Note: Descriptions are shown in the official language in which they were submitted.
DRILL BIT BIT WITH SELF-ADJUSTING PADS
TECHNICAL FIELD
This disclosure relates generally to drill bits and systems that utilize same
for
drilling wellbores.
BACKGROUND
Oil wells (also referred to as "wellbores" or "boreholes") are drilled with a
drill string that includes a tubular member having a drilling assembly (also
referred
to as the "bottomhole assembly" or "BHA"). The BHA typically includes devices
and sensors that provide information relating to a variety of parameters
relating to
the drilling operations ("drilling parameters"), behavior of the BHA ("BHA
parameters") and parameters relating to the formation surrounding the wellbore
("formation parameters"). A drill bit attached to the bottom end of the BHA is
rotated by rotating the drill string and/or by a drilling motor (also referred
to as a
"mud motor") in the BHA to disintegrate the rock formation to drill the
wellbore. A
large number of wellbores are drilled along contoured trajectories. For
example, a
single wellbore may include one or more vertical sections, deviated sections
and
horizontal sections through differing types of rock formations. When drilling
progresses from a soft formation, such as sand, to a hard formation, such as
shale, or
vice versa, the rate of penetration (ROP) of the drill changes and can cause
(decreases or increases) excessive fluctuations or vibration (lateral or
torsional) in
the drill bit. The ROP is typically controlled by controlling the weight-on-
bit
(WOB) and rotational speed (revolutions per minute or "RPM") of the drill bit
so as
to control drill bit fluctuations. The WOB is controlled by controlling the
hook load
at the surface and the RPM is controlled by controlling the drill string
rotation at the
surface and/or by controlling the drilling motor speed in the BHA. Controlling
the
drill bit fluctuations and ROP by such methods requires the drilling system or
operator to take actions at the surface. The impact of such surface actions on
the
drill bit fluctuations is not substantially immediate. Drill bit
aggressiveness
contributes to the vibration, whirl and stick-slip for a given WOB and drill
bit
rotational speed. "Depth of Cut" (DOC) of a drill bit, generally defined as
"the
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distance the drill bit advances along axially into the formation in one
revolution," is
a contributing factor relating to the drill bit aggressiveness. Controlling
DOC can
provide smoother borehole, avoid premature damage to the cutters and prolong
operating life of the drill bit.
The disclosure herein provides a drill bit and drilling systems using the same
configured to control the rate of change of instantaneous DOC of a drill bit
during
drilling of a wellbore.
DISCLOSURE
In one aspect, a drill bit is disclosed, including: a bit body; a pad
associated
with the bit body; a rate control device coupled to the pad that extends from
a bit
surface at a first rate and retracts from an extended position to a retracted
position at
a second rate in response to external force applied onto the pad, the rate
control
device including: a piston for applying a force on the pad; a biasing member
that
applies a force on the piston to extend the pad at the first rate; a fluid
chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber.
In another aspect, a method of drilling a wellbore is disclosed, including:
providing a drill bit including a bit body, a pad associated with the bit
body, and a
rate control device; conveying a drill string into a formation, the drill
string having a
drill bit at the end thereof; selectively extending the pad from a bit surface
at a first
rate via the rate control device; selectively retracting from an extended
position to a
retracted position at a second rate in response to external force applied onto
the pad
via the rate control device, the rate control device including: a piston for
applying a
force on the pad; a biasing member that applies a force on the piston to
extend the
pad at the first rate; a fluid chamber associated with the piston; and
controlling a
fluid pressure within the fluid chamber via a pressure management device; and
drilling the wellbore using the drill string.
In another aspect, a system for drilling a wellbore is disclosed, including: a
drilling assembly having a drill bit, the drill bit including: a bit body; a
pad
associated with the bit body; a rate control device coupled to the pad that
extends
from a bit surface at a first rate and retracts from an extended position to a
retracted
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position at a second rate in response to external force applied onto the pad,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber.
In another aspect, a drill bit is disclosed, including: a bit body; a pad
associated with the bit body; a rate control device coupled to the pad that
extends
from a bit surface at a first rate and retracts from an extended position to a
retracted
position at a second rate in response to an external force applied, the rate
control
device including: a piston for applying a force on the pad; a biasing member
that
applies a force on the piston to expose the pad at the first rate; and a
rotary device
that applies a force on the piston to hide the pad at the second rate.
In another aspect, a drill bit is disclosed, comprising: a bit body; a self-
adjusting pad associated with the bit body; and a rate control device coupled
to the
pad that extends from a bit surface at a first rate to reduce vibration and
retracts from
an extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber, wherein the pressure management device is a
multi-stage orifice.
In another aspect, a drill bit is disclosed, comprising: a bit body; a self-
adjusting pad associated with the bit body; and a rate control device coupled
to the
pad that extends from a bit surface at a first rate to reduce vibration and
retracts from
an extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber, wherein the pressure management device is a
high precision gap disposed between the piston and the fluid chamber.
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In another aspect, a drill bit is disclosed, comprising: a bit body; a self-
adjusting pad associated with the bit body; and a rate control device coupled
to the
pad that extends from a bit surface at a first rate to reduce vibration and
retracts from
an extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a plurality of hydraulically linked pistons for
applying a
force on the pad; a biasing member that applies a force on the pistons to
extend the
pad at the first rate; a fluid chamber associated with the piston; and a
pressure
management device for controlling a fluid pressure within the fluid chamber.
