Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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ECCENTRIC SLEEVE FOR DIRECTIONAL DRILLING SYSTEMS
FIELD OF THE DISCLOSURE
The present disclosure is related to downhole drilling tools including, but
not
limited to, drill bits, sleeves, bottom-hole assemblies, and more particularly
to design,
manufacture and/or selection of such downhole drilling tools.
BACKGROUND OF THE DISCLOSURE
Various types of rotary drill bits, reamers, stabilizers and other downhole
drilling tools may be used to form a borehole in the earth. Such wellbores are
often
formed using a rotary drill bit attached to the end of a generally hollow,
tubular drill
string extending from a well head. Rotation of a rotary drill bit
progressively cuts away
adjacent portions of a downhole formation using cutting elements and cutting
structures
disposed on exterior portions of the rotary drill bit. Examples of such rotary
drill bits
include, but are not limited to, fixed cutter drill bits, drag bits, PDC drill
bits, matrix
drill bits, roller cone drill bits, rotary cone drill bits and rock bits used
in drilling oil and
gas wells. Cutting action associated with such drill bits generally uses
weight on bit
(WOB) and rotation of associated cutting elements into adjacent portions of a
downhole formation to push the bit into the formation to cause cutting and
drilling.
Drilling fluid may also be provided to perform several functions including
washing
away formation materials and other downhole debris from the bottom of a
wellbore,
cleaning associated cutting elements and cutting structures and carrying
formation
cuttings and other downhole debris upward to an associated well surface.
Some rotary drill bits have been formed with blades extending from a bit body
with a respective gage sleeve disposed proximate an uphole edge of each blade.
Gage
sleeves have been disposed at a positive angle or positive taper relative to a
rotational
axis of an associated rotary drill bit. Gage sleeves have also been disposed
at a negative
angle or negative taper relative to a rotational axis of an associated rotary
drill bit. Such
gage sleeves may sometimes be referred to as having either a positive "axial"
taper or a
negative "axial" taper. The rotational axis of a rotary drill bit will
generally be disposed
on and aligned with a longitudinal axis extending through straight portions of
a
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wellbore formed by the associated rotary drill bit. Therefore, the axial taper
of
associated gage sleeves may also be described as a "longitudinal" taper.
SUMMARY
In one embodiment, a drill bit includes a bit body configured to rotate about
a
bit rotational axis and a sleeve coupled to the bit body. The sleeve is
coupled to the bit
body on an uphole portion of the bit body. The sleeve has a smaller diameter
than the
bit body and has a portion aligned with an edge portion of the bit body. The
edge
portion is located on the circumference of the bit body.
In another embodiment, a downhole drilling tool operable to form a wellbore
includes a bit body coupled to an eccentric sleeve. The sleeve is coupled to
the bit body
at an uphole portion of the bit body. The bit body is configured to remove
material to
form a portion of the wellbore.
In yet another embodiment, a downhole drilling tool includes a bit body
configured to rotate about a bit rotational axis and a first sleeve coupled to
the bit body
at an uphole portion of the bit body. The first sleeve has a smaller diameter
than the bit
body and has a portion aligned with an edge portion of the bit body. The edge
portion is
located on the circumference of the bit body.
BRIEF DESCRIPTION OF THE DRAWINGS
A more complete and thorough understanding of the various embodiments and
advantages thereof may be acquired by referring to the following description
taken in
conjunction with the accompanying drawings, wherein:
FIGURE lA is an illustration of an example directional drilling system for
drilling a wellbore;
FIGURE 1B is an illustration of an example system operable to simulate
drilling a directional wellbore;
FIGURE 1C is a block diagram representing various capabilities of systems and
computer programs for simulating drilling a directional wellbore;
FIGURE 2A is a schematic drawing showing an isometric view with portions
broken away of a rotary drill bit with six (6) degrees of freedom which may be
used to
describe motion of the rotary drill bit in three dimensions in a bit
coordinate system;
FIGURE 2B is a schematic drawing showing forces applied to a rotary drill bit
while forming a substantially vertical wellbore;
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FIGURE 3A is a schematic representation showing a side force applied to a
rotary drill bit at an instant in time in a two dimensional Cartesian bit
coordinate
system;
FIGURE 3B is a schematic representation showing a trajectory of a directional
wellbore and a rotary drill bit disposed in a tilt plane at an instant of time
in a three
dimensional Cartesian hole coordinate system;
FIGURE 3C is a schematic representation showing the rotary drill bit in
FIGURE 3B at the same instant of time in a two dimensional Cartesian hole
coordinate
system;
FIGURE 4A is a schematic drawing in section and in elevation with portions
broken away showing one example of a point-the-bit directional drilling system
and
associated rotary drill bit disposed adjacent to the end of a wellbore;
FIGURE 4B is a graphical representation showing portions of a point-the-bit
directional drilling system forming a directional wellbore;
FIGURE 4C is a schematic drawing in section with portions broken away
showing a point-the-bit directional drilling system and associated drill bit
disposed in a
generally horizontal wellbore;
FIGURE 4D is a graphical representation showing various forces acting on the
drill bit of FIGURE 4C;
FIGURE 5 is a schematic drawing in section with portions broken away of a
rotary drill bit showing changes in bit side forces with respect to changes in
dog leg
severity (DLS) during drilling of a directional wellbore;
FIGURE 6 is a side view of an example bit including a sleeve with full gage;
FIGURE 7 is a side view of an example bit including a sleeve with under gage;
FIGURE 8 is a side view of an example bit including a sleeve with tapered
gage;
FIGURES 9A and 9B are views of an example embodiment of a bit including an
eccentric sleeve;
FIGURES 10A, 10B, and 10C are views of an example embodiment of a bit
including a sleeve with multiple eccentric segments and/or a bit including
multiple
eccentric sleeves; and
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FIGURES 11A, 11B, 11C, and 11D are views of another example embodiment
of a bit including a sleeve with multiple eccentric segments and/or a bit
including
multiple eccentric sleeves.
DETAILED DESCRIPTION
Reference to the following terms may be useful to the understanding and
application of an eccentric sleeve for directional drilling systems.
The terms "axial taper" or "axially tapered" may be used in this application
to
describe various components or portions of a rotary drill bit, sleeve, near
bit stabilizer,
other downhole drilling tool and/or components such as a gage sleeve disposed
at an
angle relative to an associated bit rotational axis.
The term "bottom hole assembly" or "BHA" may be used in this application to
describe various components and assemblies disposed proximate a rotary drill
bit at the
downhole end of a drill string. Examples of components and assemblies (not
expressly
shown) which may be included in a BHA include, but are not limited to, a bent
sub, a
downhole drilling motor, a near bit reamer, stabilizers and downhole
instruments. A
BHA may also include various types of well logging tools (not expressly shown)
and
other downhole drilling tools associated with directional drilling of a
wellbore.
Examples of such logging tools and/or directional drilling tools may include,
but are
not limited to, acoustic, neutron, gamma ray, density, photoelectric, nuclear
magnetic
resonance, rotary steering tools and/or any other commercially available well
tool.
The terms "cutting element" and "cutting elements" may be used in this
application to include, but are not limited to, various types of cutters,
compacts, buttons,
inserts and gage cutters satisfactory for use with a wide variety of rotary
drill bits.
Impact arrestors may be included as part of the cutting structure on some
types of rotary
drill bits and may sometimes function as cutting elements to remove formation
materials from adjacent portions of a wellbore. Polycrystalline diamond
compacts
(PDC) and tungsten carbide inserts are often used to form cutting elements or
cutters.
Various types of other hard, abrasive materials may also be satisfactorily
used to form
cutting elements or cutters.
The term "cutting structure" may be used in this application to include
various
combinations and arrangements of cutting elements, impact arrestors and/or
gage
cutters formed on exterior portions of a rotary drill bit and/or sleeve. Some
rotary drill
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bits and/or sleeves may include one or more blades extending from an
associated bit
body with cutters disposed of the blades. Such blades may also be referred to
as "cutter
blades." Various configurations of blades and cutters may be used to form
cutting
structures for a rotary drill bit and/or sleeve.
5 The
terms "downhole" and "uphole" may be used in this application to describe
the location of various components of a rotary drill bit relative to portions
of the rotary
drill bit which engage the bottom or end of a wellbore to remove adjacent
formation
materials. For example an "uphole" component may be located closer to an
associated
drill string or BHA as compared to a "downhole" component which may be located
closer to the bottom or end of the wellbore.
The term "gage" as used in this application may include a gage, gage segment,
gage portion or any other portion of a rotary drill bit incorporating
teachings of the
present disclosure. Gages may be used to define or establish a nominal inside
diameter
of a wellbore formed by an associated rotary drill bit. A gage may be located
downhole
and adjacent to a gage sleeve. A gage, gage segment, gage portion or gage
sleeve may
include one or more layers of hardfacing material. One or more gage cutters,
gage
inserts, gage compacts or gage buttons may be disposed on or adjacent to a
gage, gage
segment, gage portion or gage sleeve.
The term "rotary drill bit" may be used in this application to include various
types of fixed cutter drill bits, drag bits, matrix drill bits, steel body
drill bits, roller cone
drill bits, rotary cone drill bits and rock bits operable to form a wellbore
extending
through one or more downhole formations. Rotary drill bits and associated
components
formed having many different designs, configurations and/or dimensions. A
rotary
drill bit or other downhole drilling tool may be described as having multiple
components, segments or portions. For example, one component of a drill bit
may be
described as a "cutting face profile" or "bit face profile" responsible for
removal of
formation materials to form an associated wellbore. For some types of drill
bits the
"cutting face profile" or "bit face profile" may be further divided into three
segments
such as "inner cutters or cone cutters," "nose cutters" and/or "shoulder
cutters."
