U.S. patent application number 12/644641 was filed with the patent office on 2010-07-01 for drill bits with a fluid cushion for reduced friction and methods of making and using same.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Chad J. Beuershausen, Trung Huynh, Britney E. Meckfessel, Thorsten Schwefe.
Application Number | 20100163307 12/644641 |
Document ID | / |
Family ID | 42283512 |
Filed Date | 2010-07-01 |
United States Patent
Application |
20100163307 |
Kind Code |
A1 |
Schwefe; Thorsten ; et
al. |
July 1, 2010 |
Drill Bits With a Fluid Cushion For Reduced Friction and Methods of
Making and Using Same
Abstract
A drill bit is disclosed that in one configuration may include
at least one cutter on a face section of the bit and at least one
opening proximate the at least one cutter configured to discharge
fluid under pressure onto the formation to create a fluid cushion
between the drill bit and the formation during a drilling
operation. An actuation device associated with the drill bit may be
utilized to provide fluid under pressure to the at least one
opening.
Inventors: |
Schwefe; Thorsten; (Spring,
TX) ; Beuershausen; Chad J.; (Magnolia, TX) ;
Meckfessel; Britney E.; (Conroe, TX) ; Huynh;
Trung; (Houston, TX) |
Correspondence
Address: |
MADAN & SRIRAM, P.C.
2603 AUGUSTA DRIVE, SUITE 700
HOUSTON
TX
77057-5662
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
42283512 |
Appl. No.: |
12/644641 |
Filed: |
December 22, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61142049 |
Dec 31, 2008 |
|
|
|
Current U.S.
Class: |
175/24 ; 175/232;
175/317; 175/393; 175/57; 76/108.1 |
Current CPC
Class: |
E21B 10/60 20130101 |
Class at
Publication: |
175/24 ; 175/232;
175/317; 175/393; 175/57; 76/108.1 |
International
Class: |
E21B 21/10 20060101
E21B021/10; E21B 21/00 20060101 E21B021/00; E21B 10/60 20060101
E21B010/60; E21B 7/00 20060101 E21B007/00; E21B 44/00 20060101
E21B044/00; B21K 5/04 20060101 B21K005/04 |
Claims
1. A drill bit, comprising: a face section that includes one or
more cutters thereon configured to penetrate into a formation; at
least one opening in the drill bit configured to discharge fluid
under pressure onto the formation; and an actuation unit configured
to supply the fluid under pressure to the at least one opening when
the drill bit is engaged for cutting the formation.
2. The drill bit of claim 1, wherein the at least one opening
comprises a plurality of openings and wherein the actuation unit is
configured to supply the fluid under pressure to each of the
openings.
3. The drill bit of claim 1, wherein the at least one opening is
located at one or: a face section; gage section; and cone
section.
4. The drill bit of claim 1, wherein the actuation unit comprises a
control valve in a fluid line that supplies the fluid to the at
least one opening to control the amount of the fluid to the at
least one opening.
5. The drill bit of claim 4, further comprising a pump configured
to supply the fluid to the valve.
6. The drill bit of claim 4, wherein the control valve is one of: a
one-way valve; and an electrical valve.
7. The drill bit of claim 1, wherein the actuation unit includes a
ring device configured to open and close a fluid passage to the at
least one opening.
8. The drill bit of claim 1, further comprising a controller
configured to control the actuation device for providing fluid
under pressure to the at least one opening.
9. The drill bit of claim 1, further comprising a sensor that
provides signals relating to the pressure of the fluid supplied to
the at least one opening.
10. A method of drilling a wellbore, comprising: conveying a drill
bit attached to a bottomhole assembly into the wellbore, the drill
bit having at least one cutter on a face section of the drill bit
and at least one opening proximate to at least one cutter, the at
least one opening configured to discharge a fluid under pressure
onto a formation when the drill bit is engaged in cutting the
formation; drilling the wellbore by rotating the drill bit; and
supplying the fluid under pressure to the at least one opening to
create a fluid cushion between the face section of the drill bit
and the formation.
11. The method of claim 10, wherein the at least one opening
includes a plurality of openings and wherein the method further
comprises providing fluid under substantially the same pressure to
each of the openings.
12. The method of claim 10, further comprising controlling the
supply of the fluid to the at least one opening in response to a
selected parameter.
13. The method of claim 12, wherein the selected parameter relates
to one or more of: a dysfunction relating to the drill bit; a
dysfunction relating to the bottomhole assembly; a change of
formation; vibration; whirl; stick-slip; bending moment;
oscillation; torque; rate of penetration; weight-on-bit; tangential
acceleration; axial acceleration; radial acceleration; and drill
bit fluctuation.
