 connected thereto, such as by threaded couplings. The drill bit 15 may be rotated 16 by the top drive 5 via the drill pipe 10p and/or the BHA 10b may further include a drilling motor (not shown) for rotating the drill bit. The BHA 10b may further include an instrumentation sub (not shown), such as a measurement while drilling (MWD) and/or a logging while drilling (LWD) sub.
The fluid transport system 1t may include an upper marine riser package (UMRP) 20, a marine riser 25, a booster line 27, and a choke line 28. The UMRP 20 may include a diverter 21, a flex joint 22, a slip (aka telescopic) joint 23, a tensioner 24, and a rotating control device (RCD) 26. A lower end of the RCD 26 may be connected to an upper end of the riser 25, such as by a flanged connection. The slip joint 23 may include an outer barrel connected to an upper end of the RCD 26, such as by a flanged connection, and an inner barrel connected to the flex joint 22, such as by a flanged connection. The outer barrel may also be connected to the tensioner 24, such as by a tensioner ring.
The flex joint 22 may also connect to the diverter 21, such as by a flanged connection. The diverter 21 may also be connected to the rig floor 4, such as by a bracket. The slip joint 23 may be operable to extend and retract in response to heave of the MODU 1m relative to the riser 25 while the tensioner 24 may reel wire rope in response to the heave, thereby supporting the riser 25 from the MODU 1m while accommodating the heave. The riser 25 may extend from the PCA 1p to the MODU 1m and may connect to the MODU via the UMRP 20. The riser 25 may have one or more buoyancy modules (not shown) disposed therealong to reduce load on the tensioner 24.
The PCA 1p may be connected to the wellhead 50 adjacently located to a floor 2f of the sea 2. A conductor string 51 may be driven into the seafloor 2f. The conductor string 51 may include a housing and joints of conductor pipe connected together, such as by threaded couplings. Once the conductor string 51 has been set, a subsea wellbore 90 may be drilled into the seafloor 2f and a casing string 52 may be deployed into the wellbore. The casing string 52 may include a wellhead housing and joints of casing connected together, such as by threaded couplings. The wellhead housing may land in the conductor housing during deployment of the casing string 52. The casing string 52 may be cemented 91 into the wellbore 90. The casing string 52 may extend to a depth adjacent a bottom of an upper formation 94u. The upper formation 94u may be non-productive and a lower formation 94b may be a hydrocarbon-bearing reservoir.
Alternatively, the lower formation 94b may be non-productive (e.g., a depleted zone), environmentally sensitive, such as an aquifer, or unstable. Although shown as vertical, the wellbore 90 may include a vertical portion and a deviated, such as horizontal, portion.
The PCA 1p may include a wellhead adapter 40b, one or more flow crosses 41u,m,b, one or more blow out preventers (BOPs) 42a,u,b, a lower marine riser package (LMRP), one or more accumulators 44, and a receiver 46. The LMRP may include a control pod 76, a flex joint 43, and a connector 40u. The wellhead adapter 40b, flow crosses 41u,m,b, BOPs 42a,u,b, receiver 46, connector 40u, and flex joint 43 may each include a housing having a longitudinal bore therethrough and may each be connected, such as by flanges, such that a continuous bore is maintained therethrough. The bore may have drift diameter, corresponding to a drift diameter of the wellhead 50. The flex joints 23, 43 may accommodate respective horizontal and/or rotational (aka pitch and roll) movement of the MODU 1m relative to the riser 25 and the riser relative to the PCA 1p.
Each of the connector 40u and wellhead adapter 40b may include one or more fasteners, such as dogs, for fastening the LMRP to the BOPs 42a,u,b and the PCA 1p to an external profile of the wellhead housing, respectively. Each of the connector 40u and wellhead adapter 40b may further include a seal sleeve for engaging an internal profile of the respective receiver 46 and wellhead housing. Each of the connector 40u and wellhead adapter 40b may be in electric or hydraulic communication with the control pod 76 and/or further include an electric or hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV) (not shown) may operate the actuator for engaging the dogs with the external profile.
The LMRP may receive a lower end of the riser 25 and connect the riser to the PCA 1p. The control pod 76 may be in electric, hydraulic, and/or optical communication with a programmable logic controller (PLC) 75 and/or a rig controller (not shown) onboard the MODU 1m via an umbilical 70. The control pod 76 may include one or more control valves (not shown) in communication with the BOPs 42a,u,b for operation thereof. Each control valve may include an electric or hydraulic actuator in communication with the umbilical 70. The umbilical 70 may include one or more hydraulic and/or electric control conduit/cables for the actuators. The accumulators 44 may store pressurized hydraulic fluid for operating the BOPs 42a,u,b. Additionally, the accumulators 44 may be used for operating one or more of the other components of the PCA 1p. The PLC 75 and/or rig controller may operate the PCA 1p via the umbilical 70 and the control pod 76.
