Note: Descriptions are shown in the official language in which they were submitted.
CA 02285759 2004-07-19
ADJUSTABLE GAUGE DOWNHOLE DRILLING ASSEMBLY
TECHNICAL FIELD
The present invention relates to a downhole drilling assembly for use
primarily in directional drilling which drilling assembly includes a downhole
motor and
incorporates an adjustable gauge stabilizer.
BACKGROUND OF THE INVENTION
Directional drilling involves controlling the direction of a wellbore as it is
being drilled. Since wellbores are drilled in three dimensional space, the
direction of a
wellbore includes both its inclination relative to vertical as well as its
azimuth. Usually the
goal of directional drilling is to reach a target subterranean destination
with the drill string.
It is often necessary to adjust the direction of the wellbore frequently while
directional drilling, either to accommodate a planned change in direction or
to compensate
for unintended and unwanted deflection of the wellbore. Unwanted deflection
may result
from a variety of factors, including the characteristics of the formation
being drilled, the
makeup of the bottom hole drilling assembly and the manner in which the
wellbore is being
drilled. Directional drilling typically utilizes a combination of three basic
techniques, each
of which presents its own special features.
First, the entire drill string may be rotated from the surface, which in turn
rotates a drilling bit connected to the end of the drill string. This
technique, sometimes
called "rotary drilling", is commonly used in non-directional drilling and in
directional
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drilling where no change in direction is required or intended. This technique
is
relatively inexpensive because the use of specialized equipment such as
downhole
drilling motors can usually be kept to a minimum, but offers relatively little
control
over the direction of the wellbore.
Second, the drilling bit may be rotated by a downhole motor which is
powered by the circulation of fluid supplied from the surface. This technique,
sometimes called "sliding drilling", is typically used in directional drilling
to effect a
change in direction of a wellbore, such as in the building of an angle of
deflection, and
almost always involves the use of specialized equipment in addition to the
downhole
drilling motor, including bent subs or motor housings, steering tools and
nonmagnetic
drill string components. Furthermore, since the drill string is not rotated
during sliding
drilling, it is prone to sticking in the wellbore, particularly as the angle
of deflection of
the wellbore from the vertical increases. For this reason, and due also to the
relatively
high cost of sliding drilling, this technique is not typically used in
directional drilling
except where a change in direction is to be effected.
Third, rotation of the drill string may be superimposed upon rotation of
the drilling bit by the downhole motor. Although this technique utilizes much
of the
specialized equipment used in the second technique, it may in some cases be
cost
effective because of the high drilling rates that can sometimes be achieved
and also
because a change from sliding drilling to the third technique and back again
can be
made without first tripping the drill string in and out of the wellbore.
The design of the bottom hole assembly of the drill string can enhance the
effectiveness of all three of these techniques. In particular, in all three
techniques the
use of stabilizers in the bottom hole assembly can assist both in reducing
unwanted
deflection of a wellbore and in effecting a desired change in direction of the
wellbore.
Conventional stabilizers can be divided into two broad categories. The
first category includes rotating blade stabilizers which are incorporated into
the drill
string and either rotate or slide with the drill string. The second category
includes non-
rotating sleeve stabilizers which typically comprise a ribbed sleeve rotatably
mounted
on a mandrel so that during drilling operations, the sleeve does not rotate
while the
mandrel rotates or slides with the drill string. Rotating blade type
stabilizers are far
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more common and versatile than non-rotating sleeve stabilizers, which tend to
be used
primarily in hard formations and where only mild wellbore deflections are
experienced.
The primary purpose of using stabilizers in the bottom hole assembly is to
stabilize the drilling bit that is attached to the distal end of the bottom
hole assembly so
that it rotates properly on its axis. When a bottom hole assembly is properly
stabilized,
the weight applied to the drilling bit can be optimized.
A secondary purpose of using stabilizers in the bottom hole assembly is to
assist in steering the drill string so that the direction of the wellbore can
be controlled.
For example, properly positioned stabilizers can assist either in increasing
or decreasing
the deflection angle of the wellbore either by supporting the drill string
near the drilling
bit or by not supporting the drill string near the drilling bit.
Stabilizers are thus versatile tools which are useful in all three directional
drilling techniques. The design of a bottom hole assembly requires
consideration of
where, what type and how many stabilizers should be incorporated into the
drill string.
A single stabilizing point directly above the drill bit will tend to act as a
pivot point for the drill string and may result in the drilling bit pushing to
one side as
weight on bit is increased, thus causing deflection of the wellbore. A second
stabilizing
point may reduce some of this effect, but preferably at least three
stabilizing points are
utilized if a straight wellbore is desired. The specific design of these
stabilization
points, which results in a "packed hole assembly", must be carefully
determined in the
context of the particular application.
In directional drilling applications, the pivot point provided by a near bit
stabilizer can be used to advantage where deflection angle building is
necessary.
Alternatively, the deflection angle of the wellbore can sometimes be reduced
by
eliminating the near bit stabilizer but maintaining one or more stabilizers
further up the
drill string so that the drill string below the stabilizers will tend to drop
down like a
pendulum. This arrangement is sometimes referred to as a "packed pendulum
assembly".
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Since it is usually necessary to adjust the direction of the wellbore
frequently during directional drilling, it can be seen that the desired number
and
location of stabilizers in the drill string may vary from time to time during
drilling.
Unfortunately, the entire drill string must first be removed from the wellbore
in order
to add or remove a conventional stabilizer to or from the drill string. This
is extremely
costly and time consuming.
Furthermore, conventional rotating blade type stabilizers are not
generally suited for use near the drilling bit in situations where a downhole
motor is
used to rotate the drill string, since the stabilizer is then rotated by the
motor along with
the drilling bit, which can result in excessive torque loading on the motor.
In addition,
the stabilizer may be damaged by being rotated in the wellbore at the speeds
produced
by downhole motors.
Some attempts have been made in the prior art to address these problems.
None of these attempts, however, have provided a fully satisfactory solution.
U.S. Patent No. 4,407,377 (Russell) and U.S. Patent No. 4,491,187 (Russell)
both describe an adjustable gauge surface controlled rotating blade type
stabilizer in
which the stabilizer blades can be alternated between retracted and extended
positions
by alternately circulating and not circulating fluid through the stabilizer
body. The
radial position of the stabilizer blades is controlled by a grooved barrel cam
and a
complementary pin which control the axial movement of an expander sleeve
associated
with the stabilizer blades while the fluid is alternately circulated and not
circulated.
The adjustable gauge stabilizer taught by Russell offers flexibility in
drilling procedures
since the stabilizer blades can be extended or retracted downhole without
first
removing the drill string from the wellbore. It is intended, however, to be
connected
directly into the drill string and is therefore not well suited for use as a
near bit
stabilizer in conjunction with a downhole drilling motor. Where the adjustable
gauge
stabilizer described in Russell is used with a downhole drilling motor it must
be
connected into the drill string above the drilling motor, which will place it
a
considerable distance from the drilling bit.
U.S. Patent No. 5,139,094 (Prevedel et al) and U.S. Patent No. 5,181,576
(Askew et al) both describe a downhole drilling assembly including a downhole
motor
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and a near bit rotating blade type stabilizer with stabilizer blades that can
be alternated
between retracted and extended positions. The assembly includes a mandrel, a
sleeve
mounted on the mandrel for limited rotation relative to the mandrel, and
radially
movable members on the sleeve which are extended or retracted by relative
rotation
between the mandrel and the sleeve. The mandrel is further mounted on a
spindle
which is coupled to a drive shaft extending from the power section of the
downhole
motor. As a result, the assembly described in the Prevedel and Askew patents
provides
for adjustable stabilization near the drilling bit in circumstances where a
downhole
motor is used. It is, however, subject to some significant limitations.
First, the extension and retraction of the stabilizer blades is effected
through rotation of the drill string relative to the mandrel. This limits the
control that
can be exercised over the radial position of the stabilizer blades in the
course of
different stages of drilling, since rotation of the drill string in one
direction will extend
the stabilizer blades and rotation of the drill string in the other direction
will retract the
stabilizer blades. As acknowledged in the Prevedel and Askew patents, this can
be
detrimental due to the tendency of the drill string to oscillate about its
longitudinal axis
when sliding drilling is being conducted. In addition, rotation of the drill
string is only
effective to extend and retract the stabilizer blades if the sleeve is in
frictional contact
with the wellbore so that the mandrel can rotate relative to the sleeve as the
drill string
rotates. This requirement may render the stabilizer ineffective in situations
where the
wellbore is washed out.
Second, the stabilizer blades cannot be locked in either of the extended or
retracted positions, which further limits the control that can be exercised
over the radial
position of the stabilizer blades. For example, the stabilizer described in
Prevedel and
Askew is designed to move to the extended position when drilling is taking
place
entirely or partially through rotation of the drill string, and is designed to
move to the
retracted position when sliding drilling is occurring. These positions may be
entirely
inconsistent with the wishes of the drilling crew, but without a locking
mechanism
associated with the stabilizer blades there is no way to perform drilling with
the drill
string rotating while the stabilizer blades are in the retracted position and
there is no
way to perform sliding drilling with the stabilizer blades in the extended
position.
