Note: Descriptions are shown in the official language in which they were submitted.
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TACHOMETER FOR A ROTATING CONTROL DEVICE
BACKGROUND OF THE DISCLOSURE
Field of the Disclosure
[0ool] The present disclosure generally relates to a tachometer for a
rotating
control device.
Description of the Related Art
[0002] 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.
[0003] 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 DISCLOSURE
[0004] The present disclosure generally relates to a tachometer for a
rotating
control device. In one embodiment, a rotating control device (ROD) 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
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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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] 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.
[0006] Figures 1A-1C illustrate a drilling system utilizing a rotating
control device,
according to one embodiment of the present disclosure.
[0007] Figure 2 illustrates the rotating control device.
[0oos] Figures 3A and 3B illustrate a tachometer of the rotating control
device.
[0009] Figure 4A illustrates a pocket formed in a stripper retainer of
the rotating
control device for receiving a probe of the tachometer. Figures 4B and 40
illustrate a
pocket formed in a flange of the rotating control device for receiving a base
of the
tachometer.
[0olo] Figure 5 illustrates a probe of the tachometer.
[0011] Figures 6A and 6B illustrate a gyroscope usable with the probe,
according
to another embodiment of the present disclosure.
[0012] Figure 7 illustrates a rotating control device having a data sub,
according to
another embodiment of the present disclosure.
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DETAILED DESCRIPTION
[0013] Figures 1A-1C illustrate a drilling system 1 utilizing a rotating
control device
(ROD) 26, according to one embodiment of the present disclosure. The drilling
system 1 may include a mobile offshore drilling unit (MODU) 1m, such as a semi-
submersible, a drilling rig 1r, a fluid handling system 1h, a fluid transport
system it, a
pressure control assembly (PCA) 1p, and a drill string 10. The MODU 1m may
carry
the drilling rig 1r and the fluid handling system 1h aboard and may include a
moon
pool, through which drilling operations are conducted. The semi-submersible
MODU
1m may include a lower barge hull which floats below a surface (aka waterline)
2s of
sea 2 and is, therefore, less subject to surface wave action. Stability
columns (only
one shown) may be mounted on the lower barge hull for supporting an upper hull
above the waterline. The upper hull may have one or more decks for carrying
the
drilling rig 1r and fluid handling system 1h. The MODU 1m may further have a
dynamic positioning system (DPS) (not shown) or be moored for maintaining the
moon pool in position over a subsea wellhead 50.
[0014] 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.
[0015] 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
loinked 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.
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[0016] 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 lm. 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).
[0017] 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.
[0018] The fluid transport system it 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 (ROD) 26. A lower end of the ROD 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 ROD 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.
[0019] 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 lm 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 lp to the MODU
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im 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.
[0020] 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.
[0021] 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.
[0022] The PCA lp may include a wellhead adapter 40b, one or more flow
crosses
41u,m,b, one or more blow out preventers (B0P5) 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 lm relative to the
riser
25 and the riser relative to the PCA lp.
[0023] 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
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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.
[0024] 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 lp via the umbilical 70 and the control pod 76.
[0025] 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.
[0026] 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.
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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.
[0027] 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.
[0028] 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 260 of the ROD 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.
[0029] 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.
[0030] Alternatively, the choke actuator may be electrical or pneumatic.
[0031] 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
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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.
[0032]
Alternatively, the supply flow meter 34d may be a mass flow meter or a
stroke counter of the mud pump 30.
[0033]
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.
[0034] 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
ROD 26. The returns 60r may be diverted by the ROD 26 into the return line 29
via
the ROD outlet 260. 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.
[0035] 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
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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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
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[0040] 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.
[0041] 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.
[0042] 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.
[0043] Alternatively, the ROD 26 may be used with a riserless drilling
system. The
ROD 26 may then be assembled as part of a riserless package connected to the
annular BOP 47a and the return line 29 and ROD 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.
[0044] Figure 2 illustrates the ROD 26. The ROD 26 may include a docking
station, a bearing assembly 110, and a tachometer 200. The docking station may
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located adjacent to the waterline 2s and may be submerged. The docking station
may include the outlet 260 (not shown, see Figure 1A), an interface 26i (not
shown,
see Figure 1A), a housing 101, and a latch 102, 103, 105. The housing 101 may
be
tubular and include one or more sections 101a-c connected together, such as by
flanged connections. The housing 101 may further include an upper flange 104u
connected to an upper housing section 101a, such as by welding, and a lower
flange
104f connected to a lower housing section 101c, such as by welding. The upper
flange 104u may connect the docking station to the slip joint 23 and the lower
flange
may connect the housing 101 to the outlet 260.