In another aspect, a drill bit is disclosed, comprising: a bit body; a self-
adjusting pad associated with the bit body; and a rate control device coupled
to the
pad that extends from a bit surface at a first rate to reduce vibration and
retracts from
an extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber, wherein the pad is a plurality of pads that
extend
from the rate control device, and wherein the rate control device is centrally
disposed.
In another aspect, a drill bit is disclosed, comprising: a bit body; a self-
adjusting pad associated with the bit body; and a rate control device coupled
to the
pad that extends from a bit surface at a first rate to reduce vibration and
retracts from
an extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber, wherein the rate control device is oriented
with a
tilt against a direction of rotation of the drill bit to minimize a tangential
component
of a frictional force experienced by the piston.
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In another aspect, a method of drilling a wellbore is disclosed, comprising:
providing a drill bit including a bit body, a self-adjusting pad associated
with the bit
body, and a rate control device; conveying a drill string into a forniation,
the drill
string having the drill bit at the end thereof; selectively extending the pad
from a bit
surface at a first rate via the rate control device to reduce vibration;
selectively
retracting the pad from an extended position to a retracted position at a
second rate
in response to external force applied onto the pad via the rate control device
to
decrease friction and increase maneuverability, the rate control device
including: a
piston for applying a force on the pad; a biasing member that applies a force
on the
piston to extend the pad at the first rate; and a fluid chamber associated
with the
piston; controlling a fluid pressure within the fluid chamber via a pressure
management device, wherein the pressure management device is a multi-stage
orifice; and drilling the wellbore using the drill string.
In another aspect, a method of drilling a wellbore is disclosed, comprising:
providing a drill bit including a bit body, a self-adjusting pad associated
with the bit
body, and a rate control device; conveying a drill string into a formation,
the drill
string having the drill bit at the end thereof; selectively extending the pad
from a bit
surface at a first rate via the rate control device to reduce vibration;
selectively
retracting the pad from an extended position to a retracted position at a
second rate
in response to external force applied onto the pad via the rate control device
to
decrease friction and increase maneuverability, the rate control device
including: a
piston for applying a force on the pad; a biasing member that applies a force
on the
piston to extend the pad at the first rate; and a fluid chamber associated
with the
piston; controlling a fluid pressure within the fluid chamber via a pressure
management device, wherein the pressure management device is a high precision
gap disposed between the piston and the fluid chamber; and drilling the
wellbore
using the drill string.
In another aspect, a method of drilling a wellbore is disclosed, comprising:
providing a drill bit including a bit body, a self-adjusting pad associated
with the bit
body, and a rate control device; conveying a drill string into a formation,
the drill
string having a drill bit at the end thereof; selectively extending the pad
from a bit
surface at a first rate via the rate control device to reduce vibration;
selectively
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retracting the pad from an extended position to a retracted position at a
second rate
in response to external force applied onto the pad via the rate control device
to
decrease friction and increase maneuverability, the rate control device
including: a
plurality of hydraulically linked pistons for applying a force on the pad; a
biasing
member that applies a force on the pistons to extend the pad at the first
rate; and a
fluid chamber associated with the piston; controlling a fluid pressure within
the fluid
chamber via a pressure management device; and drilling the wellbore using the
drill
string.
In another aspect, a method of drilling a wellbore is disclosed, comprising:
providing a drill bit including a bit body, a self-adjusting pad associated
with the bit
body, and a rate control device; conveying a drill string into a formation,
the drill
string having the drill bit at the end thereof; selectively extending the pad
from a bit
surface at a first rate via the rate control device to reduce vibration;
selectively
retracting the pad from an extended position to a retracted position at a
second rate
in response to external force applied onto the pad via the rate control device
to
decrease friction and increase maneuverability, the rate control device
including: a
piston for applying a force on the pad, wherein the pad is a plurality of pads
that
extend from the rate control device, wherein the rate control device is
centrally
disposed; a biasing member that applies a force on the piston to extend the
pad at the
first rate; and a fluid chamber associated with the piston; controlling a
fluid pressure
within the fluid chamber via a pressure management device; and drilling the
wellbore using the drill string.
In another aspect, a system for drilling a wellbore is disclosed, comprising:
a
drilling assembly having a drill bit, the drill bit including: a bit body; a
self-adjusting
pad associated with the bit body; and a rate control device coupled to the pad
that
extends from a bit surface at a first rate to reduce vibration and retracts
from an
extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
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pressure within the fluid chamber, wherein the pressure management device is a
multi-stage orifice.
In another aspect, a system for drilling a wellbore is disclosed, comprising:
a
drilling assembly having a drill bit, the drill bit including: a bit body; a
self-adjusting
pad associated with the bit body; and a rate control device coupled to the pad
that
extends from a bit surface at a first rate to reduce vibration and retracts
from an
extended position to a retracted position at a second rate in response to
external
force applied onto the pad to decrease friction and increase maneuverability,
the rate
control device including: a piston for applying a force on the pad; a biasing
member
that applies a force on the piston to extend the pad at the first rate; a
fluid chamber
associated with the piston; and a pressure management device for controlling a
fluid
pressure within the fluid chamber, wherein the pressure management device is a
high precision gap disposed between the piston and the fluid chamber.
