Note: Descriptions are shown in the official language in which they were submitted.
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Downhole Tool with Multiple Pistons
Background
100011 This section is intended to introduce the reader to various aspects of
art
that may be related to various aspects of the presently described embodiments.
This discussion is believed to be helpful in providing the reader with
background
information to facilitate a better understanding of the various aspects of the
described embodiments. Accordingly, it should be understood that these
statements are to be read in this light and not as admissions of prior art.
100021 In a hydrocarbon production well, it is many times beneficial to be
able to
regulate flow of fluids from an earth formation into a wellbore, from the
wellbore
into the formation, and within the wellbore. A variety of purposes may be
served
by such regulation, including prevention of water or gas coning, minimizing
sand
production, minimizing water and/or gas production, maximizing oil production,
balancing production among zones, transmitting signals, etc.
100031 For example, it is common to deploy hydraulic control lines in
subterranean wellbores, such as oil wells, in order to control downhole
equipment.
Packers, valves, and perforating guns are some of the downhole tool types that
can
be controlled by changes in pressure in the fluid contained in the hydraulic
control
lines or contained in production or drill pipes. In some prior art systems,
multiple
control lines are deployed in the wellbore to control multiple downhole tools.
Typically the top end of each control line extends to the surface (land or sea
floor)
and is connected to a hydraulic pump that can control the pressure of the
fluid
inside the line.
[0004] A control line must be passed through a feedthrough of a packer in
order
to extend the control line from the top to the bottom of the packer (or across
the
packer). Among others, a function of a packer is to seal the wellbore annulus
across the packer. However, each time a control line is extended through a
feedthrough, a potential leak path is created in the packer potentially
allowing the
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seal created by the packer to fail. Therefore, the prior art would benefit
from a
system that decreases the number of control lines necessary to control
multiple
downhole tools.
Brief Description of the Drawings
[0005] For a detailed description of the embodiments of the invention,
reference
will now be made to the accompanying drawings in which:
[0006] FIG. 1 shows schematic view of a well system including pressure
operating devices in accordance with one or more embodiments of the present
disclosure;
[0007] FIG. 2 shows a cross-sectional view of a downhole tool for use within a
system or wellbore in accordance with one or more embodiments of the present
disclosure; and
[0008] FIG. 3 shows a cross-sectional view of a downhole tool for use within a
system or wellbore in accordance with one or more embodiments of the present
disclosure.
[0009] The illustrated figures are only exemplary and are not intended to
assert
or imply any limitation with regard to the environment, architecture, design,
or
process in which different embodiments may be implemented.
Detailed Description
[0010] Turning now to the present figures, FIG. 1 shows a well system 5 that
can
embody principles of the present disclosure. The system 5 of the present
disclosure will be specifically described below such that the system 5 is used
to
control a pressure operating device, such as an indexing sleeve. However, it
should be understood that the system 5 can control the operation of any
hydraulically actuated downhole tool 6, including but not limited to flow
control
devices, packers, perforating guns, safety valves, pumps, gas lift valves,
anchors,
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bridge plugs, and sliding sleeves. Moreover, by using an embodiment in
accordance with the present disclosure, any combination of downhole tools may
be connected and controlled in accordance with the discussion below.
[0011] As depicted in FIG. 1, a wellbore 10 extends from the surface 12 into
the
earth and intersects at least one formation 14. The wellbore 10 can be a land
well
or a subsea well, in which the surface 12 may correspond to the bottom of the
ocean or sea, or a platform well. In this embodiment, the wellbore 10 may be
cased, but the present disclosure is not so limited. Further, tubing 16 is
deployed
within wellbore 10, in which the tubing 16 may include production tubing,
coiled
tubing, drill pipe, or any other tubular member or apparatus for conveyance
used
in subterranean wells. One or more valve systems 17 may be deployed on the
tubing 16, in which each valve system 17 may include a flow control device 18
disposable downhole, such as a sleeve valve, a ball valve, a disc valve, a
choke, a
variable orifice valve, an in-line valve, or any other type of valve known in
the art.
Each valve system 17 may also include an indexing sleeve 20 that is associated
with its corresponding flow control device 18. The indexing sleeve 20 may be
coupled and hydraulically connected to the tubing 16 such that pressure in the
tubing 16 is received by the indexing sleeve 20.
100121 A change in pressure or a pressure cycle in the tubing 16, such as
induced
by a pressure source, may be used to control or actuate each indexing sleeve
20.