The term "straight hole" may be used to describe a wellbore or portions of a
wellbore that extends at generally a constant angle relative to vertical.
Vertical
wellbores and horizontal wellbores are examples of straight holes.
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The terms "slant hole" and "slant hole segment" may be used to describe a
straight hole formed at a substantially constant angle relative to vertical.
The constant
angle of a slant hole is typically less than ninety degrees (90 ) and greater
than zero
degrees (0 ).
Most straight holes such as vertical wellbores and horizontal wellbores with
any
significant length will have some variation from vertical or horizontal based
in part on
characteristics of associated drilling equipment used to form such wellbores.
A slant
hole may have similar variations depending upon the length and associated
drilling
equipment used to form the slant hole.
The term "kick off segment" may be used to describe a portion or section of a
wellbore forming a transition between the end point of a straight hole segment
and the
first point where a desired dogleg severity or tilt rate is achieved. A kick
off segment
may be formed as a transition from a vertical wellbore to an equilibrium
wellbore with
a constant curvature or tilt rate. A kick off segment of a wellbore may have a
variable
curvature and a variable rate of change in degrees from vertical (variable
tilt rate).
The term "directional wellbore" may be used in this application to describe a
wellbore or portions of a wellbore that extend at a desired angle or angles
relative to
vertical. Such angles are greater than normal variations associated with
straight holes.
A directional wellbore sometimes may be described as a wellbore deviated from
vertical.
Sections, segments and/or portions of a directional wellbore may include, but
are not limited to, a vertical section, a kick off section, a building
section, a holding
section (sometimes referred to as a "tangent section") and/or a dropping
section.
Vertical sections may have substantially no change in degrees from vertical.
Build
segments generally have a positive, constant rate of change in degrees. Drop
segments
generally have a negative, constant rate of change in degrees. Holding
sections such as
slant holes or tangent segments and horizontal segments may extend at
respective fixed
angles relative to vertical and may have substantially zero rate of change in
degrees
from vertical.
Transition sections formed between straight hole portions of a wellbore may
include, but are not limited to, kick off segments, building segments and
dropping
segments. Such transition sections generally have a rate of change in degrees
either
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greater than or less than zero. The rate of change in degrees may vary along
the length
of all or portions of a transition section or may be substantially constant
along the
length of all or portions of the transition section.
A building segment having a relatively constant radius and a relatively
constant
change in degrees from vertical (i.e., constant tilt rate) may be used to form
a transition
from vertical segments to a slant hole segment or horizontal segment of a
wellbore. A
dropping segment may have a relatively constant radius and a relatively
constant
change in degrees from vertical (constant tilt rate) may be used to form a
transition from
a slant hole segment or a horizontal segment to a vertical segment of a
wellbore. For
example, see FIGURE 1A. Building segments and dropping segments may also be
described as "equilibrium" segments.
The terms "dogleg severity" or "DLS" may be used to describe the rate of
change in degrees of a wellbore from vertical during drilling of the wellbore.
DLS is
often measured in degrees per one hundred feet ( /100 ft). A straight hole,
vertical hole,
slant hole or horizontal hole will generally have a value of DLS of
approximately zero.
DLS may be positive, negative or zero.
Tilt angle (TA) may be defined as the angle in degrees from vertical of a
segment or portion of a wellbore. A vertical wellbore has a generally constant
tilt angle
(TA) approximately equal to zero. A horizontal wellbore has a generally
constant tilt
angle (TA) approximately equal to ninety degrees (90 ).
Tilt rate (TR) may be defined as the rate of change of a wellbore in degrees
(TA)
from vertical per hour of drilling. Tilt rate may also be referred to as
"steer rate."
TRd(TA)
=
dt
Where t = drilling time in hours
Tilt rate (TR) of a drill bit may also be defined as DLS times rate of
penetration
(ROP).
TR = DLS x ROP/100 = (degrees/hour)
Tilt rate and tilt angle may be used to plan, evaluate, or execute directional
drilling. DLS of respective segments, portions or sections of a wellbore and
corresponding tilt rate may be also used to conduct such planning, evaluation,
or
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execution. Increasing the DLS capability of a drilling tool may increase the
ability to
directionally drill a wellbore with a greater range of angles.
The terms "downhole data" and "downhole drilling conditions" may include,
but are not limited to, wellbore data, formation data, or drilling equipment
operating
data.
The terms "design parameters," "operating parameters," "wellbore parameters"
and "formation parameters" may sometimes be used to refer to respective types
of data
used to simulate or effect drilling. The terms "parameter" and "parameters"
may be
used to describe a range of data or multiple ranges of data. The terms
"operating" and
"operational" may sometimes be used interchangeably.
Various teachings of the present disclosure directed towards certain of
downhole drilling tools may also be used to design and/or select other types
of
downhole drilling tools. For example, a sleeve¨such as an eccentric
sleeve¨located
proximate a drill bit may function similar to a passive gage or an active
gage.
One difference between a "passive gage" and an "active gage" may be that a
passive gage will generally not remove formation materials from the sidewall
of a
wellbore or borehole while an active gage may at least partially cut into the
sidewall of
a wellbore or borehole during directional drilling. A passive gage may deform
a
sidewall plastically or elastically during directional drilling. Active gage
cutting
elements generally contact and remove formation material from sidewall
portions of a
wellbore. For active and passive gages the primary force is generally a normal
force
which extends generally perpendicular to the associated gage face either
active or
passive.
FIGURE lA is an illustration of an example directional drilling system 20 for
drilling a wellbore 60. Directional drilling system 20 may be operable to form
wellbores having a wide variety of profiles or trajectories. Directional
drilling system
20 and wellbore 60 may be used to describe various features of the present
disclosure
with respect to use of an eccentric sleeve for directional drilling.
Directional drilling system 20 may include land drilling rig 22. However,
teachings of the present disclosure may be applied to wellbores using drilling
systems
associated with offshore platforms, semi-submersible, drill ships and any
other drilling
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system satisfactory for forming a wellbore extending through one or more
downhole
formations.
Drilling rig 22 and associated directional drilling equipment 50 may be
located
proximate well head 24. Drilling rig 22 also includes rotary table 38, rotary
drive motor
40 and other equipment associated with rotation of drill string 32 within
wellbore 60.
Annulus 66 may be formed between the exterior of drill string 32 and the
inside
diameter of wellbore 60.
For some applications drilling rig 22 may also include top drive motor or top
drive unit 42. Blow out preventers (not expressly shown) and other equipment
associated with drilling a wellbore may also be provided at well head 24. One
or more
pumps 26 may be used to pump drilling fluid 28 from fluid reservoir or pit 30
to one end
of drill string 32 extending from well head 24. Conduit 34 may be used to
supply
drilling mud from pump 26 to the one end of drilling string 32 extending from
well head
24. Conduit 36 may be used to return drilling fluid, formation cuttings and/or
downhole debris from the bottom or end 62 of wellbore 60 to fluid reservoir or
pit 30.
Various types of pipes, tube and/or conduits may be used to form conduits 34
and 36.
Drill string 32 may extend from well head 24 and may be coupled with a supply
of drilling fluid such as pit or reservoir 30. Opposite end of drill string 32
may include
a BHA 90 and drill bit 100 disposed adjacent to end 62 of wellbore 60.
At end 62 of wellbore 60 drilling fluid may mix with formation cuttings and
other downhole debris proximate drill bit 100. The drilling fluid will then
flow
upwardly through annulus 66 to return formation cuttings and other downhole
debris to
well head 24. Conduit 36 may return the drilling fluid to reservoir 30.
Various types of
screens, filters and/or centrifuges (not expressly shown) may be provided to
remove
formation cuttings and other downhole debris prior to returning drilling fluid
to pit 30.
Directional drilling system 20 may include various downhole drilling tools and
components associated with a measurement while drilling (MWD) system that
provides
logging data and other information from the bottom of wellbore 60 to
directional
drilling equipment 50. As discussed later in more detail, directional drilling
system 20
may include an eccentric sleeve, such as those embodied in FIGURES 9-11, for
directional drilling.
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Directional drilling equipment 50 may include one or more electronic devices
configured to monitor and/or control the drilling of wellbore 60. Logging data
and
other information may be communicated from end 62 of wellbore 60 through drill
string 32 using MWD techniques and converted to electrical signals at well
surface 24.
5 Electrical conduit or wires 52 may communicate the electrical signals to
input device
54. The logging data provided from input device 54 may then be directed to a
data
processing system 56. Various displays 58 may be provided as part of
directional
drilling equipment 50. Printer 59 and associated printouts 59a may also be
used to
monitor the performance of drilling string 32, BHA 90 and associated drill bit
100.
10 Outputs 57 may be communicated to various components associated with
operating
drilling rig 22, to various remote locations to monitor and/or control the
performance of
directional drilling system 20, or to users simulating the drilling of
wellbore 60.
Data processing system 56 may include a processor coupled to a memory. The
processor may comprise, for example a microprocessor, microcontroller, digital
signal
processor (DSP), application specific integrated circuit (ASIC), or any other
digital or
analog circuitry configured to interpret and/or execute program instructions
and/or
process data. In some embodiments, the processor may interpret and/or execute
program instructions and/or process data stored in the memory. Such program
instructions or process data may constitute portions of software for carrying
out
simulation, monitoring, or control of the directional drilling described
herein. The
memory may include any system, device, or apparatus configured to hold and/or
house
one or more memory modules; for example, the memory may include read-only
memory, random access memory, solid state memory, or disk-based memory. Each
memory module may include any system, device or apparatus configured to retain
program instructions and/or data for a period of time (e.g., computer-readable
non-transitory media).
