Note: Descriptions are shown in the official language in which they were submitted.
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CARTRIDGE FOR A ROTARY DRILL BIT
The present disclosure relates to a cartridge for a drill bit of a rotary
directional drilling
system. The cartridge may be used to control the direction of a well-bore in a
subsurface
formation. The well-bore may be used for the extraction of hydrocarbons, water
or geothermal
energy or for the installation of utilities, although this disclosure will
focus mainly on drilling
systems for the extraction of hydrocarbons. The present disclosure also
relates to a kit
comprising the cartridge and a drill bit and to a method for directional
drilling of a well-bore in
a formation.
A rotational or rotary drilling system typically comprises a rotary drill bit
arranged at the
end of a drill string. The drill bits are provided with mechanical cutters for
cutting the well-
bore. Examples of rotary drill bits include polycrystalline diamond compact
(PDC) drill bits and
roller cone bits. The drilling string is formed of multiple tubular sections
or pipes which are
added to the drill string as the depth of the well-bore increases. During
drilling, the drill bits
are rotated by rotating the entire drill string using a drive system located
at the surface. When
rotated, the drill bits produce drilling cuttings as they cut through the
formation. Drilling fluid
or drilling mud is pumped down the inside of the drill string to the drill bit
and passes into the
well-bore through nozzles formed in the drill bit. The drilling fluid helps to
lubricate the drilling
process and minerals contained in the drilling fluid help to seal the well-
bore. Another function
of drilling fluid is to carry the drilling cuttings out of the well-bore.
Systems and methods for rotary directional drilling in a subsurface formation
are
known. As used herein, the term "directional drilling" refers to the practice
of drilling a well-
bore in which at least a portion of the well is not vertical. The direction of
the drill string can
be steered or deviated from a straight vertical path to drill the well-bore in
a desired direction.
In the oil and gas industry this can be used to access more of the natural
resources present
in a mineral formation than would otherwise be achievable using conventional
vertical drilling.
For example, the drill bit can be steered into a horizontal direction to
follow a horizontal seam
in a formation to liberate natural resources along a length of the horizontal
seam.
To determine the position and orientation of the drill bit, tools such as
measure-while-
drilling (MWD) tools may be used. Such tools provide the data require to drill
a certain
trajectory. MWD tools may use accelerometers to measure inclination and
magnetometers to
determine azimuth to provide a three-dimensional overview of drilling
progress. Data from the
measurement tools is sent to an operator at the surface via a telemetry
system. Power for the
tools may be provided via a connection to the surface or more commonly by
means of a remote
power source such as a battery or a turbine generator arranged in the flow of
drilling fluid.
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Directional drilling can be achieved by a number of methods. The most common
method is to use a "bent sub" and a positive displacement motor or mud motor.
A bent sub is
a short length of pipe with threaded connections at either end for connection
to the drill string.
The axis of the lower connection is slightly angularly offset (less than 3
degrees) from the axis
of the upper connection. The bent sub is introduced into the drill string near
its downstream
end at a small distance from the drill bit, which tilts the angle of the drill
string below it and also
tilts the axis of the drill bit. It is therefore not possible to rotate the
drill bit by rotating the drill
string due to the angular offset. Instead, a positive displacement motor is
arranged between
the bent sub and the drill bit. In some arrangements the bent sub is integral
to the positive
displacement motor. The positive displacement motor has a drive shaft, which
is connected
to the drill bit, and generates torque by the passage of drilling fluid
through the positive
displacement motor. By pumping drilling fluid down the drill sting and through
the positive
displacement motor, the drill bit can be rotated and a deviated section of
well-bore can be
drilled. However, to continue drilling in a straight line once the direction
of the well-bore has
been changed it is necessary to remove the bent sub from the drill string
which involves pulling
the entire drill string out of the well-bore. This is both time consuming and
costly.
Another method of direction drilling is to use a steerable drilling system. In
one type
of steerable drilling system, the bent sub is placed very close to the drill
bit so that the tilt angle
is much closer to the drill bit compared to the conventional bent sub assembly
and therefore
the offset of the drill bit is much lower. As a result, the drill bit can also
be rotated by rotating
the entire drill string from the surface. Therefore, the steerable drilling
system can be steered
in the direction of the bent sub by pumping drilling fluid to the drill bit
and using a positive
displacement motor to drive the drill bit. To drill in a straight line, the
drill bit can be rotated by
both rotating the drilling string and pumping drilling fluid to the drill bit.
Whilst this will cause
the drill bit to sweep around due to its relatively small offset tilt, any
effect of the tilt angle on
the drill bit will be eliminated or averaged out equally in all directions by
the rotation of the
entire assembly such that the overall drilling direction is in a straight
line. However, sweeping
the bit in this manner can result in increased wear of the drill bit.
Since steerable drilling systems allow direction to be changed whilst rotating
the drill
string, higher rates of penetration and smoother well-bores can be achieved.
Other types of
steerable drilling systems may use different methods of directing the drill
bit in a desired
direction, for example, by using actuatable thrust pads to push the bit in a
lateral direction.
However, such systems may also result in increased wear on the drill bit and
other drilling
components. Furthermore, the requirement for additional components such as a
positive
displacement motors increases the complexity and cost of such systems and
increases the
likelihood of component failure.
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Instead of transferring mechanical force to the formation from a remote
steering unit,
some other types of steerable drilling systems may use drill bit hydraulics to
achieve a steering
force by controlling the flow and direction of drilling fluid exiting the
drill bit. Known systems
and methods of doing this to date have used specially adapted nozzles on the
drill bit to obtain
a directional drilling effect. However, this has required substantial
modifications to
conventional drill bits and often necessitated the use of rotating seals or
valves which
increased the complexity of the system and made the system more vulnerable to
the extreme
operating conditions experienced during drilling operations. In particular,
known systems were
also very susceptible to the severe vibrations and axial loads experienced
during drill and
accurately controlling the direction of fluid flow proved challenging. Such
systems often
required additional sections of pipe to be added to the drilling string to
accommodate the flow
control components, which increased the length of the string. This made the
system more
susceptible to the bending loads encountered as the direction of the drilling
string was being
changed.
