Note: Descriptions are shown in the official language in which they were submitted.
CA 02618311 2008-01-16
APPARATUS AND METHOD FOR STABILIZATION OF DOWNHOLE TOOLS
BACKGROUND OF THE INVENTION
Field of the Invention
Embodiments described herein generally relate to methods and apparatus for
stabilizing a downhole tool during a downhole operation. Particularly, the
embodiments
relate to an expandable stabilizer adapted to contact the interior of a
tubular in a
wellbore during a downhole operation. More particularly, the embodiments
relate to a
fluid actuated stabilizer that is offset from a radius of a body of the
stabilizer in order to
improve stabilization while increasing the life of the stabilizer and downhole
tool.
Description of the Related Art
During the drilling and production of oil and gas wells, a wellbore is formed
in the
earth and typically lined with a tubular that is cemented into place to
prevent cave ins
and to facilitate isolation of certain areas of the wellbore for collection of
hydrocarbons.
During drilling and production, a number of items may become stuck in the
wellbore.
Those items may be cemented in place in the wellbore and/or lodged in the
wellbore.
Such stuck items may prevent further operations in the wellbore both below and
above
the location of the item. Those items may include drill pipe, packers, and
downhole
tools. In order to remove the item, milling tools are used to cut or drill the
item from the
wellbore.
Typical milling tools have blades located on the lower end of the milling
tool.
The blades form a cutting surface. As the milling tool is rotated, the cutting
surface will
cut through the stuck item. The cutting of the stuck item will wear away the
cutting
surface and eventually require the replacement of the milling tool. The time
required to
remove and replace the milling tool amounts to a substantial cost due to lost
rig time
and the equipment costs. Therefore, extending the life of the milling tool
greatly
increases the cost effectiveness of the milling operation.
A number of factors contribute to the milling tool wear, including blade
material,
blade configuration, and vibration of the milling tool. Vibration of the
milling tool is
caused by the milling tool and the milling tool conveyance being of a smaller
diameter
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CA 02618311 2008-01-16
than a wellbore tubular in which the milling operation is taking place. The
smaller
diameter of the milling tool creates a clearance area between the tubular and
the tool
allowing movement of the tool in the tubular. Further, the milling tools are
often built
significantly smaller than the tubular in order to ensure that the milling
tool will pass any
restrictions downhole. In addition, often times the tubular that is deeper in
the wellbore
has a smaller wall thickness than the tubular near the surface of the
weilbore: The
smaller wall thickness causes the wellbore inner diameter to be larger at the
bottom
than near the surface. This creates an even larger clearance area between the
milling
tool and the tubular. When the milling tool is rotated to mill the stuck item,
the milling
tool and the conveyance move and vibrate rapidly in the clearance area. This
vibration
greatly reduces the life of the milling tool and decreases the rate the
milling tool cuts the
stuck item.
Currently, in order to minimize vibration during milling, stabilizers are used
in
conjunction with the milling tool. Traditional stabilizers were fixed members
coupled to
the milling tool. The traditional stabilizers have fixed length protrusions
extending
radially from the stabilizer. These protrusions have an outer diameter of
close to the
minimum inner diameter of the tubular they were run into. The traditional
stabilizers
must be small enough to travel within the tubular and therefore always have
some
degree of clearance between the stabilizer and the inner diameter of the
tubular.
Though traditional stabilizers are robust, they do little to hamper vibration.
Further, bow spring stabilizers are used to stabilize a milling tool. The bow
spring stabilizer is simply a plurality of thin metal sheets located
circumferentially
around the stabilizer. Once downhole, the bow springs are actuated to bow
radially
outward and into contact with the internal diameter of the tubular. The bow
spring
stabilizers are not effective at reducing the vibration in the milling tool.
This is due to
the bow spring being flexible and allowing vibration to transfer through the
bow spring
and to the milling tool during a milling operation. Further, the bow spring
lacks
robustness and is often subject to mechanical failure when debris or
restrictions are
encountered.
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CA 02618311 2008-01-16
There is a need for a method and apparatus to reduce the vibration of a
milling
tool thereby increasing the longevity and the effectiveness of the milling
tool. There is
also a need for an expandable stabilizer that may engage an inner diameter of
a
downhole tubular during a milling operation. There is a further need for a
stabilizer that
is compliant in order to take up inner diameter tolerance and/or variation of
the wellbore
during a downhole operation.