Teachings of the present disclosure may be used to simulate drilling a wide
variety of vertical, directional, deviated, slanted and/or horizontal
wellbores with
drilling equipment containing an eccentric sleeve. Teachings of the present
disclosure
may include but are not limited to simulating drilling wellbore 60, designing
drill bits
for use in drilling wellbore 60 or selecting drill bits from existing designs
for use in
drilling wellbore 60.
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Wellbore 60 may be generally described as a directional wellbore or a deviated
wellbore having multiple segments or sections. Section 60a of wellbore 60 may
be
defined by casing 64 extending from well head 24 to a selected downhole
location.
Remaining portions of wellbore 60 may be generally described as "open hole" or
4 Luncased."
Wellbore 60 may be generally described as having multiple sections, segments
or portions with respective values of DLS. The tilt rate for drill bit 100
during
formation of wellbore 60 may be a function of DLS for each segment, section or
portion
of wellbore 60 times the rate of penetration for drill bit 100 during
formation of the
respective segment, section or portion thereof. The tilt rate of drill bit 100
during
formation of straight hole sections or vertical section 60a and horizontal
section 80h (as
illustrated in FIGURE 4C) will be approximately equal to zero. The DLS
capability,
and consequently the tilt rate capability, of drilling equipment such as a
downhole
drilling tool for use in a directional drilling system 20¨for example, a tool
including
drill bit 100¨may be affected by the selection of an eccentric sleeve for
directional
drilling. For example, selection of an eccentric sleeve for directional
drilling as
embodied in FIGURES 9-11 may increase the DLS capability of the directional
drilling
system 20 including drill bit 100. Examples of different DLS values may be
illustrated
in sections 60a-60f.
Section 60a extending from well head 24 may be generally described as a
vertical, straight hole section with a value of DLS approximately equal to
zero. When
the value of DLS is zero, drill bit 100 will have a tilt rate of approximately
zero during
formation of the corresponding section of wellbore 60.
A first transition from vertical section 60a may be described as kick off
section
60b. For some applications the value of DLS for kick off section 60b may be
greater
than zero and may vary from the end of vertical section 60a to the beginning
of a second
transition segment or building section 60c. Building section 60c may be formed
with
relatively constant radius 70c and a substantially constant value of DLS.
Building
section 60c may also be referred to as third section 60c of wellbore 60.
Fourth section 60d may extend from build section 60c opposite from second
section 60b. Fourth section 60d may be described as a slant hole portion of
wellbore 60.
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Section 60d may have a DLS of approximately zero. Fourth section 60d may also
be
referred to as a "holding" section.
Fifth section 60e may start at the end of holding section 60d. Fifth section
60e
may be described as a "drop" section having a generally downward looking
profile.
Drop section 60e may have relatively constant radius 70e.
Sixth section 60f may also be described as a holding section or slant hole
section with a DLS of approximately zero. Section 60f as shown in FIGURE lA is
being formed by drill bit 100, BHA 90, drill string 32 and associated
components of
drilling system 20. Such components may include an eccentric sleeve.
FIGURE 1B is an illustration of an example system operable to simulate
drilling a directional wellbore. System 300 may calculate, for example, bit
walk force,
walk rate and walk angle based at least in part on bit cutter layout, bit gage
geometry,
sleeve size, sleeve geometry, hole size, hole geometry, rock compressive
strength,
inclination of formation layers, bit steering mechanism, bit rotational speed,
penetration rate and dogleg severity. In one embodiment, sleeve size and
sleeve
geometry may include information regarding the eccentric nature of a sleeve to
be used
in drilling the directional wellbore. In another embodiment, dogleg severity
may be
calculated using the sleeve size and or sleeve geometry.
System 300 may include one or more processing resources 310 operable to run
software and computer programs incorporating teachings of the present
disclosure.
Processing resource 310 may comprise, for example a general purpose computer,
microprocessor, microcontroller, digital signal processor (DSP), application
specific
integrated circuit (ASIC), or any other digital or analog circuitry configured
to interpret
and/or execute program instructions and/or process data. The memory resource
320
may include any system, device, or apparatus configured to hold and/or house
one or
more memory modules; for example, the memory resource 320 may include read-
only
memory, random access memory, solid state memory, or disk-based memory. Each
memory module may include any system, device or apparatus configured to retain
program instructions and/or data for a period of time (e.g., computer-readable
non-transitory media). One or more input devices 330 may be operate to supply
data
and other information to processing resource 310 and/or memory resource 320. A
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keyboard, keypad, touch screen and other digital input mechanisms may be used
as an
input device.
Display resource 340 may be operable to display both data input into
processing
resource 310 and the results of simulations and/or calculations performed
therein. A
copy of input data and results of such simulations and calculations may also
be
provided at printer 350.
For some applications, system 300 may be operably coupled with
communication network 360 to accept inputs from remote locations and to
provide the
results of simulation and associated calculations to remote locations and/or
facilities
such as directional drilling equipment 50 shown in FIGURE 1A.
FIGURE 1C is a block diagram representing some of the inputs that may be
used to simulate or cause forming a directional wellbore such as shown in
FIGURE 1A.
Input 370 may include the type of rotary steering system such as point-the-bit
or
push-the bit. Input 370 may also include the drilling mode such as vertical,
horizontal,
slant hole, building, dropping, transition and/or kick-off Operational
parameters 372
may include DLS, WOB, ROP, revolutions-per-minute (RPM) and other parameters.
In one embodiment, DLS may be calculated given parameters, simulation, or
testing
results from using an eccentric sleeve. In another embodiment, WOB may be
reduced
by stick-slip vibration during directional drilling due associated with
frictional torque
due to contact between portions of drilling equipment¨such as a sleeve or side
of a
bit¨and the wellbore. In such embodiments, selection of an eccentric sleeve
such as
those embodied in FIGURES 9-11 may be made with consideration of such
operational
parameters for effective drilling of a wellbore.
Formation information 374 may include soft, medium or hard formation
materials, multiple layers of formation materials, inclination of formation
layers, the
presence of hard stringers and/or the presence of concretions or very hard
stones in one
or more formation layers. Soft formations may include, but are not limited to,
unconsolidated sands, clay, soft limestone and other downhole formations
having
similar characteristics. Medium formations may include, but are not limited
to, calcites,
dolomites, limestone and some shale formations. Hard formation materials may
include, but are not limited to, hard shales, hard limestone and hard
calcites.
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Output 380 may include, but is not limited to, changes in WOB, TOB and/or
any imbalances on associated cutting elements or cutting structures. Output
382 may
include walk angle, walk force and/or walk rate of an associated drill bit.
Outputs 384
may include required build rate, drop rate and/or steering forces required to
form a
desired wellbore profile. Output variations 388 may include variations in any
of the
previous outputs over the length of forming an associated wellbore.
Additional contributors may also be used to simulate and evaluate the
performance of a drill bit and/or other downhole drilling tools in forming a
directional
wellbore. Contributors 390 may include, but are not limited to, the location
and design
of cone cutters, nose cutters, shoulder cutters and/or gage cutters.
Contributors 392
may include the length/width of gage sleeves, taper of gage sleeves, number of
gage
sleeves, geometry of eccentric gage sleeves, axes of rotation of eccentric
gage sleeves,
circumferences and diameters of eccentric gage sleeves, heights and
arrangements of
eccentric gage sleeves, blade spiral and/or under gage dimensions of a drill
bit or other
downhole drilling tool.
Movement or motion of a drill bit and associated drilling equipment in three
dimensions (3D) during formation of a segment, section or portion of a
wellbore may
be defined by a Cartesian coordinate system (X, Y, and Z axes) and/or a
spherical
coordinate system (two angles cp and 0 and a single radius p) in accordance
with
teachings of the present disclosure. Examples of Cartesian coordinate systems
are
shown in FIGURES 2A and 3B. The location of downhole drilling equipment or
tools
and adjacent portions of a wellbore may be translated between a Cartesian
coordinate
system and a spherical coordinate system.
A Cartesian coordinate system generally includes a Z axis and an X axis and a
Y
axis which extend normal to each other and normal to the Z axis. See for
example
FIGURE 2A. A Cartesian bit coordinate system may be defined by a Z axis
extending
along a rotational axis or bit rotational axis of the drill bit. See FIGURE
2A. A
Cartesian hole coordinate system (sometimes referred to as a "downhole
coordinate
system" or a "wellbore coordinate system") may be defined by a Z axis
extending along
a rotational axis of the wellbore. See FIGURE 3B. In FIGURE 2A the X, Y and Z
axes
include subscript (b) to indicate a "bit coordinate system." In FIGURES 3A, 3B
and 3C
the X, Y and Z axes include subscript (h) to indicate a "hole coordinate
system."
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FIGURE 2A is a schematic drawing showing an example drill bit 100. Drill bit
100 may include bit body 120 having a plurality of blades 128 with respective
junk slots
or fluid flow paths 140 formed therebetween. In one embodiment, drill bit 100
may be
a rotary drill bit. A plurality of cutting elements 130 may be disposed on the
exterior
5 portions
of each blade 128. Each blade 128 may include respective gage surface or
gage portion 154. Gage surface 154 may be an active gage and/or a passive
gage.
Respective gage cutter 130g may be disposed on each blade 128. A plurality of
impact
arrestors 142 may also be disposed on each blade 128. In one embodiment, drill
bit 100
may be configured to be used with a downhole drilling tool including an
eccentric
10 sleeve such as those embodied in FIGURES 9-11.