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U.S. Patent No. 5,265,684 (Rosenhauch) and U.S. Patent No. 5,293,945
(Rosenhauch et al) describe a downhole adjustable rotating blade type
stabilizer similar
to that described in the Russell patents, in that the radial position of the
stabilizer blades
can be alternated between extended and retracted positions by circulating or
not
circulating fluid through the stabilizer body. Instead of a barrel cam and
complementary pin, however, the adjustable stabilizer described in Rosenhauch
uses a
locking sleeve to fix the stabilizer blades in either the extended or
retracted positions.
This adjustable stabilizer appears to share the same disadvantages as the
stabilizer
described in Russell, in that it must be connected into the drill string above
the
downhole motor for directional drilling applications. A further disadvantage
of the
stabilizer described in Rosenhauch is that a two step procedure is necessary
to extend
and retract the stabilizer blades, since the stabilizer blades must be moved
radially and
the locking sleeve must be moved into or out of position.
Finally, Sperry-Sun Drilling Services, a division of Dresser Industries, Inc.
manufactures an adjustable gauge rotating blade type stabilizer known as the
Sperry-
Sun AGS (TM) which is similar in principle to the adjustable stabilizer
described in the
Russell patents. In the Sperry-Sun AGS (TM), the radial position of the
stabilizer blades
is controlled by a grooved barrel cam and a complementary pin which control
the axial
movement of a series of ramps associated with the stabilizer blades while
fluid is
alternately circulated and not circulated through the stabilizer body. The
Sperry-Sun
AGS (TM) also includes a mechanism for signalling to the surface by using the
pressure
drop of the circulating fluid through the stabilizer body whether the
stabilizer blades
are in the extended or retracted position. For applications where a downhole
drilling
motor is used, the Sperry-Sun AGS (TM) must be connected into the drill string
above
the downhole motor, a significant distance from the drilling bit, and thus
cannot be
used in such applications as a near bit stabilizer.
There is therefore a need in the drilling industry for a stabilizer having
one or more stabilizer elements which can be moved radially, which stabilizer
can be
connected into a drill string between the power unit of a downhole motor and
the
drilling bit.
By positioning one or more adjustable gauge stabilizers between the
power unit and the drilling bit, perhaps in combination with non-adjustable
stabilizers,
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more control can be maintained over the direction of the wellbore being
drilled while
still allowing for significant flexibility in the design of the bottom hole
assembly. This
flexibility can result in a single drilling assembly being capable of
functioning as a
multitude of bottom hole assembly designs, including a packed hole assembly, a
packed
pendulum assembly, and variations thereof. This flexibility may also result in
a single
bottom hole assembly being capable of establishing build rates and drop rates
in
addition to maintaining a constant angle of deviation during drilling.
There is also a general need in the drilling industry for drilling assemblies
which incorporate components which contribute to the amount of control which
can be
maintained over the direction of the wellbore being drilled, which components
are
ideally located relatively near to the drilling bit.
U.S. Patent No. 5,163,521 (Comeau et al), U.S. Patent No. 5,410,303
(Comeau et al) and U.S. Patent No. 5,602,541 (Comeau et al) describe a system
for
drilling deviated boreholes using a downhole motor in which wellbore
inclination data
is collected by a sensor or sensors positioned below the motor in close
proximity to the
drilling bit, which inclination data is transmitted via acoustic or
electromagnetic signals
to a receiver or receivers positioned above the motor for further transmission
to the
surface. This system is directed at overcoming problems associated with the
reliability
of inclination data which is collected a considerable distance from the
drilling bit.
One disadvantage of the system described in Comeau is that the
inclination sensors are positioned below the bent housing which is associated
with the
downhole motor, with the result that the accuracy of the system is dependent
upon the
toolface position and the bend magnitude of the bent housing.
SUMMARY OF THE INVENTION
The present invention relates to a downhole drilling assembly of the type
which includes a downhole motor for driving a drilling bit without rotating
the drill
string to which the drilling assembly is connected. It further relates to a
downhole
drilling assembly in which a first stabilizer is included between the power
unit of the
downhole motor and connection point for the drilling bit. The first stabilizer
is movable
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radially and is preferably adjustable between one or more retracted positions
and one
or more extended positions.
More particularly, the invention relates to a downhole drilling assembly
comprising a housing having an upper end for connection to a drill string and
a lower
end, a fluid passage extending through the housing from the upper end to the
lower
end, a power unit contained within the housing, a drive assembly extending
within the
housing between the power unit and the lower end of the housing such that a
mandrel
chamber is defined between the drive assembly and the housing, a radially
movable
first stabilizer associated with the housing and located between the power
unit and the
lower end of the housing, an axially movable mandrel contained within the
mandrel
chamber, the mandrel being associated with a stabilizer actuator for causing
radial
movement of the first stabilizer in response to axial movement of the mandrel,
and a
sensor apparatus located between the power unit and the lower end of the
housing for
sensing at least one drilling parameter.
The sensor apparatus is comprised of one or more sensors for gathering
information about at least one drilling parameter relating to drilling
operations or about
the environment in which drilling is taking place. The drilling parameters may
include
any such parameters, including but not limited to wellbore inclination,
wellbore
azimuth, toolface orientation, weight-on-bit, torque, wellbore pressure,
wellbore
temperature, natural gamma ray emissions or mud cake resistivity.
Preferably, the sensor apparatus is comprised of an inclinometer sensor
for sensing the inclination of the drilling assembly. Preferably the
inclinometer sensor
is comprised of an accelerometer, which is preferably a triaxial
accelerometer.
The sensor apparatus may be further comprised of a transmitter for
transmitting information obtained from the sensor or sensors to a surface
communication system. Preferably the power unit is located between the surface
communication system and the sensor apparatus.
The transmitter may be comprised of any device which is capable of
transmitting the information to the surface communication system. Preferably
the
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transmitter is an electrical, magnetic, electromagnetic or acoustic
transmitter. Most
preferably, the transmitter is an acoustic transmitter.
Preferably, the drive assembly is rotatable relative to the housing.
Preferably the mandrel is urged toward the lower end of the housing in
response to a
fluid being passed through the fluid passage from the upper end of the housing
toward
the lower end of the housing. Preferably the first stabilizer is capable of
moving
radially between at least one retracted position and at least one extended
position.
The drilling assembly may further comprise a second stabilizer located
between the power unit and the lower end of the housing. The second stabilizer
may be
any type of adjustable or non-adjustable stabilizer, and may be located
anywhere
between the power unit and the lower end of the housing.
Preferably, the second stabilizer is a non-adjustable stabilizer. Preferably
the second stabilizer is located a first axial distance from the lower end of
the housing
and preferably the first stabilizer is located a second axial distance from
the lower end
of the housing. Preferably the second axial distance is greater than the first
axial
distance.
Preferably, the second stabilizer has a second stabilizer gauge, the first
stabilizer has a retracted gauge when the first stabilizer is in the retracted
position, the
first stabilizer has an extended gauge when the first stabilizer is in the
extended
position, the second stabilizer gauge is greater than the retracted gauge and
the second
stabilizer gauge is less than the extended gauge.
In the preferred embodiment, the first axial distance, the second axial
distance, the second stabilizer gauge, the retracted gauge and the extended
gauge are
selected so that the drilling assembly will provide a build angle during
drilling
operations when the first stabilizer is in the retracted position and so that
the drilling
assembly will provide a drop angle when the first stabilizer is in the
extended position.
The drilling assembly may be further comprised of a bent housing
assembly located between the power unit and the lower end of the housing.
Preferably
the bent housing assembly is located between the sensor apparatus and the
lower end
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of the housing. The bent housing assembly may provide a fixed or adjustable
bend of
any magnitude compatible with the drilling operations being conducted. The
bent
housing assembly may be a separate component of the drilling assembly or it
may be
integrated with other components of the drilling assembly.
Preferably the drilling assembly further comprises a biasing device for
urging the mandrel toward the upper end of the housing. In the preferred
embodiment, the biasing device comprises a spring or springs contained in the
mandrel
chamber which act upon both the housing and the mandrel.
The mandrel may have an upper end which communicates with the fluid
passage so that the mandrel is urged toward the lower end of the housing in
response
to the fluid being passed through the fluid passage from the upper end of the
housing
toward the lower end of the housing.
The first stabilizer may include an inner radial surface which extends into
the mandrel chamber when the first stabilizer is in a retracted position. The
first
stabilizer may include one or more pistons which are moved radially by the
stabilizer
actuator. The first stabilizer may also comprise one or a plurality of
stabilizer elements
which are spaced circumferentially around the housing. In the preferred
embodiment
the first stabilizer includes three stabilizer elements. Each stabilizer
element may
comprise a set of pistons spaced axially along the housing. In the preferred
embodiment each stabilizer element includes five pistons. The set of pistons
may be
spaced linearly or they may be spaced in a spiral or other configuration. One
or more
of the stabilizer elements may further comprise a stabilizer blade connected
to the set of
pistons. Each stabilizer element or piston may extend an equal distance to its
extended
position, or this distance may vary between stabilizer elements or pistons.