The present disclosure has taken the foregoing problems with known rotary
directional
drilling systems into account.
According to an example of the present disclosure, there is provided a
cartridge for a
drill bit of a rotary directional drilling system. The cartridge comprises a
cartridge housing
having an inlet end for receiving drilling fluid from a drill string and an
outlet end at which
drilling fluid can exit the cartridge housing. The cartridge further comprises
a flow diverter
configured to selectively control the flow direction of drilling fluid as the
drilling fluid exits the
cartridge housing.
An example of the present disclosure includes a cartridge for a drill bit of a
rotary
directional drilling system, the cartridge comprising: a cartridge housing
having an inlet end
for receiving drilling fluid from a drill string and an outlet end at which
drilling fluid can exit the
cartridge housing; and a flow diverter; wherein the flow diverter is moveable
relative to the
cartridge housing to selectively control the flow direction of drilling fluid
as the drilling fluid exits
the cartridge housing; wherein the cartridge is adapted to be received within
an internal space
of a drill bit.
An example of the present disclosure includes a cartridge for a drill bit of a
rotary
directional drilling system, the cartridge comprising: a cartridge housing
having an inlet end
for receiving drilling fluid from a drill string and an outlet end at which
drilling fluid can exit the
cartridge housing; a flow diverter configured to selectively control the flow
direction of drilling
fluid as the drilling fluid exits the cartridge housing; and a bearing
assembly for supporting the
flow diverter; wherein the bearing assembly comprises at least one bearing
located at the
outlet end of the cartridge housing.
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An example of the present disclosure includes a cartridge for a drill bit of a
rotary
directional drilling system, the cartridge comprising: a cartridge housing
having an inlet end
for receiving drilling fluid from a drill string and an outlet end at which
drilling fluid can exit the
cartridge housing; a flow diverter configured to selectively control the flow
direction of drilling
fluid as the drilling fluid exits the cartridge housing; and a bearing
assembly for supporting the
flow diverter; wherein the bearing assembly comprises at least one bearing
located within the
cartridge housing.
The inlet end of the cartridge housing may comprise an inlet for receiving a
drilling fluid
from the drill string. The inlet may be an opening in the cartridge housing.
The inlet may be
the only inlet of the cartridge housing. The inlet may be configured to
receive at least 50
percent by volume of the drilling fluid which passes into the drill bit. The
inlet may be configured
to receive at least 80 percent by volume of the drilling fluid which passes
into the drill bit. The
inlet may be configured to receive all of the drilling fluid which passes into
the drill bit.
The outlet end of the cartridge housing may comprise an outlet at which
drilling fluid
passing through the cartridge can exit the cartridge housing. The outlet may
be an opening
in the cartridge housing. The outlet may be the only outlet of the cartridge
housing. The
cartridge may be arranged such that, when the cartridge is received in a drill
bit of a rotary
drilling system, at least 50 percent by volume of the drilling fluid exiting
the cartridge will exit
through the outlet of the cartridge housing. The cartridge may be arranged
such that, when
the cartridge is received in a drill bit of a rotary drilling system, at least
80 percent by volume
of the drilling fluid exiting the cartridge will exit through the outlet of
the cartridge housing. The
cartridge may be arranged such that, when the cartridge is received in a drill
bit of a rotary
drilling system, all drilling fluid exiting the cartridge will exit through
the outlet of the cartridge
housing.
The cartridge uses fluid flow to change the direction of the drill bit during
a directional
drilling operation. In particular, the cartridge uses differential fluid flow
through the nozzles of
a drill bit to change direction. By diverting at least a portion of the
drilling fluid in a selected
direction toward a particular segment of the well-bore, drilling fluid will
exit the nozzle or
nozzles of the drill bit in that segment of the well-bore at a faster
velocity, resulting in a
pressure drop at those nozzles and a differential pressure being established
across the drill
bit and around the sides of the drill bit in the return annulus aligned to the
diverted flow, which
helps to steer the drill bit in a desired direction.
The cartridge may be adapted to be received within an internal space of a
drill bit.
Advantageously, this allows an existing steerable rotary drill bit to be
converted for use in a
directional drilling system without the need to produce a specially designed
drill bit or to modify
the nozzles of the drill bit. Only relatively minor modifications are required
to convert the drill
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bits, which include producing the internal space, or resizing the existing
internal space, within
the drill bit to receive the cartridge. This can be carried out quickly and
easily in a machine
shop. This may lead to time and cost savings for producing steerable drill
bits.
A further advantage of the cartridge being adapted to be received within an
internal
space of a drill bit, is that the cartridge is protected from the drilling
operation and does not
suffer the same wear that other conventional components may exhibit as a
result of being in
physical contact with the well-bore during drilling. The cartridge of the
present disclosure is
smaller and lighter than known apparatus and is better supported by being
located within the
drill bit. Furthermore, locating the cartridge within the drill bit means that
the cartridge moves
around less than if it were outside the drill bit and part of the drill
string, which puts less stress
on the internal components of the cartridge.
The flow diverter may be moveable relative to the cartridge housing to
selectively
control the flow direction of drilling fluid as the drilling fluid exits the
cartridge housing. This
allows the flow diverter to be decoupled from the rotation of the drill string
and the drill bit so
that the flow diverter can be held geostationary to control the directing of
drilling fluid into a
particular segment of the well-bore. It also allows the rotational position of
the flow diverter to
be accurately controlled. As used herein, the term "geostationary" means
stationary or not
moving relative to the surrounding subsurface formation or well-bore. For
example, the flow
diverter can be held geostationary whilst the drill bit rotates about it such
that the flow diverter
is maintained in the same spatial position in relation to the well-bore.