Drill bit 100 may translate linearly relative to the X, Y and Z axes as shown
in
FIGURE 2A (three (3) degrees of freedom). Drill bit 100 may also rotate
relative to the
X, Y and Z axes (three (3) additional degrees of freedom). As a result
movement of
drill bit 100 relative to the X, Y and Z axes as shown in FIGURES 2A and 2B,
drill bit
15 100 may
be described as having six (6) degrees of freedom. During drilling, these
parameters may be expressed by WOB, bit walk forces, RPM, ROP, DLS, bend
length
(BL) and azimuth angle of an associated tilt plane. Thus, factors that affect
WOB
and/or DLS in turn affect the movement of drill bit 100. In one embodiment,
such
factors may include the choice of an eccentric sleeve such as shown in FIGURES
9-11.
When sufficient force from drill string 32 has been applied to drill bit 100,
cutting elements 130 will engage and remove adjacent portions of a downhole
formation at bottom hole or end 62 of wellbore 60. Removing such formation
materials
will allow downhole drilling equipment including drill bit 100 and associated
drill
string 32 to move linearly relative to adjacent portions of wellbore 60.
Various kinematic parameters associated with forming a wellbore using a drill
bit may be based upon RPM and ROP of the drill bit into adjacent portions of a
downhole formation. Arrow 110 in FIGURE 2A may be used to represent forces
which
move drill bit 100 linearly relative to rotational axis 104a. Such linear
forces typically
result from weight applied to drill bit 100 by drill string 32, resulting in
WOB. If there
is no weight on drill bit 100, no axial penetration will occur at end or
bottom hole 62 of
wellbore 60.
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Rotational force 112 may be applied to drill bit 100 by rotation of drill
string 32.
RPM of drill bit 100 may be a function of rotational force 112. Rotation speed
of drill
bit 100 is generally defined relative to the rotational axis of drill bit 100
which
corresponds with Z axis 104.
Arrow 116 indicates rotational forces which may be applied to drill bit 100
relative to X axis 106. Arrow 118 indicates rotational forces which may be
applied to
drill bit 100 relative to Y axis 108. Rotational forces 116 and 118 may result
from
interaction between cutting elements 130 disposed on exterior portions of
drill bit 100
and adjacent portions of bottom hole 62 during the forming of wellbore 60.
Rotational
forces applied to drill bit 100 along X axis 106 and Y axis 108 may result in
tilting of
drill bit 100 relative to adjacent portions of drill string 32 and wellbore
60.
FIGURE 2B is a schematic drawing of drill bit 100 disposed within vertical
section or straight hole section 60a of wellbore 60. During the drilling of a
vertical
section or any other straight hole section of a wellbore, the bit rotational
axis of drill bit
100 will generally be aligned with a corresponding rotational axis of the
straight hole
section. The incremental change or the incremental movement of drill bit 100
in a
linear direction during a single revolution may be represented by AZ in FIGURE
2B.
Rate of penetration of a drill bit is typically a function of both WOB and
RPM.
For some applications a downhole motor (not expressly shown) may be provided
as
part of BHA 90 to also rotate drill bit 100. The ROP of a drill bit is
generally stated in
feet per hour.
The axial penetration of drill bit 100 may be defined relative to bit
rotational
axis 104a in an associated bit coordinate system. An equivalent side
penetration rate or
lateral penetration rate due to tilt motion of drill bit 100 may be defined
relative to an
associated hole coordinate system. Examples of a hole coordinate system are
shown in
FIGURES 3A, 3B and 3C.
FIGURES 3A, 3B and 3C are graphical representations of various kinematic
parameters which may be satisfactorily used to model or simulate drilling
segments or
portions of a wellbore having a value of DLS greater than zero. In one
embodiment,
such kinematic parameters may be associated with the drilling of a wellbore by
a
downhole drilling tool with an eccentric sleeve. The values of the kinetic
parameters
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may be affected by the effects upon DLS or WOB as caused by the choice of an
eccentric sleeve such as those embodied in FIGURES 9-11.
FIGURE 3A shows a schematic cross-section of drill bit 100 in two dimensions
relative to a Cartesian bit coordinate system. The bit coordinate system is
defined in
part by X axis 106 and Y axis 108 extending from bit rotational axis 104a.
FIGURES
3B and 3C show graphical representations of drill bit 100 during drilling of a
transition
segment such as kick off segment 60b of wellbore 60 in a Cartesian hole
coordinate
system defined in part by Z axis 74, X axis 76 and Y axis 78.
A side force is generally applied to a drill bit by an associated directional
drilling system to form a wellbore having a desired profile or trajectory
using the drill
bit. For a given set of drilling equipment design parameters and a given set
of
downhole drilling conditions, a respective side force must be applied to an
associated
drill bit to achieve a desired DLS or tilt rate. Therefore, forming a
directional wellbore
using a point-the-bit directional drilling system, a push-the-bit directional
drilling
system or any other directional drilling system may be simulated by
determining
required bit side force to achieve desired DLS or tilt rate for each segment
of a
directional wellbore.
FIGURE 3A shows side force 114 extending at angle 72 relative to X axis 106.
Side force 114 may be applied to drill bit 100 by directional drilling system
20. Angle
72 (sometimes referred to as an "azimuth" angle) extends from rotational axis
104a of
drill bit 100 and represents the angle at which side force 114 will be applied
to drill bit
100. For some applications side force 114 may be applied to drill bit 100 at a
relatively
constant azimuth angle.
Directional drilling systems such as drill bit steering unit 92b shown in
FIGURE 4A may be used to either vary the amount of side force 114 or to
maintain a
relatively constant amount of side force 114 applied to drill bit 100.
Directional drilling
systems may also vary the azimuth angle at which a side force is applied to a
drill bit to
correspond with a desired wellbore trajectory or drill path. In one
embodiment, the
amount of side force 114 required to achieve a desired DLS or the ability to
select a
particular an azimuth angle may depend upon a choice of an eccentric sleeve
such as
those embodied in FIGURES 9-11.
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During drilling of straight hole segments of wellbore 60, side forces applied
to
drill bit 100 may be substantially minimized (approximately zero side forces)
or may be
balanced such that the resultant value of any side forces will be
approximately zero.
Straight hole segments of wellbore 60 as shown in FIGURE lA include, but are
not
limited to, vertical section 60a, holding section or slant hole section 60d,
and holding
section or slant hole section 60f. During formation of straight hole segments
of
wellbore 60, the primary direction of movement or translation of drill bit 100
will be
generally linear relative to an associated longitudinal axis of the respective
wellbore
segment and relative to associated bit rotational axis 104a.
During the drilling of portions of wellbore 60 having a DLS with a value
greater
than zero or less than zero, a side force (Fs) or equivalent side force may be
applied to
an associated drill bit to cause formation of corresponding wellbore segments
60b, 60c
and 60e.
For some applications such as when a push-the-bit directional drilling system
is
used with a drill bit, an applied side force may result in a combination of
bit tilting and
side cutting or lateral penetration of adjacent portions of a wellbore. For
other
applications such as when a point-the-bit directional drilling system is used
with an
associated drill bit, side cutting or lateral penetration may generally be
small or may not
even occur. When a point-the-bit directional drilling system is used with a
drill bit,
directional portions of a wellbore may be formed primarily as a result of bit
penetration
along an associated bit rotational axis and tilting of the drill bit relative
to a wellbore
axis.
Side force 114 may be adjusted or varied to cause associated cutting elements
130 to interact with adjacent portions of a downhole formation so that drill
bit 100 will
follow profile or trajectory 68a, as shown in FIGURE 3B, or any other desired
profile.
Respective tilting angles of drill bit 100 will vary along the length of
trajectory 68a.
Arrow 174 corresponds with the variable tilt rate of drill bit 100 relative to
vertical at
any one location along trajectory 68a. During movement of drill bit 100 along
profile
or trajectory 68a, the respective tilt angle at each location on trajectory
68a will
generally increase relative to Z axis 74 of the hole coordinate system shown
in FIGURE
3B. For embodiments such as shown in FIGURE 3B, the tilt angle at each point
on
trajectory 68a will be approximately equal to an angle formed by a respective
tangent
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extending from the point in question and intersecting Z axis 74. Therefore,
the tilt rate
will also vary along the length of trajectory 168.
During the formation of kick off segment 60b and any other portions of a
wellbore in which the value of DLS is either greater than zero or less than
zero and is
not constant, drill bit 100 may experience side cutting motion, bit tilting
motion and
axial penetration in a direction associated with cutting or removing of
formation
materials from the end or bottom of a wellbore.
For embodiments as shown in FIGURES 3A, 3B and 3C directional drilling
system 20 may cause drill bit 100 to move in the same azimuth plane 170 during
formation of kick off segment 60b. FIGURES 3B and 3C show relatively constant
azimuth plane angle 172 relative to the X axis 76 and Y axis 78. Arrow 114 as
shown in
FIGURE 3A represents a side force applied to drill bit 100 by directional
drilling
system 20. Arrow 114 may generally extend normal to rotational axis 104a of
drill bit
100. Arrow 114 may also be disposed in tilt plane 170. A side force applied to
a drill
bit in a tilt plane by an associate drill bit steering unit or directional
drilling system may
also be referred to as a "steer force."
During the formation of a directional wellbore such as shown in FIGURE 3B,
without consideration of bit walk, rotational axis 104a of drill bit 100 and a
longitudinal
axis of BHA 90 may generally lie in tilt plane 170. Drill bit 100 may
experience tilting
motion in tilt plane 170 while rotating relative to rotational axis 104a.
Tilting motion
may result from a side force or steer force applied to drill bit 100 by a
directional
steering unit. See FIGURES 4A and 4B. Tilting motion often results from a
combination of side forces and/or axial forces applied to drill bit 100 by
directional
drilling system 20.