In another aspect, a drill bit is disclosed, comprising: a bit body; a pad
associated with the bit body; and a rate control device coupled to the pad
that
extends from a bit surface at a first rate to provide a low depth of cut and
retracts
from an extended position to a retracted position at a second rate in response
to an
external force applied, the rate control device including: a piston for
applying a force
on the pad; a biasing member that applies a force on the piston to expose the
pad at
the first rate; and a rotary device that applies a force on the piston to hide
the pad at
the second rate, wherein the second rate is less than the first rate.
Examples of certain features of the apparatus and method disclosed herein
are summarized rather broadly in order that the detailed description thereof
that
follows may be better understood. There are, of coUrse, additional features of
the
apparatus and method disclosed hereinafter that will form the subject of the
claims
appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
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The disclosure herein is best understood with reference to the accompanying
figures, wherein like numerals have generally been assigned to like elements
and in
which:
FIG. 1 is a schematic diagram of an exemplary drilling system that includes a
drill string that has a drill bit made according to one embodiment of the
disclosure;
FIG. 2 shows a partial cross-sectional view of an exemplary drill bit with a
pad
and a rate control device for controlling the rates of extending and
retracting the pad
from a drill bit surface, according to one embodiment of the disclosure;
FIG. 3 shows an alternative embodiment of the rate control device that
operates
the pad via a hydraulic line;
FIG. 4 shows an embodiment of a rate control device configured to operate
multiple pads;
FIG. 5 shows placement of a rate control device of FIG. 3 in the crown section
of the drill bit;
FIG. 6 shows placement of a rate control device of in fluid passage or flow
path
of the drill bit;
FIG. 7 shows a drill bit, wherein the rate control device and the pad are
placed
on an outside surface of the drill bit;
FIG. 8A shows an embodiment of a rate control device with a multistage
orifice;
FIG. 8B shows an embodiment of a multistage orifice for use with the rate
control device illustrated in FIG. 8A;
FIG. 9 shows an embodiment of a rate control device with a high precision gap;
FIG. 10 shows an embodiment of a rate control device configured to operate
multiple pads;
FIG. 11 shows an embodiment of a rate control device configured to operate
extending from the center of the bit;
FIG. 12 shows an embodiment of a rate control device with a multi-wall
chamber;
FIG. 13 shows an embodiment of a rate control device with a compensated
piston;
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FIG. 14 shows an embodiment of a rate control device with a rotary device; and
FIG. 15 shows an alternate embodiment of a rate control device.
MODE(S) FOR CARRYING OUT THE INVENTION
FIG. 1 is a schematic diagram of an exemplary drilling system 100 that may
utilize drill bits made according to the disclosure herein. FIG. 1 shows a
wellbore 110
having an upper section 111 with a casing 112 installed therein and a lower
section 114
being drilled with a drill string 118. The drill string 118 is shown to
include a tubular
member 116 with a BHA 130 attached at its bottom end. The tubular member 116
may
be made up by joining drill pipe sections or it may be a coiled-tubing. A
drill bit 150 is
shown attached to the bottom end of the BHA 130 for disintegrating the rock
formation 119 to drill the wellbore 110 of a selected diameter.
Drill string 118 is shown conveyed into the wellbore 110 from a rig 180 at the
surface 167. The exemplary rig 180 shown is a land rig for ease of
explanation. The
apparatus and methods disclosed herein may also be utilized with an offshore
rig used
for drilling wellbores under water. A rotary table 169 or a top drive (not
shown)
coupled to the drill string 118 may be utilized to rotate the drill string 118
to rotate the
BHA 130 and thus the drill bit 150 to drill the wellbore 110. A drilling motor
155 (also
referred to as the "mud motor") may be provided in the BHA 130 to rotate the
drill
bit 150. The drilling motor 155 may be used alone to rotate the drill bit 150
or to
superimpose the rotation of the drill bit by the drill string 118. A control
unit (or
controller) 190, which may be a computer-based unit, may be placed at the
surface 167
to receive and process data transmitted by the sensors in the drill bit 150
and the sensors
in the BHA 130, and to control selected operations of the various devices and
sensors in
the BHA 130. The surface controller 190, in one embodiment, may include a
processor 192, a data storage device (or a computer-readable medium) 194 for
storing
data, algorithms and computer programs 196. The data storage device 194 may be
any
suitable device, including, but not limited to, a read-only memory (ROM), a
random-access memory (RAM), a flash memory, a magnetic tape, a hard disk and
an
optical disk. During drilling, a drilling fluid 179 from a source thereof is
pumped under
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pressure into the tubular member 116. The drilling fluid discharges at the
bottom of the
drill bit 150 and returns to the surface via the annular space (also referred
as the
"annulus") between the drill string 118 and the inside wall 142 of the
wellbore 110.
