Note: Descriptions are shown in the official language in which they were submitted.
CA 02672658 2013-10-11
System for steering a drill string
BACKGROUND OF THE INVENTION
This invention relates to drill bits, specifically drill bit assemblies for
use in oil,
gas, geothermal, and horizontal drilling. The ability to accurately adjust the
direction of
drilling in downhole drilling applications is desirable to direct the borehole
toward
specific targets. A number of steering systems have been devised for this
purpose.
One such system is disclosed in U.S. Patent No. 5,803,185. It discloses a
steerable
rotary drilling system with a bottom hole assembly which includes, in addition
to the drill
bit, a modulated bias unit and a control unit, the bias unit comprising a
number of
hydraulic actuators around the periphery of the unit, each having a movable
thrust
member which is hydraulically displaceable outwardly for engagement with the
formation of the borehole being drilled. Each actuator may be connected,
through a
control valve, to a source of drilling fluid under pressure and the operation
of the valve is
controlled by the control unit so as to modulate the fluid pressure supplied
to the
actuators as the bias unit rotates. If the control valve is operated in
synchronism with
rotation of the bias unit the thrust members impart a lateral bias to the bias
unit, and
hence to the drill bit, to control the direction of drilling.
BRIEF SUMMARY OF THE INVENTION
In one aspect of the present invention, a drill bit assembly has a body
portion
intermediate a shank portion and a working portion. The working portion has at
least one
cutting element and at least a portion of a shaft is disposed within the body
portion and
protrudes from the working portion. The shaft has a distal end rotationally
isolated from
the body portion and is in communication with a subterranean formation. A
motor is
adapted to rotationally control the distal end.
- I -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
The motor may be an electric motor, a hydraulic motor, a positive displacement
motor, or combinations thereof. the electric motor is a stepper motor, an AC
motor, a
universal motor, a three-phase AC induction motor, a three-phase AC
synchronous
motor, a two-phase AC servo motor, a single-phase AC induction motor, a single-
phase AC synchronous motor, a torque motor, a permanent magnet motor, a DC
motor, a brushless DC motor, a coreless DC motor, a linear motor, a doubly- or
singly- fed motor, or combinations thereof The motor may be powered by a
turbine, a
battery, or a power transmission system from the surface or downhole.
The motor may be in communication with a downhole generator. The generator
may have magnets made of samarium cobalt.
A gear assembly may be intermediate and in communication with the shaft and
the motor. The shaft may be in communication with the motor through a second
gear
assembly. The second gear assembly may be a planetary gear system. The second
gear assembly may have a gear ratio of at least 2:1.
The shaft may protrude from the working portion 6 to 20 inches. A sensor
disposed within the drill bit assembly may measure the orientation of the
shaft with
respect to the drill bit assembly. The distal end may be asymmetric.
A sensor secured to the drill bit assembly may measure and maintains the
orientation of the drill bit assembly with respect to a subterranean
formation. The
sensor may be a gyroscope, an inclinometer, a magnetometer or combinations
thereof
The drill bit assembly may be in communication with a downhole telemetry
system.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 is a cross-sectional diagram of an embodiment of a drill string
suspended in
a bore hole.
Fig. 2 is a cross-sectional diagram of an embodiment of a drill bit assembly.
Fig. 3 is a cross-sectional diagram of another embodiment of a drill bit
assembly.
Fig. 4 is a cross-sectional diagram of an embodiment of a portion of a tool
string.
- 2 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
Fig. 5 is a sectional diagram of an embodiment of a gear assembly in a
downhole
tool string component.
Fig. 6 is a schematic diagram of an embodiment of a generator in communication
with a load.
Fig. 7 is a schematic diagram of another embodiment of a generator in
communication with a load.
Fig. 8 is a cross-sectional diagram of another embodiment of a portion of a
drill
bit assembly.
Fig. 9 is a sectional diagram of another embodiment of a gear assembly in a
drill
bit assembly.
Fig. 10 is a cross-sectional diagram of another embodiment of a drill string
suspended in a bore hole.
Fig. 11 is a perspective diagram of various embodiments of a drilling rig.
Fig. 12 is a perspective diagram of an embodiment of a distal end of a shaft.
Fig. 13 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 14 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 15 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 16 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 17 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 18 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 19 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 20 is a perspective diagram of another embodiment of a distal end of a
shaft.
Fig. 21 is a perspective diagram of another embodiment of a distal end of a
shaft.
DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED
EMBODIMENT
- 3 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
Fig. 1 is an embodiment of a drill string 100 suspended by a derrick 101. A
bottom-hole assembly 102 and/or drill bit assembly 102 is located at the
bottom of a
bore hole 103 and comprises a drill bit 104. As the drill bit 104 rotates
downhole the
drill string 100 advances farther into the earth. The drill string may
penetrate soft or
hard subterranean formations 105. The drill bit assembly may comprise data
acquisition devices which may gather data. The data may be sent to the surface
via a
transmission system to a data swivel 106. The data swivel 106 may send the
data to
the surface equipment. Further, the surface equipment may send data and/or
power to
downhole tools and/or the drill bit assembly 102.
Fig. 2 discloses a cross-sectional diagram of the drill bit assembly 102. The
drill
bit assembly may comprise a mud turbine 201, a battery 201 or a power
transmission
system from the surface or downhole used to power electronic instrumentation
devices
and tools disposed in the drill bit assembly 102. The turbine 201 may be in
communication with power generators 203 creating a power supply for the drill
bit
assembly 102 and drill string 100. The drill bit assembly 102 may also
comprise power
converters 204 to adapt the electrical output of the power source 201 to an AC
power
source.
The drill bit assembly 102 may also comprise a steering motor 205 adapted to
rotationally control a shaft 202 disposed within a body portion 209 of the
drill bit 104
and protrudes from a working portion 210 of the drill bit 104. The shaft 202
may
protrude from the working portion 210 6 to 20 inches. The shaft 202 may
comprise a
distal end 211 rotationally isolated from the body portion 209 and in
communication
with the subterranean formation 105. The shaft 202 and its distal end 211 may
be
utilized to steer the drill bit assembly 102 and drill string 100 through the
formation
105.
The motor 205 may be an electric motor, a hydraulic motor, a positive
displacement motor, or combinations thereof The electric motor may be a
stepper
motor, an AC motor, a universal motor, a three-phase AC induction motor, a
three-
- 4 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
phase AC synchronous motor, a two-phase AC servo motor, a single-phase AC
induction motor, a single-phase AC synchronous motor, a torque motor, a
permanent
magnet motor, a DC motor, a brushless DC motor, a coreless DC motor, a linear
motor,
a doubly- or singly- fed motor, or combinations thereof. The drill bit
assembly 102 may
comprise a steering motor control 204 adapted to provide control of the motor
205. A
sensor may be disposed within the drill bit assembly 102 to measure the
orientation of
the shaft 202 with respect to the drill bit assembly 102.
The drill bit assembly may also comprise a gear assembly 206 to control the
rpm
of the shaft 202. Inclination and direction sensors 207 may also be disposed
within the
drill bit assembly to detect and measure the location of the drill bit
assembly 102
downhole. The direction sensors 207 may also maintain the orientation of the
drill bit
assembly with respect to a subterranean formation 105. The sensors 207 may be
gyroscopes, inclinometers, magnetometers or combinations thereof. A telemetry
network liffl( 208 may also be disposed within the drill bit assembly 102.
Figs. 3 and 4 disclose an alternative embodiment of the present invention. The
drill bit assembly 102 may comprise a first rotor 300 disposed within a bore
301 of the
drill bit assembly 102 adjacent to the drill bit 104, which is in
communication with the
shaft 202. The first rotor 300 may be part of the turbine 201, though the
first rotor 300
may also be part of a motor. The turbine 201 preferably comprises from 3 to 5
impellers 304 fixed to the first rotor. A plurality of stator vanes 305
adjacent each of
the impellers 304 may be rotationally fixed with respect to the bore of the
assembly
102. A second gear assembly 210 connects the second rotor 307 to the first
rotor 300.
The second gear assembly may comprise a gear ratio of at least 2:1. The second
gear
assembly 210 may be adapted to rotate the second rotor 307 faster than the
first rotor
300. As drilling fluid passes through the turbine 201 in the bore 301, the
impellers 304
rotate, spinning the second gear assembly 210 and the first and second rotors.
Preferably the first and second rotors will rotate at different speeds,
preferably the
second rotor 307 will rotate 1.5 to 8 times faster. The stator vanes 305 in
the turbine
- 5 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
201 may help increase the efficiency of the turbine 201 by redirecting the
flow of the
drilling fluid by preventing the fluid from flowing in a circular path down
the bore 301
of the drill string 100.