If drill bit 100 walks, either left toward X axis 76 or right toward Y axis
78, bit
100 will generally not remain in the same azimuth plane or tilt plane 170
during
formation of kickoff segment 60b. Arrow 177 as shown in FIGURES 3B and 3C
represents a walk force which will cause drill bit 100 to "walk" left relative
to tilt plane
170.
FIGURES 4A-4D are illustrations of various aspects of point-the-bit
directional
drilling systems. Such point-the-bit directional drilling systems may utilize
a fulcrum
point to be formed between an associated bit cutting structure or bit face
profile and
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associated point-the-bit rotary steering system (RSS). The fulcrum point may
be
formed by a sleeve disposed uphole from the associated drill bit. In one
embodiment,
the fulcrum point may be formed by an eccentric sleeve such as those embodied
in
FIGURES 9-11. Such a fulcrum point may be formed by the interaction of a
sleeve of a
5 downhole
drilling tool with a wellbore being drilled. Such contact may form the
fulcrum point necessary to turn the bit to directional drill the wellbore. The
ability to
form a fulcrum further uphole may thus allow a sharper angle of directional
drilling.
FIGURE 4A shows portions of a downhole drilling tool disposed in a generally
vertical section of wellbore 60a as drill bit 100b begins to form kick off
segment 60b.
10 BHA 90b
may include drill bit steering unit 92b which may provide one portion of a
point-the-bit directional drilling system. A point-the-bit directional
drilling system
may usually generate a deflection which deforms portions of an associated
drill string
to direct an associated drill bit in a desired trajectory. There are several
steering or
deflection mechanisms associated with point-the-bit rotary steering systems.
However,
15 a common
feature of point-the-bit RSS may be a deflection angle generated between
the rotational axis of an associated drill bit and longitudinal axis of an
associated
wellbore.
Point-the-bit directional drilling systems may form a directional wellbore
using
a combination of axial bit penetration, bit rotation and bit tilting. Point-
the-bit
20
directional drilling systems may not produce side penetration in as high of
magnitude as,
for example, push-the-bit directional drilling systems. Examples of a point-
the-bit
directional drilling system are the Geo-Pilot Rotary Steerable System and
SlickBore Matched Drilling Service available from Sperry Drilling Services at
Halliburton Company.
Drill bit 100b may extend from BHA 90b to the end 62 of wellbore 60. Sleeve
61 may be included in drill bit 100b or may be coupled to drill bit 100b. In
one
embodiment, sleeve 61 may include one or more cutting blades. The number of
blades
on sleeve 61 may be different than the number of blades on drill bit 100b.
Bottom hole
assembly 90 may be aligned with vertical axis 74 while rotary drill bit 100 is
aligned
with rate of penetration axis 55. Kick-off load 63 may be applied by the side
wall of
wellbore 60 on an uphole portion of drill bit 100b to point-the-bit in the
direction of rate
of penetration axis 55. In a steering mode, the BHA 90b causes more or less of
kick-off
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load 63 to be applied to the uphole portion of the drill bit 100b. The contact
of drill bit
100b at the point of kick-off load 63 acts as a fulcrum point.
FIGURE 4B is a graphical representation showing various parameters
associated with a point-the-bit directional drilling system. Steering unit 92b
may
generally include bent subassembly 96b. A wide variety of bent subassemblies
may be
satisfactorily used to allow drill string 32 to rotate drill bit 100b while
bent subassembly
96b directs or points drill bit 100b at a desired angle away from vertical
axis 74. Bent
subassembly 96b may include sleeve 61 and/or bit 100b.
Bend length 204b may be a function of the distance between fulcrum point 65
and the end of drill bit 100b. Bend length may be used as one of the inputs to
simulate
forming portions of a wellbore, and may be the distance from a fulcrum point
of an
associated bent subassembly to a furthest location on a "bit face" or "bit
face profile" of
an associated drill bit. The furthest location may sometimes be referred to as
the
extreme end of the associated drill bit.
Since bend length associated with a point-the-bit directional drilling system
is
usually relatively small (often less than 12 times associated bit size), most
of the cutting
action associated with forming a directional wellbore may be a combination of
axial bit
penetration, bit rotation and bit tilting. See FIGURE 4A.
Some bent subassemblies have a constant "bent angle." Other bent
subassemblies have a variable or adjustable "bent angle." Bend length 204b is
generally a function of the dimensions and configurations of associated bent
subassembly 96b. As previously noted, side penetration of drill bit will
generally not
occur in a point-the-bit directional drilling system. Arrow 200 represents the
rate of
penetration along rotational axis of drill bit 100b.
FIGURES 4C and 4D show various forces associated with drill bit 100b
attached near sleeve 240 building an angle relative to horizontal segment 60h
of a
wellbore. Uphole portion 242 of sleeve 240 may contact adjacent portions of
horizontal segment 60b to provide desired fulcrum point 155 for point-the-bit
rotary
steering system 92b. Fulcrum point 155 may be utilized to apply directional
force to
steer the bit in directional drilling at a specified angle. The formation of
fulcrum point
155 may allow steering of the bit 100b. The formation of fulcrum point 155
further
uphole may allow a sharper angle of steering of the bit 100b.
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The bit face profile for drill bit 100b in FIGURE 4C may include a recessed
portion or cone shaped with a plurality of cone cutters 130c disposed therein.
Each
blade (not expressly shown) may include a respective nose segment which
defines in
part an extreme downhole end of drill bit 100b. A plurality of nose cutters
130n may be
disposed on each nose segment. Each blade may also have a respective shoulder
extending outward from the respective nose segment. A plurality of shoulder
cutters
130s may be disposed on each blade.
For some applications, drill bit 100b and associated sleeve 240 may be divided
into five zones for use in evaluating building an angle. Interaction of sleeve
240 with
low side 68 in zone 235 may generate stick-slip vibration force 241, which may
be
proportional to the normal forces 184g shown in FIGURE 4D. Thus, the selection
of
type of sleeve 240 and the degree to which sleeve 240 engages the side of the
wellbore
may affect the stick-slip vibration force. The stick-slip vibration force may
be in the
opposite direction as the axial penetration, causing a reduction on WOB. The
reduction
in WOB may decrease the rate of drilling of drill bit 100b.
In FIGURE 4D, zone E may correspond with zone 235 of FIGURE 4C.
Reaction forces or normal forces 184g shown in FIGURE 4D may result from
interactions with respective high sides 67 and low sides 68 of well bore of
horizontal
segment 60h.
In one embodiment, simulations of forming a wellbore may be used to modify
cutting elements, bit face profiles, gages, eccentric sleeves, and other
characteristics of
a drill bit or associated downhole drilling tools. In another embodiment, such
modifications may be made to affect WOB, DLS, side forces, or other
parameters.
Such parameters may be affected by a choice of sleeves such as sleeve 240.
FIGURE 5 is a schematic drawing showing drill bit 100 in solid lines in a
first
position associated with forming a generally vertical section of a wellbore.
Drill bit 100
is also shown in dotted lines in FIGURE 5 showing a directional portion of a
wellbore
such as kick off segment 60a. The graph shown in FIGURE 5 indicates that the
amount
of bit side force required to produce a tilt rate corresponding with the
associated DLS
will generally increase as the dogleg severity of the deviated wellbore
increases. The
shape of curve 194 as shown in FIGURE 5 may be a function of downhole drilling
tool
design parameters and/or associated downhole drilling conditions. For example,
the
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selection of sleeves for a downhole drilling tool may have impact upon DLS and
WOB
and consequently upon the ability to drill a wellbore. Sleeves used with drill
bit 100
may be under gage, tapered gage, full gage, eccentric, or a combination
thereof In a
specific example, selection of an embodiment of an eccentric sleeve as shown
in
FIGURES 9-11 for the downhole drilling tool may increase DLS capabilities,
reducing
the bit side force required to steer the bit and increasing the possible tilt
rate.
FIGURE 6 is a representation of an example drill bit 600 including a sleeve
604
with full gage. Sleeve 604 may have the same or approximately the same
diameter as
other portions of the drill bit 600, or as bit body 602. Bit body 602 may
rotate around
bit rotational axis 606 during drilling. In point-the-bit directional steering
systems, the
bit body 602 may have a long length in order to steer the bit. In one
embodiment, the
long length, shown in FIGURE 6 as bit total length 608, may be greater than
approximately 75% of the diameter of bit body 602, shown in FIGURE 6 as bit
total
diameter 610. Such a relatively long bit length may be used to form a fulcrum
point in
the sleeve 604. A fulcrum point may be the point of contact between a portion
of the bit
body 602 or sleeve 604 and the side of the wellbore 60 as illustrated by
fulcrum point
155 in FIGURE 4C. The fulcrum point may be used to direct, point, or steer the
bit in
directional steering. In one embodiment, the fulcrum point may be formed at or
near
the uphole end of the sleeve 604. The ability to form an effective fulcrum
point may be
manifested by the DLS capabilities of the drill bit 600, which may indicate
how large of
an angle in a wellbore may be directionally drilled by the drill bit 600.
A sleeve such as sleeve 604 with the same or approximately the same diameter
as the bit total diameter 610 may be referred to as a sleeve with full gage.
If sleeve 604
has the same or approximately the same diameter as the bit total diameter 610,
a
fulcrum point in sleeve 604 may be formed with a high certainty. The ability
to form a
fulcrum point in sleeve 604 and specifically the ability to form a fulcrum
point near the
top of sleeve 604 may increase the DLS capability of drill bit 600. However,
frictional
torque due to contact between sleeve 604 and the wellbore that is being
drilled may be
quite high. This frictional torque may lead to stick-slip vibration, and may
lead to a
reduction in effective WOB during directional drilling. This reduction in
effective
WOB may decrease the penetration rate of the drill bit 600.
