Note: Descriptions are shown in the official language in which they were submitted.
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DOWNHOLE TOOL FOR CEMENTING A BOREHOLE
BACKGROUND
[0001] This section is intended to provide relevant background information to
facilitate a better understanding of the various aspects of the described
embodiments. Accordingly, these statements are to be read in this light and
not as
admissions of prior art.
[0002] Hydraulic cement compositions are commonly utilized in subterranean
operations, particularly subterranean well completion and remedial operations.
For
example, hydraulic cement compositions are used in primary cementing
operations
where pipe strings, such as casings and liners, are cemented in well bores.
[0003] In typical primary cementing operations, hydraulic cement compositions
are pumped into the annulus between the wall of a borehole and the exterior
surface of the pipe string disposed within the borehole. The cement
composition is
permitted to set in the annulus, forming an annular sheath of hardened,
substantially impermeable cement that supports and positions the pipe string
in the
borehole and bonds the exterior surface of the pipe string to the wall of the
borehole. The cement composition may be pumped down the inner diameter of the
pipe string, out through a casing shoe and/or circulation valve at the bottom
of the
pipe string and up through the annulus to its desired location.
[0004] In some scenarios, the conventional cementing operations may be
performed in two or more stages, where casing is placed within a borehole and
a
portion of the casing is cemented. Thereafter, one or more cementing
operations
are performed to cement the remaining portion(s) of the casing into place.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] Embodiments of the downhole tool for cementing a borehole are
described with reference to the following figures. The same numbers are used
throughout the figures to reference like features and components. The features
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depicted in the figures are not necessarily shown to scale. Certain features
of the
embodiments may be shown exaggerated in scale or in somewhat schematic form,
and some details of elements may not be shown in the interest of clarity and
conciseness,
[0006] FIG. 1 is a drilling system, according to one or more embodiments;
[0007] FIG. 2 is a cementing system for performing a multi-stage cementing
operation, according to one or more embodiments;
[0008] FIG. 3 is a cross-sectional view of a downhole tool in a run-in
position,
according to one or more embodiments;
[0009] FIG. 4 is a cross-sectional view of the downhole tool of FIG. 3 in an
open
position;
[0010] FIG. 5 is a cross-sectional view of the downhole tool of FIG. 3 in a
closed
position;
[0011] FIG. 6 is a cross-sectional view of a downhole tool in a run-in
position,
according to one or more embodiments;
[0012] FIG. 7 is a cross-sectional view of the downhole tool of FIG. 6 in an
open
position;
[0013] FIG. 8 is a cross-sectional view of the downhole tool of FIG. 6 in a
closed
position;
[0014] FIG. 9 is a cross-sectional view of a downhole tool in a run-in
position,
according to one or more embodiments;
[0015] FIG. 10 is a cross-sectional view of the downhole tool of FIG. 9 in an
open position; and
[0016] FIG. 11 is a cross-sectional view of the downhole tool of FIG. 9 in a
closed position.
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DETAILED DESCRIPTION
[0017] The present disclosure describes a downhole tool for cementing a
borehole. The downhole tool is used in a multi-stage cementing operation to be
conducted within the borehole.
[0018] A main borehole may in some instances be formed in a substantially
vertical orientation relative to a surface of the well, and a lateral borehole
may in
some instances be formed in a substantially horizontal orientation relative to
the
surface of the well. However, reference herein to either the main borehole or
the
lateral borehole is not meant to imply any particular orientation, and the
orientation of each of these boreholes may include portions that are vertical,
non-
vertical, horizontal or non-horizontal. Further, the term "uphole" refers a
direction
that is towards the surface of the well, while the term "downhole" refers a
direction that is away from the surface of the well.
[0019] FIG. 1 is a drilling system 100, according to one or more embodiments.
The well site 102 includes include a drilling rig 104 that has various
characteristics
and features associated with a "land drilling rig." Various types of drilling
equipment such as a rotary table, drilling fluid pumps, and drilling fluid
tanks (not
shown) may also be located at a well site 102. However, downhole drilling
tools
incorporating teachings of the present disclosure may be satisfactorily used
with
drilling equipment located on offshore platforms, drill ships, semi-
submersibles
and drilling barges (not shown).