Preferably the stabilizer actuator comprises a ramped outer surface for
engagement with the inner radial surface of the first stabilizer to effect
radial movement
of the first stabilizer. Preferably the ramped outer surface increases in
radial dimension
in a direction toward the upper end of the housing.
In the preferred embodiment, the stabilizer actuator comprises a set of
axially spaced ramp rings which move axially with the mandrel, with an equal
number
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of ramp rings to the number of pistons in a set of pistons. Each ramp ring
therefore
actuates a separate piston in a set of pistons. In the preferred embodiment,
where there
are five pistons in each set of pistons and three stabilizer elements, there
are five ramp
rings and each ramp ring actuates one piston in each of the three sets of
pistons.
The drilling assembly may further comprise a balancing piston assembly
associated with the mandrel chamber. Preferably the balancing piston assembly
includes a wellbore fluid compartment and an oil compartment within the
mandrel
chamber, which compartments are separated by a balancing piston. In the
preferred
embodiment, the oil compartment contains the springs of the biasing device,
the barrel
cam and its bearings, and the set of ramp rings. In the preferred embodiment,
the oil
compartment is filled with oil and serves to lubricate the springs of the
biasing device,
the barrel cam and its bearings, the ramp rings and pistons, and also serves
to provide
that when the drilling assembly is in use, a pressure exerted on an outer
radial surface
of the first stabilizer is substantially the same as a pressure exerted on the
inner radial
surface of the first stabilizer.
Preferably a wellbore fluid port, which preferably includes a filter plug to
prevent solid material from entering the drilling assembly, is included on the
housing.
The wellbore fluid port preferably communicates with the balancing piston to
transmit
wellbore pressure to the balancing piston and thus the oil compartment. In the
preferred embodiment, the wellbore fluid compartment and the oil compartment
are
designed so that the balancing piston will move relative to the mandrel so
that the
volume of wellbore fluid contained in the wellbore fluid compartment is
constant for
any axial position of the mandrel.
Preferably the drilling assembly includes an indexing mechanism
associated with the mandrel. In the preferred embodiment, the indexing
mechanism
provides for a first maximum downward position of the mandrel in which the
first
stabilizer is in a retracted position, a second maximum downward position of
the
mandrel in which the first stabilizer is in an extended position, and a
maximum upward
position in which the first stabilizer is in a rest position. In the preferred
embodiment
the indexing mechanism comprises a barrel cam rotatably contained in the
mandrel
chamber and axially movable with the mandrel and a barrel cam pin associated
with the
housing which engages a groove in the barrel cam to control the axial movement
of the
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mandrel. In the preferred embodiment, there is a stop lug associated with the
housing
and a first shoulder, a second shoulder and a third shoulder associated with
the barrel
cam. The stop lug engages the first shoulder when the mandrel is at the first
maximum
downward position, engages the second shoulder when the mandrel is at the
second
maximum downward position and engages the third shoulder when the mandrel is
at
the maximum upward position.
Preferably the drilling assembly includes a signalling device for signalling
whether the mandrel is in the first maximum downward position or in the second
maximum downward position. In the preferred embodiment, the signalling device
comprises a flow restriction device associated with the mandrel and the drive
shaft
which causes the pressure drop experienced by fluid which passes through the
fluid
passage to be different depending upon whether the mandrel is in the first
maximum
downward position or the second maximum downward position.
In the preferred embodiment, the flow restriction device changes the cross
sectional area of the fluid passage depending upon the axial position of the
mandrel in
order to selectively restrict the flow of circulating fluid through the fluid
passage.
Preferably, the drive assembly is supported in the housing by at least one
bearing. In the preferred embodiment, the drive assembly is supported by a
thrust
bearing assembly and by at least three radial bearings which are spaced
axially within
the housing. Finally, the drilling assembly may include a drilling bit
attached to the
drive assembly adjacent to the lower end of the housing.
BRIEF DESCRIPTION OF DRAWINGS
Embodiments of the invention will now be described with reference to the
accompanying drawings, in which:
Figure 1 is a side view schematic drawing of a preferred embodiment of a
drilling assembly according to the present invention;
Figures 2-7 together constitute a detailed longitudinal section view of the
drilling assembly of Figure 1 with the first stabilizer in an extended
position, with
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Figure 3 being a continuation of Figure 2, with Figure 4 being a continuation
of Figure
3, and so on;
Figures 8-13 together constitute a detailed longitudinal section view of the
drilling assembly of Figure 1 with the first stabilizer in a rest position,
with Figure 9
being a continuation of Figure 8, with Figure 10 being a continuation of
Figure 9, and so
on;
Figures 14-19 together constitute a detailed longitudinal section view of
the drilling assembly of Figure 1 with the first stabilizer in a retracted
position, with
Figure 15 being a continuation of Figure 14, with Figure 16 being a
continuation of
Figure 15, and so on;
Figure 20 is a pictorial view of a stabilizer piston according to a preferred
embodiment of the present invention;
Figure 21 is a pictorial view of a ramp ring according to a preferred
embodiment of the present invention;
Figure 22 is a pictorial view of a barrel cam according to a preferred
embodiment of the present invention.
DETAILED DESCRIPTION
The present invention relates to a downhole drilling assembly for
connection to a drill string. It includes a drilling motor for driving a
drilling bit and an
adjustable gauge stabilizer which is located between the power unit of the
motor and
the connection point for the drilling bit.
Conventional downhole motor assemblies comprise a downhole motor
connected to a drive shaft. During drilling operations, the motor assembly is
connected
to the end of a drill string and a drilling bit is connected to the end of the
drive shaft so
that the drilling bit can be driven by the motor without rotation of the drill
string.
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A typical downhole motor assembly includes several component parts
connected end to end. These parts usually include a power unit, a transmission
unit for
connecting the power unit to the drive shaft, a bearing section for supporting
the power
unit and the drive shaft, and a housing for containing the drive shaft. The
housing and
the transmission unit may be straight or they may be bent. They may also be
adjustable
between straight and bent configurations.
A conventional motor assembly may also include a non-adjustable
stabilizer either as part of the housing or as a separate component connected
to the
housing. Another optional feature of a conventional motor assembly is a dump
sub
which is connected above the power unit. The dump sub typically contains a
valve
which is ported to allow fluid flow between the drill string and the annulus
when the
motor assembly is downhole.
The present invention combines a conventional downhole motor assembly
with an adjustable gauge stabilizer into one downhole drilling assembly. In
its
preferred embodiment, and referring to Figure 1 through Figure 22, the
downhole
drilling assembly (20) of the present invention generally includes a housing
(22), a fluid
passage (24), a power unit (26), a drive assembly (28), a first stabilizer
(30) and a
mandrel (32). In the preferred embodiment, the downhole drilling assembly (20)
also
includes a sensor apparatus (23), a bent housing assembly (25) and a second
stabilizer
(27).
The main function of the housing (22) is to contain and protect the various
components of the assembly (20). In the preferred embodiment, the housing (22)
includes an upper end (34) and a lower end (36) and consists of a number of
tubular
sections connected together with threaded connections. From the upper end (34)
to the
lower end (36), these sections include a dump sub housing (38), a power unit
housing
(40), a transmission unit housing (42), an upper radial bearing housing (37),
a piston
housing (50), a spring housing (39), a flow restrictor housing (41), a sensor
crossover
housing (43), a sensor housing (45), a bent housing (47), a bearing housing
(44), and a
bottom housing cap (52).
The fluid passage (24) extends through the interior of the housing (22)
from the upper end (34) to the lower end (36). The upper end (34) of the
housing (22) is
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threaded to enable the assembly (20) to be connected to a drill string (54).
The bent
housing (47) may comprise either a fixed bent housing or an adjustable bent
housing.
The bent housing (47) may also be comprised of one of the other housing
sections
instead of being comprised of a separate bent housing (47).
In the preferred embodiment, the assembly (20) includes a conventional
dump sub (56) which as in conventional downhole motor assemblies permits fluid
flow
between the drill string (54) and the wellbore under certain conditions when
the
assembly (20) is downhole. The dump sub (56) is optional, and any type of dump
sub
(56) or equivalent device may be used with the invention if so desired. If no
dump sub
(56) is included in the assembly (20), the power unit (26) may be connected
directly to
the drill string (54), in which case the upper end (34) of the housing (22) is
the upper
end of the power unit housing (40).
The power unit (26) is contained within the power unit housing (40), and
in the preferred embodiment comprises a conventional positive displacement
downhole
motor which converts hydraulic energy derived from circulating fluid into
mechanical
energy in the form of a rotating rotor shaft (58). Other types of downhole
motors,
including electric motors, may however be used in the invention as long as
they can
provide the requisite rotational or reciprocating energy.
In the preferred embodiment, the main function of the drive assembly (28)
is to transmit rotational and thrust energy from the power unit (26) to a
drilling bit (60)
which is connected to the drive assembly (28) when the assembly (20) is in
use. The
drive assembly (28) is rotatable relative to the housing (22).