The BHA 130 may further include one or more downhole sensors (collectively
designated by numeral 175). The sensors 175 may include any number and type of
sensors, including, but not limited to, sensors generally known as the
measurement-while-drilling (MWD) sensors or the logging-while-drilling (LWD)
sensors, and sensors that provide information relating to the behavior of the
BHA 130,
such as drill bit rotation (revolutions per minute or "RPM"), tool face,
pressure,
vibration, whirl, bending, and stick-slip. The BHA 130 may further include a
control
unit (or controller) 170 that controls the operation of one or more devices
and sensors in
the BHA 130. The controller 170 may include, among other things, circuits to
process
the signals from sensor 175, a processor 172 (such as a microprocessor) to
process the
digitized signals, a data storage device 174 (such as a solid-state-memory),
and a
computer program 176. The processor 172 may process the digitized signals, and
control downhole devices and sensors, and communicate data information with
the
controller 190 via a two-way telemetry unit 188.
Still referring to FIG. 1, the drill bit 150 includes a face section (or
bottom
section) 152. The face section 152 or a portion thereof faces the formation in
front of
the drill bit or the wellbore bottom during drilling. The drill bit 150, in
one aspect,
includes one or more pads 160 that may be extended and retracted from a
selected
surface of the drill bit 150. The pads 160 are also referred to herein as the
"extensible
pads," "extendable pads," or "adjustable pads." A suitable actuation device
(or
actuation unit) 165 in the drill bit 150 may be utilized to extend and retract
one or more
pads from a drill bit surface during drilling of the wellbore 110. In one
aspect, the
actuation device 165 may control the rate of extension and retraction of the
pad 160.
The actuation device is also referred to as a "rate control device" or "rate
controller." In
another aspect, the actuation device is a passive device that automatically
adjusts or
self-adjusts the extension and retraction of the pad 160 based on or in
response to the
force or pressure applied to the pad 160 during drilling. In certain
embodiments,
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actuation device 165 and pad 160 are actuated by contact with the formation.
Further, a
substantial force on pads 160 is experienced when the depth of cut of drill
bit 150 is
changed rapidly. Accordingly, it is desirable for actuation mechanism 165 to
resist
changes to the depth of cut. In certain embodiments, actuation mechanism 165
will
increase the weight on bit at a given depth of cut. In other embodiments,
actuation
mechanism 165 will reduce the depth of cut for a given weight on bit. The rate
of
extension and retraction of the pad may be preset as described in more detail
in
reference to FIGS. 2-4.
FIG. 2 shows an exemplary drill bit 200 made according to one embodiment of
.. the disclosure. In an exemplary embodiment, the drill bit 200 is a
polycrystalline
diamond compact (PDC) bit having a bit body 201 that includes a neck or neck
section 210, a shank 220 and a crown or crown section 230. In other
embodiments, the
drill bit 200 is any suitable drill bit or formation removal device for use in
a formation.
In other embodiments, drill bit 200 is any suitable downhole rotary tool. The
neck 210
has a tapered upper end 212 having threads 212a thereon for connecting the
drill bit 200
to a box end of the drilling assembly 130 (FIG. 1). The shank 220 has a lower
vertical
or straight section 222 that is fixedly connected to the crown 230 at a joint
224. The
crown 230 includes a face or face section 232 that faces the formation during
drilling.
The crown 230 includes a number of blades, such as blades 234a, 234b, etc. A
typical
PDC bit includes 3-7 blades. Each blade has a face (also referred to as a
"face section")
and a side (also referred to as a "side section"). For example, blade 234a has
a
face 232a and a side 236a, while blade 234b has a face 232b and a side 236b.
The
sides 236a and 236b extend along the longitudinal or vertical axis 202 of the
drill
bit 200. Each blade further includes a number of cutters. In the particular
embodiment
of FIG. 2, blade 234a is shown to include cutters 238a on a portion of the
side 236a and
cutters 238b along the face 232a while blade 234b is shown to include cutters
239a on
the side 239a and cutters 239b on the face 232b.
Still referring to FIG. 2, the drill bit 200 includes one or more elements or
members (also referred to herein as pads) that extend and retract from a
surface 252 of
the drill bit 200. FIG. 2 shows a pad 250 movably placed in a cavity or recess
254 in
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the crown section 230. An activation device 260 may be coupled to the pad 250
to
extend and retract the pad 250 from a drill bit surface location 252. In one
aspect, the
activation device 260 controls the rate of extension and retraction of the pad
250. In
another aspect, the device 260 extends the pad at a first rate and retracts
the pad at a
second rate. In embodiments, the first rate and second rate may be the same or
different
rates. In another aspect, the rate of extension of the pad 250 may be greater
than the
rate of retraction. As noted above, the device 260 also is referred to herein
as a "rate
control device" or a "rate controller." In the particular embodiment of the
device 260,
the pad 250 is directly coupled to the device 260 via a mechanical connection
or
connecting member 256. In one aspect, the device 260 includes a chamber 270
that
houses a double acting reciprocating member, such as a piston 280, that
sealingly
divides the chamber 270 into a first chamber 272 and a second chamber or
reservoir 274. Both chambers 272 and 274 are filled with a hydraulic fluid 278
suitable
for downhole use, such as oil. A biasing member, such as a spring 284, in the
first
chamber 272, applies a selected force on the piston 280 to cause it to move
outward.
Since the piston 280 is connected to the pad 250, moving the piston outward
causes the
pad 250 to extend from the surface 252 of the drill bit 200. In one aspect,
the
chambers 272 and 274 are in fluid communication with each other via a first
fluid flow
path or flow line 282 and a second fluid flow path or flow line 286. A flow
control
device, such as a check valve 285, placed in the fluid flow line 282, may be
utilized to
control the rate of flow of the fluid from chamber 274 to chamber 272.