[0020] The drilling system 100 includes a drill string 106 associated with a
drill
bit 108 that is used to form a borehole 110. Specifically, FIG. 1 depicts a
rotary
steerable system (RSS) 112 that may be used to perform directional drilling.
The
term "directional drilling" may be used to describe drilling a wellbore or
portions
of a wellbore that extend at a desired angle or angles relative to vertical.
The
desired angles may be greater than normal variations associated with vertical
wellbores. Directional drilling may be used to access multiple target
reservoirs
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within a single borehole or reach a reservoir that may be inaccessible via a
vertical
wellbore. The RSS 112 may use a point-the-bit method to cause the direction of
the drill bit 108 to vary relative to the housing of the rotary steerable
drilling
system 112 by bending a shaft running through the rotary steerable drilling
system
112.
[0021] The drilling system 100 also includes a bottom hole assembly (BHA) 114.
The BHA 114 may include a wide variety of components, such as components 116
and 118, configured to form the borehole 110. Such components may include, but
are not limited to, drill bits (e.g., the drill bit 108), coring bits, drill
collars, rotary
steering tools (e.g., the RSS 112) or other directional drilling tools,
downhole
drilling motors, reamers, hole enlargers or stabilizers. The number and types
of
components included in the BHA 114 may depend on anticipated downhole
drilling conditions and the type of wellbore that is to be formed. The BHA 114
may also include various types of well logging tools and other downhole tools
associated with directional drilling of a wellbore such as so-called
measurement-
while-drilling (MWD) or logging-while-drilling (LWD) tools. Examples of
logging tools and/or directional drilling tools may include, but are not
limited to,
acoustic, neutron, gamma ray, density, photoelectric, nuclear magnetic
resonance,
rotary steering tools and/or any other available well tool. Further, the BHA
114
may also include a rotary drive (not expressly shown) that rotates at least
part of
the drill string 106 together with components 116 and/or 118.
[0022] The drill bit 108 includes one or more blades 120 disposed outwardly
from exterior portions of a rotary bit body 122. The drill bit 108 rotates
with
respect to a bit rotational axis 124 in a direction defined by directional
arrow 126.
The blades 120 include one or more cutting elements 128 disposed outwardly
from
exterior portions of each blade 120. The blades 120 may also include one or
more
depth of cut controllers (not shown) configured to control the depth of cut of
the
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cutting elements 128. The blades 120 may further include one or more gage pads
(not expressly shown) disposed on blades 120.
[0023] Various types of drilling fluid may be pumped from the surface of the
well site 102 downhole through the drill string 106 to the attached drill bit
108.
The drilling fluids may be directed to flow from the drill string 106 to
respective
nozzles passing through the drill bit 108. The drilling fluid may be
circulated
uphole to the well surface through an annulus 130 surrounding the drill string
106.
[0024] The borehole 110 is defined in part by a casing string 132 extending
from
the surface of the well site 102 to a selected downhole location. Portions of
the
borehole 110 that do not include the casing string 132 may be described as
"open
hole," while portions of the borehole 110 that include the casing string 132
may be
referred to as a "cased hole." In open hole sections, the annulus 130 is be
defined
in part by an outside diameter 134 of the drill string 106 and an inside
diameter
136 of the borehole 110. In cased hole sections, the annulus 130 is defined in
part
by an outside diameter 134 of the drill string 106 and an inside diameter 138
of the
casing string 132.
[0025] To case the borehole 110, casing string 132 is run into the borehole
110
(e.g., using a running tool) and hung on a casing hanger (not shown). Cement
is
pumped through the casing string 132 and into the annulus 130 between the
casing
string 132 and the borehole wall 118 (or a previously run casing string) in
order to
cement the casing string 132 into place. In one or more embodiments, the
cementing process may be done in stages in which multiple sections of cement
are
pumped behind the same casing string. For example, when a casing string 132 is
too long to cement by only pumping cement into the annulus from a distal end
of
the casing string 132, a multi-stage cementing operation may be performed. To
avoid drilling through the casing string 132 and cement at that location, a
first
stage of a multi-stage cementing operation may be performed to cement the
portion of the casing string 132 below the predetermined location and a second
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stage of a multi-stage cementing operation may be performed to cement the
casing
string 132 above the predetermined location.