A lower end of the booster line 27 may be connected to a branch of the flow cross 41u by a shutoff valve 45a. A booster manifold may also connect to the booster line lower end and have a prong connected to a respective branch of each flow cross 41m,b. Shutoff valves 45b,c may be disposed in respective prongs of the booster manifold. Alternatively, a separate kill line (not shown) may be connected to the branches of the flow crosses 41m,b instead of the booster manifold. An upper end of the booster line 27 may be connected to an outlet of a booster pump (not shown). A lower end of the choke line 28 may have prongs connected to respective second branches of the flow crosses 41m,b. Shutoff valves 45d,e may be disposed in respective prongs of the choke line lower end.
A pressure sensor 47a may be connected to a second branch of the upper flow cross 41u. Pressure sensors 47b,c may be connected to the choke line prongs between respective shutoff valves 45d,e and respective flow cross second branches. Each pressure sensor 47a-c may be in data communication with the control pod 76. The lines 27, 28 and umbilical 70 may extend between the MODU 1m and the PCA 1p by being fastened to brackets disposed along the riser 25. Each shutoff valve 45a-e may be automated and have a hydraulic actuator (not shown) operable by the control pod 76.
Alternatively, the umbilical may be extend between the MODU and the PCA independently of the riser. Alternatively, the valve actuators may be electrical or pneumatic.
The fluid handling system 1h may include a return line 29, mud pump 30, a solids separator, such as a shale shaker 33, one or more flow meters 34d,r, one or more pressure sensors 35d,r, a variable choke valve, such as returns choke 36, a supply line 37p,h, and a reservoir for drilling fluid 60d, such as a tank. A lower end of the return line 29 may be connected to an outlet 26o of the RCD 26 and an upper end of the return line may be connected to an inlet of the mud pump 30. The returns pressure sensor 35r, returns choke 36, returns flow meter 34r, and shale shaker 33 may be assembled as part of the return line 29. A lower end of standpipe 37p may be connected to an outlet of the mud pump 30 and an upper end of Kelly hose 37h may be connected to an inlet of the top drive 5. The supply pressure sensor 35d and supply flow meter 34d may be assembled as part of the supply line 37p,h.
The returns choke 36 may include a hydraulic actuator operated by the PLC 75 via a hydraulic power unit (HPU) (not shown). The returns choke 36 may be operated by the PLC 75 to maintain backpressure in the riser 25. Each pressure sensor 35d,r may be in data communication with the PLC 75. The returns pressure sensor 35r may be operable to measure backpressure exerted by the returns choke 36. The supply pressure sensor 35d may be operable to measure standpipe pressure.
Alternatively, the choke actuator may be electrical or pneumatic.
The returns flow meter 34r may be a mass flow meter, such as a Coriolis flow meter, and may be in data communication with the PLC 75. The returns flow meter 34r may be connected in the return line 29 downstream of the returns choke 36 and may be operable to measure a flow rate of the drilling returns 60r. The supply 34d flow meter may be a volumetric flow meter, such as a Venturi flow meter and may be in data communication with the PLC 75. The supply flow meter 34d may be operable to measure a flow rate of drilling fluid 60d supplied by the mud pump 30 to the drill string 10 via the top drive 5. The PLC 75 may receive a density measurement of the drilling fluid 60d from a mud blender (not shown) to determine a mass flow rate of the drilling fluid from the volumetric measurement of the supply flow meter 34d.
Alternatively, the supply flow meter 34d may be a mass flow meter or a stroke counter of the mud pump 30.
To conduct a drilling operation, the mud pump 30 may pump drilling fluid 60d from the drilling fluid tank, through the pump outlet, standpipe 37p and Kelly hose 37h to the top drive 5. The drilling fluid 60d may include a base liquid. The base liquid may be refined or synthetic oil, water, brine, or a water/oil emulsion. The drilling fluid 60d may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud.