SUMMARY OF THE INVENTION
A method of stabilizing a downhole tool in a wellbore during a downhole
operation is described herein. The method may include coupling a stabilizing
tool to the
downhole tool, the stabilizing tool having a plurality of stabilizer members
and running
the downhole tool and the stabilizing tool into the wellbore. The method may
further
include extending the plurality of stabilization members into engagement with
a surface
in the wellbore.
An apparatus for stabilizing a downhole operation in a wellbore is described
herein. The apparatus may include a tubular body and a stabilizing member
operatively
coupled to the tubular body and configured to engage a surface in the
wellbore. The
apparatus may further include a piston and cylinder assembly at least
partially
contained within the tubular body and configured to move the stabilizing
member
between a retracted position and an extended position.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the present
invention
can be understood in detail, a more particular description of the invention,
briefly
summarized above, may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however, that the
appended
drawings illustrate only typical embodiments of this invention and are
therefore not to
be considered limiting of its scope, for the invention may admit to other
equally effective
embodiments.
Figure 1 is a schematic view of a wellbore and bottom hole assembly (BHA)
according to one embodiment described herein.
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Figure 2A is a perspective view of a stabilizer according to one embodiment
described herein.
Figure 2B is a cross sectional perspective view of a stabilizer according to
one
embodiment described herein.
Figure 2C is a cross sectional view of an actuator according to one embodiment
described herein.
Figure 2D is a cross sectional view of a portion of an actuator according to
one
embodiment described herein.
Figure 3 is a cross sectional view of a tubular and a stabilizer according to
one
embodiment described herein.
Figure 4 is a view of a stabilizer according to one embodiment described
herein.
Figure 5 is an exploded perspective view of a stabilization member according
to
one embodiment described herein.
Figure 6A is a perspective cross sectional view of a stabilizer according to
one
embodiment described herein.
Figure 6B is an exploded view of a stabilizer according to one embodiment
described herein.
Figure 7 is a perspective view of a stabilizer according to one embodiment
described herein.
Figure 8A is a perspective view of a stabilizer according to one embodiment
described herein.
Figure 8B is a cross sectional view of a stabilization member according to one
embodiment described herein.
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CA 02618311 2008-01-16
DETAILED DESCRIPTION
Embodiments of apparatus and methods for stabilizing a downhole tool during a
downhole operation in a wellbore are provided. In one embodiment, the downhole
tool
is a milling tool for use with a milling operation; however, it should be
appreciated that
the downhole tool may be any tool including but not limited to a drilling
tool, a drill bit, a
broaching tool, and a flexible broach. In one embodiment, an expandable
stabilizer is
operatively coupled to the downhole tool and a conveyance and lowered into a
wellbore. The downhole tool is lowered until it reaches a location where a
downhole
operation is to be performed. For example, the location may be a location
where an
item is stuck in the wellbore. Because the stabilizer is expandable, it may be
run into
the wellbore in a retracted position. This allows the stabilizer to easily
pass through the
wellbore and any restrictions that may be encountered in the wellbore. Upon
reaching
the location, the stabilizer may be activated in order to extend a plurality
of stabilizing
members into engagement with an interior diameter of a tubular in the
wellbore. The
extension of the stabilizer members is accomplished by an actuator positioned
along an
axis which is offset from a radial dimension of the stabilizer, as will be
described in
more detail below. The stabilizer allows the downhole tool to rotate within
the tubular
while preventing the downhole tool from moving substantially radially in' the
tubular.
Further, the arrangement of the actuators for the stabilizer members allow for
compliant
stabilization of the downhole tool. In other words, the stabilizing members
may comply
or retract at least partially when tubular inner diameter variations or
restrictions are
encountered. The stabilizing of the downhole tool allows the downhole tool to
operate
longer. Once the downhole operation is complete, the downhole tool and the
stabilizer
are removed from the wellbore and other downhole operations may be performed.