[0026] FIG. 2 depicts a cementing system for performing a multi-stage
cementing operation in accordance with one or more embodiments. The system
200 includes a downhole tool 202 interconnected in a casing string 204 having
an
upper casing portion 206 and a lower casing portion 208, the upper casing
portion
206 being located above the downhole tool 202 and the lower casing portion 208
being located below the downhole tool 202. The downhole tool 202 is
interconnected in the casing string 204 at a location determined based on the
operation, borehole conditions, operating equipment, and/or predetermined well
plans, among other factors, and is used to perform a multi-stage cementing
operation in which a first stage of cementing is performed followed by one or
more additional stages of cementing.
[0027] As shown, the casing string 204 is run into a borehole 210 that
includes a
previously run casing string 212 which was cemented into place using cement
214.
The casing string 204 may be run into the borehole 210 using a running tool
(not
shown) connected to a rig, such as drilling rig 104 in FIG. 1, and/or other
operating equipment known in the art.
[0028] Once the casing string 204 is run into the borehole 210, a first stage
of a
multi-stage cementing process may be performed. Cement is pumped along a flow
path through a bore 216 inside of the casing string 204 and the downhole tool
202
as indicated by arrows 218 and out a distal end 220 of the casing string 204.
Cement may then flow into an annulus 222 between the casing string 204 and a
borehole wall 224 and uphole along a length of the casing string 204. Pumping
may be stopped when the cement slurry reaches a predetermined depth 226 along
the length of the casing string 204. Once the cement slurry has set, the
downhole
tool 202 is opened and additional cement slurry is pumped downhole and enters
the annulus 222 through the downhole tool. Once the cement slurry pumped
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through the downhole tool 202 is set, the process can be repeated with
additional
downhole tools 202 as necessary until the multi-stage cementing process is
completed.
[0029] In one or more embodiments, the predetermined depth 226 may be
determined based on the total length of the casing string 204, borehole
conditions,
operating equipment, and/or predetermined well plans, among other factors. It
should be understood that the predetermined depth 226 may be at any location
along the length of the casing string 204 and may extend into the annulus 222
between the casing string 204 and the previously run casing string 212. In
addition, although not shown, it should be understood that other equipment
such as
guide shoes, float collars, flapper valves, stage plugs, and the like, may be
included and used in the multi-stage cementing process without departing from
the
scope of the present disclosure.
[0030] In another embodiment, a packer (not shown), such as, but not limited
to,
an inflatable packer or a swellable packer, may be set or a fluid barrier of
fluid
denser than the cement slurry may be created downhole the downhole tool 202. A
packer may be used to isolate the formation downhole of the downhole tool 202
prior to pumping cement slurry into the annulus. A packer or fluid barrier may
be
used when the formation downhole of the downhole tool 202 is weak and will not
allow the cementing operation to be completed.
[0031] Turning now to FIGs. 3-5, FIGs. 3-5 illustrate a downhole tool 300 that
may be used in place of downhole tool 202 when performing a multi-stage
cementing process. The downhole tool 300 is sequentially positionable between
a
run-in position, an open position, and a closed position, as described in more
detail
below. The downhole tool 300 includes a tubular body 302 that includes one or
more ports 304 and an inner sleeve 306. The inner sleeve 306 is initially held
in
the run-in position that blocks the port 304, as shown in FIG. 3, via one or
more
shear pins 308. The inner sleeve and/or tubular body 302 also include multiple
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seals 310 to prevent fluid from flowing out from the bore 312 of the downhole
tool
300 to an area radially outside of the downhole tool 300 when the inner sleeve
306
is in the run-in position.
[0032] When it is desired to open the downhole tool 300, a pressurized fluid
is
flowed through the bore 312 of the downhole tool 300 in the indicated
direction
314. The geometry of the sleeve and positions of the seals 310 is such that
the
pressure applies an unbalanced force on the inner sleeve 306. The unbalanced
force on the inner sleeve 306 causes the inner sleeve 306 to shift into an
open
position, as shown in FIG. 4. The open position exposes the ports 304 and
allows
fluid to pass from the bore 312 of the downhole tool, through the ports 304,
and
into an annulus surrounding the downhole tool 300. In at least one embodiment,
the inner sleeve 306 is retained in the open position via a locking mechanism
(not
shown) such as, but not limited to a ratcheting mechanism, a lock ring, or a
collet.