In the preferred embodiment, the drive assembly (28) comprises a
transmission shaft (62) which is connected to the rotor shaft (58) by an upper
articulated
connection (64) and a drive shaft (66) which is connected to the transmission
shaft (62)
by a lower articulated connection (68). The transmission shaft (62), the upper
articulated connection (64) and the lower articulated connection (68) are all
contained
within the transmission unit housing (42). The use of the articulated
connections (64,
68) helps to eliminate eccentric motions of the rotor shaft (58) as well as
effects caused
by the use of bent housing sections as part of the assembly (20).
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CA 02285759 1999-10-08
The drive shaft (66) extends through the interior of the upper radial
bearing housing (37), the piston housing (50), the spring housing (39), the
flow restrictor
housing (41), the sensor crossover housing (43), the sensor housing (45), the
bent
housing (47), the bearing housing (44) and protrudes through the bottom
housing cap
(52) past the lower end (36) of the housing (22).
In the preferred embodiment, the drive shaft (66) includes an upper drive
shaft cap (70) which is coupled with a threaded connection to the transmission
shaft (62)
by the lower articulated connection (68). The upper drive shaft cap (70) in
turn is
coupled with a threaded connection to an upper drive shaft (71), which in turn
is
coupled with a threaded connection to a mid drive shaft cap (73), which in
turn is
coupled with a threaded connection to a sensor housing shaft (75), which in
turn is
coupled with an upper bent housing connection (77) to a bent housing shaft
(79), which
in turn is coupled with a lower bent housing connection (81) to a lower drive
shaft cap
(83), which in turn is coupled with a threaded connection to a lower drive
shaft (74).
The lower drive shaft (74) has a lower end (76) which has a box connection
into which
may be connected the drilling bit (60).
The upper drive shaft cap (70), the mid drive shaft cap (73), the sensor
housing shaft (75), the lower drive shaft cap (83) and the lower drive shaft
(74) each
have at least a partially hollow bore so that circulating fluid such as
drilling mud can
pass through the interior of the drive shaft (66). As a result, the fluid
passage (24)
extends partly through the interior of the drive shaft (66) and partly through
the
exterior of the drive shaft (66) by an arrangement of fluid inlet ports and
flow diverter
passages located along the length of the drive shaft (66).
In the preferred embodiment there are four upper fluid inlet ports (78)
spaced equally around the circumference of the upper drive shaft cap (70),
four mid
fluid inlet ports (85) spaced equally around the circumference of the mid
drive shaft cap
(73) and four lower fluid inlet ports (87) spaced equally around the
circumference of the
lower drive shaft cap (83). In the preferred embodiment, there are also four
upper flow
diverter passages (89) spaced equally around the circumference of the upper
drive shaft
cap (70) and four mid flow diverter passages (91) spaced equally around the
circumference of the sensor housing shaft (75). An upper protective sleeve
(93) is
fastened to the inner surface of the upper radial bearing housing (37)
adjacent to the
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upper flow diverter passages (89) with set screws (95) and a mid protective
sleeve (97) is
fastened to the inner surface of the bent housing (47) adjacent to the mid
flow diverter
passages (91) with set screws (101). The purpose of the protective sleeves
(93,97) is to
protect the housing from the abrasive effects of circulating fluid. Other
arrangements
and numbers of fluid inlet ports (78,85,87) and flow diverter passages (89,91)
may be
used.
The fluid inlet ports (78,85,87) permit circulating fluid to pass from the
annular space around the exterior of the drive shaft (66) into the hollow
interior bore of
the drive shaft (66). Conversely, the flow diverter passages (89,91) permit
circulating
fluid to pass from the hollow interior bore of the drive shaft (66) to the
annular space
around the exterior of the drive shaft (66). A small amount of circulating
fluid may pass
through the annular space surrounding the drive shaft (66) along most of the
length of
the drive shaft (66). This small amount of circulating fluid serves primarily
to lubricate
some of the components of the assembly (20).
The first stabilizer (30) is radially adjustable and is actuated by axial
movement of the mandrel (32). The mandrel (32) is contained in a mandrel
chamber
(80) which is defined by an annular space between the drive shaft (66) and the
interior
of the housing (22). In the preferred embodiment, the mandrel chamber (80)
extends for
most of the length of the indexing housing (48) and the piston housing (50).
More
particularly, in the preferred embodiment the mandrel chamber (80) is defined
at one
end by the upper radial bearing housing (37) and at the other end by the
sensor
crossover housing (43). A bulkhead (82) is contained in the mandrel chamber
(80)
adjacent to the connection between the spring housing (39) and the flow
restrictor
housing (41). The function of the bulkhead (82) will be explained in detail
below.
The mandrel (32) has an upper end (84) and a lower end (86), and includes
a number of tubular sections connected together with threaded connections.
From its
upper end (84) to its lower end (86) the mandrel (32) includes an upper
mandrel (88), a
lower mandrel (96) connected to the upper mandrel (88), a lower support
mandrel (103)
connected to the lower mandrel (96) and an orifice retainer (105) connected to
the lower
support mandrel (103). The mandrel (32) is capable of limited axial movement
within
the mandrel chamber (80) in order to actuate the first stabilizer (30). Each
of the
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sections of the mandrel (32) performs a specific function in the operation of
the
assembly (20).
The first stabilizer (30) is associated with the piston housing (50). In the
preferred embodiment the first stabilizer (30) comprises pistons (98)
positioned in
piston seats (100) in the piston housing (50). Referring to Figure 20, each
piston (98) has
an inner radial surface (102) and an outer radial surface (104). The piston
seats (100)
extend through the piston housing (50) into the mandrel chamber (80) so that
the inner
radial surface (102) of each piston (98) interfaces with the mandrel chamber
(32) and the
outer radial surface (104) of each piston (98) interfaces with the exterior of
the piston
housing (50). Each of the pistons (98) includes a piston seal (99) for
providing a seal
between the piston (98) and its corresponding piston seat (100).
In the preferred embodiment, the pistons (98) are capable of radial
movement relative to the piston housing (50) between a number of different
positions,
including a retracted position and an extended position. In the retracted
position, the
outer radial surfaces (104) of the pistons (98) are flush with the exterior of
the piston
housing (50) and the inner radial surfaces (102) of the pistons (98) extend
into the
mandrel chamber (80). In the extended position, the outer radial surfaces
(104) of the
pistons (98) protrude outward from the exterior of the piston housing (50). In
the
preferred embodiment, the pistons (98) are also capable of movement into a
rest
position in which the outer radial surfaces (104) of the pistons (98) are
withdrawn
slightly inside the exterior of the piston housing (50). Figures 2 through 7
depict the
assembly (20) in the extended position. Figures 8 through 13 depict the
assembly (20) in
the rest position. Figures 14 through 19 depict the assembly (20) in the
retracted
position.
The radial position of the first stabilizer (30) is determined by a stabilizer
actuator which is associated with the mandrel (32) and which causes radial
movement
of the first stabilizer (30) in response to axial movement of the mandrel
(32).
Referring to Figure 21, in the preferred embodiment the stabilizer actuator
comprises a set of ramp rings (106) having ramped outer surfaces (108) which
engage
the inner radial surfaces of the pistons (98). The ramp rings (106) are
tubular collars
which are mounted on a narrow section of the upper mandrel (88) between a
shoulder
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(110) on the upper mandrel (88) and the point of connection between the upper
mandrel
(88) and the lower mandrel (96) such that the ramp rings (106) move axially
with the
mandrel (32).
The ramped outer surfaces (108) of the ramp rings (106) extend into the
mandrel chamber (80) in order to engage the inner radial surfaces (102) of the
pistons
(98) and are arranged so that their ramped outer surfaces (108) increase in
radial
dimension in a direction toward the upper end (34) of the housing (22) so that
the
pistons (98) are moved radially outward in response to movement of the mandrel
(32)
toward the lower end (36) of the housing (22). The pistons (98) are maintained
in
engagement with the ramp rings (106) by tracks (112) on the outer ramped
surfaces
(108) of the ramp rings (106) which engage complementary grooves (114) in the
inner
radial surfaces of the pistons (98). The pistons (98) slide along the grooves
(114) in
response to axial movement of the mandrel (32).
In the preferred embodiment, the first stabilizer (30) includes three
stabilizer elements spaced circumferentially around the piston housing (50).
Each
stabilizer element in turn includes a set of pistons (98) spaced axially along
the piston
housing (50). In the preferred embodiment, each set of pistons (98) includes
five pistons
so that the first stabilizer (30) therefore includes fifteen pistons (98)
spaced
circumferentially and axially on the piston housing (50).
In the preferred embodiment, the stabilizer actuator includes five ramp
rings (196) so that a separate ramp ring (106) actuates each piston (98) in a
set of pistons
(98). In addition, each ramp ring (106) actuates one piston (98) in each of
the three
stabilizer elements so that three pistons (98) are therefore actuated by each
ramp ring
(106), and each of the three stabilizer elements and each of the fifteen
pistons (98)
making up the three stabilizer elements extends and retracts the same radial
distance in
response to axial movement of the mandrel (32).