Figure 1 shows a schematic view of a wellbore 100 with a tubular 102 cemented
in place, a drill rig 104, a conveyance 108, a downhole tool 110, shown as a
milling tool,
a stabilizer 112, and an item 114 stuck in the wellbore 100. The tubular 102,
as shown,
is a casing which has a tapered inner diameter. That is, the wall thickness of
the casing
near the surface of the earth is larger than the wall thickness of the casing
lower in the
wellbore, thereby creating a larger inner diameter of the tubular 102 at lower
depths.
Though shown having a tapered inner diameter, it should be appreciated that
the
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CA 02618311 2008-01-16
tubular 102 may have any configuration including, but not limited to, a
constant inner
diameter, a larger inner diameter near the surface, or varying inner
diameters.
Although shown as the casing cemented into the wellbore 100, it should be
appreciated
that the casing may not be cemented in place or there may be no casing.
Further, it
should be appreciated that the tubular 102 may be any tubular for use in a
wellbore
including, but not limited to, a drill pipe, a production tubular, a liner,
and a coiled
tubing. Additionally, the invention may be used in an uncased or open portion
of the
wellbore 100. The conveyance 108 may be a drill string which may be rotated
and
axially translated from the drill rig 104; however, it should be appreciated
that the
conveyance could be any conveyance including, but not limited to, a co-rod, a
wire line,
a slick line, coiled tubing, and casing. The downhole tool 110 may be coupled
to a
drilling motor (not shown) in order to rotate the downhole tool 110 in a
manner
independent from the conveyance 108, or may be manipulated by the conveyance
108.
The downhole tool 110 may be any downhole tool for use in a wellbore.
The lower end of the stabilizer 112 is shown connected to the downhole tool
110
and the upper end connected to the conveyance 108. Although the stabilizer is
shown
as a separate unit, it should be appreciated that the stabilizer may be
integral with the
downhole tool 110. The stabilizer 112, as will be described in more detail
below, and
the downhole tool 110 are lowered into the wellbore 100 until the downhole
tool 110
engages the item 114 that is stuck in the wellbore. The item 114, as shown, is
a packer
which has been set in the tubular 102; however, the item 114 may be any item
stuck in
the wellbore 100 including, but not limited to, drill pipe, casing, production
tubing, liner,
centralizers, whipstocks, valves, drill bits, or drill shoes. Optionally, the
item 114 may
be cemented in place in the wellbore 100. Preferably, the downhole tool 110
engages
the item 114 while the downhole tool 110 is rotating. In one embodiment, the
downhole
tool is a milling tool having a milling end 116 configured to mill away the
item 114 and
any cement attached to the item 114, while the stabilizer 112 substantially
prevents
vibration of the downhole tool 110. The downhole tool 110 is lowered while
rotating and
milling until the item 114 is no longer obstructing the wellbore 100.
The stabilizer 112 may include one or more stabilizing members 118, shown
schematically in Figure 1. As shown, the stabilizing members 118 are in the
retracted
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CA 02618311 2008-01-16
or run in position. The retracted position is a position that allows the
stabilizer 112 and
the stabilizing members 118 to have an outer diameter that is less than the
smallest
inner diameter of the tubular 102. This allows the stabilizer 112 and the
downhole tool
110 to run into the wellbore 100 without becoming stuck on the tubular 102 or
another
restriction in the tubular 102. When the downhole operation is to commence, or
at any
other desired time, the stabilizing members 118 may be activated. Upon
activation, the
stabilizing members 118 extend from the stabilizer 112 until they engage the
inner
diameter of the tubular 102. The stabilizer 112 and the stabilizing members
118 are
arranged in a manner that allows the stabilizing members 118 to stabilize the
downhole
tool 110 while not expanding the tubular 102, as will be described in more
detail below.
During the stabilization process the stabilizing members 118 may retract or
expand in
compliance with the conditions on the inner diameter of the tubular 102. Thus,
if the
inner diameter of the tubular 102 increases as the downhole operation moves
down the
tubular 102, the stabilizing members will automatically extend to the new
inner diameter
of the tubular 102. Further, if the inner diameter of the tubular 102
decreases, or a
restriction is encountered, the stabilizing members automatically retract or
comply with
the change.