[0033] Once the cementing operation has been completed, a plug 500 is pumped
downhole and engages with a shoulder 502 coupled to or formed in an uphole end
portion 504 of the inner sleeve 306. The pressure applied to the plug 500 is
great
enough that the locking mechanism holding the inner sleeve 306 in the open
position is overcome and the inner sleeve 306 shifts into a closed position,
as
shown in FIG. 5. The movement to the closed position blocks the ports 304 in
the
tubular body 302 and prevents fluid from flowing out from the bore 312 of the
downhole tool 300. In at least one embodiment, the inner sleeve 306 is
retained in
the closed position via a second locking mechanism such as, but not limited to
a
ratcheting mechanism, a lock ring, or a collet.
[0034] In at least one embodiment, the interior surface 316 of the inner
sleeve
306 includes a profile 318 as shown in FIGs. 3-5 shaped to receive a setting
tool
(not shown). The setting tool engages with the profile to shift the inner
sleeve 306
to the open and closed positions. In other embodiments, the profile may be
omitted.
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[0035] Referring now to FIGs. 6-8, FIGs. 6-8 illustrate a downhole tool 600
that
may be used in place of downhole tool 202 when performing a multi-stage
cementing process. FIGS. 6-8 include many features that are similar to the
features
described above with reference to FIGs. 3-5. Accordingly, such features will
not
be described again in detail, except as necessary for the understanding of the
downhole tool 600 shown in FIGs. 6-8.
[0036] Similar to the downhole tool 300 described above, downhole tool 600
includes a tubular body 302 having one or more ports 304 and an inner sleeve
602
that is slidable within the tubular body 302 to control flow from the bore 312
of
the downhole tool 600 through the ports 304 in the tubular body 302. As shown
in
FIG. 6, the inner sleeve 602 includes one or more ports 604 that are aligned
with
the ports in the tubular body 302 when the inner sleeve is positioned in the
run-in
position. The downhole tool 600 also includes a seat 606 positioned within the
inner sleeve 602. When positioned in the run-in position, shown in FIG. 6, the
seat
606 and associated seals 608 block the flow of fluid from the bore 312 through
the
ports 304, 604 in the tubular body 302 and the inner sleeve 602. Similar to
the
inner sleeve, the seat is retained in the run-in position via one or more
shear pins
610.
[0037] When it is desired to open the downhole tool 600, an opening plug 700
is
pumped downhole and engages with a shoulder 702 coupled to or formed in the
seat 606, as shown in FIG. 7. The opening plug 700 shifts the seat 606 as
shown,
allowing fluid to flow from the bore 312 of the downhole tool, through the
ports
304, 604 in the tubular body 302 and the inner sleeve 602, and into an annulus
surrounding the downhole tool 600. In at least one embodiment, the seat 606 is
retained in the open position via a locking mechanism such as, but not limited
to a
ratcheting mechanism, a lock ring, or a collet.
[0038] Once the cementing operation has been completed, a plug 500 is pumped
downhole and engages with a shoulder 502 coupled to for formed in an uphole
end
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portion 504 of the inner sleeve 602. The pressure applied to the plug 500 is
great
enough that the shear pins 308 holding the inner sleeve 306 in the open
position
are sheared and the inner sleeve 602 shifts into a closed position, as shown
in FIG.
8. The movement to the closed position blocks the ports 304 in the tubular
body
302 and prevents fluid from flowing out from the bore 312 of the downhole tool
300. In at least one embodiment, the inner sleeve 602 is retained in the
closed
position via a second locking mechanism such as, but not limited to a
ratcheting
mechanism, a lock ring, or a collet.
[0039] Turning now to FIGs. 9-11, FIGs. 9-11 illustrate a downhole tool 900
that
may be used in place of downhole tool 202 when performing a multi-stage
cementing process. FIGS. 9-11 include many features that are similar to the
features described above with reference to FIGs. 3-8. Accordingly, such
features
will not be described again in detail, except as necessary for the
understanding of
the downhole tool 900 shown in FIGs. 9-11.