14. The method of claim 10, wherein supplying the fluid under
pressure comprises using an actuation device that is one of: a pump
configured to supply the fluid under pressure to the at least one
opening; and a mechanical device that opens and closes a fluid
supply line to the at least one opening.
15. A method of manufacturing a drill bit, comprising: providing a
drill bit having at least one cutter on a face section of the drill
bit; and forming at least one opening proximate the at least one
cutter configured to discharge a fluid under pressure onto a
formation when the drill bit is engaged in cutting the
formation.
16. The method of claim 15, further comprising providing a fluid
supply unit configured to supply the fluid under pressure to the at
least one opening via a fluid channel.
17. The method of claim 16, further comprising providing a control
unit configured to control the fluid supply unit in response to a
parameter of interest.
18. The method of claim 17, further comprising providing a sensor
configured to provide a measurement relating to the parameter of
interest.
19. The method of claim 17, wherein the parameter of interest is
one or more of: a dysfunction relating to the drill bit; a
dysfunction relating to the bottomhole assembly; a change of
formation; vibration; whirl; stick-slip; bending moment;
oscillation; torque; rate of penetration; weight-on-bit; tangential
acceleration; axial acceleration; radial acceleration; and drill
bit fluctuation.
20. The method of claim 15, further comprising controlling the
supply of the fluid to the at least one opening in response to a
selected parameter.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from the U.S. Provisional
Patent Application having the Ser. No. 61/142,049 filed Dec. 31,
2008.
BACKGROUND INFORMATION
[0002] 1. Field of the Disclosure
[0003] This disclosure relates generally to drill bits and systems
that utilize the same for drilling wellbores.
[0004] 2. Background of the Art
[0005] 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 is attached to the bottom end of the BHA. The drill bit
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 a drilling condition changes, it is desirable to
alter one or more drilling parameters, such as rate of penetration
(ROP), depth of cut (DOC) of the drill bit cutters, weight-on-bit
(WOB), rotational speed of the drill bit (RPM), etc., to alter a
behavior of the drill bit, such as whirl. stick-slip, vibration,
etc. The ROP is typically controlled by controlling the
weight-on-bit (WOB) and RPM. WOB is controlled by varying the hook
load at the surface and the RPM is controlled by altering the drill
string rotation at the surface and/or by controlling the drilling
motor speed in the BHA. Such methods require the drilling system or
operator to take actions at the surface. Therefore, the impact of
such surface actions on the drill bit behavior is not substantially
immediate--it occurs a later time period, depending upon the
wellbore depth.
[0006] Therefore, there is a need to provide an improved drill bit
and a system for using the same for controlling drill bit behavior
during drilling of wellbores.
SUMMARY
[0007] In one aspect, a drill bit is disclosed that, in one
configuration, includes one or more cutters on a face section
thereof and one or more fluid openings proximate to the cutters.
The fluid openings are configured to discharge fluid under pressure
onto the formation during drilling. The discharged fluid provides a
cushion between the drill bit face and the formation, which reduces
friction between the drill bit face and the formation.
[0008] In another aspect, a method of making a drill bit is
disclosed that may include: providing one or more cutters on a face
section of the drill bit and providing one or more fluid channels
proximate to the cutters configured to discharge high pressure
fluid onto the formation to reduce friction between the drill bit
face and the formation during drilling of a wellbore.
[0009] In another aspect, a method of drilling a wellbore is
provided that may include: conveying a drill bit attached to a
bottomhole assembly into the wellbore, the drill bit having one or
more cutters on a face section thereof and one or more fluid
channels proximate to the cutters configured to discharge fluid
under pressure on the formation to create a fluid cushion between
the formation and the face section to reduce friction between the
formation and the face section; and drilling the wellbore using the
drill bit while discharging the fluid under pressure onto the
formation.