Figure 2A shows a schematic view of the stabilizer 112 according to one
embodiment described herein. The stabilizer 112 may have a body 200, one or
more
pockets 202, an enlarged diameter portion 204, one or more actuators 206, one
or
more stabilization members 118, and one or more connector ends 207. The
connector
ends 207 are adapted to couple the stabilizer 112 to the conveyance 108 and/or
the
downhole tool 110, or any other downhole member. The connector ends 207 may
use
any mechanism for connecting the stabilizer 112 to other downhole tool
members,
including but not limited to, a threaded connection, a welded connection, and
a pinned
connection.
The one or more pockets 202 formed in the body 200 may be adapted to house
the stabilizing members 118 when in the retracted position. The one or more
pockets
202 may be deep enough to include the entire stabilizing member 118 within the
one or
more pocket 202 when the stabilizing member 118 is in the retracted position.
Thus,
with the stabilizing members 118 are in the retracted position, the
stabilizing members
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CA 02618311 2008-01-16
118 would not extend past the outer diameter of the body 200. It should be
appreciated
that the one or more pockets may be at any depth. The one or more pockets 202
may
further include a housing portion 209, as shown in Figure 2B, adapted to house
all or a
portion of the one or more actuators 206. In an alternative embodiment, the
one or
more pockets only houses a portion of the one or more actuators 206. In this
arrangement, the one or more stabilizing members 118 would always be entirely
outside an outer diameter of the body 200.
The stabilization member 118, shown, is a roller adapted to extend from the
body 200 of the stabilizer 112. The stabilizing members 118 may couple to the
one or
more actuators 206. The one or more actuators 206 are configured to move the
stabilizing members 118 from the retracted position to the extended position.
Although
shown as a roller, it should be appreciated that the stabilization member 118
may be
any member adapted to prevent vibration during a downhole operation including,
but
not limited to, a plurality of spheres, one or more pads, or any non rotating
member.
Figure 2B is a perspective cross-sectional view of the stabilizer 112 cut
through
the one or more actuators 206. The stabilizer 112 is shown with three
actuators 206.
Each actuator 206 has an actuation axis 208 which is the axis traveled by the
stabilization members 118 when moving between the retracted position and the
extended position. The actuation axis 208 is offset from the radius R of the
body 200.
In this aspect, the actuation axis 208 is always offset from, or at an angle
to, any radius
of the body 200 of the stabilizer 112. That is, the actuation axis 208 is not
in line with
any radius of the body 200. This offset provides the actuation axis 208 with a
longer
axis than a radius of the body. As a result of this offset, the stroke (e.g.
distance) of the
actuator 206 is greater compared to the stroke of an equivalent actuator
extending
radially from the center of the stabilizer 112. Therefore, the stabilization
members 118
may extend out further to engage the interior of a tubular 102 due to this
offset, or
tangential, configuration, than stabilizer members extending substantially on
a radial
axis from the center of the body.
Figure 2C shows a schematic cross sectional view of the actuator 206 located
in
the housing portion 209 and coupled to the stabilization member 118, according
to one
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embodiment. The actuator 206 comprises an extendable member 210 and a
stationary
member 212. As shown, the extendable member 210 is in the form of a piston
cylinder,
and the stationary member 212 is in the form of a piston rod. It should be
appreciated
that the extendable member 210 may be any suitable extendable member
including,
but not limited to, a piston rod. Further, it should be appreciated that the
stationary
member 212 may be any member, including but not limited to, the housing
portion 209
or a piston cylinder. The stationary member 212 may be coupled to the
stabilizer 112
by a coupling member 214. The coupling member 214 may be of any type
including,
but not limited to, a threaded connection, a welded connection, a glued
connection, or a
collet type. In one embodiment, the extendable member 210 is positioned on
each end
of the stabilization member 118. In another embodiment, the extendable member
210
is positioned on one end of the stabilization member 118 and the other end is
either
fixed or allowed to move with the extendable member 210.
The extendable member 210 may include a one or more seals 216 configured to
prevent fluid from flowing past the extendable member 210. A flow path 218
fluidly
couples a piston surface 220 of the extendable member 210 to a communication
path
within the wellbore 100. The flow path 218 allows fluid to enter the housing
portion 209
and exert a force on the piston surface 220. The force in turn extends the
extendable
member 210, and thereby the stabilization members 118 move the extended
position.