Any number, configuration and shape of stabilizer elements, pistons (98)
and ramp rings (106) may however be used in the assembly (20). In particular,
the
pistons (98) in a set of pistons (98) may be spaced axially in a straight line
or in a
spiralling line depending upon the stabilizer requirements. In the preferred
embodiment, the pistons (98) are spaced axially in a spiralling line.
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The stabilizer elements and pistons (98) may also be designed to extend
and retract unequal distances in response to axial movement of the mandrel
(32). For
example, fewer than three stabilizer elements can be provided or several
stabilizer
elements with different degrees of extension may be used if asymmetrical
stabilization
is desired.
Although the pistons (98) in the preferred embodiment are round, they
may also be elongated or may be any other shape and a set of pistons (98) may
include
only one piston (98). The stabilizer elements may also include stabilizer
blades which in
the preferred embodiment may be connected to the sets of pistons (98) and in
particular
to the outer radial surfaces (104) of the pistons (98). The stabilizer blades
if used may be
of any suitable shape, configuration or material.
The first stabilizer (30) may also include an adjustable sleeve associated
with the stabilizer elements which is capable of rotation relative to the
stabilizer
elements so that the first stabilizer (30) of the present invention can
function as a non-
rotating sleeve type adjustable gauge stabilizer.
The lower mandrel (96) and its associated components provide an
indexing mechanism to facilitate movement of the first stabilizer (30) between
various
positions. In the preferred embodiment, the first stabilizer (30) may be moved
between
a retracted position, an extended position and a rest position. A tubular
barrel cam
(116) is rotatably mounted on the lower mandrel (96) and is supported by an
upper
thrust bearing (118) and a lower thrust bearing (120). The barrel cam (116) is
thus
contained in the mandrel chamber (80) and is capable of rotation relative to
the mandrel
(32). Referring to Figure 22, the barrel cam (116) includes a continuous
groove (122)
around its external circumference. A first position (124) in the groove (122)
corresponds
to a first maximum downward position of the mandrel (32) in which the first
stabilizer
(30) is in the retracted position. A second position (126) in the groove (122)
corresponds
to a second maximum downward position of the mandrel (32) in which the first
stabilizer (30) is in the extended position. A third position (128) in the
groove (122)
corresponds to a maximum upward position of the mandrel in which the first
stabilizer
(30) is in the rest position. There are two locations in the groove (122)
corresponding to
each of the first position (124), the second position (126) and the third
position (128),
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CA 02285759 1999-10-08
with the two locations being separated by 180°. The groove (122) varies
in depth about
the circumference of the barrel cam (116).
The barrel cam further includes a first shoulder (132) at each of the two
first positions (124) in the groove (122), a second shoulder (134) at each of
the two
second positions (126) in the groove (122), and a third shoulder (136) at each
of the two
third positions (128) in the groove (122).
The barrel cam (116) is held on the lower mandrel (96) by a barrel cam nut
(130) which is connected to the lower mandrel (96) with a threaded connection
and held
in place with set screws (131).
In the preferred embodiment, the piston housing (50) includes a pair of
barrel cam bushings (138) which are separated by 180°. These barrel cam
bushings (138)
protrude into the mandrel chamber (80) adjacent to the barrel cam (116). At
least one of
these barrel cam bushings (138) is equipped with a barrel cam pin (140) which
also
protrudes into the mandrel chamber (80) for engagement with the groove (122)
in the
barrel cam (116). The barrel cam pin (140) is spring loaded so that it is
urged into the
mandrel chamber (80) but is capable of limited radial movement in order to
enable it to
move in the groove (122) about the entire circumference of the barrel cam
(116) as the
barrel cam (116) rotates relative to the mandrel (32) and the housing (22).
The variable depth groove (122) in the barrel cam (116) includes steps
along its length so that the barrel cam pin (140) can move only in one
direction in the
groove (122) and will be prevented from moving in the other direction due to
the
combined effects of the spring loading of the barrel cam pin (140) and the
steps in the
groove (122). The groove (122) is configured so that the barrel cam pin (140)
will move
in sequence in the groove (122) to the first position (124), the third
position (128), the
second position (126), the third position (128), the first position (124), the
third position
(128), the second position (126), the third position (128) and so on. In other
words, the
first stabilizer (30) always moves through the rest position between movements
from
the retracted position to the extended position or vice versa.
As the barrel cam pin (140) moves along the groove (122) to the first
position (124), the barrel cam bushings (138) will function as stop lugs and
will engage
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the first shoulders (132) on the barrel cam (116) to support the mandrel (32)
axially
relative to the housing (22). Similarly, as the barrel cam pin (140) moves
along the
groove (122) from the first position (124) to the third position (128) and
then to the
second position (126), the barrel cam bushings (138) will engage the third
shoulders
(136) and the second shoulders (134) on the barrel cam (116) respectively to
support the
mandrel (32) axially relative to the housing (22).
Other types and configurations of indexing mechanisms may be utilized
in the invention, provided that they perform the function of regulating axial
movement
of the mandrel (32) relative to the housing (22).
In the preferred embodiment, the drive shaft (66) is supported radially by
radial bearings at three primary locations along its length. First, a lower
drive shaft
bearing (142) is provided adjacent to the lower end (36) of the housing (22).
More
particularly, the lower drive shaft bearing (142) is located in an annular
space between
the bottom housing cap (52) and the lower drive shaft (74), and is mounted on
the lower
drive shaft (74) for rotation with the lower drive shaft. The lower drive
shaft bearing
(142) thus rotates relative to the bottom housing cap (52).
Second, the mid drive shaft cap (73) is supported by a mid drive shaft
bearing (146) which is located in an annular space between the mid drive shaft
cap (73)
and the sensor crossover housing (43). In the preferred embodiment, the mid
drive
shaft bearing (146) is mounted on the sensor crossover housing (43) with set
screws
(147). The mid drive shaft cap (73) thus rotates relative to the mid drive
shaft bearing
(146).
Third, the upper drive shaft cap (70) is supported by an upper drive shaft
bearing (150) which is located in an annular space between the upper radial
bearing
housing (37) and the upper drive shaft cap (70). In the preferred embodiment,
the
upper drive shaft bearing (150) is mounted on the upper radial bearing housing
(37)
with set screws (152) and the upper drive shaft cap (70) therefore rotates
relative to the
upper drive shaft bearing (150).
In the preferred embodiment, the lower drive shaft bearing (142), the mid
drive shaft bearing (146) and the upper drive shaft bearing (150) are all
fused tungsten
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CA 02285759 1999-10-08
carbide coated journal type bearings which are lubricated with circulating
fluid, but
other types of radial bearing and means of lubrication may be utilized.
The number and location of the radial bearings may be varied as long as
adequate radial support for the drive shaft (66) is provided. In the preferred
embodiment, the lower drive shaft cap (83) is supported by a second lower
drive shaft
bearing (153) which is located in an annular space between the bearing housing
(44) and
the lower drive shaft cap (83). This second lower drive shaft bearing (153) is
mounted
on the bearing housing (44) with set screws (155). In addition, in the
preferred
embodiment, the sensor housing shaft (75) is supported by a sensor housing
drive shaft
bearing (157) which is located in an annular space between the sensor housing
(45) and
the sensor housing shaft (75). This sensor housing drive shaft bearing (157)
is mounted
on the sensor housing (45) with a retaining pin (159).
In the preferred embodiment the lower mandrel (96) and its associated
components also provide a biasing device for urging the mandrel (32) toward
the upper
end (34) of the housing (22). The lower mandrel (96) defines a spring chamber
(154) in
an annular space between the lower mandrel (96) and the piston housing (50)
and the
spring housing (39). A lower spring stop (156) is positioned in the spring
chamber (154)
toward its lower end and is fastened to the spring housing (39) with a
retaining pin
(163). An upper spring stop comprising a spring spacer (160) is positioned in
the spring
chamber (154) at its upper end and abuts the barrel cam nut (130). A return
spring (164)
is contained in the spring chamber (154) between the lower spring stop (156)
and the
spring spacer (160).
The return spring (164) is capable of extension and compression in the
spring chamber (154) through a range corresponding at least to the permitted
axial
movement of the mandrel (32) between the rest position and the extended
position. The
return spring (164) exerts an upward force on the barrel cam nut (130) which
tends to
move the mandrel (32) toward the upper end (34) of the housing (22).
Other forms of biasing mechanism may be utilized in the invention. For
example, other forms of spring or even compressed gases could be contained in
the
spring chamber (154).
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In the preferred embodiment, the upper mandrel (88) also provides an
upper end (84) of the mandrel (32) which communicates with the fluid passage
(24) to
effect downward axial movement of the mandrel (32) when circulating fluid is
circulated through the assembly (20), thus compressing the return spring
(154).
In the preferred embodiment, the lower mandrel (96) defines a balancing
piston chamber (174) located in an annular space between the lower mandrel
(96) and
the spring housing (39). The balancing piston chamber (174) contains an
annular
balancing piston (176) which is axially movable in the balancing piston
chamber (174).
The balancing piston (176) includes seals (178) on its inner radius and its
outer radius
which engage the outer surface of the lower mandrel (96) and the inner surface
of the
spring housing (39) respectively and which prevent fluid from passing by the
balancing
piston (176) in the balancing piston chamber (174).