The flow diverter may be located at or proximal to the outlet end or downhole
end of
the cartridge housing. As used herein, the term "downhole" refers to a
direction toward or
facing the bottom of the well-bore. Furthermore, the term "uphole" refers to a
direction toward
or facing the top of the well-bore.
The cartridge may further comprise a bearing assembly for supporting the flow
diverter.
The bearing assembly may comprise at least one bearing located at the outlet
end of the
cartridge housing. Advantageously, by supporting the flow diverter using at
least one bearing
located at the outlet end of the cartridge housing, the flow diverter is
supported at or close to
the point where it is receiving force or pressure. The bearing reduces the
likelihood of the flow
diverter being damaged and helps it continue to turn freely.
The bearing assembly may comprise at least one bearing located within the
cartridge
housing. The at least one bearing located within the cartridge housing may be
positioned
between the inlet of the cartridge housing and the flow diverter. That is, the
at least one
bearing may be positioned upstream of the flow diverter. As such, the at least
one bearing
may be positioned upstream of the outlet end of the cartridge housing.
Locating at least one
bearing for the flow diverter within the cartridge housing and positioned
upstream of the flow
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diverter helps to keep the apparatus for the directional drilling system
compact and arranges
the bearing support close to the flow diverter so that it is well supported at
or close to the point
it is receiving force or pressure. This makes the arrangement stiffer so there
is less bending
of the flow diverter or components it is mounted on. This arrangement also
helps to protect
the at least one bearing.
The bearing assembly may comprise a first thrust bearing located at the outlet
end of
the cartridge housing. This helps the flow diverter resist the axial loads it
encounters from the
column of drilling fluid above it, which flows down the drill string and
strikes the flow diverter
before being diverted.
The first thrust bearing may be a conical bearing. The conical thrust bearing
may
advantageously help the flow diverter to resist both lateral and axial loads
it encounters during
drilling. The first thrust bearing may be configured to rotate about a
longitudinal axis of the
cartridge. The longitudinal axis of the cartridge may be centrally located in
the cartridge.
The first thrust bearing may comprise a pin bearing. The pin bearing may
comprise a
male pin part coupled to the flow diverter. The male pin part may be
configured to cooperate
with a female pin part for receiving and supporting the male pin part. The
female pin part may
be coupled to the drill bit. For example, the female pin part may be formed as
a recess in the
base of a shank bore of the drill bit. The male pin part may have a
substantially conical shape.
The female pin part may be a substantially conical shaped recess. The
substantially conical
shaped recess of the female pin part may correspond to the substantially
conical shape of the
male pin part.
The bearing assembly may comprises a second thrust bearing located within the
cartridge housing. The second thrust bearing further assists the flow diverter
to resist the axial
loads it encounters.
Optionally, the second thrust bearing may comprises a biasing member for
biasing the
position of the flow diverter in an axial direction. The biasing member may
comprise a resilient
element. The biasing member may comprises a spring or elastomeric element. The
biasing
member helps to hold the flow diverter in a fixed axial position. This may
help to prevent the
flow diverter from moving by any significant amount in the axial direction,
such as shaking or
vibrating, during use of the cartridge in a well-bore. This can help to reduce
the likelihood of
damage to the flow diverter and any related components, such as one or more
associated
axial bearing surface, during use of the cartridge in a well-bore. For
example, the biasing
member may help to hold the flow diverter, and any associated first thrust
bearing located at
the outlet end of the flow diverter, against a corresponding bearing surface
of the drill bit.
The bearing assembly may comprise a radial bearing located within the
cartridge
housing. The radial bearing may help the flow diverter resist bending loads
and/or inertial
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loads, which in turn helps to reduce rotational drag. The radial bearing may
comprise a
spacing member and two contact members arranged at each end of the spacing
member.
The contact members may contact the spindle of the cartridge. The contact
members may
comprise one or both of tungsten carbide and polycrystalline diamond.
Preferably, the surface
of the contact members comprises one or both of tungsten carbide and
polycrystalline
diamond. Preferably, each contact member comprises a body formed of a first
material, and
a surface coating formed of a second material, wherein the second material
comprises or
consists of one or both of tungsten carbide and polycrystalline diamond.
The cartridge housing may be configured to rotate with the drill bit. The flow
diverter
may be rotatably mounted within the cartridge housing. This arrangement allows
the flow
diverter to be decoupled from the rotation of the drill bit and drill string
so that it can be held
geostationary for directing drilling fluid into a particular segment of the
well-bore. The cartridge
housing may therefore comprise one or more components for securing the
cartridge housing
in a fixed position within a drill bit.
The flow diverter may be mounted on a spindle. The spindle may be fixedly
attached
to the flow diverter and configured to rotate with the flow diverter. The
spindle may be rotatably
mounted within the radial bearing. This arrangement helps the spindle resist
bending and
radial loads. The spindle may have a length such that the spindle does not
extend outside the
cartridge.
The cartridge may further comprise a support hanger. The support hanger may
support the radial bearing. The support hanger allows the radial bearing to be
mounted
centrally and close to the spindle.
Optionally, the support hanger may be arranged proximal or adjacent to the
flow
diverter. This arrangement reduces the length of spindle between the support
hanger and the
flow diverter, which increases the stiffness of the arrangement and helps
reduce bending and
deflection of the spindle. This reduces rotational drag and helps the flow
diverter to turn freely.
The support hanger may comprise a plurality of apertures to allow drilling
fluid to pass
through the support hanger. This allows the support hanger to span the
internal chamber of
the cartridge housing to centrally support the spindle of the flow diverter
whilst still allowing
drilling fluid to pass through.
The support hanger may be arranged upstream of the flow diverter. The support
hanger may be fixed relative to the cartridge housing. The support hanger may
be fixed to the
inside of the cartridge housing.
The cartridge may further comprise a connector to connect the flow diverter to
a
rotation control unit for controlling the rotational position of the flow
diverter. The connector
may be arranged at one end of the spindle. The connector may be arranged at an
upstream
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or uphole end of the spindle. The connector may be arranged within the
cartridge housing.