It should be noted that in one embodiment each stabilization member 118
includes the
extendable member 210 on each end of the stabilization member 118. The piston
surface 220 of each extendable member 210 has a surface area that is
configured to
allow the stabilization member 118 to move radially outward into engagement
with the
surrounding tubular (or wellbore) in order to stabilize the downhole tool.
Additionally,
the stabilization member 118 includes a surface area that is configured to
provide a
large contact area between the stabilization member 118 and the surrounding
tubular
(or wellbore). As such, the fluid pressure acting on the surface area of each
piston
surface 220 causes the stabilization member 118 to move radially outward such
that
the large contact area of the stabilization member 118 engages the surrounding
tubular
to stabilize the downhole tool while not expanding the tubular. In contrast, a
fluid
actuated expansion tool typically includes a large piston area and rotary
members
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CA 02618311 2008-01-16
having a small contact area such that a large force is exerted on the small
contact area
with the surrounding tubular in order to expand the tubular.
In one embodiment, the communication path may be located in the interior of
the
stabilizer 112. Thus, fluid pressure in the conveyance 110 or the wellbore 100
may be
increased to increase the fluid pressure within the stabilizer 112. The
increased
pressure in the stabilizer is communicated through the flow path 218 to the
piston
surface 220. The fluid may be hydraulic fluid or pneumatic fluid.
In an alternative embodiment, the communication path is located outside of the
stabilizer 112. In this embodiment, the flow path would couple directly to the
exterior of
the stabilizer 112 and would be influenced by the fluid pressure in the
annular area
between the stabilizer 112 and the tubular 102.
The actuator 206 may include a throw limiter 222, which is shown as integral
with the stationary member 212. The throw limiter 222 stops the extendable
member
210 from extending beyond a predetermined extended position. When the
extendable
member 210 engages the throw limiter 222, the force applied to the piston
surface 220
is mechanically transferred to another location on the stabilizer 112. In one
embodiment, the force may be transferred to the coupling member 214. This
feature
enables the stabilizer 112 to be designed specifically for the tubular 102 in
which the
downhole operation is to be performed.
In an alternative embodiment, the extendable member 210 may be locked
against the throw limiter 222 during a stabilization operation by a fluid or
mechanical
device. Locking the extendable member 210 against the throw limiter 222 keeps
the
extendable member 210 in the extended position during stabilization. When a
variance
or restriction is encountered within the wellbore, the extendable members 210
will
remain against the throw limiter 222. A flexible member, as will be described
in more
detail below, may then allow the stabilization members 118 to retract and
comply with
the variance in the wellbore while the extendable members 210 are still
engaged with
the throw limiter 222. A fluid pressure higher than the force required to
actuate the
flexible member may be used in order to lock the extendable member to the
throw
CA 02618311 2008-01-16
limiter 222. Further, a mechanical lock (not shown), including but not limited
to a pin or
a collet, may be used to lock the extendable member 210 against the throw
limiter 222.
In one embodiment, the stabilizer 112 includes one or more flexible members
built into the system. The flexible member may be adapted to allow the
stabilization
members 118 to comply with any change in the inner diameter of the tubular or
any
restriction in the tubular during the stabilization process. That is, the
stabilization
members 118 will automatically comply to accommodate a restriction without the
need
to change the fluid actuation pressure in the actuator. The flexible member
may be
incorporated in the actuator 206, the stabilization member 118 or the coupling
between
the actuator 206 and the stabilization member 118.
In one embodiment shown, the flexible member is one or more grooves 230 cut
into the extendable member 210, as shown in Figure 2D. The one or more grooves
230 may be formed in the extendable member 210 between the stabilization end
232
and the piston surface 220. The one or more grooves 230 enable the extendable
member 210 to be substantially rigid under normal operating conditions.
However,
when large loads are applied to the stabilization member 118 and thereby to
the
stabilization end 232 of the actuator 206, the extendable member 210 will
compress
between the piston surface 220 and a stabilization end 232. Once the
restriction has
passed, the one or more grooves 230 will allow the extendable member to return
to its
original length. As shown, the one or more grooves 230 are one helical groove;
however, it should be appreciated that the grooves may have any configuration,
including but not limited to, multiple helical grooves, a series of lateral
grooves, a series
of transverse grooves, and/or multiple apertures. In yet another embodiment,
the
flexible member may be a portion of the extendable member 210 which is
constructed
of a flexible material such as a polymer, an elastomer, or a rubber. The
flexible
member may be integral with the actuator or be a separate member such as a
spring.