[0040] Similar to the downhole tools 300, 600 described above, downhole tool
900 includes a tubular body 302 having one or more ports 304 and an inner
sleeve
902 that is slidable within the tubular body 302 to control flow from the bore
312
of the downhole tool 900 through the ports 304 in the tubular body 302. As
shown
in FIG. 6, the inner sleeve 902 includes one or more ports 904 that are offset
from
ports in the tubular body 302 when the inner sleeve is positioned in the run-
in
position. The downhole tool 900 also includes a seat 606 positioned within the
inner sleeve 902. When positioned in the run-in position, shown in FIG. 9, the
inner sleeve 902 blocks the flow of fluid from the bore 312 through the ports
304
in the tubular body 302.
[0041] When it is desired to open the downhole tool 900, an opening plug 700
is
pumped downhole and engages with a shoulder 702 coupled to or formed in the
seat 606, as shown in FIG. 10. The opening plug 700 shifts the seat 606 as
shown,
allowing fluid to flow from the bore 312 of the downhole tool, through the
ports
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304, 904 in the tubular body 302 and the inner sleeve 902, and into an annulus
surrounding the downhole tool 900. In at least one embodiment, the inner
sleeve
902 is retained in the open position via a locking mechanism such as, but not
limited to a ratcheting mechanism, a lock ring, or a collet.
[0042] Once the cementing operation has been completed, a plug 500 is pumped
downhole and engages with a shoulder 502 coupled to for formed in an uphole
end
portion 504 of the inner sleeve 902. The pressure applied to the plug 500 is
great
enough that the locking mechanism holding the inner sleeve 902 in the open
position is overcome and the inner sleeve 902 shifts into a closed position,
as
shown in FIG. 11. The movement to the closed position blocks the ports 304 in
the
tubular body 302 and prevents fluid from flowing out from the bore 312 of the
downhole tool 900. In at least one embodiment, the inner sleeve 902 is
retained in
the closed position via a second locking mechanism such as, but not limited to
a
ratcheting mechanism, a lock ring, or a collet.
[0043] Further examples include:
[0044] Example 1 is a downhole tool. The downhole tool includes a tubular
body and an inner sleeve that is slidable within the tubular body. The tubular
body
includes a port that allows fluid flow between a bore of the downhole tool and
an
area outside of the tubular body. The downhole tool is sequentially
positionable in
a run-in position that blocks fluid flow through the port in the tubular body,
then in
an open position that allows fluid flow through the port in the tubular bod,
and
then in a closed position that blocks fluid flow through the port in the
tubular
body.
[0045] In Example 2, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve blocks fluid flow
through the port in the tubular body when in the downhole tool is in the run-
in
position.
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[0046] In Example 3, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve is sequentially
positionable in a run-in position, then in an open position, and then in a
closed
position.
[0047] In Example 4, the embodiments of any preceding paragraph or
combination thereof further include a seat disposed within the inner sleeve.
The
seat includes a shoulder shaped to receive a plug to shift the inner sleeve to
position the downhole tool in the open position.
[0048] In Example 5, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve and the tubular
body
are shaped such that the downhole tool is shiftable into an open position via
an
unbalanced force acting on the inner sleeve, the unbalanced force due to fluid
pressure within the downhole tool.
[0049] In Example 6, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve includes a
shoulder
shaped to receive a plug to shift the inner sleeve to position the downhole
tool in
the closed position.
[0050] In Example 7, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve comprises a
profile
on an interior surface of the inner sleeve.
[0051] In Example 8, the embodiments of any preceding paragraph or
combination thereof further include a seat slidable within the inner sleeve.
Additionally, the inner sleeve further includes a port that, when the downhole
tool
is positioned in the run-in position, is aligned with the port in the tubular
body.
Further, the seat is positionable in a run-in position that blocks fluid flow
through
the port in the inner sleeve and an open position that allows fluid flow
through the
port in the inner sleeve.