[0010] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] The disclosure herein is best understood with reference to
the accompanying figures in which like numerals have generally been
assigned to like elements and in which:
[0012] FIG. 1 is a schematic diagram of an exemplary drilling
system that includes a drill string that includes a drill bit at
its bottom end made according to one embodiment of the
disclosure;
[0013] FIG. 2A is a perspective view of an exemplary drill bit
showing placement of one or more fluid openings on a bottom section
of the drill bit according to one embodiment of the disclosure;
[0014] FIG. 2B shows a perspective view of the bottom section of
the drill bit of FIG. 2A showing an exemplary symmetric placement
of fluid openings proximate to cutters on certain blades of the
drill bit according to one embodiment of the disclosure;
[0015] FIG. 3A is a schematic illustration of a side portion of the
drill bit of FIG. 2A that shows a fluid channel in communication
with each fluid opening from the center waterway of the drill bit
and a control unit for supplying fluid under pressure to each of
the fluid channels according to one embodiment of the disclosure;
and
[0016] FIG. 3B shows a common control valve for controlling fluid
supply to a number of fluid channels in the drill bit according to
one embodiment of the disclosure.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0017] 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 a coiled-tubing or
made by joining drill pipe sections. A drill bit 150 is shown
attached to the bottom end of the BHA 130 for cutting the rock
formation 119 to drill the wellbore 110 of a selected diameter.
[0018] 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 offshore rigs (not
shown) used for drilling wellbores under water. A rotary table 169
or a top drive 168 coupled to the drill string 118 may be utilized
to rotate the drill string 118, BHA 130 and 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 150
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 accessible to
the processor 192. 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 pressure into the tubular
member 116. The drilling fluid is discharged at the bottom of the
drill bit 150 and returned to the surface via the annular space 120
(also referred as the "annulus") between the drill string 118 and
the inside wall 142 of the wellbore 110.
[0019] 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,
may include one or more cutters 154 and one or more fluid openings
160 at the face section 152. The fluid openings may be proximate
the cutters and configured to discharge or inject the fluid under
pressure from the face section 152 of the drill bit 150 onto the
formation in front of the drill bit during drilling of the wellbore
110. The drill bit 150 also includes relatively large additional
openings in the drill bit (as described in reference to FIG. 2B)
that are configured to discharge the drilling fluid at the drill
bit bottom to move the cuttings made by the drill bit to the
surface 167 via the annulus 120. The fluid openings 160 are
typically small diameter openings proximate the cutters on the face
section 152 that are capable of discharging fluid under high
pressure to create a fluid laminate or a fluid cushion between the
face section 152 of the drill bit 150 and the formation 162 in
front of the drill bit. The fluid cushion may reduce the depth of
cut of one or more of the cutters 154 proximate to the fluid
openings 160. The depth of the fluid cushion may depend upon the
pressure of the fluid discharged from the fluid openings 160. The
depth of cut of the cutters 154 may depend on the fluid cushion
depth. A suitable actuation device (or actuation unit) 165 in the
BHA 130 and/or in the drill bit 150 may be utilized to control the
supply of the fluid to the fluid openings 160 during drilling of
the wellbore 110. A suitable sensor 178 associated with the
openings 160 or the actuation device 165 may provide signals
corresponding to the pressure of the fluid discharged from the
openings 160.
[0020] Still referring to FIG. 1, 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 and the drill
bit 150, such as drill bit rotation speed (revolutions per minute
or "RPM"), tool face, pressure, vibration, whirl, oscillation,
bending, stick-slip and formation type. The BHA 130 may further
include a control unit (or controller) 170 configured to control
the operation of the actuation device 165 and for at least
partially processing data received from the sensors 175. The
controller 170 may include circuits configured to process the
signals from the sensors (e.g., amplify and digitize the signals),
a processor 172 (such as a microprocessor) to process the digitized
signals, a data storage device 174 (such as a solid-state-memory),
and computer programs 176 accessible to the processor 170. The
processor 172 may process the digitized signals, control the
operation of the actuation device 165, process data from sensors
175, control the operations of the sensors 175 and other downhole
devices, and communicate data information with the controller 190
via a two-way telemetry unit 188. The controller 170, in one
aspect, adjusts the actuation device 165 to control the fluid
cushion between the drill bit 150 and the formation 162 in response
to one or more parameters of interest based on the programmed
instructions stored in the data storage device 174 and/or
instructions received from the surface controller 190. Adjusting or
altering the fluid cushion, in turn, alters the depth of cut of one
or more cutters.