A retraction member, not shown, may be included in the actuator 206. The
retraction member may be configured to retract and/or bias the extendable
member
toward the retracted position. Thus, the stabilization members 118 will remain
in the
retracted position until an operator or controller initiates the stabilization
process. This
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CA 02618311 2008-01-16
enables the stabilizer to run into the wellbore 100 without inadvertently
extending the
stabilization members 118. Thus, the stabilization members 118 are unlikely to
encounter a restriction in the wellbore during the run in process.
The offset actuation axis 208 of the actuators 206 provides an increased
mechanical advantage over a substantially radial actuated stabilizer. The
offset
actuation axis 208 decreases the amount of required actuator to stabilize when
compared to a substantially radially actuated stabilizer. Figure 3 shows a
schematic
cross sectional view of the stabilizer 112 having a stabilization member 118
having the
offset actuation axis 208 and a radial stabilizer 300. The example radial
stabilizer 300,
as shown, has a radial stabilizing member 302, a radial actuator 304, and a
radial axis
306; however, it should be appreciated that there may be any number of radial
stabilizing members 302 and radial actuators 304. When actuated the radial
stabilizer
300 creates a force Fn which is normal to the tubular 102 surface it
encounters. That
is, the full actuation force is encountered by the tubular in a direction
radially from the
interior of the tubular 102. Further, the rotation of the radial stabilizer
300 in either
direction will not effect the loading of the tubular 102.
The offset actuation axis 208 allows the stabilization member 118 to engage
the
tubular 102 at an angle O. A resultant force Fr caused by the stabilization
members
118 is broken up into two effective forces Fl, F2, acting on the tubular 102.
Therefore,
the load acting on the tubular 102 radially outward is reduced by a factor
depending on
the degree of the angle O. Further, the direction of rotation of the downhole
tool 110
and stabilizer 112 may play a factor in the amount of load transferred to the
tubular 102
when using the offset actuation axis 208. Thus, rotation of the stabilizer 112
in a
clockwise direction 308 will reduce the force F2 applied to the tubular 102
because the
rotation is acting against the force F2. Further, rotation of the stabilizer
112 in a
counterclockwise direction 310 will tend to increase the force F2 applied to
the tubular
102 because the rotation is acting with the force F2. The offset actuation
axis 208
allows a portion of a friction load created between the tubular and the
stabilization
members 118 to be absorbed along the axis. This makes the stabilizer 112 more
resistant to tangential loads while stabilizing the downhole tool.
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The angle O creates a pair of resultant forces acting on the housing portion
209
of the body 200. The force F3, as shown, will transfer load from a side of the
actuator
206 to the housing portion 209. This side load F3 will help prevent the
actuator 206
from retracting by creating a binding force that is normal to the actuation
axis 208.
Thus, if the same amount of pressure is applied to the stabilization members
118 as the
radial stabilization members 302, the angle O will reduce the load applied to
the tubular
102 and decrease the tendency for the actuator 206 to retract due to the
normal force.
The offset actuation axis 208 also provides more space than the radial
stabilization members 302. This is due to the greater distance from the
stabilizer 112
end of the actuator 206 to the point of contact on the tubular 102 than the
radial
stabilizer 300. This allows for a greater range of application for any given
size of tool
thereby providing more flexibility in the design of the stabilizer 112. This
allows for
many improvements to the stabilizer including, but not limited to, a larger
stabilization
members 118, a longer piston stroke, and a larger flexible member or any
combination
thereof. The larger stabilization members 118 may be a roller having a larger
diameter
than the radial stabilization member 302. The larger roller also enables a
longer life of
the stabilization member 118 due to its increased robustness. Further, the
loading on
the tubular 102 created by the larger roller will be distributed over a wider
area than the
smaller radial stabilization member 302. Thus, the offset actuation axis 208
enables an
increased roller diameter thereby extending the life of the stabilizer 112.
The stabilizer
112 with larger diameter rollers and longer rollers lowers the contact stress
on the
tubular when compared to radial stabilizers. This lower contact stress further
prevents
unwanted expansion of the tubular.