In the preferred embodiment, a wellbore fluid compartment (180) is
defined by that portion of the balancing piston chamber (174) which is located
below
the balancing piston (176). One end of an oil compartment (182) is defined by
that
portion of the balancing piston chamber (174) which is located above the
balancing
piston (176).
The function of the wellbore fluid compartment (180) is to expose the
balancing piston (176) to the downhole pressure of the wellbore adjacent to
the
assembly (20). A wellbore fluid port and filter plug (184) are located on the
spring
housing (39) adjacent to the wellbore fluid compartment (180) and communicate
with
the wellbore fluid compartment (180) for this purpose. Since the wellbore
fluid
compartment (180) should be exposed to the downhole pressure of the wellbore
and not
the pressure through the interior of the assembly (20), a seal is provided
near the lower
end (86) of the mandrel (32) to prevent wellbore fluids from escaping the
wellbore fluid
compartment (180) and to prevent other fluids from entering the wellbore fluid
compartment (180).
The oil compartment (182) extends axially from the balancing piston (176)
to the upper end (84) of the mandrel (32) in an annular space located between
the
housing (22) and the mandrel (32). The function of the oil compartment is
twofold.
First, it serves to lubricate the various components associated with the
spring chamber
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CA 02285759 1999-10-08
(154), the barrel cam (116) and the first stabilizer (30). Second, the oil
compartment
(182) transmits the downhole pressure of the wellbore from the balancing
piston (176)
to the first stabilizer (30), and in particular to the inner radial surfaces
(102) of the
pistons (98) so that only the differential pressure required to overcome the
upward
force exerted on the mandrel (32) by the return spring (164) will be necessary
to move
the mandrel (32) toward the lower end (36) of the housing (22) and thus extend
the
stabilizer elements. A sealable oil compartment filling port (186) is provided
in the
piston housing (50) to allow filling of the oil compartment (182).
In addition, since the oil compartment (182) must be segregated from
circulating fluid and from wellbore fluid, seals are provided on many of the
components defining the oil compartment (182) to prevent oil from escaping the
oil
compartment (182) and to prevent other fluids from entering the oil
compartment (182).
In particular, seals are provided at the upper end (84) of the mandrel (32)
and at the
point of connection between the upper mandrel (88) and the lower mandrel (96).
The
piston seals (99) also provide a seal between the pistons (98) and the piston
seats (100).
One of the preferred features of the present invention is the specific design
of the wellbore fluid compartment (180) and the oil compartment (182), which
preferably maintain a constant volume of wellbore fluid in the wellbore fluid
compartment (180) regardless of the axial position of the mandrel (32)
relative to the
housing (22). In other words, the volume of the wellbore fluid compartment
(180) is
designed to remain constant. The importance of this feature is that it will
reduce the
action of solid materials contained in the wellbore fluid being alternately
drawn into
and expelled from the wellbore fluid compartment (180) as the mandrel (32)
moves
axially in the housing (22), which action can clog the filter plug (184) or
even the entire
wellbore fluid compartment (180) with solid particles which are suspended in
the
wellbore fluid.
This design is achieved in the preferred embodiment first, by fastening the
bulkhead (82) to the housing (22), and second, by ensuring that the balancing
piston
(176) at all times remains stationary relative to the housing (22) so that the
position of
the balancing piston (176) relative to the bulkhead (82) is constant for all
axial positions
of the mandrel (32). This in turn ensures that the volume of the wellbore
fluid
compartment (180) remains constant for all axial positions of the mandrel
(32). In the
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CA 02285759 1999-10-08
preferred embodiment, the bulkhead (82) is fastened to the spring housing (39)
with a
retaining pin (181).
Referring to Figures 2 through 19, it can be seen that movement of the
balancing piston (176) relative to the mandrel (32) from the maximum upward
position
to the second maximum downward position reduces the overall length of the oil
compartment (182) by an amount equal to the distance travelled by the
balancing piston
(176), which in turn reduces the volume of the oil compartment (182) by an
amount
equal to the distance travelled by the balancing piston (176) multiplied by
the cross
sectional area of the balancing piston (176). As the pistons (98) move outward
radially
in response to downward movement of the mandrel (32), however, the volume of
the
oil compartment (182) adjacent to the pistons (98) increases.
As a result, the desired design effect of the preferred embodiment can be
accomplished by ensuring that when the mandrel (32) is moved axially downward
the
increased volume of oil needed to fill the oil compartment (182) adjacent to
the pistons
(98) is equal to the reduced volume of the oil compartment (182) caused by
downward
movement of the mandrel (32), and by ensuring that the reverse occurs when the
mandrel (32) is moved axially upward. The volume of oil displaced by axial
movement
of the balancing piston (176) must therefore be carefully matched with the
volume of oil
displaced by radial movement of the pistons (98).
In the preferred embodiment, this effect is further achieved by sizing the
cross sectional area of the balancing piston (176) to match the cross
sectional area of the
bulkhead (82) so that the volume of that portion of the wellbore fluid
compartment
(180) adjacent to the bulkhead (82) changes in response to axial movement of
the
mandrel (32) by an amount equal to the change in volume caused by movement of
the
balancing piston (176) relative to the mandrel (32), which sizing simplifies
the
calculation of the cross sectional area of the balancing piston (176) that is
required to
achieve the desired design effect.
The assembly (20) is preferably equipped with a signalling device for
signalling whether the mandrel (32) is in the first maximum downward position
or in
the second maximum downward position. This signalling device may comprise any
device or means that is capable of providing the necessary indication, which
preferably
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CA 02285759 1999-10-08
should include a signal that can be observed by the drilling crew who are
operating the
assembly (20). In the preferred embodiment the signalling device is comprised
of a flow
restriction device which selectively restricts the flow of circulating fluid
through the
fluid passage (24) depending upon the position of the mandrel (32).
In the preferred embodiment, the lower support mandrel (103) and the
lower end of the upper drive shaft (71) cooperate to provide the signalling
device.
Referring to Figures 4, 10 and 16, the lower support mandrel (103) includes a
restriction
ring (220) and a guard ring (222) fastened on its inner surface, while the
lower end of
the upper drive shaft (71) includes an upper flow hoop (224), a mid flow hoop
(226) and
a lower flow hoop (228) fastened on its outer surface. The restriction ring
(220) and the
flow hoops (224,226,228) cooperate to alter the cross-sectional area of the
fluid passage
(24) depending upon the relative axial position of the mandrel (32) relative
to the drive
shaft (66). The restriction ring (220) and the guard ring (222) are held in
place with the
orifice retainer (105). The flow hoops (224,226,228) are maintained in
position against a
shoulder (230) on the upper drive shaft (71) by a shim (232) mounted on the
upper drive
shaft (71) adjacent to the lower flow hoop (228).
Referring to Figure 4, when the mandrel (32) is in the second maximum
downward position so that the stabilizer elements are extended, the
restriction ring
(220) is positioned opposite an expanded section of the mid flow hoop (226) so
that the
cross-sectional area of the fluid passage (24) is reduced adjacent to the
restriction ring
(220). There is thus some relative restriction of flow of the circulating
fluid when the
stabilizer elements are extended and a significant pressure drop will be
experienced by
the circulating fluid in passing through the fluid passage (24) adjacent to
the restriction
ring (220). This relatively high pressure drop will translate to a relatively
high output
pressure at the circulating fluid pump.
Referring to Figures 10 and 16, when the mandrel (32) is in either the first
maximum downward position or the rest position, the restriction ring (220) is
positioned opposite either the upper flow hoop (224) or the upper drive shaft
(71), with
the result that relatively little restriction of flow and a relatively small
pressure drop
will be experienced by the circulating fluid in passing through the fluid
passage (24)
adjacent to the restriction ring (220). This relatively low pressure drop will
translate to
a relatively low output pressure at the circulating fluid pump.
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CA 02285759 1999-10-08
The difference in output pressure at the circulating fluid pump which is
caused by the position of the restriction ring (220) relative to the flow
hoops
(224,226,228) can be sensed from the surface by the drilling crew. The
signalling device
can be designed and assembled to provide different output pressures for
different
drilling conditions by altering the dimensions of the restriction ring (220),
the flow
hoops (224,226,228) and the annular space between the lower support mandrel
(103)
and the upper drive shaft (71).
The sensor apparatus (23) includes one or more sensors for gathering
information about at least one drilling parameter relating to drilling
operations or about
the environment in which drilling is taking place. This information may relate
to
drilling parameters such as wellbore inclination, wellbore azimuth, toolface
orientation,
weight-on-bit, torque, wellbore pressure, wellbore temperature, natural gamma
ray
emissions, mud cake resistivity and so on. The sensor apparatus (23) may
gather and
store such information for later retrieval, or the sensor apparatus (23) may
be equipped
with a transmitter for transmitting information. The sensor apparatus (23) may
also be
equipped with a receiver for receiving information. The sensors may be
positioned in
one location or they may be positioned in various locations to optimize the
information
gathering process.