The drilling fluid 60d may flow from the Kelly hose 37h and into the drill string 10 via the top drive 5 and open Kelly valve 11. The drilling fluid 60d may flow down through the drill string 10 and exit the drill bit 15, where the fluid may circulate the cuttings away from the bit and return the cuttings up an annulus 95 formed between an inner surface of the casing 91 or wellbore 90 and an outer surface of the drill string 10. The returns 60r (drilling fluid 60d plus cuttings) may flow through the annulus 95 to the wellhead 50. The returns 60r may continue from the wellhead 50 and into the riser 25 via the PCA 1p. The returns 60r may flow up the riser 25 to the RCD 26. The returns 60r may be diverted by the RCD 26 into the return line 29 via the RCD outlet 26o. The returns 60r may continue through the returns choke 36 and the flow meter 34r. The returns 60r may then flow into the shale shaker 33 and be processed thereby to remove the cuttings, thereby completing a cycle. As the drilling fluid 60d and returns 60r circulate, the drill string 10 may be rotated 16 by the top drive 5 and lowered by the traveling block 6, thereby extending the wellbore 90 into the lower formation 94b.
The PLC 75 may be programmed to operate the returns choke 36 so that a target bottomhole pressure (BHP) is maintained in the annulus 95 during the drilling operation. The target BHP may be selected to be within a drilling window defined as greater than or equal to a minimum threshold pressure, such as pore pressure, of the lower formation 94b and less than or equal to a maximum threshold pressure, such as fracture pressure, of the lower formation, such as an average of the pore and fracture BHPs.
Alternatively, the minimum threshold may be stability pressure and/or the maximum threshold may be leakoff pressure. Alternatively, threshold pressure gradients may be used instead of pressures and the gradients may be at other depths along the lower formation 94b besides bottomhole, such as the depth of the maximum pore gradient and the depth of the minimum fracture gradient. Alternatively, the PLC 75 may be free to vary the BHP within the window during the drilling operation.
A static density of the drilling fluid 60d (typically assumed equal to returns 60r; effect of cuttings typically assumed to be negligible) may correspond to a threshold pressure gradient of the lower formation 94b, such as being equal to a pore pressure gradient. During the drilling operation, the PLC 75 may execute a real time simulation of the drilling operation in order to predict the actual BHP from measured data, such as standpipe pressure from sensor 35d, mud pump flow rate from the supply flow meter 34d, wellhead pressure from any of the sensors 47a-c, and return fluid flow rate from the return flow meter 34r. The PLC 75 may then compare the predicted BHP to the target BHP and adjust the returns choke 36 accordingly.
Alternatively, a static density of the drilling fluid 60d may be slightly less than the pore pressure gradient such that an equivalent circulation density (ECD) (static density plus dynamic friction drag) during drilling is equal to the pore pressure gradient. Alternatively, a static density of the drilling fluid 60d may be slightly greater than the pore pressure gradient.
During the drilling operation, the PLC 75 may also perform a mass balance to monitor for a kick (not shown) or lost circulation (not shown). As the drilling fluid 60d is being pumped into the wellbore 90 by the mud pump 30 and the returns 60r are being received from the return line 29, the PLC 75 may compare the mass flow rates (i.e., drilling fluid flow rate minus returns flow rate) using the respective flow meters 34d,r. The PLC 75 may use the mass balance to monitor for formation fluid (not shown) entering the annulus 95 and contaminating the returns 60r or returns entering the formation 94b.
Alternatively, the return line 29 may further include a gas detector (not shown) assembled as part thereof and the gas detector may capture and analyze samples of the returns 60r as an additional safeguard for kick detection during drilling. The gas detector may include a probe having a membrane for sampling gas from the returns 60r, a gas chromatograph, and a carrier system for delivering the gas sample to the chromatograph.
Upon detection of a kick or lost circulation, the PLC 75 may take remedial action, such as diverting the flow of returns 60r from an outlet of the returns flow meter 34r to a degassing spool (not shown). The degassing spool may include automated shutoff valves at each end and a mud-gas separator (MGS). A first end of the degassing spool may be connected to the return line 29 between the returns flow meter 34r and the shaker 33 and a second end of the degasser spool may be connected to an inlet of the shaker. The MGS may include an inlet and a liquid outlet assembled as part of the degassing spool and a gas outlet connected to a flare or a gas storage vessel. The PLC 75 may also adjust the returns choke 36 accordingly, such as tightening the choke in response to a kick and loosening the choke in response to loss of the returns.
Alternatively, the booster pump may be operated during drilling to compensate for any size discrepancy between the riser annulus and the casing/wellbore annulus and the PLC may account for boosting in the BHP control and mass balance using an additional flow meter. Alternatively, the PLC 75 may estimate a mass rate of cuttings (and add the cuttings mass rate to the intake sum) using a rate of penetration (ROP) of the drill bit or a mass flow meter may be added to the cuttings chute of the shaker and the PLC may directly measure the cuttings mass rate.