In another embodiment, the stabilizer 112 includes multiple segments 400, as
shown in Figure 4. Each of the segments 400 includes a plurality of
stabilization
members 118. Any number of segments 400 may be used according to the
requirements of the stabilization operation. The stabilization members 118
within each
of the segments 400 may have any number of configurations around the
circumference
of the stabilizer 112. Further, the segments 400 may axially overlap one
another.
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Figure 5, shows an exploded view of the stabilization member 118 which is
shown as a roller 500. The roller 500 may include a roller pin 502 adapted to
fit inside
the roller 500. At the ends of the roller pin 502 are two seals 504 or o-rings
adapted to
hold a lubricant in the space between the roller pin 502 and the roller 500.
The
lubricant allows the roller 500 to rotate about the roller pin 502 with a
minimal amount of
friction between the two surfaces. The ends of the roller pin 502 may comprise
a
connector pin 506. The connector pin 506 may be adapted to mate with a bearing
cap
508 at each end of the roller pin 502. With the bearing caps 508 coupled to
the roller
pin 502, the roller 500 may be substantially prevented from moving axially
relative to
the roller pin 502. The bearing caps 508 may act as a bearing which absorbs
axial
forces from the roller 500 during a stabilization operation. The bearing caps
508 and/or
the connector pin 506 are adapted to couple directly to the actuators 206.
Although
shown as the stabilization members 118 being lubricated rollers 500, it should
be
appreciated that the rollers 500 may assume any form including, but not
limited to, a
solid roller member having pin ends coupled to the actuator 206 and/or a one
piece
design.
In yet another alternative embodiment, the throw limiter 222 is externally
mounted to the stabilizer 112, as shown in Figure 6A. In this embodiment, the
throw
limiter couples directly to the outer portion of the stabilizer 112 and
extends to a desired
position. When the upper end of the extendable member 210 engages the throw
limiter
222, the extendable member will be prevented from further movement in the
extended
direction. The throw limiter 222 in this embodiment may include a silt screen
600,
shown schematically. The silt screen 600 prevents wellbore fluids and debris
from
engaging the actuator 206 from a hole 602 created to accommodate the throw
limiter
222.
In yet another alternative embodiment, the stationary member is simply the
housing portion 209 of the stabilizer 112, as shown in Figure 6A. In this
embodiment
the extendable member 210 is fluidly sealed in the housing portion 209 and
moves in
response to fluid pressure applied to the piston surface 220 as described
above. The
extendable member 210 may include a piston member 604 and an actuator member
606. The piston member 604 is adapted to sealing engage the housing portion
209 and
14
CA 02618311 2008-01-16
thereby reacts to the force created by the fluid pressure, as described above.
The
piston member 604 moves in response to the fluid pressure or a biasing force
in order
to move the actuator member 606. The actuator member 606 moves the
stabilization
member 118. The actuator member 606 may include any of the flexible members
described above.
Figure 6B shows an exploded schematic view of the stabilization member 118,
the actuators 206, the body 200 of the stabilizer 112, and the pockets 202.
The
stabilization member 118 may be the roller 500 having the bearing caps 508.
The
bearing caps 508 are adapted to engage the stabilization end 232 of the
actuator 206.
The engagement between the stabilization end 232 and the bearing caps 508 may
be
accomplished using any method including, but not limited to, a pin, a screw, a
form, or
press fitting. The actuators 206 couple to the stabilizer 112 with the roller
500 engaged
between the actuators 206. With the actuators 206 coupled to the roller
bearing caps
508, the roller 500 is free to rotate about its own longitudinal axis while
being prevented
from movement in the axial direction.
In yet another embodiment, the stabilization members 118 are helically
arranged
around the outer diameter of the stabilizer 112, as shown in Figure 7. This
arrangement may require a plurality of independent rollers 700 within each of
the
stabilization members 118. This allows the independent rollers 700 of the
stabilization
member 118 to rotate at different speeds during stabilization. The helically
arranged
stabilization members 118 may allow for 360 roller contact around the
interior of the
tubular during stabilization. The helically arranged stabilization members may
be
configured to produce a tractor effect. Thus, as the stabilization members 118
rotate,
the helically arrangement pulls the stabilizer down or up hole. This feature
allows the
stabilizer 112 to drive the downhole tool in the wellbore. In a deviated or
horizontal
wellbore the drive feature of the helically arranged stabilizers may assist in
controlling
and/or enabling applied weight to the downhole tool.