In the preferred embodiment, the sensor apparatus (23) includes an
inclinometer sensor (234) for sensing the inclination of the drilling assembly
(20) in the
wellbore. This inclinometer sensor (234) is preferably comprised of a triaxial
accelerometer which senses the inclination of the drilling assembly (20)
relative to
gravity, but any type of sensor or combination of sensors which is capable of
gathering
the information which is desired to be gathered may be included in the sensor
apparatus (23).
In the preferred embodiment, the sensor apparatus (23) also includes a
transmitter (236), a power supply (238) and a processor (240) for processing
information
received from sensors before the information is transmitted. The components of
the
sensor apparatus (23) may be contained in a single location or they may be
positioned at
different locations along the drill string (54) or the drilling assembly (20).
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In the preferred embodiment the sensor apparatus (23), including the
inclinometer sensor (234), the transmitter (236), the power supply (238) and
the
processor (240) are all positioned in an instrument cavity (242) formed in the
sensor
housing (45). The sensor housing (45) in turn is surrounded by a pressure
sleeve (244)
which is held in place on the sensor housing (45) by being threadably
connected to the
lower end of the sensor crossover housing (43). The function of the pressure
sleeve
(244) is to isolate the sensor apparatus (23) from pressures exerted on the
exterior of the
drilling assembly (20) during drilling operations. Seals are provided between
the
sensor housing (45) and the pressure sleeve (244) to prevent wellbore fluids
from
entering the instrument cavity (242).
In the preferred embodiment, the transmitter (236) is used to transmit
information from the sensor apparatus (23) to a surface communication device
(248)
located above the drilling assembly (20). Preferably the surface communication
device
(248) is a measurement-while-drilling ("MWD") apparatus.
The transmitter (236) may transmit information to the surface
communication device (248) in any manner which will preserve the integrity of
the
information. Preferably the information is transmitted by the transmitter
(236) using
electrical, magnetic, electromagnetic or acoustic signals.
In the preferred embodiment, the information is transmitted from the
sensor apparatus (23) to the surface communication device (248) in the manner
described in U.S. Patent No. 5,163,521 (Comeau et al), U.S. Patent No.
5,410,303
(Comeau et al) and U.S. Patent No. 5,602,541 (Comeau et al). In particular, in
the
preferred embodiment, the transmitter (236) is an acoustic transmitter which
transmits
acoustic signals from the sensor apparatus (23) to the surface communication
device
(248). This acoustic signal is transmitted from the instrument cavity (242)
through a
signal passage (250) to the fluid passage (24) and then through the drilling
assembly
(20) to the surface communication device (248). The signal passage (250) is
equipped
with a seal (252) which permits acoustic signals to pass through the signal
passage (250)
but which prevents circulating fluid from entering the instrument cavity
(242).
In the preferred embodiment, the sensor apparatus (23) is further
equipped with a device for sensing rotation of the drive shaft (66). This
device is
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CA 02285759 1999-10-08
comprised of a magnet (254) which is mounted on the sensor housing shaft (75)
adjacent
to the instrument cavity (242) and a rotation sensor (256) positioned in the
instrument
cavity (242) which detects changes in rotational movement of the magnet (254)
caused
by rotation or non-rotation of the drive shaft (66). This rotation sensing
device may be
useful in the gathering of information by the sensor apparatus (23) and the
transmission
of such information, particularly where it is intended that the sensor
apparatus (23)
gather information only when the drive shaft (66) is not rotating.
The sensor apparatus (23) may be located anywhere along the drill string
(54) but is preferably part of the drilling assembly (20). In particular, the
inclinometer
sensor (234) is preferably located relatively near to the lower end (76) of
the lower drive
shaft (74) so that information gathered by the inclinometer sensor (234) is
representative
of the inclination of the drilling assembly (20) existing in the proximity of
the drilling bit
(60). In addition, the inclinometer sensor (234) is also preferably located
above the bent
housing assembly (25) so that the information gathered by the inclinometer
sensor (234)
is not distorted by the orientation of the drilling bit relative to the
longitudinal axis of
the wellbore (toolface orientation) or by the magnitude of the bend of the
bent housing
assembly (25). As a result, in the preferred embodiment, the sensor apparatus
(23)
including the inclinometer sensor (234) is located directly above the bent
housing
assembly (25), which in turn is located relatively near to the lower end (76)
of the lower
drive shaft (74).
The bent housing assembly (25) facilitates some control over the direction
of drilling when drilling occurs with the use of the downhole motor without
rotation of
the drill string (54). The bent housing assembly (25) is particularly useful
for initiating a
deviated wellbore where a deviation or "build" angle must be established. The
bent
housing assembly (25) may be combined with other sections of the drilling
assembly
(20) and may either include a fixed bend or an adjustable bend.
Preferably, the bent housing assembly (25) is a separate section of the
drilling assembly (20) and comprises either a fixed or adjustable bent
housing. The
amount of the bend of the bent housing assembly (25) may be any amount which
is
compatible with the drilling conditions, but is typically between about 0.5
degrees and
about 3.0 degrees. In the preferred embodiment, the bent housing assembly (25)
includes the bent housing (47), the bent housing shaft (79), the upper bent
housing
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CA 02285759 1999-10-08
connection (77) and the lower bent housing connection (81). In the preferred
embodiment, the bent housing assembly (25) includes a fixed bend of 0.5
degrees
The bent housing assembly (25) may be located anywhere along the drill
string (54) but is preferably part of the drilling assembly (20). More
preferably, and as
discussed above, the sensor apparatus (23) is preferably located near to the
drilling bit
(60) but above the bent housing assembly (25). As a result, in the preferred
embodiment
the bent housing assembly (25) is located relatively near to the lower end
(76) of the
lower drive shaft (74) so that the sensor apparatus (23) may be located above
the bent
housing assembly (25) and yet still be relatively near to the lower end (76)
of the lower
drive shaft (74). This configuration also provides the further advantage of a
relatively
short distance between the bent housing assembly (25) and the drilling bit
(60), with the
result that the drilling assembly (20) is relatively stiff between the bent
housing
assembly (25) and the drilling bit (60) and is therefore less prone to bending
below the
bent housing assembly (25).
In the preferred embodiment, the bearing housing (44) includes
components of a conventional bearing assembly (204) of the type commonly used
in
downhole drilling motor assemblies. Other bearing designs may, however be used
in
the invention.
The function of the bearing assembly (204) is to provide thrust and radial
support to the drive shaft (66) in the housing (22) and in particular to
protect the drive
shaft (66) and its components from high axial loads experienced by the
drilling bit (60).
As a result, the bearing assembly (204) is preferably located relatively near
to the lower
end (76) of the lower drive shaft (74) and preferably below other components
of the
drilling assembly (20) so that axial loads exerted on the lower end (76) of
the lower
drive shaft (74) will be carried by the housing (22) along a substantial
portion of the
length of the drilling assembly (20). In the preferred embodiment, the bearing
assembly
(204) is therefore located immediately above the lower drive shaft bearing
(142).
In the preferred embodiment, the bearing assembly (204) includes a
double direction ball style thrust bearing (206) located in an annular space
between the
lower drive shaft (74) and the bearing housing (44). The bearing surface on
the housing
(22) is a shoulder (207) on the inner surface of the bearing housing (44) and
the bearing
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surface on the drive shaft (66) is the lower end (208) of the lower drive
shaft cap (83).
The thrust bearing (206) is contained by the lower end of the lower drive
shaft cap (83)
and by the upper end of the bottom housing cap (52). Spacers (210), shims
(212) and
belleville springs (214) may be provided on the housing (22) and on the drive
shaft (66)
to ensure that the thrust bearing (206) provides appropriate support for the
drive shaft
(66).
In the preferred embodiment, the drilling assembly (20) may be used for
rotary drilling in which the drill string (54) is rotated, sliding drilling in
which the drive
shaft (66) is rotated by the power unit (26) and in a hybrid form of drilling
in which
rotation of the drill string (54) is superimposed upon rotation of the drive
shaft (66).
The first stabilizer (30) may be positioned at any location along the drilling
assembly. The second stabilizer (27) is optional and may also be positioned at
any
location along the drilling assembly (20). Preferably both the first
stabilizer (30) and the
second stabilizer (27) are positioned between the power unit (26) and the
drilling bit
(60).
Control over the direction of drilling using the drilling assembly (20)
during sliding drilling is provided by the bent housing assembly (25), whereby
the
drilling assembly (20) and thus the direction of the bend is oriented relative
to the
longitudinal axis of the wellbore to drill in a desired direction.
Some additional control over the direction of drilling using the drilling
assembly (20) during both sliding and rotary drilling may be achieved by the
design
and configuration of the first stabilizer (30) and the second stabilizer (27
in the drilling
assembly (20). Further control may be achieved by the actuation of the first
stabilizer
(30).
In the preferred embodiment, the second stabilizer (27) is a non-adjustable
stabilizer which is located a first axial distance (260) from the lower end of
the housing
(36), and the first stabilizer (30) is an adjustable gauge stabilizer which is
located a
second axial distance (262) from the lower end of the housing (36). In the
preferred
embodiment the second axial distance (262) is greater than the first axial
distance (260).