The second rotor 307 may be a part of an electric generator 308. The electric
generator 308 also comprises a stator surrounding the second rotor 307. The
stator may
comprise an electrically conductive coil with 1 to 50 windings. One such
generator 308
which may be used is the Astro 40 from AstroFlight, Inc. The generator 308 may
comprise separate magnetic strips disposed along the outside of the rotor 307
which
magnetically interact with the coil as it rotates, producing a current in the
electrically
conductive coil. The magnetic strips are preferably made of samarium cobalt
due to its
high curie temperature and high resistance to demagnetization.
The coil is in communication with a load. When the load is applied, power is
drawn from the generator 308, causing the second rotor 307 to slow its
rotation, which
thereby slows the rotation of the turbine 201 and the first rotor 300. Thus
the load may
be applied to control the iotation of the downhole turbine 201. Since the
second rotor
307 rotates faster than the first rotor 300, it produces less torque whereby
less electrical
current from the load is required to slow its rotation. Thus the second gear
assembly
210 provides the advantage of reducing the electrical power requirements to
control the
rotation of the turbine 201. This is very beneficial since downhole power is a
challenge
to generate and store downhole.
There may also be a second generator 409 connected to the first generator 308
in
order to create more current or to aid in the rotation of the first generator
308. The load
may be a resistor, nichrome wires, coiled wires, electronics, or combinations
thereof.
The load may be applied and disconnected at a rate at least as fast as the
rotational
speed of the second rotor 307.
The electrical generators 308, 409 may be in communication with the load as
part
of electrical circuitry 401. The electrical circuitry 401 may be disposed
within the bore
wall 402 of the drill bit assembly 102. The generator 308 may be connected to
the
- 6 -
CA 02672658 2013-10-11
electrical circuitry 401 through a coaxial cable 403. The circuitry 401 may be
part of a
closed-loop system. The electrical circuitry 401 may also comprise sensors for
monitoring various aspects of the drilling, such as the rotational speed or
orientation of
the drill bit assembly 102 with respect to the formation 105. Sensors may also
measure
the orientation of the generator 308 with respect to the drill bit assembly
102.
The data collected from these sensors may be used to adjust the rotational
speed
of the turbine 201 in order to control the shaft 202 and its distal end 211.
The distal end
211 may comprise an asymmetric tip which may be used to steer the drill bit
104 and
therefore the drill string 101. The control of the turbine 201 controls the
speed and
orientation of the distal end 211 and therefore the drilling trajectory. The
shaft 202 may
be connected to the first rotor 300 through the gear assembly 206, which may
rotate the
shaft 202 in the opposite direction as the turbine 201 is rotating. Thus with
the help of
controlling the turbine's 201 rotational speed, the shaft 202 may be made to
rotate with
respect to the drill string 100 while being substantially stationary with
respect to the
formation 105 being drilled and allowing the distal end 211 to steer the drill
string 100.
The load may be in communication with a downhole telemetry system 404. One
such system is the IntelliServ system disclosed in U.S. Patent No. 6,670,880.
Data
collected from sensors or other electrical components downhole may be sent to
the
surface through the telemetry system 404. The data may be analyzed at the
surface in
order to monitor conditions downhole. Operators at the surface may use the
data to alter
drilling speed if the drill bit assembly 102 encounters formations 105 of
varying hardness.
Other types of telemetry systems 404 may include mud pulse systems,
electromagnetic
wave systems, inductive systems, fiber optic systems, direct connect systems,
wired pipe
systems, or any combinations thereof. In some embodiments, the sensors may be
part of a
feed back loop which controls the logic controlling the load. In such
embodiments,
the drilling may be automated and electrical equipment may comprise sufficient
intelligence to avoid potentially harsh drilling formations 105 while keeping
the drill
- 7 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
string 100 on the right trajectory. In some embodiments, drilling may be fully
automated where the desired trajectory and location of the pay load is
programmed into
the electrical equipment and allowed to run itself without the need for manual
controls.
Stabilizers 312 may be disposed around the shaft 202 and within the bore 301
of
the drill bit 104 or drill bit assembly 102, which may prevent buckling or de-
centralizing of the shaft 202.
The turbine 201, gear assemblies 206, 210, and/or generators 308, 409 may be
disposed within a protective casing 3 15 within the bore 301 of the drill bit
assembly
102. The casing 315 is secured to the bore wall 402 such that anything
disposed within
may be axially fixed with respect to the center of the bore 301. The casing
315 may
comprise passages at locations where it is connected to the bore wall 402 such
that the
drilling fluid may be allowed to pass through.