Similarly,
another flow control device, such as a check valve 287, placed in fluid flow
line 286,
may be utilized to control the rate of flow of the fluid 278 from chamber 272
to
chamber 274. The flow control devices 285 and 287 may be configured at the
surface
to set the rates of flow through fluid flow lines 282 and 286, respectively.
In another
aspect, the rates may be set or dynamically adjusted by an active device, such
as by
controlling fluid flows between the chambers by actively controlled valves. In
certain
embodiments, the fluid flow is control actively by adjusting fluid properties
by using
electro or magneto rhological fluids and controllers. In other embodiments,
piezo
electronics are utilized to control fluid flows. In one aspect, one or both
flow control
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devices 285 and 287 may include a variable control biasing device, such as a
spring, to
provide a constant flow rate from one chamber to another. Constant fluid flow
rate
exchange between the chambers 272 and 274 provides a first constant rate for
the
extension for the piston 280 and a second constant rate for the retraction of
the
piston 280 and, thus, corresponding constant rates for extension and
retraction of the
pad 250. The size of the flow control lines 282 and 286 along with the setting
of their
corresponding biasing devices 285 and 287 define the flow rates through lines
282 and
286, respectively, and thus the corresponding rate of extension and retraction
of the
pad 250. In one aspect, the fluid flow line 282 and its corresponding flow
control
device 285 may be set such that when the drill bit 250 is not in use, i.e.,
there is no
external force being applied onto the pad 250, the biasing member 280 will
extend the
pad 250 to the maximum extended position. In one aspect, the flow control line
282
may be configured so that the biasing member 280 extends the pad 250
relatively fast or
suddenly. When the drill bit is in operation, such as during drilling of a
wellbore, the
weight on bit applied to the bit exerts an external force on the pad 250. This
external
force causes the pad 250 to apply a force or pressure on the piston 280 and
thus on the
biasing member 284.
In one aspect, the fluid flow line 286 may be configured to allow relatively
slow
flow rate of the fluid from chamber 272 into chamber or reservoir 274, thereby
causing
the pad to retract relatively slowly. As an example, the extension rate of the
pad 250
may be set so that the pad 250 extends from the fully retracted position to a
fully
extended position over a few seconds while it retracts from the fully extended
position
to the fully retracted position over one or several minutes or longer (such as
between
2-5 minutes). It will be noted, that any suitable rate may be set for the
extension and
.. retraction of the pad 250. In one aspect, the device 260 is a passive
device that adjusts
the extension and retraction of a pad based on or in response to the force or
pressure
applied on the pad 250. In an exemplary embodiment, the pads 250 are wear
resistant
elements, such as cutters, ovoids, elements making rolling contact, or other
elements
that reduce friction with earth formations. In certain embodiments, pads 250
are
directly in front and in the same cutting groove as the cutters 239a, 238b. In
an
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exemplary embodiment, device 260 is oriented with a tilt against the direction
of
rotation to minimize the tangential component of friction force experienced by
the
piston 280. In certain embodiments, the device 260 is located inside the
blades 234a,
234b, etc. supported by the bit body 201 with a press fit near the face 232a
of the
bit 200 and a threaded cap or retainer or a snap ring near the top end of the
side
portion 234a, 234b.
FIG. 3 shows an alternative rate control device 300. The device 300 includes a
fluid chamber 370 divided by a double acting piston 380 into a first chamber
372 and a
second chamber or reservoir 374. The chambers 372 and 374 are filled with a
hydraulic
fluid 378. A first fluid flow line 382 and an associated flow control device
385 allow
the fluid 378 to flow from chamber 374 to chamber 372 at a first flow rate and
a fluid
flow line 386 and an associated flow control device 387 allow the fluid 378 to
flow
from the chamber 372 to chamber 374 at a second rate. The piston 380 is
connected to
a force transfer device 390 that includes a piston 392 in a chamber 394. The
chamber 394 contains a hydraulic fluid 395, which is in fluid communication
with a
pad 350. In one aspect, the pad 350 may be placed in a chamber 352, which
chamber is
in fluid communication with the fluid 395 in chamber 394. When the biasing
device 384 moves the piston 380 outward, it moves the piston 392 outward and
into the
chamber 394. Piston 392 expels fluid 395 from chamber 394 into the chamber
352,
which extends the pad 350. When a force is applied on to the pad 350, it
pushes the
fluid in chamber 352 into chamber 394, which applies a force onto the piston
380. The
rate of the movement of the piston 380 is controlled by the flow of the fluid
through the
fluid flow line 386 and flow control device 387. In the particular
configuration shown
in FIG. 3, the rate control device 300 is not directly connected to the pad
350, which
enables isolation of the device 300 from the pad 350 and allows it to be
located at any
desired location in the drill bit, as described in reference to FIGS. 5-6. In
another
aspect, the pad 350 may be directly connected to a cutter 399 or an end of the
pad 350
may be made as a cutter. In this configuration, the cutter 399 acts both as a
cutter and
an extendable and a retractable pad.