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FIGURE 7 is a representation of an example drill bit 700 including a sleeve
704
with under gage. Bit body 702 may rotate around bit rotational axis 706 during
drilling.
As described in accordance with FIGURE 6, in point-the-bit directional
steering
systems, the bit body 702 may have a long length in order to steer the bit. In
one
embodiment, such a long length, shown in FIGURE 7 as bit total length 712, may
be
greater than approximately 75% of the diameter of bit body 702, shown in
FIGURE 7
as bit total diameter 710. A relatively long bit length may be used to form a
fulcrum
point in the sleeve 704, which may be used to steer the bit. In one
embodiment, the
fulcrum point may be formed at or near the top of the sleeve 704.
In one embodiment, sleeve 704 may have a diameter that is smaller than the bit
total diameter 710. A gap 708 having a uniform or nearly uniform distance
along the
length of sleeve 704 may be formed between the sleeve 704 and the wellbore.
The gap
708 between the sleeve and the wellbore may cause a lack of contact between
the sleeve
and the wellbore. This lack of contact may reduce the ability to form a
fulcrum point
along the sleeve, or at the uphole end of the sleeve.
FIGURE 8 is a representation of an example drill bit 800 including a sleeve
804
with tapered gage. Bit body 802 may rotate around bit rotational axis 806
during
drilling. As described in accordance with FIGURE 6, in point-the-bit
directional
steering systems, the bit body 802 may have a long length in order to steer
the bit. In
one embodiment, a long length, shown in FIGURE 8 as bit total length 812, may
be
greater than approximately 75% of the diameter of bit body 802, shown in
FIGURE 8
as bit total diameter 810. This relatively long bit length may be used to form
a fulcrum
point in the sleeve 804, which may be used to steer the bit. In one
embodiment, the
fulcrum point may be formed at or near the top of the sleeve 804.
In one embodiment, sleeve 804 may have a diameter approximately equal to the
bit total diameter 810 at the bottom of sleeve 804, which may taper towards
the top of
sleeve 804, at which point the sleeve 804 may have a diameter that is smaller
than the
bit total diameter 810. As a result, a gap 808 may exist between the sleeve
804 and the
wellbore at the top of sleeve 804. The sleeve may be referred to as a sleeve
with tapered
gage. The gap 808 between the portions of the sleeve and the wellbore may
cause a
lack of contact between these portions of the sleeve and the wellbore. The
lack of
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contact may reduce the ability to form a fulcrum point along the sleeve, or at
the uphole
end of the sleeve.
In sleeves such as sleeve 704 and sleeve 804, contact with the wellbore may be
reduced. Consequently, stick-slip vibration may be reduced when compared to
full
5 gage
sleeves such as sleeve 604, which may have greater contact with the wellbore
than
sleeves 704 and 804. A reduction in stick-slip vibration may reduce friction
forces such
as stick-slip vibration force 241 in FIGURE 4C. The reduction in stick-slip
vibration
force 241 may maintain higher levels of WOB, thus effecting greater rates of
drilling.
However, returning to FIGURES 7 and 8, because sleeves 704 and 804 have under
or
10 tapered
gages, contact with the wellbore wall by the sleeve is reduced. Such contact
may be used to form a fulcrum point. Consequently, the ability of sleeves 704
and 804
to form a fulcrum point, and specifically a fulcrum point near the top of
sleeve 704 and
sleeve 804 may be also be reduced. The fulcrum point may be illustrated, for
example,
by fulcrum point 155 of FIGURE 4C.
15 Forming
a fulcrum point in a downhole drilling tool, and specifically near the
top of a sleeve in the downhole drilling tool, may be used to increase the
ability to
directionally drill a borehole with the downhole drilling tool. The DLS
capabilities of a
downhole drilling tool such as 600, 700, or 800 may be directly related to the
ability to
steer the downhole drilling tool in greater angles. The greater the DLS
capability of a
20 downhole
drilling tool, the greater the drilling may be tilted for the purposes of
directional drilling.
Consequently, the design of a sleeve may affect the DLS capabilities of a
given
downhole drilling tool. As described above, in a full gage drill bit such as
600, DLS
capabilities may be better retained with sleeve 604 having a diameter
approximately
25 equal to
the bit total diameter 610. However, in drill bit 700 or drill bit 800, the
under
gage or tapered gage may significantly reduce the dogleg capability of the
downhole
drilling tool because the ability to form a fulcrum point¨specifically, a
fulcrum point
at or near the top of the sleeve¨has been reduced.
FIGURE 9A is a side view of an example embodiment of a drill bit 900
including an eccentric sleeve 904. Drill bit 900 may be designed, simulated,
and/or
implemented in any suitable fashion, including according to the teachings of
FIGURES
1-5. For example, drill bit 900 may implement the sleeve 61 and/or bit 100b of
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FIGURE 4. Drill bit 900 may include a bit body 902 rotating around a bit
rotational
axis 906. In one embodiment, eccentric sleeve 904 may be mass balanced around
a
geometrical axis 908. In another embodiment, eccentric sleeve 904 may be mass
balanced around bit rotational axis 906. Eccentric sleeve 904 may be
implemented by
any drilling sleeve sufficient to fulfill one or more teachings of this
disclosure. In one
embodiment, eccentric sleeve 904 may be implemented by a drilling sleeve
located at
an offset from bit rotational axis 906. In another embodiment, eccentric
sleeve 904
may be offset from bit rotational axis 906 in terms of the geometrical axis
908 being
offset from bit rotational axis 906 by a distance Aa. Bit body 902 and
eccentric sleeve
904 may be configured to rotate around bit rotational axis 906. As drill bit
900 rotates
during drilling, one portion of eccentric sleeve 904 may contact the surface
of the
wellbore 60, and another portions of eccentric sleeve 904 located
approximately one
hundred eighty degrees (180 ) from the first portion may be separated from the
wellbore 60 by a gap having a distance. This distance, AA, may be
approximately equal
to two times Aa, the distance of the offset between the sleeve geometrical
axis 908 and
bit rotational axis 906.
FIGURE 9B is a cross-sectional view from a vertical perspective of an example
embodiment of a drill bit 900 as shown in FIGURE 9A including an eccentric
sleeve
904 and a bit body 902. Eccentric sleeve 904 may be smaller in diameter than
bit body
902. Eccentric sleeve 904 may be aligned at the edge of the circumference of
bit body
902 such that a portion of the exterior of eccentric sleeve 904 is aligned
with a portion
of the exterior of bit body 902. Eccentric sleeve 904 might not extrude past
the exterior
of bit body 902. Bit body 902 may include a bit rotational axis that may
correspond to
the location of the bit rotational axis 906 of FIGURE 9A as it passes through
the
cross-section of bit body 902. Eccentric sleeve 904 may include a geometrical
axis that
may correspond to the location of the geometrical axis 908 of FIGURE 9A as it
passes
through the cross-section of eccentric sleeve 904. The offset of the eccentric
sleeve 904,
Aa, may be equal to the distance between geometrical axis 908 and bit
rotational axis
906. Eccentric sleeve 904 may be offset from bit body 902 such that only a
portion of
eccentric sleeve 904 contacts the surface of the wellbore 60 created by bit
body 902.
During rotation of bit 900, a portions of eccentric sleeve 904 may contact the
surface of
the wellbore 60 and, approximately one-hundred eighty degrees (180 ) from the
point
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of contact, a gap having a distance of AA = 2*Aa may be formed between the
surface of
the wellbore 60 and the eccentric sleeve 904.
In operation, the rotation of a downhole drilling tool including an eccentric
sleeve, for example, as illustrated in FIGURE 9 during drilling may reduce
frictional
torque, reduce stick-slip vibration, and/or increase DLS capability. A
downhole
drilling tool including an eccentric sleeve may rotate to operate an
associated bit.
During drilling of a wellbore 60 using directional drilling system 20 as
illustrated in
FIGURE 1A, a portion of the eccentric sleeve 904 may come into contact with
the
surface of the wellbore 60, providing a fulcrum point on at least a portion of
the
eccentric sleeve 904 at least one time during a single revolution of bit 900.
For example,
drill bit 900 may rotate while engaging bit body 902 during directional
drilling.
Eccentric sleeve 904 may contact the surface of the wellbore 60 sufficiently
to establish
a fulcrum point on a certain percentage of the sleeve's surface area during a
given
revolution of the downhole drilling tool. The percentage of the sleeve's
surface area
may depend upon the offset Aa, the diameter of bit body 902, and the angle of
directional drilling. Simultaneously, the contact area with the wellbore 60 at
any
instance in time may be less than the contact in a downhole drilling tool with
a full gage
sleeve, thus, reducing stick-slip vibration. Thus, the DLS capabilities of a
downhole
drilling tool using an eccentric sleeve may be increased compared to a
downhole
drilling tool using a tapered or under gage sleeve, while also providing
reduced
frictional torque and/or stick-slip vibration.
FIGURE 10A is a side view of an example embodiment of a drill bit 1000
including a sleeve with multiple eccentric segments and/or a bit including
multiple
eccentric sleeves. Drill bit 1000 may be designed, simulated, and/or
implemented in
any suitable fashion, including according to the teachings of FIGURES 1-5. For
example, drill bit 1000 may implement the sleeve 61 and/or bit 100b of FIGURE
4.