This arrangement may help to protect the connector.
The flow diverter may be configured to divert drilling fluid with respect to a
longitudinal
axis of the cartridge. The flow diverter may comprise an eccentric flow-
diverting aperture for
diverting the drilling fluid. In this arrangement, the flow-diverting aperture
is offset from the
longitudinal axis of the cartridge so that fluid is diverted away from the
longitudinal axis, which
helps to divert drilling fluid to a segment of the well-bore via the nozzles
in the drill bit.
The flow diverter may comprise a plate or plate member arranged to occlude or
close
the downhole or downstream open end or outlet end of the cartridge housing.
The plate or
plate member may be a disc-shaped plate. The flow-diverting aperture may
comprise an
arcuate opening in the plate or plate member.
The flow-diverting aperture may be configured to communicate with at least one
inlet
of a nozzle of a drill bit. The cartridge may be configured to direct
substantially all of the drilling
fluid to the inlet of a single nozzle of a drill bit. In this arrangement,
substantially all of the
drilling fluid will exit the drill bit from a single nozzle within a
relatively narrow segment of the
well-bore.
The flow-diverting aperture may be configured to communicate with a plurality
of inlets
of a corresponding plurality of nozzles of a drill bit. For example, the
dimensions of the flow-
diverting aperture may be greater than the space between the inlets to the
nozzles in the drill
bit so that the flow-diverting aperture spans more than one inlet. The
cartridge may be
configured to direct substantially all of the drilling fluid to the inlets of
multiple nozzles of a drill
bit. In this arrangement, substantially all of the drilling fluid will exit
the drill bit from more than
one nozzle within a wider segment of the well-bore compared to an arrangement
in which the
fluid exits a single nozzle.
The cartridge may be adapted to be received within a shank bore of a drill
bit. The
cartridge may be adapted to be received entirely within a shank bore of a
drill bit. This
arrangement means that the cartridge and flow diverting components are
contained within the
drill bit. There is no requirement for additional drill string sections to
house these components
and therefore this arrangement provides for a compact and robust directional
drilling system.
The cartridge housing may comprise a single part. The cartridge housing may
comprise a plurality of parts. The cartridge housing may comprise a tubular
sleeve. The
cartridge housing may comprise a single sleeve. The cartridge housing may
comprise multiple
sleeves.
According to another example of the present disclosure, there is provided a
kit
comprising any of the cartridges described above and a drill bit of a rotary
directional drilling
system. The drill bit may be a PDC bit or a roller cone bit.
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According to another example of the present disclosure, there is provided a
method
for directional drilling of a well-bore in a formation. The method comprises
receiving a
cartridge within an internal space of a drill bit. The cartridge comprises a
cartridge housing
having an inlet end for receiving drilling fluid from a drill string and an
outlet end at which
drilling fluid exits the cartridge housing. The cartridge further comprises a
flow diverter to
selectively control the flow direction of drilling fluid as the drilling fluid
exits the cartridge
housing. The method further comprises using the flow diverter to selectively
direct at least a
portion of the drilling fluid to one or more nozzles of a drill bit.
The method may further comprise connecting the flow diverter to a rotation
control
unit; rotating the flow diverter relative to the rotation of the drill string
in a rotational direction
opposite to that of the drilling drill string; and controlling the rotational
position of the flow
diverter to selectively direct at least a portion of the drilling fluid to one
or more nozzles of a
drill bit.
The cartridge may be received in a drill bit at a drilling site or drilling
rig.
Embodiments of the present disclosure are described below in more detail, by
way of
example only, with reference to the accompanying drawings, in which:
Figure 1 is a longitudinal cross-section of a rotary drill bit which is
configured to receive
the cartridge of the present disclosure.
Figure 2 is a plan view of the drill bit of Figure 1.
Figure 3 is a longitudinal cross-section of an upper part of the drill bit of
Figure 1
showing a cartridge in accordance with an embodiment of the present disclosure
received in
the bit.
Figure 4A is a longitudinal cross-section of a flow diverter and spindle of
the cartridge
of Figure 3.
Figure 4B is a rear or downhole view of a flow diverter and spindle of the
cartridge of
Figure 3.
Figure 5 is a perspective view of the support hanger of the cartridge of
Figure 3.
Figure 6 is a longitudinal cross-section of an upper part of the drill bit of
Figure 1
showing a cartridge in accordance with another embodiment of the present
disclosure
received in the bit.
Figure 7A is a longitudinal cross-section of a flow diverter and spindle of
the cartridge
of Figure 6.
Figure 7B is a rear or downhole view of a flow diverter and spindle of the
cartridge of
Figure 6.
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Figures 8A to 8D are plan views of the drill bit and cartridge assembly of
Figures 3 and
6 showing different positions of the flow-diverting aperture in the flow
diverter relative to one
or more bit windows of the nozzles of the drill bit.
Figure 9A is a schematic illustration of the drill bit and cartridge assembly
of Figures 3
and 6 connected to part of a drill string and arranged in a well-bore of a
subsurface formation.
This figure also shows the forces acting on the drill bit as a result of using
the cartridge of the
present disclosure.
Figure 9B is an uphole view of the arrangement shown in Figure 9A.
Figure 1 shows a rotary drill bit 1 for directional drilling of a well-bore in
an earth or
subsurface formation. The drill bit 1 is a polycrystalline diamond compact
(PDC) bit. However,
it will be appreciated that the cartridge of the present disclosure may be
applied to other types
of drill bit. The drill bit 1 comprises a bit body or shank 2 provided with
mechanical cutting
means in the form of PDC cutters 4. The cutters 4 form a bit face 6 at a
downhole end of the
drill bit 1. During drilling, the bit face 6 is facing and located near the
bottom of a well-bore
(not shown). A longitudinal axis of the drill bit 1 is indicated by line A-A.