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FIG. 4 shows a common rate control device 400 configured to operate more than
one pad, such as pads 350a, 350b 350n. The rate control device 400 is the same
as
shown and described in FIG. 2, except that it is shown to apply force onto the
pads 350a, 350b 350n via an intermediate device 390, as shown and described in
reference to FIG. 3. In the embodiment of FIG. 4, each of the pads 350a, 350b
350n
is housed in separate chambers 352a, 352b ... 352n respectively. The fluid 395
from
chamber 394 is supplied to all chambers, thereby automatically and
simultaneously
extending and retracting each of the pads 350a, 350b 350n based on external
forces
applied to each such pad during drilling. In aspects, the rate control device
400 may
include a suitable pressure compensator 499 for downhole use. Similarly any of
the rate
controllers made according to any of the embodiments may employ a suitable
pressure
compensator.
FIG. 5 shows an isometric view of a drill bit 500, wherein a rate control
device 560 is placed in a crown section 530 of the drill bit 500. The rate
control
device 560 is the same as shown in FIG. 2, but is coupled to a pad 550 via a
hydraulic
connection 540 and a fluid line 542. The rate control device 560 is shown
placed in a
recess 580 accessible from an outside surface 582 of the crown section 530.
The
pad 550 is shown placed at a face location section 552 on the drill bit face
532, while
the hydraulic connection 540 is shown placed in the crown 530 between the pad
550
and the rate control device 560. It should be noted that the rate control
device 560 may
be placed at any desired location in the drill bit, including in the shank 520
and neck
section 510 and the hydraulic line 542 may be routed in any desired manner
from the
rate control device 560 to the pad 550. Such a configuration provides
flexibility of
placing the rate control device substantially anywhere in the drill bit.
FIG. 6 shows an isometric view of a drill bit 600, wherein a rate control
device 660 is placed in a fluid passage 625 of the drill bit 600. In the
particular drill bit
configuration of FIG. 6, the hydraulic connection 640 is placed proximate the
rate
control device 660. A hydraulic line 670 is run from the hydraulic connection
640 to
the pad 650 through the shank 620 and the crown 630 of the drill bit 600.
During
drilling, a drilling fluid flows through the passage 625. To enable the
drilling fluid to
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flow freely through the passage 625, the rate control device 660 may be
provided with a
through bore or passage 655 and the hydraulic connection device 640 may be
provided
with a flow passage 645.
FIG. 7 shows a drill bit 700, wherein an integrated pad and rate control
device 750 is placed on an outside surface of the drill bit 700. In one
aspect, the
device 750 includes a rate control device 760 connected to a pad 755. In one
aspect, the
device 750 is a sealed unit that may be attached to any outside surface of the
drill
bit 700. The rate control device 760 may be the same as or different from the
rate
control devices described herein in reference to FIGS. 2-6. In the particular
embodiment of FIG. 7, the pad is shown connected to a side 720a of a blade 720
of the
drill bit 700. The device 750 may be attached or placed at any other suitable
location in
the drill bit 700. Alternatively or in addition thereto, the device 750 may be
integrated
into a blade so that the pad will extend toward a desired direction from the
drill bit.
FIG. 8A shows an integrated rate control device 800. In an exemplary
embodiment rate control devices 800 are individual self-contained cartridges
to be
disposed inside the blades of a bit, such as the bits previously described. In
this
embodiment, rate control functionality is achieved through a pressure
management
device, such as multi-stage orifice 899. FIG. 8B shows the multi-stage orifice
899 with
a plurality of orifices 898 that provide a tortuous path for fluid 878 between
upper
chamber 872 and lower chamber 874. In an exemplary embodiment, upper
chamber 872 is subject to a higher pressure than lower chamber 874. In certain
embodiments, lower chamber 874 is close to downhole pressure. Accordingly, in
an
exemplary embodiment, multistage orifice 899 controls the movement and
pressure
within rate control device 800 in conjunction with biasing member 884, by
controlling
the flow of fluid 878 therein. Accordingly, the rate of pad 850 is effectively
controlled
by adjusting the properties of the orifice 899. In certain embodiments, the
lower
chamber 874 is pressure-compensated. In an exemplary embodiment, the lower
chamber 874 is pressure compensated with downhole pressure to minimize the
pressure
differential across the mud-oil seal 875 at the bit face.
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FIG. 9 shows an integrated rate control device 900. In an exemplary
embodiment, rate control devices 900 are self-contained cartridges disposed
inside the
blades of a bit, such as the bits previously described. In this embodiment,
the rate
control functionality is achieved through a pressure management device, such
as
high-precision gap 999 between the piston 980 and the cylinder 994. The
high-precision gap 999 allows a predetermined amount of fluid 978 to be
transferred
between upper chamber 972 and lower chamber 974 at a given pressure
differential,
effectively controlling the rate of movement of piston 980. In certain
embodiments,
high-precision gap 999 also acts as a high-pressure seal between the two
chambers 972,
974. In certain embodiments, the chambers 972, 974 respectively contain a high
pressure fluid and a low pressure fluid. In an exemplary embodiment, the lower
chamber 974 (low pressure chamber) is pressure-compensated with downhole
pressure
to minimize the pressure differential across the mud-oil seal (not shown) at
the bit face.
In an exemplary embodiment, the pressure-compensation is achieved through
bellows
in communication with the downhole formation pressure.