Drill bit 1000 may include a bit body 1002 configured to rotate around a bit
rotational
axis 1006. In one embodiment, drill bit 1000 may include a sleeve with one or
more
eccentric sleeve segments. In another embodiment, drill bit 1000 may include
one or
more eccentric sleeves. For example, drill bit 1000 may include a first
eccentric sleeve
1004 and a second eccentric sleeve 1010. In one embodiment, eccentric sleeve
1004
may be mass balanced around a geometrical axis 1008 and eccentric sleeve 1010
may
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be mass balanced around a geometrical axis 1012. In another embodiment, each
of
eccentric sleeves 1004 and 1010 may be individually mass balanced around bit
rotational axis 1006. In yet another embodiment, eccentric sleeves 1004 and
1010
together may be mass balanced around bit rotational axis 1006. Eccentric
sleeves 1004
and 1010 may be implemented by any drilling sleeves sufficient to fulfill one
or more
teachings of this disclosure. Drill bit 1000 and its components, such as bit
body 1002
and eccentric sleeves 1004 and 1010 may be configured to rotate as a single
body
around bit rotational axis 1006.
In one embodiment, eccentric sleeve 1004 may be implemented by a drilling
sleeve or drilling sleeve segment located at an offset from bit rotational
axis 1006.
Eccentric sleeve 1004 may be offset from bit rotational axis 1006 in terms of
the
geometrical axis 1008 being offset from bit rotational axis 1006 by a distance
Aa.
Eccentric sleeve 1010 may be implemented by a drilling sleeve or drilling
sleeve
segment located at an offset from bit rotational axis 1006. Eccentric sleeve
1010 may
be offset from bit rotational axis 1006 in terms of a geometrical axis 1012
being offset
from bit rotational axis 1006 by a distance Ab. The diameter of eccentric
sleeves 1004
and 1010 may be smaller than the diameter of bit 1002. Eccentric sleeves 1004
and
1010 may be arranged at opposite sides of drill bit 1000. Eccentric sleeve
1004 and
eccentric sleeve 1010 may be arranged such that a portion of eccentric sleeve
1004 is
aligned with a first portion of bit body 1002 and a portion of eccentric
sleeve 1010 is
aligned with a second portion of bit body 1002, where the first and second
portions of
bit body 1002 are located approximately 180 from each other. Eccentric
sleeves 1004
and 1010 may be arranged vertically on top of one another.
As drill bit 1000 rotates during drilling, one portion of eccentric sleeve
1004
may contact the surface of the wellbore 60 and another portion of eccentric
sleeve 1004
located approximately 180 from the first portion may be separated from the
surface of
the wellbore 60 by a gap having a distance of AA. The distance of AA may be
approximately equal to two times Aa, the distance of the offset between the
sleeve
geometrical axis 1008 and bit rotational axis 1006. Additionally as drill bit
1000 rotates,
one portion of eccentric sleeve 1010 may be in contact with the surface of the
wellbore
60 and another portion of eccentric sleeve 1010 located approximately 180
from the
first portion may be separated from the surface of the wellbore 60 by a gap
having a
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distance of AB. The distance of AB may be equal to two times Ab, the distance
of the
offset between the sleeve geometrical axis 1012 and bit rotational axis 1006.
In one
embodiment, if the offset of eccentric sleeve 1004 (Aa) and the offset of
eccentric
sleeve 1010 (Ab) are approximately equal, then the distances between the
respective
sleeves and the wellbore 60 wall¨AA and AB¨may also be approximately equal.
FIGURES 10B and 10C are cross-sectional views from a vertical perspective of
an example embodiment of a drill bit 1000 as shown in FIGURE 10A including a
sleeve
with multiple eccentric segments and/or a bit with multiple eccentric sleeves.
FIGURE
10B illustrates the position of eccentric sleeve 1004 relative to bit body
1002, and
FIGURE 10C illustrates the position of eccentric sleeve 1010 relative to bit
body 1002.
Eccentric sleeves 1004 and 1010 may be smaller in diameter than bit body 1002.
Bit
body 1002 may include a bit rotational axis 1006 that may correspond to the
location of
the bit rotational axis 1006 of FIGURE 10A as it passes through the cross-
section of bit
body 1002. Eccentric sleeves 1004 and 1010 may be aligned at the edge of the
circumference of bit body 1002 such that a portion of each of the exterior of
eccentric
sleeves 1004 and 1010 are aligned with portions of the exterior of bit body
1002.
Eccentric sleeves 1004 and 1010 might not extrude past the exterior of bit
body 1002.
Eccentric sleeve 1004 may include a geometrical axis 1008 that corresponds to
the location of the geometrical axis 1008 of eccentric sleeve 1004 of FIGURE
10A as it
passes through the cross-section of eccentric sleeve 1004 in FIGURE 10B. The
offset
of eccentric sleeve 1004, Aa, may be approximately equal to the distance
between
geometrical axis 1008 and bit rotational axis 1006. Eccentric sleeve 1004 may
be offset
from bit body 1002 such that only a portion of eccentric sleeve 1004 contacts
the
surface of the wellbore 60 created by bit body 1002. During rotation, a
portion of
eccentric sleeve 1004 may contact the surface of the wellbore 60 and,
approximately
180 from the point of contact, a gap having a distance of 2*Aa (AA) may be
formed
between the surface of the wellbore 60 and eccentric sleeve 1004.
Eccentric sleeve 1010 may include a geometrical axis 1012. Geometrical axis
1012 may correspond to the location of the geometrical axis 1012 of eccentric
sleeve
1010 of FIGURE 10A as it passes through the cross-section of eccentric sleeve
10 in
FIGURE 10C. The offset of eccentric sleeve 1010, Ab, may be approximately
equal to
the distance between geometrical axis 1012 and bit rotational axis 1006.
Eccentric
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sleeve 1010 may be offset from bit body 1002 such that a portion of eccentric
sleeve
1010 contacts the surface of the wellbore 60 created by bit body 1002. During
rotation,
a portion of eccentric sleeve 1010 may contact the surface of the wellbore 60
and,
approximately 180 from the point of contact, a gap having a distance of 2*Ab
(AB)
5 may be formed between the surface of the wellbore 60 and eccentric sleeve
1010. In
one embodiment, eccentric sleeves 1004 and 1010 may be arranged so that they
each
contact the wellbore 60 approximately 180 apart from each other.
In operation, the rotation of a downhole drilling tool or bit including
eccentric
sleeves such as those in FIGURE 10 during drilling may reduce frictional
torque,
10 reduce stick-slip vibration, and/or increase DLS capability. A downhole
drilling tool
including eccentric sleeves or a sleeve with eccentric segments may rotate to
operate an
associated bit. During drilling of a wellbore 60 using directional drilling
system 20 as
illustrated in FIGURE 1A, a portion of each eccentric sleeve may come into
contact
with surface of the wellbore 60, providing a fulcrum point on at least a
portion of the
15 eccentric sleeves during a single revolution of the bit.
For example, drill bit 1000 may rotate while engaging bit body 1002 during
directional drilling. Eccentric sleeves 1004 and 1010 may contact the surface
of the
wellbore 60 sufficiently to establish a fulcrum point with a certain
percentage of the
sleeve's surface area during a given revolution. The percentage of the
sleeve's surface
20 area may depend upon offsets Aa and Ab, the diameter of bit body 1002,
and the angle
of directional drilling. For example, a downhole drilling tool such as those
embodied
by drill bit 1000 or using bit body 1002, which include dual eccentric
sleeves, may be
able to establish a fulcrum point at least twice during the a single
revolution of the bit.
Simultaneously, the contact area with the wellbore 60 at any instance in time
may be
25 less than the contact in a downhole drilling tool with a full gage
sleeve, thus reducing
stick-slip vibration. Thus, the DLS capabilities of a downhole drilling tool
including
two offset eccentric sleeves or sleeve segments may be increased compared to a
downhole drilling tool using a tapered or under gage sleeve, while also
providing
reduced frictional torque and/or stick-slip vibration.
30 FIGURE 11A is a side view of another example embodiment of a drill bit
1100
including a sleeve with multiple eccentric segments and/or a drill bit with
multiple
eccentric sleeves. Drill bit 1100 may be designed, simulated, and/or
implemented in
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any suitable fashion, including according to the teachings of FIGURES 1-5. For
example, drill bit 1000 may implement the sleeve 61 and/or bit 100b of FIGURE
4.
Drill bit 1100 may contain a bit body 1102 configured to rotate around a bit
rotational
axis 1106. In one embodiment, drill bit 1100 may include a sleeve with one or
more
eccentric sleeve segments. In another embodiment, drill bit 1100 may include
one or
more eccentric sleeves. For example, drill bit 1100 may include eccentric
sleeves,
including a first eccentric sleeve 1103, a second eccentric sleeve 1104, and a
third
eccentric sleeve 1105. In one embodiment, eccentric sleeves 1103, 1104 and
1105 may
each be mass balanced around its own geometrical axis (not shown). In another
embodiment, eccentric sleeves 1103, 1104 and 1105 may each be mass balanced
around bit rotational axis 1106. In yet another embodiment, eccentric sleeves
1103,
1104 and 1105 may together be mass balanced around bit rotational axis 1106.
Eccentric sleeves 1103, 1104 and 1105 may be implemented by any drilling
sleeves
sufficient to fulfill one or more teachings of this disclosure. Drill bit 1100
and its
components, such as bit body 1102, eccentric sleeves 1103, 1104 and 1105 may
be
configured to rotate as a single body around bit rotational axis 1106.
Eccentric sleeves
1103, 1104 and 1105 may be arranged on top of one another in any suitable
order.
In one embodiment, eccentric sleeve 1103 may be implemented by a drilling
sleeve or drilling sleeve segment located at an offset from bit rotational
axis 1106.