Alternatively, the RCD 26 may be used with a riserless drilling system. The RCD 26 may then be assembled as part of a riserless package connected to the annular BOP 47a and the return line 29 and RCD umbilical 71 may extend from the riserless package to the MODU 1m. Alternatively, the LMRP may further include a returns pump. Alternatively, the drilling system may be dual gradient including a lifting fluid pump or compressor connected to the LMRP.
The latch 102, 103, 105 may include a hydraulic actuator, such as a piston 102, one or more (two shown) fasteners, such as dogs 103, and a body 105. The latch body 105 may be connected to the housing 101, such as by threaded couplings. A piston chamber may be formed between the latch body 105 and a mid housing section 101b. The latch body 105 may have openings formed through a wall thereof for receiving the respective dogs 103. The latch piston 102 may be disposed in the piston chamber and may carry seals isolating an upper portion of the chamber from a lower portion of the chamber. A cam surface may be formed on an inner surface of the piston 102 for radially displacing the dogs 103. The latch body 105 may further have a landing shoulder formed in an inner surface thereof for receiving a protective sleeve (not shown) or the bearing assembly 110. The protective sleeve may be installed for operation of the drilling system is in an overbalanced mode.
Hydraulic passages (not shown) may be formed through the mid housing section 101b and may provide fluid communication between the interface 26i and respective portions of the hydraulic chamber for selective operation of the piston 103. An RCD umbilical 71 (not shown, see
The bearing assembly 110 may include a bearing pack 111, a housing seal assembly 113, 114, one or more strippers 115u,b, and a catch, such as a sleeve 112. The upper stripper 115u may include a gland 116g, an upper retainer 116u, and a seal 120u. The gland 116g and the upper retainer 116u may be connected together, such as by threaded couplings. The upper stripper seal 120u may be longitudinally and torsionally connected to the upper retainer 116u, such as by fasteners (not shown). The gland 116g may be longitudinally and torsionally connected to a rotating mandrel 111m of the bearing pack 111, such as by threaded couplings. The lower stripper 115b may include a lower retainer 116b and a seal 120b. The lower stripper seal 120b may be longitudinally and torsionally connected to the lower retainer 116b, such as by fasteners (not shown). The lower retainer 116b may be longitudinally and torsionally connected to the rotating mandrel 111m, such as by threaded couplings.
Each stripper seal 120u,b may be directional and oriented to seal against the drill pipe 10p in response to higher pressure in the riser 25 than the UMRP 20 (components thereof above the RCD 26). Each stripper seal 120u,b may have a conical shape for fluid pressure to act against a respective tapered surface 119u,b thereof, thereby generating sealing pressure against the drill pipe 10p. Each stripper seal 120u,b may have an inner diameter slightly less than a pipe diameter of the drill pipe 10p to form an interference fit therebetween. Each stripper seal 120u,b may be made from a flexible material, such as an elastomer or elastomeric copolymer, to accommodate and seal against threaded couplings of the drill pipe 10p having a larger tool joint diameter.
The drill pipe 10p may be received through a bore of the bearing assembly 110 so that the stripper seals 120u,b may engage the drill pipe. The stripper seals 120u,b may provide a desired barrier in the riser 25 either when the drill pipe 10p is stationary or rotating. The lower stripper seal 120b may be exposed to the returns 60r to serve as the primary seal. The upper stripper seal 120u may be idle as long as the lower stripper seal 120b is functioning. Should the lower stripper seal 120b fail, the returns 60r may leak therethrough and exert pressure on the upper stripper seal 120u via an annular fluid passage 121 formed between the bearing mandrel 111m and the drill pipe 10p.
The bearing pack 111 may support the strippers 115u,b from the catch sleeve 112 such that the strippers may rotate relative to the housing 101 (and the catch sleeve). The bearing pack 111 may include one or more radial bearings, one or more thrust bearings, and a self contained lubricant system. The lubricant system may include a reservoir having a lubricant, such as bearing oil, and a balance piston in communication with the returns 60r for maintaining oil pressure in the reservoir at a pressure equal to or slightly greater than the returns pressure. The bearing pack 111 may be disposed between the strippers 115u,b and be housed in and connected to the catch sleeve 112, such as by threaded couplings and/or fasteners.