FIG. 10 shows a drill bit 1000 with a rate controller 1090 located in the bit
shank 1091 of the drill bit 1000. In an exemplary embodiment, rate control
device 1090
is hydraulically connected to multiple pistons 1080 via hydraulic passages
1092 that
allow passage of fluid 1078 therethrough to act as a linkage 1056a.
Advantageously,
the central location of rate control device 1090 allows for a large space for
the rate
control device 1090 while allowing multiple pistons 1080 to be utilized and
share load
during drill bit operation. In certain embodiments, the pressure drop across
the bit 1000
is utilized to create the downward force. In these embodiments, the low
pressure
chamber 1074 is compensated to have the same pressure as the drilling fluid
pressure
inside the bit, while the top rod or chamber 1072 of the compensated piston
1080 is
exposed to the pressure inside the bit 1000 causing a net downward force. In
certain
embodiments, a secondary linkage 1056b is hydraulically or mechanically linked
to the
pad 1050.
FIG. 11 shows a drill bit 1100 with a rate controller 1190 centrally located
in the
drill bit 1100. In an exemplary embodiment, the rate control device 1190 is
centrally
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located and mechanically or hydraulically connected to multiple pads 1150.
Advantageously, this allows for reduction in the peak pressure inside the rate
controller 1190 and also reduces number of parts as the pads 1150 as centrally
actuated
as shown in FIG. 4.
FIG. 12 shows a rate control device 1200 that utilizes a triple-walled
cylinder 1298 with annular gaps 1299 between walls 1298a, 1298b, 1298c. In an
exemplary embodiment, annular gap 1299 is a pressure management device, such
as a
high precision gap to restrict flow of fluid 1278 to control the movement of
piston 1280.
In an exemplary embodiment, fluid flow 1278 moves through ports 1299a and
1299b to
interface with both sides of piston 1280. In certain embodiments, ports 1299a
and
1299b have check valves to restrict fluid flow 1278. During operation, fluid
1278 is
restricted by gap 1299 to control the flow of fluid 1278, resulting in the
controlled
movement of piston 1280. In certain embodiments, a pressure compensator 1297
is
utilized to compensate the pressure of lower chamber 1274 to downhole fluid
pressure.
FIG. 13 shows a rate control device 1300 with a compensated piston 1380. In
an exemplary embodiment, a double acting piston 1380 with substantially equal
rod size
is exposed to both upper chamber 1372 and lower chamber 1374. In an exemplary
embodiment, both ends piston 1380 are exposed to the bottomhole pressure so
that net
force on the piston 1380 due to drilling fluid pressure is near zero. In
certain
embodiments, a hydraulic accumulator 1399 can be used with the compensated
piston 1380 to accommodate for fluid volume changes with temperature, trapped
air,
and leakages. In certain embodiments, a biasing member 1378 is utilized to
provide a
downward force. Advantageously, both chambers 1372, 1374 are compensated to
minimize the pressure differential between the rate control device 1300 and
the
wellbore.
FIG. 14 shows a rate control device 1400 that utilizes a rotary seal 1496 at
the
mud-oil interface when disposed within a drill bit (shown schematically as
1401). In an
exemplary embodiment, a cam 1492 is located outside of the drill bit 1401 and
the
rotary motion is transmitted via shaft 1491 into the bit body through a rotary
seal 1496.
The rotary motion is converted into a translational motion inside the bit body
using a
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second cam 1493 and a follower 1494 attached to the piston 1480. In certain
embodiments, such as when a low depth of cut is desired, the first cam 1492
exposes the
adaptive element 1450 attached. As external load is experienced by first cam
1492, the
load rotates the first cam 1492, and in turn the second cam 1493, which in
turn causes
inward motion (hiding) of the piston 1480. When external load is released, the
piston 1480 extends due to the spring 1484 force, and in turn rotates the cams
1492,
1493 and exposes the adaptive elements 1450. Thus, the contact element 1450 is
extended (exposed) and retracted (hidden) at different rates controlled by cam
1492,
1493 profile and biasing member 1484 characteristics.
FIG. 15 shows a rate control device 1500 that utilizes a fixed pressure
management device 1599. In an exemplary embodiment, pressure management
device 1599 is stationary relative to moving piston 1580. In an exemplary
embodiment,
downhole fluid pressure 1575 is exerted upon separator 1597 to compensate the
pressure of reservoir 1574. Fluid 1587 may flow between fluid chamber 1572 and
reservoir 1574 via pressure management device 1599. In one aspect, the chamber
1572
and reservoir 1574 are in fluid communication with each other via a first
fluid flow path
or flow line 1582 and a second fluid flow path or flow line 1586. A flow
control
device, such as a check valve 1585, placed in the fluid flow line 1582, may be
utilized
to control the rate of flow of the fluid from reservoir 1574 to chamber 1572.
Similarly,
another flow control device, such as a check valve 1587, placed in fluid flow
line 1586,
may be utilized to control the rate of flow of the fluid 1578 from chamber
1572 to
reservoir 1574. The flow control devices 1585 and 1587 may be configured at
the
surface to set the rates of flow through fluid flow lines 1582 and 1586,
respectively. In
certain embodiments, the pressure excited from downhole fluid 1575 biases the
piston 1580 downward.