An actuation in each indexing sleeve 20 may activate, deactivate, or change
the
setting of the corresponding flow control device 18, depending on the
construction
and configuration of the relevant indexing sleeve 20 and flow control device
18. In
the present application, the indexing sleeves 20 are constructed and
configured so
as to function in concert or together so as to provide a different permutation
of
settings of the plurality of the flow control devices 18 for each pressure
change or
cycle induced in the tubing 16. A user can thereby control the valve systems
17 as
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a system to select his/her desired permutation of settings for each of the
flow
control devices 18.
[0013] Referring now to FIG. 2, a cross-sectional view of a downhole tool 100
for use within a system or wellbore (e.g., shown in FIG. 1) in accordance with
one
or more embodiments of the present disclosure is shown. The tool 100 includes
a
tool body 102 that has an axis 104 extending therethrough. The tool body 102
further includes an inner housing 106 and an outer housing 108, with the inner
housing 106 positioned within the outer housing 108. Accordingly, a bore of
the
inner housing 106 may also be defined as a bore 110 for the tool 100, and the
inner
housing 106 and the outer housing 108 may form an annulus 112 therebetween.
The annulus 112 is in fluid communication with the bore 110 of the tool 100,
such
as by having one or more ports 132 or flow channels formed within the inner
housing 106 to enable fluid flow between the bore 110 and the annulus 112.
[0014] The tool 100 also includes a pressure operating device 114, such as an
indexing sleeve discussed above. The pressure operating device 114 may be in
fluid communication with the annulus 112 and/or the bore 110 of the tool 100.
For
example, in this embodiment, the pressure operating device 114 is positioned
within the annulus 112 of the tool 100. As the pressure operating device 114
is in
fluid communication with the annulus 112 and the bore 110 of the tool 100,
pressure (e.g., fluid pressure) introduced into the bore 110 of the tool 100
is
communicated to and exerted upon the pressure operating device 114. A change
in
pressure or a pressure cycle in the bore 110 of the tool 100 may therefore be
used
to control or actuate the pressure operating device 114. Accordingly, the
pressure
operating device 114 is used to operate in response to a pressure above an
operating pressure (e.g., 3,000 psi, 20,700 kPa). Therefore, when pressure is
introduced into the bore 110 above the operating pressure, the pressure may be
used to operate and activate the pressure operating device 114. When pressure
is
below the operating pressure, the pressure operating device 114 may remain
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inactive. For example, a pressure above the operating pressure, such as above
about 3,000 psi, will cause an indexing sleeve to move a flow control device,
such
as to open or close the flow control device, to control fluid flow through the
bore
110 of the tool 100.
[0015] Referring still to FIG. 2, the tool 100 may include two or more pistons
positioned therein. For example, as shown, a primary piston 116 (e.g., upper
piston, first piston) may be positioned within the annulus 112 between the
inner
housing 106 and the outer housing 108, thereby forming a primary cavity 118
within the annulus 112. The primary piston 116 includes one or more seals 120
to
sealingly engage an outer surface of the inner housing 106 and/or an inner
surface
of the outer housing 108. The primary piston 116 may be used to separate well
fluids introduced into the bore 110 of the tool 100 from fluids (e.g., control
fluid,
silicone oil) included within the primary cavity 118.
[0016] Further, a backup piston 122 (e.g., lower piston, second piston) may be
positioned within the annulus 112 between the inner housing 106 and the outer
housing 108, thereby forming a backup cavity 124 within the annulus 112. In
particular, the backup piston 122 may be positioned between the primary piston
116 and the pressure operating device 114. The backup piston 122 may then be
positioned between and separate the primary cavity 118 from the second cavity
124, and the pressure operating device 114 may then be in fluid communication
with the second cavity 124. The backup piston 122 includes one or more seals
126
to sealingly engage an outer surface of the inner housing 106 and/or an inner
surface of the outer housing 108.
[0017] In this embodiment, the backup piston 122 may include a pressure
inhibiting device 128, such as to prevent pressure that is below a
predetermined
amount from communicating across the backup piston 122. For example, the
backup piston 122 may include a flow path 130 extending therethrough to enable
pressure and/or fluid to flow along the flow path 130 and through the backup
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piston 122. The pressure inhibiting device 128, however, may prevent pressure
that is below a predetermined amount from flowing along the flow path 130 and
through the backup piston 122. An example of a pressure inhibiting device 128
may include a frangible element (e.g., burst disc) and/or a relief valve.