The catch sleeve 112 may have a landing shoulder and a catch profile formed in an outer surface thereof. The bearing assembly 110 may be fastened to the housing 101 by engagement of the dogs 103 with the catch profile of the catch sleeve 112. The housing seal assembly 113, 114 may include a body 113 carrying one or more seals, such as o-rings, and a retainer 114. The retainer 114 may be connected to the sleeve 112, such as by threaded couplings (not shown), and the seal body 113 may be trapped between a shoulder of the catch sleeve 112 and the retainer 114. The housing seals may isolate an annulus formed between the housing 101 and the bearing assembly 110. The catch sleeve 112 may be torsionally coupled to the housing 101, such as by seal friction. The upper retainer 116u may have a landing shoulder and a catch profile formed in an inner surface thereof for retrieval of the bearing assembly 110 by a running tool (not shown).
Alternatively, each of the housing 101 and the sleeve 112 may have mating anti-rotation profiles. Alternatively, each stripper seal 120u,b inner diameter may be equal to or slightly greater than the pipe diameter. Alternatively, the latch may include a spring instead of or in addition to one of the hydraulic ports. Alternatively, the latch actuator may be electric or pneumatic instead of hydraulic. Alternatively, the bearing assembly 110 may be non-releasably connected to the housing 101. Alternatively, the docking station may be located above the waterline 2s and/or along the UMRP 20 at any other location besides a lower end thereof. Alternatively, the docking station may be located at an upper end of the UMRP 20 and the slip joint 23 and bracket connecting the UMRP to the rig may be omitted or the slip joint may be locked instead of being omitted. Alternatively, the docking station may be assembled as part of the riser 25 at any location therealong or as part of the PCA 1p.
Alternatively, an active seal RCD may be used. The active seal RCD may include one or more bladders (not shown) instead of the stripper seals and may be inflated to seal against the drill pipe by injection of inflation fluid. The active seal RCD bearing assembly may also serve as a hydraulic swivel to facilitate inflation of the bladders. Alternatively, the active seal RCD may include one or more packings and the bearing assembly may have one or pistons for selectively engaging the packings with the drill string.
The tachometer 200 may include the base 201 and the probe 210. The base 201 may include an electronics package 203 and a wireless data coupling, such as an antenna 202 and a receiver of the electronics package. The receiver of the electronics package 203 may include an amplifier and a demodulator for processing a signal received from the probe 210. The electronics package 203 may be in communication with the interface 26i via leads or jumper cable (not shown) and further include a relay, such as a modem, for transmitting data received from the probe 210 to the PLC 75 via an electric cable of the RCD umbilical 71. The electronics package 203 may also be supplied with power by the electric cable of the RCD umbilical 71.
The base 201 may be longitudinally and torsionally connected to the housing 101, such as by being disposed in the pocket 118 formed in the upper flange 104u. The pocket 118 may include a receiver portion 118r formed in an outer surface of the upper flange 104u and an antenna portion 118a formed in an inner surface of the upper flange for receiving the respective electronics package 203 and the antenna 202. A receiver cover 204r may seal and retain the electronics package 203 in the receiver pocket portion 118r and an antenna cover 204a may seal and retain the antenna 202 in the antenna pocket portion 118a. One or more fasteners may connect the receiver cover 204r to the upper flange 104u and one or more fasteners may connect the antenna cover 204a to the upper flange. Leads (not shown) may connect the electronics package 203 to the RCD interface 26i.
Alternatively, the base 201 may include a transmitter and power source for wireless communication with the PLC 75 instead of using the RCD umbilical 75.
The probe 210 may include a sensor package 211, a wireless data coupling, such as an antenna 212 and a transmitter 213, and a power source 214. Respective components of the probe 210 may be in electrical communication with each other by leads or a bus. The power source 214 may be a battery. The probe 210 may be longitudinally and torsionally connected to the upper stripper 115u, such as by being disposed in the pocket 117 formed in the upper retainer 116u. The pocket 117 may include a power portion 117p, a transmitter portion 117t, and a sensor portion 117s, each formed in an upper surface of the upper retainer 116u, and an antenna portion 117a formed in an outer surface of the upper retainer for receiving respective components of the probe 210. An upper cover 215u may seal and retain the sensor package 211, transmitter 213, and power source 214 in the respective pocket portions 117s,t,p and an antenna cover 215a may seal and retain the antenna 212 in the antenna pocket portion 117a. One or more fasteners may connect the upper cover 215u to the upper retainer 116u and one or more fasteners may connect the antenna cover 215a to the upper retainer.
Alternatively, the probe battery may be omitted and the probe may be powered using wireless power couplings, further using the data couplings as wireless power couplings, or adding a generator to the tachometer 200 utilizing the rotation of the probe relative to the base to generate electricity. The generator may deliver electricity to the probe and may also allow substitution of a capacitor for the probe battery.