[0045] 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.
[0046] 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 ROD umbilical 71 (not shown, see Figure 1A) may have hydraulic conduits and
may provide fluid communication between the ROD interface 26i and the HPU of
the
PLC 75.
[0047] 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
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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.
[0048] 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 ROD 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.
[0049] 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.
[0050] 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
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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.
[0051] 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).
[0052] 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 lp.
[0053] Alternatively, an active seal ROD may be used. The active seal
ROD 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 ROD
.. bearing assembly may also serve as a hydraulic swivel to facilitate
inflation of the
bladders. Alternatively, the active seal ROD may include one or more packings
and
the bearing assembly may have one or pistons for selectively engaging the
packings
with the drill string.
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[0054] Figures 3A and 3B illustrate the tachometer 200. Figure 4A
illustrates a
pocket 117 formed in the upper retainer 116u for receiving a probe 210 of the
tachometer 200. Figures 4B and 40 illustrate a pocket 118 formed in the upper
flange 104u for receiving a base 201 of the tachometer 200. Figure 5
illustrates the
probe 210.
[0055] 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 ROD umbilical 71. The
electronics package 203 may also be supplied with power by the electric cable
of the
ROD umbilical 71.
[0056] 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 ROD interface 26i.
[0057] Alternatively, the base 201 may include a transmitter and power
source for
wireless communication with the PLC 75 instead of using the ROD umbilical 75.
[0058] 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
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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.
[0059] 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.
[0060] 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.
[0061] 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 ROD 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
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211t is depicted as inclined between the radial and longitudinal axes for two-
dimensional illustration.
[0062] 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.
[0063] 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 ROD umbilical 71. The probe controller 211m may iteratively
monitor
the sensors 211p,r,t,v during drilling in real time.
[0064] 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
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vibration) from the angular speed and angular acceleration data. The PLC 75
may
include predetermined criteria for monitoring health of the ROD 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 ROD 26.
[0065] 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.
[0066] 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.
[0067] Figures 6A and 6B illustrate a gyroscope 400 usable with the
probe 110,
according to another embodiment of the present disclosure. The gyroscope 400
may
be used as the angular speed sensor 211r instead of the accelerometer,
discussed
.. above. The gyroscope 400 may have an inner frame 402 surrounded by an outer
frame 404. Inner frame 402 may be dithered along a dither axis 410 through the
use
of a dither driver 406. The dither driver 406 may be formed with combs of
drive fingers
that interdigitate with fingers on the inner frame 402 and may be driven with
alternating voltage signals to produce sinusoidal motion. The voltage signal
may be
.. supplied by a modulator (not shown) and the voltage may be supplied at a
frequency
corresponding to a resonant frequency of the inner frame 402. The inner frame
402
may have one or more, such as four, elongated and parallel apertures that
include the
drive fingers. A dither sensor 408 may be formed by one or more, such as four,
corners of inner frame 402 having apertures that have dither pick-off fingers
for
.. sensing the dithering motion. The sensed dithering motion may be used as
feedback
control for the dither driver 406.
[0068] 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
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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.
[0069] 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=Xsin(wt), the dither velocity is
x'=wXcos(wt), where w
is the angular frequency and is directly proportional to the resonant
frequency of the
inner frame 402 by a factor of 2pi. 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.
[0070] Figure 6B shows one-quarter of gyro 400. The other three quarters of
the
gyro 400 may be substantially identical to the portion shown. A dither flexure
mechanism 430 may be coupled between inner frame 402 and outer frame 404 to
allow inner frame 402 to move along dither axis 410, but to prevent inner
frame 402
from moving along Coriolis axis 414 relative to outer frame 404, but rather to
move
along Coriolis axis 414 only with outer frame 404.
[0071] 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.
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[0072] 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.
[0073] 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.
[0074] 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.
[0075] 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.
[0076] Figure 7 illustrates an RCD 326 having a data sub 350, according
to
another embodiment of the present disclosure. The RCD 326 may be similar to
the
RCD 26 except for the inclusion of the data sub 350. The data sub 350 may
include a
base 351 and a probe 360. The base 351 may include an electronics package 353
(similar to electronics package 203) and a wireless data coupling, such as an
antenna
352 and a receiver of the electronics package. The base 351 may be
longitudinally
and torsionally connected to the housing 301, such as by the receiver 353
being
disposed in a pocket formed in an upper flange of a lower housing section 301c
and
the antenna 352 being disposed in a groove formed in an inner surface of the
lower
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housing section. A jumper cable (not shown) may connect the receiver 353 to
the
ROD interface 26i.
[0077] 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.
[0078] 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.
[0079] 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.