[0018] In one or more embodiments, the predetermined amount of pressure for
the pressure inhibiting device 128 is lower than the operating pressure for
the
pressure operating device 114. For example, in an embodiment in which the
operating pressure for the pressure operating device 114 is at or above 3,000
psi
(20,700 kPa), the predetermined amount of pressure for the pressure inhibiting
device may be at or lower than about 2,000 psi (13,800 kPa). This may enable
fluid flow through the pressure inhibiting device 128 and the backup piston
122
such that the pressure may still be able to operate and activate the pressure
operating device 114.
[0019] A tool or system in accordance with one or more embodiments of the
present disclosure may be able to operate, even in the occurrence of one or
more
leaks within the tool. For example, with respect to FIG. 2, a leak may occur
such
that fluid can escape the cavity of the tool 100. In an embodiment in which
only
one piston is included, then the leak may cause the piston to bottom out
within the
fluid cavity and against the pressure operating device, thereby preventing
pressure
from communicating across the piston to operate and activate the pressure
operating device. However, by way of example, if a leak occurs within the
second
cavity 124 and/or a third cavity 134 (positioned on a side of the pressure
operating
device 114 opposite the backup piston 122), even though the piston 122 will
bottom out within the second cavity 124 and against the pressure operating
device
114, the pressure inhibiting device 128 will still enable fluid flow through
the
backup piston 122 such that the pressure will still be able to operate and
activate
the pressure operating device 114.
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[0020] As mentioned above, a tool in accordance with the present disclosure
may
include two or more pistons positioned therein. Accordingly, in another
embodiment, such as shown in FIG. 3, the tool 100 may include another backup
piston 140 (e.g., middle piston, third piston), such as positioned within the
annulus
112 between the inner housing 106 and the outer housing 108 to form another
back cavity 142 within the annulus 112. The additional backup piston 140 may
be
positioned between the primary piston 116 and the backup piston 122 such that
the
additional backup piston 140 is positioned between and separates the primary
cavity 118 from the additional backup cavity 142. The additional backup piston
140 may be similar to the backup piston 122 in that the additional backup
piston
140 may also include a (e.g., backup) pressure inhibiting device 144. The
backup
pressure inhibiting device 144 may be used to prevent pressure below a
predetermined amount from communicating across the additional backup piston
140. In one or more embodiments, the predetermined amount of pressure for the
backup pressure inhibiting device 144 may be higher than the predetermined
amount of pressure for the primary pressure inhibiting device 128.
[0021] In addition to the embodiments described above, many examples of
specific combinations are within the scope of the disclosure, some of which
are
detailed below:
Example 1. A downhole tool, comprising:
a tool body comprising an inner housing and an outer housing to form an
annulus
between the inner housing and the outer housing;
a primary piston positioned within the annulus to form a primary cavity within
the
annulus;
a backup piston positioned within the annulus to form a second cavity within
the
annulus; and
a pressure operating device in fluid communication with the annulus and
configured to operate in response to a pressure in the annulus.
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Example 2. The downhole tool of Example 1, wherein the pressure operating
device is configured to operate in response to the pressure in the annulus
being
above an operating pressure.
Example 3. The downhole tool of Example 2, wherein the operating pressure is
at
or above about 3,000 psi (20,700 kPa).
Example 4. The downhole tool of Example 2, wherein the backup piston is
positioned between the primary cavity and the second cavity and comprises a
pressure inhibiting device configured to prevent pressure below a
predetermined
amount from communicating across the backup piston.
Example 5. The downhole tool of Example 4, wherein the predetermined amount
of pressure for the pressure inhibiting device is lower than the operating
pressure
for the pressure operating device.
Example 6. The downhole tool of Example 4, wherein the predetermined amount
for the pressure inhibiting device is at or lower than about 2,000 psi (13,800
kPa).
Example 7. The downhole tool of Example 4, wherein the pressure inhibiting
device comprises at least one of a frangible element and a relief valve, and
wherein the frangible element comprises a burst disc.
Example 8. The downhole tool of Example 4, further comprising another backup
piston positioned within the annulus to form another backup cavity within the
annulus positioned between the primary cavity and the other backup cavity.
Example 9. The downhole tool of Example 8, wherein:
the other backup piston comprises a backup pressure inhibiting device
configured
to prevent pressure below a second predetermined amount from communicating
across the other backup piston; and
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the second predetermined amount for the backup pressure inhibiting device is
higher than the first predetermined amount for the primary pressure inhibiting
device.