The sensor package 211 may include a microcontroller (MPC) 211m, a data recorder 211d, a clock (RTC) 211c, an analog-digital converter (ADC) 211a, a pressure sensor 211p, an angular speed sensor 211r, a tilt sensor 211v, and an angular acceleration sensor 211t. The data recorder 211d may be a solid state drive. The pressure sensor 211p may be in fluid communication with the fluid passage 121 to monitor integrity of the lower stripper 119b.
The sensors 211r,v,t may each be a single axis accelerometer and may be unidirectional or bidirectional. The accelerometers may be piezoelectric, magnetostrictive, servo-controlled, reverse pendular, or microelectromechanical (MEMS). The tilt sensor 211v may be oriented along a longitudinal axis of the bearing assembly 110 to measure inclination relative to gravitational direction. Tilting of the bearing assembly 110 may be caused by misalignment of the top drive 5 with the UMRP 20, which may shorten the lifespan of the RCD 26. The angular speed sensor 211r may be oriented along a radial axis of the bearing assembly 110 to measure the centrifugal acceleration due to rotation of the bearing assembly for determining the angular speed. The angular acceleration sensor 211t may be oriented along a circumferential axis of the bearing assembly 110. The angular acceleration sensor 211t is depicted as inclined between the radial and longitudinal axes for two-dimensional illustration.
Alternatively, the sensor package 211 may include any subset of the sensors 211p,r,v,t instead of all of the sensors, including a subset of only one thereof. Alternatively, the angular speed 211r sensor may be a proximity sensor, such as a Hall effect sensor. The sensor package 211 may then have a Hall target and the base 201 may then have a Hall receiver. The frequency of the Hall response may then be monitored to determine angular speed and the amplitude of the Hall response may be monitored to determine eccentricity of the bearing assembly rotation. Alternatively, the angular speed sensor 211r may be a magnetometer.
The transmitter 213 may include an amplifier (AMP), a modulator (MOD), and an oscillator (OSC). Raw analog signals from the sensors may be received by the converter 211a, converted to digital signals, and supplied to the controller 211m. The controller 211m may process the converted signals to determine the respective parameters, and send the processed data to the recorder 211d for later recovery should the wireless data coupling fail. The controller 211m may also multiplex the processed data and supply the multiplexed data to the transmitter 213. The transmitter 213 may then condition the multiplexed data and supply the conditioned signal to the antenna 212 for electromagnetic transmission to the base antenna 202, such as at radio frequency. The base antenna 202 may receive the electromagnetic signal from the probe antenna 212 and supply the received signal to the electronics package 203. The electronics package 203 may then relay the received signal to the PLC 75 via the RCD umbilical 71. The probe controller 211m may iteratively monitor the sensors 211p,r,t,v during drilling in real time.
The PLC 75 may display the angular speed, pressure, tilt angle, and angular acceleration for the driller. The PLC 75 may determine both instantaneous angular speed and average angular speed (i.e., using five or more instantaneous measurements) and may display one or both for the driller. The PLC 75 may also compare the angular speed to the angular speed of the drill string 10 (received from the top drive 5) to determine if the bearing assembly 110 is slipping relative to the drill string. The PLC 75 may also monitor the sensor data to determine vibration of the drill string 10, such as stick-slip (torsional vibration) from the angular acceleration data, bit-bounce (longitudinal vibration) from the tilt data, and/or whirl (lateral vibration) from the angular speed and angular acceleration data. The PLC 75 may include predetermined criteria for monitoring health of the RCD 26. The PLC 75 may compare the parameters to the criteria and predict remaining lifespan of the strippers 115u,b and/or bearing pack 111. The remaining lifespan of the strippers 115u,b may be forecasted either collectively or individually and display the prediction to the driller. The PLC 75 may also make recommendations for adjustments to drilling parameters to optimize remaining lifespan of the RCD 26.
Additionally, the probe 210 may include an antenna and receiver for receiving telemetry signals from the drill string 10. The probe 210 may then communicate the signals to the PLC 75 via the base 201.
The riser 25 and LMRP 20 may be filled with liquid when the bearing assembly 110 is installed into the docking station for managed pressure drilling. As such, the antennas 202, 212 may be aligned and adjacently positioned to minimize attenuation of the radio frequency signal transmitted from the probe antenna to the base antenna through the liquid medium. A gap formed between the antennas 202, 212 may be specified, such as between two to four inches.