A threaded pin connection 10 is provided at an uphole end 12 of the drill bit
1 for
connecting the drill bit 1 to a drill string (not shown). The drill bit 1 has
an inlet port 14 for
receiving drilling fluid from the drill string. The inlet port 14 is the inlet
to shank bore 16 which
defines an internal space 18 within the bit body 2 of the drill bit 1. A
plurality of bit windows
20 are formed in the bottom of shank bore 16. Each bit window 20 marks the
inlet to a fluid
channel 22, which extends from the bit window 20 to a nozzle 24 formed in bit
face 6. It should
be noted that drill bit 1 has three fluid channels 22 and associated bit
windows 20 and nozzles
24 but two of fluid channels are not shown in Figure 1 because they are
outside the plane of
the cross-section. However, three bit windows 20 marking the inlet to each of
the three fluid
channels can be seen in Figure 2.
Drilling fluid (not shown) enters the drill bit 1 via inlet port 14 and flows
through the drill
bit 1 via shank bore 16 and each of the plurality of fluid channels 22 to
nozzles 24, where it is
ejected from the drill bit 1. The drilling fluid flows around the outside of
the drill bit between
the drill bit 1 and the walls of the well-bore (not shown) and back up the
outside of the drill
string to the surface, where it is recycled. The drilling fluid helps to
lubricate the drilling
operation and carry drill cuttings out of the well-bore and back to the
surface.
Figure 2 shows a plan view of the drill bit 1 of Figure 1. Three bit windows
20 are
formed at the bottom of shank bore 16 and communicate with nozzles 24 via
fluid channels
22. Each bit window 20 is formed as a circle sector and sweeps an angular arc
of
approximately 85 degrees. A bit web 26 is arranged between each pair of bit
windows 20 to
separate each of the fluid channels 22.
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Figure 3 shows a longitudinal cross-section of an upper part of the drill bit
1 of Figure
1 showing a cartridge 100 received in the shank bore 16 of the drill bit 1.
The cartridge 100
comprises an upper cartridge sleeve 102a and a lower cartridge sleeve 102b
which forms a
housing of the cartridge 100. The cartridge sleeves 102a and 102b are
generally tubular in
form and an outer surface of the sleeves 102a and 102b makes a close fit with
the internal
surface of the shank bore 16. The cartridge sleeves 102a and 102b rotate with
the drill bit 1.
An internal space within the sleeves 102a and 102b defines a chamber for
receiving drilling
fluid from drill string (not shown). Drilling fluid enters the cartridge 100
via an opening 104 in
the uphole end or inlet end 105 of the upper cartridge sleeve 102a. Drilling
fluid exits the
cartridge 100 at a downhole end or outlet end 107 of the lower cartridge
sleeve 102b.
A valve or flow diverter 106 is located at a downhole end or outlet end 107 of
the lower
cartridge sleeve 102b and is rotatably mounted on a spindle 108 so that the
flow diverter 106
can be decoupled from the rotation of the drill bit 1 and rotate independently
of the drill bit 1.
The spindle 108 is fixedly attached within a central collar arranged at an
uphole side of the
flow diverter 106 and turns with the flow diverter 106. The flow diverter 106
takes the form of
a disc or shallow cylinder and has a length which is less than its diameter.
An outer cylindrical
surface of the flow diverter 106 forms a close fit with an inner surface of
the lower cartridge
sleeve 102b. The flow diverter 106 has an eccentrically located flow-diverting
aperture 110
for allowing drilling fluid to pass out of the cartridge 100 to one of more
flow channels 22
formed in the drill bit 1. The flow diverter 106 diverts drilling fluid with
respect to a longitudinal
axis A-A of the cartridge 100 and drill bit 1 towards the flow-diverting
aperture 110. The flow
diverter closes the outlet end 107 of the cartridge 100 with the exception of
drilling fluid that
can pass through the flow-diverting aperture 110.
The flow diverter 106 is mounted on a first thrust bearing 112 located at the
outlet end
107 of the lower cartridge sleeve 102b. The first thrust bearing 112 comprises
a pin bearing
having a male pin part 112a arranged in a central bore formed in the downhole
end of the flow
diverter 106 and a female part 112b for receiving and supporting the male pin
part 112a
located within a central recess formed in the bottom of the shank bore 16. The
first thrust
bearing 112 helps the flow diverter 106 withstand the axial hydraulic load
placed upon the flow
diverter 106 by the column of drilling fluid above it. This arrangement helps
the flow diverter
106 to turn freely even under the high hydraulic loads experienced during a
drilling operation.
Using a centrally mounted thrust bearing as the first thrust bearing 112 has
been found to
provide better performance compared to a circumferentially mounted thrust
bearing.
A bottom section of the lower cartridge sleeve 102b has a recess 114 which
circumscribes the inner surface of the lower cartridge sleeve 102b. The recess
114
accommodates the cylindrical wall of the flow diverter 106 such that the inner
surface of the
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cylindrical wall of the flow diverter 106 is flush with the inner surface of
the uphole section of
the lower cylindrical sleeve. This arrangement reduces hindrances to fluid
flow through the
cartridge 100 and also reduces the hydraulic load on the flow diverter 106.
The spindle 108 is supported along its length by a bearing hanger or support
hanger
116. The support hanger 116 comprises an inner tubular member 118, through
which the
spindle passes, and an outer tubular member 120, which is received in recessed
portions of
the adjoining parts of the upper 102a and lower 102b cartridge sleeves. The
support hanger
116 rotates with the cartridge sleeves 102a and 102b, which in turn rotate
with the drill bit 1.
Three support legs 122 (only two shown in Figure 3) span an annular gap
between the inner
118 and outer 120 tubular members and support the inner tubular member 118.
The three
support legs 122 are equally circumferentially spaced apart around the inner
tubular member
118 and the spaces between the three support legs 122 allow drilling fluid to
pass through the
annular gap between the inner 118 and outer 120 tubular members of the support
hanger 116.