In the preferred embodiment, the radial dimensions (gauge) of the first
stabilizer (30)
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and the second stabilizer (27) and the axial distances (260,262) are selected
so that the
drilling assembly (20) will be capable of drilling to provide a build angle
when the first
stabilizer (30) is in the retracted position and will be capable of drilling
to provide a
drop angle when the first stabilizer (30) is in the extended position.
The second stabilizer (27) may, however, be an adjustable gauge stabilizer
and the first stabilizer (30) may be a non-adjustable stabilizer. Furthermore,
both the
first stabilizer (30) and the second stabilizer (27) may be adjustable gauge
stabilizers or
non-adjustable stabilizers. The first axial distance (260) may also be greater
than the
second axial distance (262).
In the preferred embodiment, the second stabilizer (27) is a sleeve
stabilizer which is threadably attached to the exterior of the bearing housing
(44). The
second stabilizer (27) may be a rotating sleeve stabilizer or a non-rotating
sleeve
stabilizer. In the preferred embodiment, the second stabilizer (27) is a non-
rotating
sleeve stabilizer.
In the preferred embodiment, the second stabilizer (27) includes four
stabilizer blades and has a second stabilizer gauge that is greater than the
retracted
gauge of the first stabilizer (30) when the first stabilizer (30) is in the
retracted position
but is less than the extended gauge of the first stabilizer (30) when the
first stabilizer
(30) is in the extended position. Furthermore, in the preferred embodiment the
first
axial distance (260) and the second axial distance (262) are selected so that
the drilling
assembly (20) will provide a build angle when the first stabilizer (30) is in
the retracted
position and will provide a drop angle when the first stabilizer (30) is in
the extended
position.
The magnitude of the build angle and the drop angle which results from
actuation of the first stabilizer (30) between the retracted position and the
extended
position will depend upon the magnitude of the difference between the gauges
of the
first stabilizer (30) and the second stabilizer (27), the magnitude of the
first axial
distance (260) and the second axial distance (262), and the amount of "play"
between
the housing (22) and the drive shaft (66), which "play" will result in a bit
drop angle.
This bit drop angle will increase the magnitude of the drop angle otherwise
created
when the first stabilizer (30) is in the extended position and will decrease
the magnitude
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CA 02285759 1999-10-08
of the build angle otherwise created when the first stabilizer (30) is in the
retracted
position.
During rotary drilling, the build or drop angle provided by the stabilizers
(30,27) will provide some steering capability which is not provided by the
bent housing
assembly (25). During sliding drilling, the build or drop angle provided by
the
stabilizers (30,27) may be used to increase or decrease the deviation provided
by the
bent housing assembly, depending upon the orientation of the bent housing
assembly
(25) relative to the longitudinal axis of the wellbore.
It can thus be seen that through careful design and configuration of the
first stabilizer (30) and the second stabilizer (27) and actuation of the
first stabilizer (30)
according to the preferred embodiment, the drilling assembly (20) may be
provided
with some added steering capability during both sliding and rotary drilling.
In preparation for operation of the assembly (20), the drilling bit (60) can
be connected to the lower end (76) of the drive shaft (66) and the assembly
(20) can be
connected to the drill string (54) as part of a bottom hole assembly. Before
the assembly
(20) is lowered into the wellbore, however, it should be surface tested by
pumping
circulating fluid through the assembly (20) in cycles first, to ensure that
the first
stabilizer (30) moves properly through its various positions and second, to
determine a
benchmark reading of circulating fluid pump output pressure for the signalling
device
in each of the different positions of the first stabilizer (30) as provided
for by the
indexing mechanism.
The assembly (20) can then be lowered into the wellbore in order to
commence drilling operations. Drilling will be performed by turning the
drilling bit
(60) either through rotation of the drill string (54), through circulation of
fluid through
the power unit (26) to rotate the drive assembly (28), or through a
combination of both.
If drilling is to be performed solely through circulation of fluid through
the power unit (26), the drilling assembly (20) should preferably be oriented
in a desired
direction relative to the longitudinal axis of the wellbore so that drilling
takes place in
the desired direction. The magnitude of the deviation provided by the bent
housing
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CA 02285759 1999-10-08
assembly (25) may then be modified by actuation of the first stabilizer (30)
between the
retracted position and the extended position.
If drilling is to be performed either solely by rotation of the drill string
(54), or by rotation of the drill string (54) together with circulation of
fluid through the
power unit (26), then the direction of the resulting wellbore may be
controlled by
actuation of the first stabilizer (30) between the retracted position and the
extended
position to provide either a build angle or a drop angle.
The first stabilizer (30) will be actuated by the difference between the
pressure of the circulating fluid being passed downward through the assembly
(20) and
the pressure of the wellbore adjacent to the assembly (20). This pressure
differential
will be applied to the upper end (84) of the mandrel (32) and will provide a
force
tending to cause the mandrel (32) to move toward the lower end (36) of the
housing
(22). The downward force will be opposed by an upward force exerted on the
mandrel
(32) by the return spring (164). If the downward force is greater than the
upward force,
the mandrel (32) will move downward relative to the housing. If the downward
force is
less than the upward force, the mandrel (32) will remain in the maximum upward
position with the barrel cam bushings (138) engaging the third shoulders (136)
on the
barrel cam (116).
If the mandrel (32) moves downward relative to the housing (22), it will
move toward either a first maximum downward position in which the stabilizer
elements are retracted and the barrel cam bushings (138) engage the first
shoulders
(132) on the barrel cam (116), or a second maximum downward position in which
the
stabilizer elements are extended and the barrel cam bushings (138) engage the
second
shoulders (134) on the barrel cam (116). The barrel cam pin (116) will
therefore travel in
the groove (122) on the barrel cam (116) as the barrel cam (116) rotates on
the barrel cam
mandrel (94) until it either reaches the first position (124) in the groove
(122) which
corresponds to the first maximum downward position of the mandrel (32) and
retraction of the stabilizer elements or it reaches the second position (126)
in the groove
(122) which corresponds to the second maximum downward position of the mandrel
(32) and extension of the stabilizer elements.
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The mandrel (32) will remain "locked" in either the first maximum
downward position or the second maximum downward position as long as the
differential pressure applied to the mandrel (32) continues to exceed the
amount
necessary to move the mandrel (32) downward to that position. If the
differential
pressure is reduced by reducing the flow of circulating fluid through the
assembly (20),
the barrel cam (116) will rotate on the barrel cam mandrel (94) and the barrel
cam pin
(140) will travel in the groove (122) toward the third position (128) which
corresponds
to the maximum upward position of the mandrel (32). Once the barrel cam pin
(140)
reaches the maximum upward position, which corresponds to the rest position of
the
stabilizer elements, subsequent increase of differential pressure will move
the mandrel
(32) downward to the maximum downward position which was not achieved in the
previous cycle.
The downward position of the mandrel (32) and thus the first stabilizer
(30) can be determined when fluid is being circulated through the assembly
(20) by
observing the output pressure of the circulating fluid pump. If the output
pressure is
relatively low, the mandrel (32) is in the first maximum downward position and
the
first stabilizer (30) is retracted. If the output pressure is relatively high,
the mandrel (32)
is in the second maximum downward position and the first stabilizer (30) is
extended.
If the first stabilizer (30) is not in the desired position at any time during
drilling
operations, the position may be changed by reducing the circulation of fluid
through
the assembly (20) and then increasing the circulation of fluid through the
assembly (20)
so that the mandrel (32) can move from one of the maximum downward positions
to
the maximum upward position and then to the other of the maximum downward
positions.
It should be noted, however, that the operation of the assembly (20) is
dependent upon proper cycling of the pressure of the circulating fluid being
passed
through the assembly (20). Unless the pressure of the circulating fluid
matches or
exceeds the differential pressure required to move the mandrel (32) to the
next
maximum downward position permitted by the indexing mechanism, the barrel cam
pin (140) will be unable to progress along the groove (122). Care must
therefore be
taken to ensure that the differential pressures required to actuate the first
stabilizer (30)
are compatible with the differential pressures required for both the specific
drilling
operation and the specific motor assembly configuration.
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CA 02285759 1999-10-08
One advantage of the assembly (20) of the present invention is that the
actuation of the first stabilizer (30) is dependent only upon the axial
position of the
mandrel (32). Since the mandrel (32) is movable independently of the housing
(22) and
the drive assembly (28) and is not required to support or transmit any
torsional or axial
loads, the actuation of the first stabilizer (30) is thus independent of the
weight on bit
and the direction or amount of rotation of the drill string (54). Furthermore,
since
actuation of the first stabilizer (30) is not dependent upon rotation of the
drill string
(54), the first stabilizer (30) may still be actuated in situations where the
assembly (20)
does not contact the sides of the wellbore due to washout or other causes.
This advantage distinguishes the present invention from many prior art
devices, and provides drilling personnel with maximum flexibility in drilling
techniques, since both rotating drill string and sliding drilling can be
accomplished with
the first stabilizer (30) in either the retracted or extended positions. It
also reduces
potential damage to the first stabilizer (30) as the assembly (20) is being
run into or out
of the wellbore by providing for the rest position of the first stabilizer
(30) in which the
stabilizer elements may actually be withdrawn past the retracted position.
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