[0021] Still referring to FIG. 1, altering cutter depth or cutter
exposure may result in altering torsional or lateral fluctuation,
whirl, stick-slip, bending moment, vibration, and/or oscillation of
the drill bit 150 and the BHA 130, which, in turn, may result in
drilling a smoother wellbore and reduce stress on the drill bit 150
and BHA 130, thereby extending the BHA and drill bit lives. For the
same WOB and RPM, the ROP is generally higher when drilling into a
soft formation, such as sand, than when drilling into a hard
formation, such as shale. Transitioning drilling from a soft
formation to a hard formation may cause excessive lateral
fluctuations because of the decrease in ROP, while transitioning
from a hard formation to a soft formation may cause excessive
torsional fluctuations in the drill bit because of increase in the
ROP. Controlling the fluctuations of the drill bit, therefore, is
desirable when transitioning from a soft formation to a hard
formation and vice versa. The fluid cushion, as mentioned earlier,
may be controlled based on one or more parameters, including, but
not limited to: pressure, tool face, ROP, whirl, vibration, torque,
bending moment, oscillations, stick-slip and rock type.
Automatically and selectively adjusting fluid cushion may enable
the system 100 to control the torsional and lateral drill bit
fluctuations, ROP and other physical drill bit and BHA parameters
without altering the weight-on-bit or the drill bit RPM. The
placement of fluid openings and apparatus for controlling the fluid
cushion is described in reference to FIGS. 2A, 2B, 3A and 3B.
[0022] FIG. 2A shows an isometric view of the drill bit 150 made
according to one embodiment of the disclosure. The drill bit 150
shown is a polycrystalline diamond compact (PDC) bit having a bit
body 212 that includes a cutting section 212a and shank 212b that
connects to a BHA 130. The cutting section 212a includes a face
section 218a (also referred to herein as the "bottom section"). For
the purpose of this disclosure, the face section 218a may comprise
a nose, cone and shoulder as shown in FIG. 3A. The cutting section
212a is shown to include a number of blade profiles 214a, 214b, . .
. 214n (also referred to as the "profiles"). Each blade profile
terminates proximate to a drill bit center 215. The bit center 215
faces (or is in front of) the bottom of the wellbore 110 ahead of
the drill bit 150 during drilling of the wellbore. A side portion
213, generally referred to as the gauge or gauge section, is
typically substantially parallel to the longitudinal axis 222 of
the drill bit 150. A number of spaced-apart cutters are placed
along each blade profile. For example, blade profile 214n is shown
to contain cutters 216a-216m. Each cutter has a cutting surface or
cutting element, such as cutting element 216a' for cutter 216a,
that engages the rock formation when the drill bit 150 is rotated
during drilling of the wellbore. Each cutter 216a-216m is
configured with a back rake angle and a side rake angle that, in
combination, define the depth of cut of the cutter into the rock
formation. Each cutter also has a maximum depth of cut.
[0023] Still referring to FIG. 2A, a number of fluid openings, such
as openings 270b on blade 214b, 270d on blade 214d and 270n on
blade 214n, may be provided to discharge fluid under pressure
therefrom to the formation in front of the openings during drilling
of the wellbore. In one aspect, the fluid openings 270a-270n may be
placed proximate to the cutter on the blade profiles 214a-214n. In
other aspects, the fluid openings may be located at any other
section of the drill bit, such as the nose section, gage section.
In another aspect, the openings may be located on any combination
of the drill bit sections. A fluid channel, such as channel 244 may
be provided in the bit body to supply the fluid under pressure to
the fluid openings as described in more detail in reference to
FIGS. 3A and 3B. In one configuration, an actuation device element
350 (FIG. 3A) may supply the fluid under pressure to the pad in
each fluid openings.
[0024] FIG. 2B shows an isometric view of a face section 252 of an
exemplary PDC drill bit 150. The drill bit 150 is shown to include
six blade profiles 260a-260f, each blade profile including a
plurality of cutters, such as cutters 262a-262m for the blade
profile 260a. Alternate blade profiles 260a, 260c and 260e are
shown converging toward the center 215 of the drill bit 250 while
the remaining blade profiles 260b, 260d and 260f are shown
terminating respectively at the side of blade profiles 260c, 260e
and 260a. One or more fluid openings may be formed on one or more
blades for discharging fluid under pressure onto the formation to
create a fluid cushion between the formation and the face section
of the drill bit. As an example, FIG. 2B shows fluid openings 270a
on blade 260a proximate cutters 262a-262m, fluid openings 270c on
blade 260c and fluid openings 270e on blade 260e. Fluid openings
may also be provided on other blades. In one aspect, the fluid
openings may be placed symmetrically or substantially symmetrically
on the blades as shown in FIG. 2B or in another suitable pattern.