A radial bearing 124 is arranged inside the hanger support 116 between the
inner
tubular member 118 and the spindle 108. The radial bearing 124 helps the flow
diverter 106
withstand bending and lateral loads placed on the flow diverter 106 and
spindle 108 during
drilling operations. This reduces rotational drag on the flow diverter 106 and
helps the flow
diverter 106 to turn freely even under the high gravitational and vibrational
loads experienced
during a drilling operation. The radial bearing 124 also helps to support the
spindle 108 and
isolate the spindle 108 and flow diverter 106 from rotating with the support
hanger 116 and
drill bit 1.
A second thrust bearing 126 is arranged between the radial bearing 124 and the
flow
diverter 106. The second thrust bearing 126 helps the flow diverter 106 to
withstand axial
loads generated by the vibration and bounce of the drill bit 1 during drilling
operations.
The first thrust bearing 112, second thrust bearing 126 and radial bearing
form a
bearing assembly of the cartridge 100.
An uphole end of the spindle 108 is connected to a drive connection 128 for
connecting
the spindle 108 and flow diverter 106 to a rotation control unit (not shown).
The rotation control
unit is used to control the rotational position of the flow diverter 106 and
to decouple the flow
diverter 106 from the rotation of the drill bit 1. The rotation control unit
can be used to hold
the flow diverter geostationary whilst the drill bit 1 rotates about it.
Consequently, the rotation
control unit can be used to control an angular position of the flow-diverting
aperture 110 from
which drilling fluid exits the shank bore 16 of the drill bit 1.
The cartridge 100 is adapted to be received entirely within the shank bore 16
of the
drill bit 1 and is retained in the shank bore 16 by a retaining clip 130,
which can be quickly
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attached or removed. The shank bore 16 may be modified to receive the
cartridge 100. The
cartridge 100 can be easily and quickly fitted to a properly adapted drill bit
1 at a drilling site.
Figures 4A and 4B show the flow diverter 106 and spindle 108 of Figure 3 in
more
detail. Figure 4A is an uphole perspective longitudinal cross-sectional view
of the spindle 108
and flow diverter 106. The flow-diverting aperture 110 is formed in a downhole
end 106b of
the flow diverter 106 and is radially offset from the longitudinal axis of the
flow diverter 106
and spindle 108 indicated by line A-A. The flow-diverting aperture 110 is
formed as a circle
sector and sweeps an angular arc of approximately 85 degrees. However, it will
be
appreciated that the angular arc of the flow-diverting aperture 110 can be
varied or tuned
depending on the drill bit the cartridge 100 is to be fitted to and the
performance required. The
remaining portion of the downhole end 106b of the flow diverter 106 is closed
and forms a
flow-blocking portion 111 which prevents drilling fluid from flowing through
this portion of the
flow diverter 106.
A recess 132 is formed in the downhole end 106b of the flow diverter 106 at a
location
substantially diametrically opposite the flow-diverting aperture 110. The
recess 132 reduces
the weight of this part of the flow diverter 106 and helps to balance the flow
diverter 106 when
it is rotating by reducing out-of-balance rotational forces. This also helps
to reduce rotational
drag on the flow diverter 106 during a drilling operation. A cylindrical wall
134 of the flow
diverter 106 extends in an uphole direction away from the downhole end 106b of
the flow
diverter 106. The spindle 108 is fixedly attached with a central collar 136
arranged on an
uphole side of the flow diverter 106. A central bore 133 is provide in the
downhole end 106b
of the flow diverter 106 to accommodate the male pin part of the first thrust
bearing (not
shown).
Figure 4B is a downhole perspective view of the flow diverter 106 and spindle
108 of
Figure 3. The cylindrical wall 134 defines an opening 138 at an uphole end
106a of the flow
diverter 106 for receiving drilling fluid. A protrusion or peak 140 is formed
at an uphole side
of the flow diverter 106 which corresponds to, and overlies, the recess 132
formed on the
downhole side (see Figure 4A). The internal profile of the uphole side of the
flow diverter 106
slopes towards the downhole end 106b of the flow diverter 106 on either side
of the peak 140
towards the flow-diverting aperture 110. Therefore a gradient is formed
between the peak 140
and the flow-diverting aperture 110 on either side of the peak 140, which
assists in diverting
drilling fluid flow incident on the uphold side of the flow diverter 106
towards the flow-diverting
aperture 110. Compared to a flat surface perpendicular to the direction of
fluid flow, the
gradient prevents drilling fluid from being brought to an abrupt halt at the
uphole side of the
flow converter 106, which reduces axial hydraulic loads on the flow diverter
106.
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Figure 5 shows the support hanger 116 of the cartridge 100 of Figure 3 in more
detail.
The support hanger 116 comprises an inner tubular member 118 having an
internal passage
119 for mounting the radial bearing (not shown), which in turn holds the
spindle (not shown).
An outer tubular member 120 is also provided and three support legs 122 span
an annular
gap between the inner 118 and outer 120 tubular members. The three support
legs 122
support the inner tubular member 118 and are equally circumferentially spaced
apart around
the inner tubular member 118. The spaces or apertures 123 between the three
support legs
122 allow drilling fluid to pass through the annular gap between the inner 118
and outer 120
tubular members of the support hanger 116.
Figure 6 shows a longitudinal cross-section of an upper part of the drill bit
1 of Figure
1 showing another embodiment of a cartridge 100 received in the shank bore 16
of the drill bit
1. The construction of the cartridge 100 in Figure 6 is similar to that of the
cartridge 100 of
Figure 3 and like references numerals have been used in Figure 6 to refer to
the same parts.
The main differences between the cartridge 100 of Figure 6 and that of Figure
3 is the
configuration of the flow diverter 106, the second thrust bearing 126 and the
radial bearing
124. The differences with the flow diverter are discussed below in reference
to Figures 7A
and 7B.