The second gear assembly 210 in the embodiment of Fig. 5 is a planetary gear
system which may be used to connect the shaft 202 to the first rotor 300. The
planetary
gear system comprises a central gear 500 which is turned by the first rotor
300
connected to the turbine 201. As the central gear 500 rotates, a plurality of
peripheral
gears 501 surrounding and interlocking the central gear 500 rotate, which in
turn cause
an outer gear ring 502 to rotate. The rotational speed ratio from the central
gear 500 to
the outer gear ring 502 depends on the sizes of the central gear 500 and the
plurality of
peripheral gears 501. The second gear assembly 210 also comprises a support
member
503 for the purpose of maintaining the peripheral gears 501 axially
stationary.
The planetary gear system is disposed within the casing 315 such that there is
a
gap 504 between the outer gear ring 502 and the casing 315 so that the war
ring 502
may rotate. The casing 3 15 may also comprise an inner bearing surface 505
such that
the second gear assembly 210 and the casing 315 may be flush with the war ring
502
and may still rotate. The casing 315 may also comprise a plurality of passages
506
wherein drilling fluid may pass through the bore 301 of the drill bit assembly
102.
- 8 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
Referring now to Fig. 6, the load 600 is a resistor in an electrical circuit
401 which
is electrically connected to the generator 308. The rotation of the generator
308
produces an AC voltage across the two generator terminals 601, 602. The
circuit
comprises a bridge rectifier 603, which converts the AC voltage into a DC
voltage. The
circuit also comprises a DC switch 604, such as a field-effect transistor
(FET), which is
driven by logic instructions 605 that turn it on or off. When the DC switch
604 is on,
the circuit is completed, causing the DC voltage to drop across the load 600
and
drawing power from the generator 308, which thereby causes the rotational
speed of
the generator 308 to slow. When the DC switch 604 is off, however, the circuit
is an
open circuit and no power is drawn from the generator 308. A FET switch may be
a
low cost option for completing the circuit, though it requires DC currents to
operate.
Fig. 7 shows another embodiment of a circuit comprising an AC switch 700. The
AC switch 700 may be a triode for alternating current (triac), which allows
the load to
be turned on or off with AC current. The triac may switch whenever the AC
voltage
crosses zero, which may happen at half cycles of the generator 308 output,
depending
on the logic instructions 605 driving the switch. An AC switch 700 alternative
to the
triac is an insulated gate bipolar transistor (IGBT). An advantage to using an
IGBT is
that the IGBT is able to switch on and off at a rate independent of the cycle
period or
zero crossing of the AC voltage from the generator 308, though the IGBT is
more
expensive and complex than the triac.
Referring to Fig. 8, the distal end 211 is adapted such that it may be used as
a
steering system for the drill string 100. The distal end 211 may comprise an
asymmetric tip such that one side 801 has more surface area exposed to the
formation
105. The gear assembly 206 is adapted such that the rotational speed of the
turbine 201
is from 10 to 25 times faster than the rotational speed of the distal end 211.
As the drill
string rotates, the turbine 201 may rotate such that the distal end 211
remains
rotationally stationary with respect to the formation 105. When the distal end
211 is
engaged against the formation 105 and is rotationally stationary with respect
to the
- 9 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
formation 105, it is believed that the asymmetry of the distal end 211 will
deviate the
direction of the drill string 100. The orientation of the distal end 211 may
be adjusted
by the logic which is h communication with the load. The sensors may indicate
the
position of the distal end 211 and through a feed back loop the logic may
adjust the
load to reorient the distal end 211. With such a method, the complex drilling
trajectories are possible. By causing the distal end 211 of the shaft 202 to
rotate with
the drill bit 104, it is believed to cause the drill string 100 to drill in a
generally straight
direction.
Referring to Fig. 9, the second gear assembly 210 may comprise spur gears. A
first spur gear 900 may be attached to the first rotor 300 and be in
communication with
a second spur gear 901. The second spur 901 gear may be attached to an
intermediate
shaft 902 supported by the casing 315. The second shaft 902 may also comprise
a third
gear 903 which is in communication with a fourth gear 904 attached to the
second rotor
307. The sizes of the gears are adapted such that the second rotor 307 rotates
faster
than the first rotor 300. The casing 315 and/or the intermediate shaft 902 may
comprise
bearing surfaces 905 to reduce friction where the casing 315 supports the
intermediate
shaft 905.