In yet another embodiment, the extendable member 210 is a rod type member,
not shown. In this embodiment, the flexible member is incorporated or coupled
to the
rod. The flexible member may be a spring which is integral with the rod
between the
CA 02618311 2008-01-16
piston surface and the stabilization end of the rod. Further, the rod may be
partially
constructed of a flexible material such as a polymer, an elastomer, or a
rubber.
In yet another embodiment, the flexible member is located between the actuator
206 and the body 200. In this embodiment the flexible member may be a spring
or
other flexible member located between the actuator 206 and the housing portion
209.
Further, a flexible arm, not shown, may be used to couple the actuator 206 to
the
stabilizer 112, thereby allowing for a predetermined amount of flexibility
between the
actuator and the stabilizer 112.
In yet another embodiment, the each stabilization member 118 is simply an
extendable member 800, as shown in Figure 8A and 8B. The extendable member has
one or more pads 802 adapted to engage the inner diameter of the tubular 102.
The
extendable member 800 may include a piston surface 804, a stationary member
806, a
throw limiter 808, and a retraction member similar to those described above.
Further,
the extendable member 800 may include a flexible member such as described
above.
In yet another embodiment, the extendable member may include multiple pieces
which move relative to one another in a telescopic manner, not shown. This
allows the
extendable member to extend further than a solid extendable member.
The stabilizer 112 may be designed to travel through a relatively small
restriction
in the tubular 102 then extend to engage the tubular 102. For example, the
item 114
may be a packer stuck in the tubular 102 below a sting of production tubing.
The
production tubing may have a much smaller internal diameter than the tubular
102,
which may be a casing. The downhole tool 110, the stabilizer 112, and the
conveyance
108 may be run through the production tubing until they are outside of the
lower end of
the production tubing. The downhole tool 110 may continue until it is
proximate to the
item 114. Once near the item 114, the stabilizer 112 is activated and the
stabilization
members 118 are moved from the retracted position to the extended position in
which
the stabilization member 118 engages the inner diameter of the tubular 102.
The
downhole operation may then be performed.
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CA 02618311 2008-01-16
In operation, the downhole tool 110 is coupled to the stabilizer 112 and the
two
are run into the wellbore 100. Initially the stabilizer 112 is in the
retracted position
thereby allowing the stabilizer to easily pass through the tubular 102. Once
the
downhole and/or stabilizing operation is to begin, fluid pressure may be
increased
within the stabilizer 112. The fluid pressure may be increased by flowing
fluid through a
nozzle of the downhole tool or by any other method. The fluid pressure causes
fluid to
flow into the flow path 218 and to exert a force on the piston surface 220.
The force on
the piston surface 609 may have to overcome a retraction force from the
retraction
member. Once the force is large enough to move the extendable member 210, the
stabilization members 118 begin to move along an axis that is at an angle to
any radius
of the stabilizer. The stabilization members 118 move toward the extended
position
until the stabilization members 118 engage the inner diameter of the tubular
102 and/or
the throw limiter 222. The stabilizer 112 may be rotated during extension or
after
extension of the stabilization members 118. The rotation of the stabilizer 112
may
cause the stabilization members 118 to roll if they are rollers. This enables
the
stabilizer to rotate freely about its own axis with minimal resistance from
the
stabilization members. The stabilizer 112 in this position prevents the
downhole tool
110 from vibrating during the downhole operation of the stuck item 114.
As the downhole operation continues, an excessive load may be applied to the
stabilization members 118. This load may be created by a restriction in the
tubular 102,
a smaller inner diameter in the tubular 102, or an inadvertent spike in fluid
pressure
acting on the extendable member 210. When the excessive load is encountered, a
flexible member within the stabilizer 112 allows the stabilization members 118
to move
toward the retracted position or allows the extendable member 210 to compress.
This
decreases the load applied between the stabilization members 118 and the
tubular 102.
Thus, the stabilization members 118 will not inadvertently deform the tubular
102.
While the foregoing is directed to embodiments of the present invention, other
and further embodiments of the invention may be devised without departing from
the
basic scope thereof, and the scope thereof is determined by the claims that
follow.
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