Similar to Figure 3, the second thrust bearing 126 of the cartridge 100 of
Figure 6 is
arranged between the radial bearing 124 and the flow diverter 106. The second
thrust bearing
126 helps the flow diverter 106 to withstand axial loads generated by the
vibration and bounce
of the drill bit 1 during drilling operations. In Figure 6, the second thrust
bearing 126 comprises
a spring 127 which acts as a biasing member and biases the position of the
flow diverter 106
in an axial direction. The spring acts in two directions: i) biasing the flow
diverter 106 towards
the outlet end 107 of the cartridge 100 to engage the first thrust bearing
112; and ii) biasing
the second thrust bearing 126 against the radial bearing 124. This helps to
keep the flow
diverter in a fixed position at the outlet end 107 of the cartridge 100 and to
reduce the vibration
or bounce experienced by the flow diverter 106, which can lead to damage of
the flow diverter
106.
Similar to Figure 3, the radial bearing 124 of the cartridge 100 of Figure 6
is arranged
inside the hanger support 116 and holds the spindle 108. The radial bearing
124 helps the
flow diverter 106 withstand bending and lateral loads placed on the flow
diverter 106 and
spindle 108 during drilling operations. In Figure 6, the radial bearing 124
comprises a spacing
member 124c and two contact members 124a and 124b arranged at each
longitudinal end of
the spacing member 124c. The contact members 124a and 124b contact the spindle
to
provide bearing support. The spacing member 124c does not contact the spindle
108 but
merely provide structural support to the contact member 124a and 124b. This
arrangement
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reduces the area of the radial bearing 124 in contact with spindle 108 which
helps to reduce
friction between the radial bearing 124 and the spindle 108. The contact
members 124a and
124b are made of tungsten carbide and/or polycrystalline diamond. The length
of the spindle
108 within the radial bearing 124 is coated with tungsten carbide to provide a
hard wearing
surface and improve the longevity of the cartridge 100.
Figures 7A and 7B show the flow diverter 106 and spindle 108 of Figure 6 in
more
detail. Figure 7A is an uphole perspective longitudinal cross-sectional view
of the flow diverter
106 and spindle 108. The flow diverter 106 comprises substantially disc-shaped
plate 109
arranged at a downhole end 106b of the flow diverter 106. A notch is formed in
the outer
circumference of the disc-shaped plate 109 to form a flow-diverting aperture
110, which is
radially offset from the longitudinal axis of the flow diverter 106 and
spindle 108 indicated by
line A-A. The outer circumference of the disc-shaped plate 109 is arranged to
closely conform
to the internal circumference of the housing of the cartridge 100 (see Figure
6) such that
substantially all the drilling fluid passes through the flow diverting
aperture 110. A central bore
133 is provide in the downhole end 106b of the flow diverter 106 to
accommodate the male
pin part of the first thrust bearing (not shown).
Figure 7B is a downhole perspective view of the flow diverter 106 and spindle
108 of
Figure 6. As can be seen in this figure, the flow-diverting aperture 110 is
formed as a circle
sector and sweeps an angular arc of approximately 85 degrees. However, it will
be
appreciated that the angular arc of the flow-diverting aperture 110 can be
varied or tuned
depending on the drill bit the cartridge 100 is to be fitted to and the
performance required. The
remaining portion of the downhole end 106b of the flow diverter 106 is closed
and forms a
flow-blocking portion 111 which prevents drilling fluid from flowing through
this portion of the
flow diverter 106. A central collar or hub 136 is arranged at an uphole end
106a of the disc-
shaped plate 109 and extends in an uphole direction. The spindle 108 is
fixedly attached to
the central hub 136. An annular recess 137 is formed at an uphole end of the
central hub 136
to accommodate the spring and part of the second thrust bearing (not shown).
Figures 8A to 8D are plan views of the drill bit 1 and cartridge 100 assembly
of Figures
3 and 6 each showing the flow-diverting aperture 110 of the flow diverter 106
in a different
position relative to one or more of the bit windows 20 and bit webs 26 of the
drill bit 1 shown
in Figure 2.
In Figure 8A, the flow-diverting aperture 110 in the flow diverter 106 and one
bit window
20 of the drill bit 1 are fully aligned. The flow area of the fluid pathway
through the aperture
110 and bit window 20 is at a maximum. Therefore, the flow velocity of the
drilling fluid through
the fluid pathway is at a minimum and this configuration results in the lowest
pressure drop.
The other two bit windows (not shown) of the drill bit 1 are blocked or
obstructed by the flow-
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blocking portion 111 of the flow diverter 106 such that substantially no
drilling fluid passes
through these bit windows.
In Figure 8B, the flow diverter 106 has rotated a small angular distance
counter-
clockwise and now the flow-diverting aperture 110 in the flow diverter106 is
partially obscured
by one of the bit webs 26 of the drill bit 1. The flow area of the fluid
pathway through the flow-
diverting aperture 110 and bit window 20 has decreased compared to that shown
in Figure
5A. Therefore, the flow velocity of the drilling fluid through the fluid
pathway has increased
and the pressure drop has increased.
In Figure 80, the flow diverter 106 has rotated a further small angular
distance counter-
clockwise and now the full width of the bit web 26 falls within flow-diverting
aperture 110 in the
flow diverter 106, that is, the bit window is obscured to the maximum extent
by the bit web 26.
The flow area of the fluid pathway through the flow-diverting aperture 110 and
bit window 20
is at a minimum. Therefore, the flow velocity of the drilling fluid through
the fluid pathway is at
a maximum and this configuration results in the highest pressure drop.
In Figure 8D, the flow diverter 106 has rotated yet a further small angular
distance
counter-clockwise. As in Figure 50, the full width of the bit web 26 falls
within aperture 110 in
the flow diverter 106, that is, the bit window is again obscured to the
maximum extent by the
bit web 26. However, this time the flow-diverting aperture 110 spans two bit
windows 20. The
flow area of the fluid pathway through the aperture 110 and bit windows 20 is
at a minimum.