Eccentric sleeve 1103 may be offset from bit rotational axis 1106 in terms of
its
geometrical axis (not shown) being offset from bit rotational axis 1106 by a
distance Aa
(not shown). Eccentric sleeve 1104 may be implemented by a drilling sleeve or
drilling
sleeve segment located at an offset from bit rotational axis 1106. Eccentric
sleeve 1104
may be offset from bit rotational axis 1106 in terms of its geometrical axis
(not shown)
being offset from bit rotational axis 1106 by a distance Ab (not shown).
Eccentric
sleeve 1105 may be implemented by a drilling sleeve or drilling sleeve segment
located
at an offset from bit rotational axis 1106. Eccentric sleeve 1105 may be
offset from bit
rotational axis 1106 in terms of its geometrical axis (not shown) being offset
from bit
rotational axis 1106 by a distance Ac (not shown). The diameters of eccentric
sleeves
1103, 1104, and 1105 may each be smaller than the diameter of bit 1106.
Eccentric
sleeves 1103, 1104, and 1105 may be spaced equally or nearly equally apart
around the
outer circumference of the drill bit 1100 or bit body 1102. In one embodiment,
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eccentric sleeves 1103, 1104, and 1105 may be spaced approximately 120 apart.
Eccentric sleeves 1103, 1104 and 1105 may be arranged such that a portion of
eccentric
sleeve 1103 is aligned with a first portion of bit body 1102, a portion of
eccentric sleeve
1104 is aligned with a second portion of bit body 1102, and a portion of
eccentric sleeve
1105 is aligned with a third portion of bit body 1102. The first, second, and
third
portions of bit body 1102 may be located approximately 120 apart. Eccentric
sleeves
1103, 1104 and 1105 may be arranged vertically on top of one another.
As drill bit 1100 rotates during drilling, one portion of eccentric sleeve
1103
may contact the surface of the wellbore 60, and another portion of eccentric
sleeve 1103
located approximately 180 from the first portion may be separated from the
surface of
the wellbore 60 by a gap having a distance of AA (not shown). Such a distance
of AA
may be approximately equal to two times Aa, the distance of the offset between
the
eccentric sleeve 1103 geometrical axis (not shown) and bit rotational axis
1106.
Additionally as drill bit 1100 rotates, one portion of eccentric sleeve 1104
may contact
the surface of the wellbore 60 and another portion of eccentric sleeve 1104
located
approximately 180 from the first portion may be separated from the surface of
the
wellbore 60 by a gap having a distance of AB (not shown). Such a distance of
AB may
be approximately equal to two times Ab, the distance of the offset between the
eccentric
sleeve 1104 geometrical axis (not shown) and bit rotational axis 1106. One
portion of
eccentric sleeve 1105 may contact the surface of the wellbore 60 and another
portion of
eccentric sleeve 1105 located approximately 180 from the first portion may be
separated from the surface of the wellbore 60 by a gap having a distance of AC
(not
shown). Such a distance of AC may be approximately equal to two times Ac, the
distance of the offset between its geometrical axis (not shown) and bit
rotational axis
1106. In one embodiment, if the offsets of eccentric sleeves 1103, 1104 and
1105 are
approximately equal then the distances between the respective sleeves and the
wellbore
60 wall¨AA and AB and AC¨may be approximately equal.
FIGURES 11B, 11C, and 11D are cross-sectional views from a vertical
perspective of an example embodiment of a drill bit as shown in FIGURE 11A
including a sleeve with multiple eccentric segments and/or a bit including
multiple
eccentric sleeves. FIGURE 11B illustrates the position of eccentric sleeve
1103
relative to bit body 1102, FIGURE 11C illustrates the position of eccentric
sleeve 1104
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relative to bit body 1102, and FIGURE 11D illustrates the position of
eccentric sleeve
1105 relative to bit body 1102. Eccentric sleeves 1103, 1104, and 1105 may
each be
smaller in diameter than bit body 1102. Bit body 1102 may include a bit
rotational axis
1106. Bit rotational axis 1106 may correspond to the location of the bit
rotational axis
1106 of FIGURE 11A as it passes through the cross-section of bit body 1102.
Eccentric
sleeves 1103, 1104 and 1105 may be aligned at the edge of the circumference of
bit
body 1102 such that a portion of each of the exterior of eccentric sleeves
1103, 1104
and 1105 are aligned with portions of the exterior of bit body 1102. Eccentric
sleeves
1103, 1104 and 1105 might not extrude past the exterior of bit body 1002.
Eccentric sleeve 1103 may include a geometrical axis 1108. Geometrical axis
1108 may correspond to the location of the geometrical axis (not shown) of
eccentric
sleeve 1103 of FIGURE 11A as it passes through the cross-section of eccentric
sleeve
1103. The offset of eccentric sleeve 1103, Aa, may be approximately equal to
the
distance between geometrical axis 1108 and bit rotational axis 1106. Eccentric
sleeve
1103 may be offset from bit body 1102 such that only a portion of eccentric
sleeve 1103
contacts the surface of the wellbore 60 created by bit body 1102. During
rotation, a
portion of eccentric sleeve 1103 may contact the surface of the wellbore 60,
and,
approximately 180 from the point of contact, a gap having a distance of 2*Aa
(AA)
may be formed between the surface of the wellbore 60 and eccentric sleeve
1103.
Eccentric sleeve 1104 may include a geometrical axis 1112. Geometrical axis
1112 may correspond to the location of the geometrical axis (not shown) of
eccentric
sleeve 1104 of FIGURE 11A as it passes through the cross-section of eccentric
sleeve
1104. The offset of eccentric sleeve 1104, Ab, may be approximately equal to
the
distance between geometrical axis 1112 and bit rotational axis 1106. Eccentric
sleeve
1104 may be offset from bit body 1102 such that only a portion of eccentric
sleeve 1104
contacts the surface of the wellbore 60 created by bit body 1102. During
rotation, a
portion of eccentric sleeve 1104 may contact the surface of the wellbore 60
and,
approximately 180 from the point of contact, a gap having a distance of 2*Ab
(AB)
may be formed between the surface of the wellbore 60 and eccentric sleeve
1104.
Eccentric sleeve 1105 may include a geometrical axis 1116. Geometrical axis
1116 may correspond to the location of the geometrical axis (not shown) of
eccentric
sleeve 1105 of FIGURE 11A as it passes through the cross-section of eccentric
sleeve
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1105. The offset of eccentric sleeve 1105, Ac, may be approximately equal to
the
distance between geometrical axis 1116 and bit rotational axis 1106. Eccentric
sleeve
1105 may be offset from bit body 1102 such that only a portion of eccentric
sleeve 1105
contacts the surface of wellbore 60 created by bit body 1102. During rotation,
a portion
of eccentric sleeve 1105 may contact the surface of the wellbore 60 and,
approximately
180 from the point of contact, a gap having a distance of 2*Ac (AC) may be
formed
between the surface of the wellbore 60 and eccentric sleeve 1105.
Eccentric sleeves 1103, 1104, and 1105 may be arranged around the
circumference of the bit body 1102 or downhole drilling tool in any suitable
fashion. In
one embodiment, eccentric sleeves 1103, 1104, and 1105 may be arranged around
the
circumference of the bit body 1102 or downhole drilling tool in equal or
nearly equal
distribution. In such an embodiment, eccentric sleeves 1103, 1104, and 1105
may be
arranged around the circumference of the bit body 1102 or downhole drilling
tool so
that they each contact the surface of the wellbore 60 approximately 120 apart
from
each other. For example, eccentric sleeve 1103 may be arranged at 0 ,
eccentric sleeve
1104 may be arranged at approximately 120 , and eccentric sleeve 1105 may be
arranged at approximately 240 around the circumference of bit body 1102.
During
drilling of a wellbore 60 using directional drilling system 20 as illustrated
in FIGURE
1A, a portion of each sleeve may come into contact with the surface of the
wellbore 60,
providing a fulcrum point on at least a portion of the eccentric sleeves
during a single
revolution of the bit.
In operation, the rotation of a downhole drilling tool or bit including triple
eccentric sleeves such as those in FIGURE 11 during drilling may reduce
frictional
torque, reduce stick-slip vibration, and/or increase DLS capability. A
downhole
drilling tool including triple eccentric sleeves or a sleeve with triple
eccentric portions
may rotate to operate an associated bit. During such activity while attempting
directional drilling, a portion of each of the eccentric sleeves may contact
the surface of
the wellbore 60 during a revolution of the bit. Each such contact may provide
a portion
in which a fulcrum point may be located during a revolution of the bit.
Eccentric
sleeves 1103, 1104, and 1105 may each contact the surface of the wellbore 60
sufficiently to establish a fulcrum point with a certain percentage of the
sleeve's surface
area during a given revolution. Such a percentage of the sleeve's surface area
may
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depend upon Aa, Ab, and Ac, the size of bit body 1102, and the angle of
directional
drilling. In one example, a triple eccentric sleeve such as those of drill bit
1100 may be
able to establish a fulcrum point at least three times during a single
revolution of the bit.
Simultaneously, the contact area with the wellbore 60 at any instance in time
may be
5 much less than such contact in a downhole drilling tool with a full gage,
thus reducing
stick-slip vibration. The reduction in stick-slip vibration may maintain
higher levels of
WOB and subsequent drilling rates. Thus, the DLS capabilities of such a
downhole
drilling tool including three offset eccentric sleeves or sleeve segments may
be
increased compared a downhole drilling tool using a tapered or under gage
sleeve,
10 while also providing reduced frictional torque and/or stick-slip
vibration.
Although the present disclosure and its advantages have been described in
detail,
it should be understood that various changes, substitutions and alternations
can be made
herein without departing from the spirit and scope of the disclosure as
defined by the
following claims.