In response to rotation of the bearing assembly 110 (about longitudinal axis thereof, depicted by 412), inner frame 402 may be caused to move along the Coriolis axis 414. Since the inner frame 402 may be dithered relative to outer frame 404 while being coupled thereto, the inner frame 402 may drive the outer frame along the Coriolis axis 414. The gyro 400 may further include a Coriolis sensor 405 for tracking this movement. The Coriolis sensor 405 may include fingers extending from the outer frame 404 along axes parallel to the dither axes and interdigitated with first and second fixed fingers anchored to the substrate. The first fixed fingers may be connected to a first direct voltage source and the second fixed fingers may be connected to a second direct voltage source having a different voltage. As the outer frame 404 moves relative to the fixed fingers, the voltage on the outer frame changes and the size and direction of movement can be determined.
This sensed Coriolis movement may be communicated to the controller 211m, which may then determine the angular speed of the bearing assembly 110 as follows. If the dither motion is x=X sin(wt), the dither velocity is x′=wX cos(wt), where w is the angular frequency and is directly proportional to the resonant frequency of the inner frame 402 by a factor of 2 pi. In response to an angular rate of motion R about the sensitive axis, a Coriolis acceleration y″=2Rx′ is induced along the Coriolis axis 414. The signal of the acceleration thus has the same angular frequency w as dither velocity x′. By sensing the movement along the Coriolis axis 414, angular speed R can thus be determined.
The dither flexure 430 may have a dither lever arm 432 connected to the outer frame 404 through a dither main flexure 434, and connected to inner frame 402 through pivot flexures 436 and 438. Identical components may be connected through a small central beam 440 to lever arm 432. A central beam 440 may encourage the lever arm 432 and the corresponding lever arm connected on the other side of beam 440 to move in the same direction along dither axis 410. At the other end of lever arm 432, flexures 436 and 438 extend toward inner frame 402 at right angles to each other to create a pivot point near the junction of flexures 436 and 438.
Flexures 436 and 438 may be made long, thereby reducing tension for a given dither displacement. The flexures 436 and 438 may be connected to inner frame 402 at points adjacent to the center of the inner frame in the length and width directions. The two pivoting flexures may be perpendicular to each other. To keep lever arm 432 stiff compared to central beam 440, the lever arm 432 may be made wide.
To reduce the mass of the outer frame 404, a number of holes 444 maybe cut out of outer frame 404. While the existence of holes 444 reduces the mass, they do not have any substantial effect on the stiffness because they create, in effect, a number of connected I-beams. The outer frame 404 may be coupled and anchored to the substrate through a connection mechanism 450 and a pair of anchors 452 that are connected together. Connection mechanism 450 may include plates 453 and 454 connected together with short flexures 456 and 458, which are perpendicular to each other.
The masses and flexures may be made from a semiconductor, such as structural polysilicon. The pivot points may be defined by flexures 456 and 458 so that outer frame 404 can easily move perpendicular to the dither motion by pivoting plate 453 relative to plate 454 thereby giving a single bending action to flexures 456 and 458 at the ends and in the center. To accomplish this, the center beam 440 may be co-linear with the pivot points.
Alternatively, the gyroscope may be any (other) embodiment discussed and/or illustrated in U.S. Pat. No. 6,122,961, which is herein incorporated by reference in its entirety.
The probe 360 may include the sensor package (not shown), a wireless data coupling, such as an antenna 362, the transmitter 363 (similar to transmitter 213), and the power source (not shown, see power source 214). The sensor package of the probe 360 may be similar to the sensor package 211 except for the substitution of a temperature sensor 311t for the pressure sensor 211p. The temperature sensor 311t may be in fluid communication with the bearing lubricant reservoir to monitor performance of the bearing assembly 111. Components of the probe 360 may be in electrical communication with each other by leads or a bus. The probe 360 may be longitudinally and torsionally connected to the catch sleeve 112, such as by the sensor package, transmitter, and power source being disposed in a pocket formed in a seal retainer 314 (the seal retainer may be connected to the sleeve 112, such as by threaded couplings) and the antenna 352 being disposed in a groove formed in an inner surface of the seal retainer.
Since the probe 360 remains torsionally still relative to the strippers, the antennas may be circumferential instead of corresponding to a shape of the respective pocket. The PLC 75 may utilize the still measurements from the probe 360 to distinguish vibration components from the tachometer measurements. Further, the tilt measurement from the still probe 360 may be utilized by the PLC 75 in favor of the tachometer tilt measurement. The still probe 360 may also be utilized during installation of the bearing assembly 310. The bearing assembly 310 may be installed by being carried on the running tool assembled as part of the drill string 10. As the bearing assembly 310 enters the housing 301, the probe 360 may emit a homing signal. Detection of the homing signal by the tachometer receiver may establish a first reference point thereto and detection of the homing signal by the data sub receiver may establish a second reference point thereto. Further, the homing signals may be time stamped and detection lag time may be used from one or both receivers to pinpoint location of the bearing assembly 310 relative to the housing 110.