Therefore, the flow velocity of the drilling fluid through the fluid pathway
is at a maximum and
this configuration results in the highest pressure drop but this time the
fluid flow is spread over
two bit windows, which in turn communicate with their respective nozzles in
the drill bit 1.
Figures 8A to 8D show the flow diverter 106 rotating to show how it can
communicate
with the bit windows 20 of the drill bit 1. However, during a directional
drilling operation, the
flow diverter 106 will be held geostationary in a fixed angular position
relative to a particular
sector of the well-bore while the drill bit 1 rotates about the flow diverter.
Rotation of the drill
bit will successively rotate the bit windows 20 of the drill bit 1 into
momentary alignment with
the flow-diverting aperture 110. Therefore, as the bit windows 20 are each
communicated
with the flow-diverting aperture 110, drilling fluid will be discharged from
the rotating drill bit 1
either as a single stream from a single nozzle, as in Figures 8A to 80, or as
a dual stream
from two nozzles, as in Figure 8D. However, each of these streams is
sequentially discharged
only into the particular sector of the well-bore corresponding to the angular
position of the flow-
diverting aperture 110.
Figure 9A is a schematic side view of the drill bit 1 and cartridge (not
shown) assembly
of Figures 3 and 6 in operation at a particular point in time. The drill bit 1
is connected to part
of a drill string 200 and arranged in a well-bore 301 of a subsurface
formation 300. Figure 9B
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is an uphole view of the arrangement of Figure 9A showing the cutters 4 and
drilling fluid
nozzles 24a, 24b and 24c arranged on the bit face 6 of the drill bit 1.
In Figures 9A and 9B, the drill bit 1 is being rotated by the drill string 200
using either
a drive system (not shown) located at the surface or a downhole mud motor (not
shown) or
both. The flow diverter of the cartridge 100 is connected to a rotation
control unit (not shown)
which is housed in a section of the drill string 200. The rotation control
unit is counter-rotating
the flow diverter (not shown) at substantially the same rotational speed as
the drill bit 1 such
that the flow diverter is being held geostationary in a constant angular
position relative to the
well-bore 301. The flow-diverting aperture (not shown) of the flow diverter is
angled in the
azimuthal direction of arrow B in Figure 9A which corresponds to the desired
direction of travel.
Therefore, drilling fluid will be discharged from the drill bit 1 into the
particular sector of the
well-bore 301 corresponding to the angular position of the flow-diverting
aperture of the flow
diverter as the nozzles successively align with the flow-diverting aperture.
At this particular
point in time, drilling fluid is exiting the drill bit 1 as a single high-
velocity stream via nozzle 24a
in Figure 9B. The stream of drilling fluid strikes the bottom of the well-bore
301 and rapidly
reverses direction to return to the surface via the annular space formed
between the drill string
200 and the well-bore 301. The diversion of drilling fluid in this manner
causes the drill bit 1
to steer in the direction of arrow B.
VVithout being bound by theory, it is believed that four physical mechanisms
are
involved in steering the drill bit 1. The first physical mechanism is a
hydraulic effect caused
by a pressure differential around the circumference of the drill bit 1. Fluid
flow at high velocity
has a lower static head pressure when compared to fluid flowing at lower
velocity. This
phenomenon is well understood and governed by Bernoulli's fluid energy
equation. As such,
the diverted return flow around the face of one segment of the drill bit 1
produces a pressure
differential around the rotating drill bit circumference which pulls the drill
bit 1 in the direction
of arrow B in Figure 9A towards the diverted flow (which is at a lower
pressure relative to the
remainder of the bit circumference). In effect, the drill bit 1 is pulled
against the formation
providing side force to bias the bit.
The second physical mechanism is also a hydraulic effect and occurs in
addition to the
Bernoulli effect. This mechanism occurs as the diverted fluid flow jets out of
the nozzle 24a
and encounters the subsurface formation 300 prior to rapidly changing
direction and flowing
around the bit as described above. This causes rapid acceleration of the
drilling fluid at the
boundary of the formation 300, which in turn causes a high positive pressure
which acts on a
segment of the bit face 6 as denoted by arrow A in Figure 9A. This creates a
bending moment
denoted by arrow C in Figure 9A which deflects the drill string 200
immediately above the drill
bit 1, producing an angle between the bit face 6 and the formation 300.
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The above two hydraulic effects; Bernoulli and high bit face pressure, are
complimentary and serve to offset and tilt the bit towards the desired tool
face.
The third physical mechanism is preferential erosion at the bit face 6 and is
a product
of biased fluid in one bit segment. The high fluid velocity caused by jetting
at the bit face as
described above produces an abrasion imbalance at the bit face 6. Abrasion
rate is
proportional to fluid velocity, hence the bit face region of high fluid
velocity experiences a
higher abrasion rate when compared to regions of lower fluid velocity. In
simple terms,
material is eroded or washed away ahead of the bit which results in a reduced
'cutting'
requirement and a more general biased direction as the bit proceeds in the
'path of least
resistance'.
The fourth physical mechanism is similar to the third mechanism but in this
case it
relates to erosion around the shoulder or side of the drill bit 1. As the
discharged drilling fluid
turns and heads back toward the surface in the low pressure region (see first
physical
mechanism above), an erosion imbalance will occur at the bit face due to a
region of high fluid
acceleration. These abrasion and erosion effects will preferentially remove
formation material
at bit face regions of high velocity and acceleration. This causes the drill
bit 1 to bias towards
regions of preferentially reduced formation.
Once the directional drilling operation has finished and the drill bit and
drill string have
been pointed in the desired direction, the drill bit can return to drilling in
a straight line. To drill
in a straight line, the flow diverter is rotated at a controlled absolute
rotational speed so that
drilling fluid is delivered to the nozzles of the drill bit in substantially
all angular positions such
that there is no overall lateral resultant force on the drill bit.