Fluid openings 217a may also be provided on the shoulder section
and/or openings 217b on the gage section of the drill bit, as shown
in FIG. 2A. In operation, fluid openings 270a, 270c and 270e
discharges a fluid under pressure onto the formation in front of
the drill bit 150. Fluid openings 217a and 217b (FIG. 2A)
discharges fluid under pressure on the formation on the side of the
drill bit 150. Although the drill bit shown is a PDC bit with six
blade profiles (260a-260f) and the fluid openings 270a-270e on
three such blades, the drill bit 150 may include any suitable
number of blade profiles and fluid openings at any desired
locations. Furthermore, the concepts shown and described herein are
equally applicable to non-PDC drill bits.
[0025] FIG. 3A shows a partial side view 300 of an exemplary blade
profile 310 of the drill bit 150 (FIG. 2B). The blade profile 310
is shown to include exemplary cutters 316 and 318 on the face
section 320 of a selected blade formed on a bit body 315. The
cutters 316 and 318 extend a selected distance from the face
section 320 of the blade profile 310. The face section 320 is
further shown to include fluid openings 340a and 340b proximate the
cutters 316 and 318 respectively. A fluid channel 345a extends from
an inside chamber 348 of the drill bit to the fluid opening 340a
while a fluid channel 345b extends from the inside chamber 348 to
the fluid opening 340b. Similarly, each of the other fluid openings
may be connected to their respective fluid channels. Typically, the
inside chamber 348 center of the drill bit, is filled with the
drilling fluid supplied (179) from the surface. In one embodiment,
a fluid under pressure from a source thereof (such as the fluid in
the chamber 348) may be supplied under pressure to each of the
fluid openings, such as openings 340a and 340b via the fluid
channels 345a and 345b, respectively. In one embodiment, an
actuation device or a power source 350 placed at a suitable
location in the drill bit 150 or in the BHA 130 may be utilized to
supply the fluid under pressure to each of the fluid channels. In
one aspect, the actuation device 350 may include a pump 351 driven
by a prime mover 352, such as a motor. A controller 170 may be
configured to control the operation of the prime mover 352. The
controller 170 may utilize instructions stored in the downhole
memory 174 and/or instructions transmitted by the surface
controller 190 (FIG. 1) to control the operation of the actuation
device 350. In one aspect, a sensor 360 may provide signals
corresponding to the pressure of the fluid discharged by the
actuation device 350, which signals may be utilized by the
controller 170 to control the actuation device 350. In another
aspect, the controller 170 may control the operation of actuation
device 350 in response to any suitable parameter of interest,
including but not limited to, vibration, oscillation, bending,
stick-slip, WOB, RPM and formation type. In the system described
above, the actuation device 350 supplies the fluid under the same
pressure to each of the openings in the drill bit. In another
aspect, a control valve 354 may be provided between the actuation
device 350 and the fluid channels, such as channels 345a, 345b . .
. 345p. The control valve 354 may be controlled by the controller
170 to control the pressure of the fluid supplied to the openings
340a, 340b, etc. The controller also may be configured to modulate
the actuation device 350 and/or control valve 354. The control
valve 354 may be coupled to the fluid channels by a distributor 370
(FIG. 3B) that receives the fluid from the actuation device and
distributes the received fluid to the individual fluid channels
345a, 345b . . . 345p. In another aspect, a mechanical rotating
device may be utilized to supply fluid to each of the channels. The
actuation device 350 may be any suitable device, including, but not
limited to, an electrical device, an electro-mechanical or
hydraulic device, a pump driven by a motor, a hydraulic device,
such as a pump driven by a fluid-driven turbine, and a mechanical
device, such as a ring-type device that selectively allows a fluid
to flow to the fluid channels 345a-345p.
[0026] Referring to FIGS. 1-3B, in operation, the fluid pressure
may be controlled based on the desired impact on the rate of
penetration of the drill bit into the earth formation and/or a
property of the drill bit 150 or the BHA 130. The fluid pressure
may be controlled based on any one or more desired parameters,
including, but not limited to, vibration, drill bit lateral or
torsional fluctuations, ROP, pressure, tool face, rock type,
vibration, whirl, bending moment, stick-slip, torque and drilling
direction. In general, however, the greater the fluid pressure, the
greater the fluid cushion, an thus greater the reduction in the ROP
of the drill bit into the formation. A drill bit made according to
any of the embodiments described herein may be employed to reduces
the depth of cut by the cutters at the face section of the drill
bit, which in turn affects the drill bit fluctuations and ROP.
Reduction in the drill bit fluctuations (torsional or lateral) may
affect one or more of the drill bit and/or BHA physical parameters.