While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.
Claims
1. A rotating control device (RCD) for use with an offshore drilling unit, comprising:
- a tubular housing having a flange formed at each end thereof;
- a stripper seal for receiving and sealing against a tubular;
- a bearing for supporting rotation of the stripper seal relative to the housing;
- a retainer for connecting the stripper seal to the bearing; and
- a tachometer, comprising: a probe connected to the retainer and comprising: a tilt sensor; an angular speed sensor; an angular acceleration sensor; a first wireless data coupling; and a microcontroller operable to receive measurements from the sensors and to transmit the measurements to a base using the first wireless data coupling; the base connected to the housing and comprising: a second wireless data coupling operable to receive the measurements; and an electronics package in communication with the second wireless data coupling and operable to relay the measurements to the offshore drilling unit.
2. The RCD of claim 1, wherein:
- the stripper seal is an upper stripper seal,
- the retainer is an upper retainer, and
- the RCD further comprises a lower stripper seal and a lower retainer for connecting the lower stripper seal to the bearing.
3. The RCD of claim 2, wherein the tachometer further comprises a pressure sensor in communication with a pathway for measuring pressure between the stripper seals.
4. The RCD of claim 1, wherein the probe further comprises a battery.
5. The RCD of claim 1, wherein the sensors are accelerometers.
6. The RCD of claim 1, wherein the angular speed sensor is a gyroscope, comprising:
- an outer frame;
- an inner frame;
- a dither driver operable to dither the inner frame relative to the outer frame; and
- a Coriolis sensor for tracking movement of the outer frame.
7. The RCD of claim 1, wherein:
- the stripper seal, bearing, and retainer are part of a bearing assembly,
- the bearing is part of a bearing pack having a self contained lubricant system,
- the bearing assembly further comprises a catch sleeve,
- the housing is part of a docking station, and
- the docking station further comprises a latch operable to engage the catch sleeve, thereby fastening the bearing assembly to the docking station.
8. The RCD of claim 7, further comprising a data sub, comprising:
- a second probe connected to the catch sleeve and comprising: a second tilt sensor; a temperature sensor in fluid communication with the lubricant system; a third wireless data coupling; and a second microcontroller operable to receive measurements from the second tilt and temperature sensors and to transmit the measurements to a second base using the third wireless data coupling; the second base connected to the housing and comprising: a fourth wireless data coupling operable to receive the measurements; and an electronics package in communication with the fourth wireless data coupling and operable to relay the measurements to the offshore drilling unit.
9. The RCD of claim 8, wherein:
- the second tilt sensor is a first accelerometer,
- the second probe further comprises second and third accelerometers, and
- the accelerometers are triaxially oriented.
10. A method for drilling a subsea wellbore using the RCD of claim 1, comprising:
- injecting drilling fluid down a drill string while rotating the drill string having a drill bit located at a bottom of the subsea wellbore,
- wherein the RCD is engaged with the drill string, thereby diverting returns from the wellbore to an outlet of the RCD; and
- monitoring the measurements while drilling the wellbore.
11. The method of claim 10, wherein the measurements are monitored by forecasting a remaining lifespan of the stripper seal.
12. The method of claim 11, wherein the lifespan is forecast using the tilt measurement.
13. The method of claim 11, further comprising adjusting a drilling parameter to optimize the remaining lifespan.
14. The method of claim 10, wherein the measurements are monitored by comparing the angular speed of the RCD to the angular speed of the drill string.
15. The method of claim 10, wherein the measurements are monitored by determining vibration of the drill string.
16. The method of claim 15, wherein the determined vibration includes stick-slip, bit-bounce, and whirl.
17. The method of claim 10, further comprising exerting backpressure on the returns.
18. The method of claim 10, further comprising, while drilling the wellbore:
- measuring a flow rate of the drilling fluid;
- measuring a flow rate of the returns; and
- comparing the returns flow rate to the drilling fluid flow rate to ensure control of an exposed formation adjacent to the wellbore.
Type: Application
Filed: Sep 12, 2013
Publication Date: Mar 13, 2014
Applicant: Weatherford/Lamb, Inc. (Houston, TX)
Inventor: Kevin L. GRAY (Houston, TX)
Application Number: 14/025,431
International Classification: E21B 19/24 (20060101); E21B 19/00 (20060101); E21B 7/12 (20060101);