Referring now to Fig. 10, a drill string 100 may be suspended by a derrick
101. A
drill bit assembly 102 is located at the bottom of a wellbore 103 and
comprises a drill
bit 104. As the drill bit 104 rotates downhole the drill string 100 advances
farther into
the earth. The drill string 100 may be steered in a preferred direction. In
some
embodiments, a sensor 207 may be disposed on drill string assembly 102 and may
be
adapted to receive acoustic signals 1001 produced by the drill bit 104. The
acoustic
signals 1001 produced by the drill bit 104 may be returned from the formation
105.
This may be useful in determining different formation 105 characteristics.
Fig. 11 illustrates embodiments of drilling rigs used in various steering
applications. In one embodiment, a drilling rig 1100 may be positioned so that
a
directional relief wellbore 1155 may be drilled to intersect another well 1150
in case of
- 10 -
CA 02672658 2009-06-12
WO 2008/076625
PCT/US2007/086323
an emergency, such as a blowout, in order to reduce subsurface pressure in a
controlled
manner. A drilling rig 1110 may be used in a drilling application in which
multiple
reservoirs 1140, such as oil or gas reservoirs, are located approximately
along a vertical
trajectory. In such circumstances, it may be beneficial to drill in a
substantially straight
trajectory 1151 adjacent the reservoirs 1140 and from the substantially
straight
trajectory 1151, drill multiple trajectories 1152 branching off the main
trajectory 1151
toward the reservoirs 1140. Also, it may be necessary during a drilling
operation for a
wellbore 1115 to be formed around obstacles 1103 such as boulders, hard
formations,
salt formations, or low pressure regions. Multiple reservoirs 1160 may be
reached with
one drilling rig 1120 when using a steerable drill string. A wellbore 1125 may
be
drilled toward a first reservoir. If other wellbores are located near the
first wellbore, the
steering capabilities of the drill string may allow each reservoir to be
drilled without
removing the drill string and repositioning the drilling rig 1120 for each
drilling
operation. In some situations, a reservoir 1170 may be located beneath a
structure 1101
such that a drilling rig 1130 cannot be positioned directly above the
reservoir and drill
a straight trajectory. Thus, a wellbore 1135 may need to be formed adjacent
the
structure 1101 and follow a curved trajectory toward the reservoir using the
steering
capabilities of the drill string. Such tool string may be equipped to drill in
off-shore
applications as well as on-shore applications.
Figs. 12 through 15 illustrate embodiments of various distal ends 211. Fig. 12
shows a primary deflecting surface 1206 having a slightly convex geometry
1200. In
the embodiment of Fig. 13, the primary surface 1206 may comprise a flat
geometry
1300. In Fig. 14, the distal end 211 may also have a slightly convex geometry
1400,
but may comprise a greater radius of curvature than the embodiment shown in
Fig. 12.
The primary deflecting surface may comprise a .750 to 1.250 inch radius. It is
believed
that a convex geometry 1400 will allow the distal end 211 to crush the
formation 105
through point loading, verses through surface loading which may occur in
embodiments with flats. It is believed that point loaded is preferred for
steering
- 11-
CA 02672658 2013-10-11
applications. Fig. 15 shows a primary surface 1206 having a slightly concave
geometry
1500. The distal end 211 may have a polygonal shape along its length.
Fig. 16 shows an asymmetric distal end 211 with a substantially flat surface
1600,
the surface 1600 intersecting a central axis 1601 of the shaft 202 at an angle
1602
between 1 and 89 degrees. Ideally, the angle 1602 is within 30 to 60 degrees.
Fig. 17
shows an asymmetric geometry of the distal end 211 comprising a cut 1701. The
cut 1701
may be concave, convex, or flat. Fig. 18 shows a geometry of a flat face 1800
with an
offset protrusion 1801. The embodiment of Fig. 19 shows an offset protrusion
1801 with
a flat face 1900. The asymmetric geometry of Fig. 20 is generally triangular.
In other
embodiments, the asymmetric geometry may be generally pyramidal. Fig. 21 shows
an
asymmetric geometry of a generally triangular 2100 distal end 211 with a
concave side
2101.
Whereas the present invention has been described in particular relation to the
drawings attached hereto, it should be understood that other and further
modifications
apart from those shown or suggested herein, may be made within the scope of
the present
invention.
- 12 -