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[0052] Example 9 is a cementing system for a borehole. The cementing system
includes a casing string positionable within the borehole and including a
downhole
tool. The downhole tool includes a tubular body and an inner sleeve that is
slidable
within the tubular body. The tubular body includes a port that allows fluid
flow
between a bore of the downhole tool and an area radially outside of the
tubular
body. The downhole tool is sequentially positionable in a run-in position that
blocks fluid flow through the port in the tubular body, then in an open
position that
allows fluid flow through the port in the tubular bod, and then in a closed
position
that blocks fluid flow through the port in the tubular body.
[0053] In Example 10, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve blocks fluid flow
through the port in the tubular body when in the downhole tool is in the run-
in
position.
[0054] In Example 11, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve is sequentially
positionable in a run-in position, then in an open position, and then in a
closed
position.
[0055] In Example 12, the embodiments of any preceding paragraph or
combination thereof further include wherein the downhole tool further includes
a
seat disposed within the inner sleeve. The seat includes a shoulder shaped to
receive a plug to shift the inner sleeve to position the downhole tool in the
open
position.
[0056] In Example 13, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve and the tubular
body
are shaped such that the inner sleeve is shiftable into an open position via
an
unbalanced force acting on the inner sleeve, the unbalanced force due to fluid
pressure within the downhole tool.
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[0057] In Example 14, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve includes a
shoulder
shaped to receive a plug to shift the inner sleeve to position the downhole
tool in
the closed position.
[0058] In Example 15, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve comprises a
profile
on an interior surface of the inner sleeve.
[0059] In Example 16, the embodiments of any preceding paragraph or
combination thereof further include wherein the inner sleeve further comprises
a
port that, when the downhole tool is positioned in the run-in position, is
aligned
with the port in the tubular body. Additionally, the downhole tool further
includes
a seat slidable within the inner sleeve, the seat positionable in a run-in
position
that blocks fluid flow through the port in the inner sleeve and an open
position that
allows fluid flow through the port in the inner sleeve.
[0060] Example 17 is a method for cementing a casing string in a borehole. The
method includes positioning a casing string comprising a downhole tool within
a
borehole, wherein the downhole tool is positioned in a run-in position that
blocks
fluid flow between a bore of the downhole tool and an annulus formed between
the casing string and a wall of the borehole. The method also includes
shifting the
downhole tool to an open position to allow fluid flow between the bore of the
downhole tool and the annulus. The method further includes shifting the
downhole
tool to a closed position to block fluid flow between the bore of the downhole
tool
and the annulus.
[0061] In Example 18, the embodiments of any preceding paragraph or
combination thereof further include wherein shifting the downhole tool to the
open
position includes shifting an inner sleeve of the downhole tool via an
unbalanced
force acting on the inner sleeve to shift the downhole tool to the open
position, the
unbalanced force due to fluid pressure within the downhole tool.
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[0062] In Example 19, the embodiments of any preceding paragraph or
combination thereof further include wherein shifting the downhole tool to the
open
position includes pumping a plug downhole to engage with a shoulder of a seat
of
the downhole tool to shift the downhole tool to the open position.
[0063] In Example 20, the embodiments of any preceding paragraph or
combination thereof further include wherein shifting the downhole tool to the
closed position includes pumping a plug downhole to engage with a shoulder of
an
inner sleeve of the downhole tool to shift the downhole tool to the closed
position.
[0064] Certain terms are used throughout the description and claims to refer
to
particular features or components. As one skilled in the art will appreciate,
different persons may refer to the same feature or component by different
names.
This document does not intend to distinguish between components or features
that
differ in name but not function.
[0065] Reference throughout this specification to "one embodiment," "an
embodiment," "an embodiment," "embodiments," "some embodiments," "certain
embodiments," or similar language means that a particular feature, structure,
or
characteristic described in connection with the embodiment may be included in
at
least one embodiment of the present disclosure. Thus, these phrases or similar
language throughout this specification may, but do not necessarily, all refer
to the
same embodiment.
[0066] The embodiments disclosed should not be interpreted, or otherwise used,
as limiting the scope of the disclosure, including the claims. It is to be
fully
recognized that the different teachings of the embodiments discussed may be
employed separately or in any suitable combination to produce desired results.
In
addition, one skilled in the art will understand that the description has
broad
application, and the discussion of any embodiment is meant only to be
exemplary
of that embodiment, and not intended to suggest that the scope of the
disclosure,
including the claims, is limited to that embodiment.