The relationship between the applied fluid pressure and the ROP may
be obtained in laboratory tests. The calculated or otherwise
determined (such as through modeling) relationship among the fluid
pressure, depth of cut, drill bit fluctuations, ROP and any other
parameter obtained from tests or actual results may be stored in
the downhole data storage device 174 and/or the surface data
storage device 194. Such information may be stored in any suitable
form, including, but not limited to, one or more algorithms,
curves, matrices and tables. The fluid pressure may be controlled
by the downhole controller 170 and/or by the surface controller
190. The system 100 provided herein may automatically and
dynamically control the fluid pressure and thus the drill bit
fluctuations, ROP and other parameters during drilling of the
wellbore 110 without changing certain other parameters, such as the
WOB and RPM. The fluid pressure to the openings 217a and 217b (FIG.
2A) on the side of the drill bit may be controlled in the same
manner as the fluid pressure to the openings on the face section.
The fluid openings on the face section and the side section may be
activated concurrently.
[0027] Thus, in one aspect, a drill bit is disclosed that in one
configuration may include a face section or bottom face that
includes one or more cutters thereon configured to penetrate into a
formation; at least one opening proximate a cutter configured to
discharge fluid under pressure onto the formation; and an actuation
device configured to supply the fluid under pressure to the at
least one opening when the drill bit is engaged for cutting the
formation. The at least one opening may comprise a plurality of
openings and the actuation device may be configured to supply the
fluid under pressure to each of the openings. In one aspect, the
actuation device may be configured to supply a drilling fluid
flowing through the drill bit to the openings when the drill bit is
engaged in drilling the wellbore. In another aspect, the actuation
device may comprise a control valve in a fluid line that supplies
the fluid to the openings to control the amount of the fluid
supplied to such openings. A suitable pump may be utilized to
supply the fluid to the control valve. The control valve may be any
suitable valve for use downhole, including, but not limited to, a
one-way valve and an electrical valve. In another aspect, the
actuation device may include a ring device configured to open and
close a fluid passage to the openings. In another aspect, a
controller associated with the drill bit may be configured to
control the actuation device for providing fluid under pressure to
the openings. The controller also may modulate the fluid supply to
the openings.
[0028] In another aspect, a method for drilling a wellbore is
provided, which method, in one aspect, may include: conveying a
drill bit attached to a bottomhole assembly into the wellbore, the
drill bit having at least one fluid channel proximate one or more
cutters on a face section of the drill bit and one or more fluid
channels proximate the one or more cutters configured to discharge
fluid under pressure on to the formation to create a fluid cushion
between the formation and the face section to reduce friction
between the formation and the face section; and drilling the
wellbore using the drill bit while supplying fluid under pressure
to the one or more channels. In one aspect, when more than one
fluid channel is provided, the method may further include providing
the fluid to each channel at the same pressure. In another aspect,
the method may further include controlling the pressure of the
supplied fluid in response to a selected parameter. The selected
parameter may include, but is not limited to, change of formation
type (e.g. from hard to soft formation and vice versa), vibration,
whirl, stick-slip, acceleration bending moment, oscillation, torque
and rate of penetration. In another aspect, the fluid may be
supplied using a suitable actuation device, including, but not
limited to: a pump unit that supplies fluid under pressure to the
one or more channels and a mechanical device that opens and closes
a fluid supply line to the one or more fluid channels.
[0029] In yet another aspect, an apparatus for use in drilling a
wellbore is provided, which, in one aspect may include: a drill bit
attached to a bottom end of a bottomhole assembly, the drill bit
having a face section that includes one or more cutters and at
least one opening configured to discharge fluid from the drill bit
and an actuation device configured to supply fluid under pressure
to the at least one opening. The apparatus may further include a
controller configured to control the actuation device to control
the supply of the fluid to the at least one opening. In one aspect,
the controller may be configured to control the actuation device in
response to a parameter, including, but not limited to: vibration,
stick-slip, weight-on-bit, rate of penetration of the drill bit;
bending moment, tangential acceleration; axial acceleration; radial
acceleration; a drill bit fluctuation, a dysfunction relating to
the drill bit, and a dysfunction relating to the drill string or
bottomhole assembly. In one aspect, the actuation device may be a
pump that supplies fluid under pressure; and a mechanical motion
device that opens and closes a fluid path to the at least one
opening. The apparatus may further include a sensor that provides
signals relating to the pressure of the fluid supplied to the at
least one opening. In another aspect, the apparatus may include a
plurality of openings proximate cutters and wherein the actuation
device supplies the fluid under pressure to each such opening at
the same pressure.
[0030] 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.
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