Example 10. The downhole tool of Example 1, wherein the pressure operating
device is positioned within the annulus and is in fluid communication with the
second cavity.
Example 11. The downhole tool of Example 1, wherein the pressure operating
device comprises an indexing sleeve.
Example 12. The downhole tool of Example 1, wherein a port is formed within
inner housing to enable fluid communication between a bore of the inner
housing
and the annulus.
Example 13. The downhole tool of Example 1, wherein at least one of the
primary
piston and the backup piston comprises a seal to sealingly engage the tool
body.
Example 14. A method to operate a pressure operating device in a downhole
tool,
the method comprising:
introducing pressure into a bore of a tool body of the downhole tool, the tool
body
comprising an inner housing and an outer housing to form an annulus between
the
inner housing and the outer housing;
communicating the pressure across a primary piston positioned within the
annulus;
communicating the pressure across a backup piston positioned within the
annulus;
and
operating the pressure operating device in response to the pressure in the
annulus.
Example 15. The method of Example 14, wherein the communicating the pressure
across the backup piston comprises communicating the pressure through a
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pressure inhibiting device of the backup piston if a pressure differential
develops
across the backup piston above a predetermined amount.
Example 16. The method of Example 15, wherein the pressure operating device
operates in response to a pressure above an operating pressure, wherein the
predetermined amount of pressure for the pressure inhibiting device is lower
than
the operating pressure for the pressure operating device.
Example 17. The method of Example 15, wherein the pressure inhibiting device
comprises at least one of a frangible element and a relief valve, and wherein
the
frangible element comprises a burst disc.
Example 18. The method of Example 15, further comprising communicating the
pressure across another backup piston positioned within the annulus, wherein
the
communicating the pressure across the other backup piston comprises
communicating the pressure through a back pressure inhibiting device of the
other
backup piston if a pressure differential develops across the other backup
piston
above a second predetermined amount, and wherein the second predetermined
amount for the backup pressure inhibiting device is higher than the first
predetermined amount for the primary pressure inhibiting device.
Example 19. The method of Example 14, wherein the pressure operating device
comprises an indexing sleeve.
Example 20. A downhole tool, comprising:
a tool body comprising an inner housing and an outer housing to form an
annulus
between the inner housing and the outer housing with the annulus in fluid
communication with a bore of the inner housing;
a primary piston positioned within the annulus to form a primary cavity within
the
annulus;
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a backup piston positioned within the annulus to form a second cavity within
the
annulus with the backup piston positioned between the primary cavity and the
second cavity;
a pressure inhibiting device configured to prevent pressure below a
predetermined
amount from communicating across the backup piston;
a pressure operating device in fluid communication with the annulus and
configured to operate in response to a pressure in the annulus above an
operating
pressure; and
wherein the predetermined amount of pressure for the pressure inhibiting
device is
lower than the operating pressure for the pressure operating device.
100221 This discussion is directed to various embodiments of the invention.
The
drawing figures are not necessarily to scale. Certain features of the
embodiments
may be shown exaggerated in scale or in somewhat schematic form and some
details of conventional elements may not be shown in the interest of clarity
and
conciseness. Although one or more of these embodiments may be preferred, 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 intimate that the scope of the disclosure, including the
claims,
is limited to that embodiment.
100231 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, unless specifically stated. In the discussion
and in
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the claims, the terms "including" and "comprising" are used in an open-ended
fashion, and thus should be interpreted to mean "including, but not limited
to... ."
Also, the term "couple" or "couples" is intended to mean either an indirect or
direct connection. In addition, the terms "axial" and "axially" generally mean
along or parallel to a central axis (e.g., central axis of a body or a port),
while the
terms "radial" and "radially" generally mean perpendicular to the central
axis. The
use of "top," "bottom," "above," "below," and variations of these terms is
made
for convenience, but does not require any particular orientation of the
components.
100241 Reference throughout this specification to "one embodiment," "an
embodiment," 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, appearances of the
phrases
"in one embodiment," "in an embodiment," and similar language throughout this
specification may, but do not necessarily, all refer to the same embodiment.
100251 Although the present invention has been described with respect to
specific
details, it is not intended that such details should be regarded as
limitations on the
scope of the invention, except to the extent that they are included in the
accompanying claims.
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