Therefore in one aspect, a drill bit is disclosed, including: a bit body; a
pad
associated with the bit body; a rate control device coupled to the pad that
extends from a
bit surface at a first rate and retracts from an extended position to a
retracted position at
a second rate in response to external force applied onto the pad, the rate
control device
.. including: a piston for applying a force on the pad; a biasing member that
applies a
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force on the piston to extend the pad at the first rate; a fluid chamber
associated with the
piston; and a pressure management device for controlling a fluid pressure
within the
fluid chamber. In certain embodiments, the second rate is less than the first
rate. In
certain embodiments, the fluid chamber is divided by the piston into a first
fluid
chamber and a second fluid chamber. In certain embodiments, the pressure
management device is a multi-stage orifice. In certain embodiments, the
pressure
management device is a high precision gap disposed between the piston and the
fluid
chamber. In certain embodiments, the fluid chamber is a triple walled cylinder
having a
first wall, a second wall and a third wall, and at least one of the first
wall, the second
wall, and the third wall includes the high precision gap. In certain
embodiments, the
piston is a double acting piston, wherein a fluid acting on a first side of
the piston
controls at least in part the first rate and a fluid acting on a second side
of the piston
controls at least in part the second rate and the pressure management device
includes at
least one rod with both a first end and a second end both exposed to a
bottomhole
pressure. In certain embodiments, the rate control device includes an
accumulator
associated with the first side of the piston and the second side of the
piston. In certain
embodiments, the piston is a plurality of hydraulically linked pistons. In
certain
embodiments, the pad is a plurality of pads that extend from the rate control
device,
wherein the rate control device is centrally disposed. In certain embodiments,
the rate
control device is oriented with a tilt against the direction of rotation of
the drill bit. In
certain embodiments, the rate control device is a self-contained cartridge. In
certain
embodiments, the self-contained cartridge is associated with the drill bit via
a press fit
or a retainer.
In another aspect, a method of drilling a wellbore is disclosed, including:
providing a drill bit including a bit body, a pad associated with the bit
body, and a rate
control device; conveying a drill string into a formation, the drill string
having a drill bit
at the end thereof; selectively extending the pad from a bit surface at a
first rate via the
rate control device; selectively retracting from an extended position to a
retracted
position at a second rate in response to external force applied onto the pad
via the rate
control device, the rate control device including: a piston for applying a
force on the
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pad; a biasing member that applies a force on the piston to extend the pad at
the first
rate; a fluid chamber associated with the piston; and controlling a fluid
pressure within
the fluid chamber via a pressure management device; and drilling the wellbore
using the
drill string. In cei tam embodiments, the second rate is less than the
first rate. In certain
embodiments, the fluid chamber is divided by the piston into a first fluid
chamber and a
second fluid chamber. In certain embodiments, the pressure management device
is a
multi-stage orifice. In certain embodiments, the pressure management device is
a high
precision gap disposed between the piston and the fluid chamber. In certain
embodiments, the fluid chamber is a triple walled cylinder having a first
wall, a second
wall and a third wall, and at least one of the first wall, the second wall,
and the third
wall includes the high precision gap. In certain embodiments, the piston is a
double
acting piston, wherein a fluid acting on a first side of the piston controls
at least in part
the first rate and a fluid acting on a second side of the piston controls at
least in part the
second rate and the pressure management device includes at least one rod with
both a
.. first end and a second end both exposed to a bottomhole pressure. In
certain
embodiments, the rate control device further includes an accumulator
associated with
the first side of the piston and the second side of the piston. In certain
embodiments,
the piston is a plurality of hydraulically linked pistons. In certain
embodiments, the pad
is a plurality of pads that extend from the rate control device, wherein the
rate control
.. device is centrally disposed.
In another aspect, a system for drilling a wellbore is disclosed, including: a
drilling assembly having a drill bit, the drill bit including: a bit body; a
pad associated
with the bit body; a rate control device coupled to the pad that extends from
a bit
surface at a first rate and retracts from an extended position to a retracted
position at a
.. second rate in response to external force applied onto the pad, the rate
control device
including: a piston for applying a force on the pad; a biasing member that
applies a
force on the piston to extend the pad at the first rate; a fluid chamber
associated with the
piston; and a pressure management device for controlling a fluid pressure
within the
fluid chamber. In certain embodiments, the second rate is less than the first
rate. In
certain embodiments, the fluid chamber is divided by the piston into a first
fluid
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chamber and a second fluid chamber. In certain embodiments, the pressure
management device is a multi-stage orifice. In certain embodiments, the
pressure
management device is a high precision gap disposed between the piston and the
fluid
chamber.
In another aspect, a drill bit is disclosed, including: a bit body; a pad
associated
with the bit body; a rate control device coupled to the pad that extends from
a bit
surface at a first rate and retracts from an extended position to a retracted
position at a
second rate in response to an external force applied, the rate control device
including: a
piston for applying a force on the pad; a biasing member that applies a force
on the
piston to expose the pad at the first rate; and a rotary device that applies a
force on the
piston to hide the pad at the second rate. In certain embodiments, the second
rate is less
than the first rate.
The foregoing disclosure is directed to certain specific embodiments for ease
of
explanation. Various changes and modifications to such embodiments, however,
will
be apparent to those skilled in the art. It is intended that all such changes
and
modifications within the scope and spirit of the appended claims be embraced
by the
disclosure herein.
