Note: Descriptions are shown in the official language in which they were submitted.
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TITLE
[0001] Downhole Tools, System and Method for Using
CROSS-REFERENCES TO RELATED APPLICATIONS
[0002] This original non-provisional application claims the benefit of
U.S.
Provisional Patent Application Ser. No. 61/885,615; is a Continuation in Part,
and claims the
benefit, of United States Patent Application Ser. No. 14/211,122, entitled
Downhole Tools
System and Method of Using filed March 14, 2014, which claims the benefit of
United States
Provisional Patent Application Ser. No. 61/801,937, entitled "Downhole Tools
System and
Method of Using" filed on March 15, 2013; and of United States Provisional
Patent Application
Ser. No. 61/862,766, entitled "Downhole Tools System and Method of Using"
filed on August
16, 2013; and is a Continuation in Part of U.S. Patent Application Ser. No.
13/462,180, filed
May 2, 2012 entitled "Downhole Tool," which claims the benefit of United
States Provisional
Patent Application Ser. No. 61/481,483 filed on May 2, 2011. Each of the
foregoing references
are incorporated herein by reference in their entirety
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR
DEVELOPMENT
[0003] Not applicable.
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BACKGROUND
1. Field
[0004] The described embodiments and invention as claimed relate to oil
and natural
gas production. More specifically, the embodiments described herein relate to
downhole tools
systems and methods used to selectively pressurize and test a production
string or casing and to
selectively activate a tool or a series of tools connected together by flow
lines.
2. Description of the Related Art.
[0005] In completion of oil and gas wells, tubing is often inserted into
the well to
function as a flow path for treating fluids into the well and for production
of hydrocarbons from
the well. Such tubing may help preserve casing integrity, optimize production,
or serve other
purposes. Such tubing may be described or labeled as casing, production
tubing, liners, tubulars,
or other terms. The term "tubing" as used in this disclosure and the claims is
not limited to any
particular type, shape, size or installation of tubular goods.
[0006] To fulfill these purposes, the tubing must maintain structural
integrity against
the pressures and pressure cycles it will encounter during its functional
life. To test this
integrity, operators will install the tubing with a closed "toe"¨the end of
the tubing furthest
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from the wellhead¨and then subject the tubing to a series of pressure tests.
These tests are
designed to demonstrate whether the tubing will hold the pressures for which
it was designed, to
which it will be subjected during operation or an acceptable alternative
pressure, depending on
the particular circumstances.
[0007] One detriment to these pressure tests is the necessity for a
closed toe. After
pressure testing, the toe must be opened to allow for free flow of fluids
through the tubing so that
further operations may take place. While formation characteristics, cement, or
other factors may
still restrict fluid flow, the presence of such factors do not alleviate the
desirability or necessity
for opening the toe of the tubing. Commonly, the toe is opened by positioning
a perforating
device in the toe and either explosively or abrasively perforating the tubing
to create one or more
openings. Perforating, however, requires additional time and equipment that
increase the cost of
the well. Therefore, there exists a need for an improved method to
economically pressure test
the tubing and open the toe of the tubing after it is installed and pressure
tested.
[0008] The present disclosure describes an improved device and method
for pressure
testing the tubing and opening the toe of tubing installed in a well. The
device and method may
be readily adapted to other well applications as well. The present disclosure
also describes
embodiments having degradable or shiftable triggering devise as well as
embodiments relating to
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actuating a series of tools using flow lines that communicate fluid pressure
between connected
tools for actuation.
SUMMARY OF CERTAIN EMBODIMENTS
[0009] The described embodiments of the present disclosure address the
problems
associated with the closed toe required for pressure testing tubing installed
in a well. Further, in
one aspect of the present disclosure, a chamber, such as a pressure chamber,
air chamber, or
atmospheric chamber, is in fluid communication with at least one surface of
the shifting element,
which may be a shifting sleeve, of the device. The chamber is isolated from
the interior of the
tubing such that fluid pressure inside the tubing is not transferred to the
chamber. A second
surface of the shifting sleeve is in fluid communication with the interior of
the tubing.
Application of fluid pressure on the interior of the tubing thereby creates a
pressure differential
across the shifting element, applying force tending to shift the shifting
element in the direction of
the pressure chamber, atmospheric chamber, or air chamber.
[0010] In a further aspect of the present disclosure, the shifting
sleeve is encased in an
enclosure such that all surfaces of the shifting element opposing the chamber
are isolated from
the fluid, and fluid pressure, in the interior of the tubing. Upon occurrence
of some pre-
determined event¨such as a minimum fluid pressure, the presence of acid, or
electromagnetic
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signal¨at least one surface of the shifting element is exposed to the fluid
pressure from the
interior of the tubing, creating differential pressure across the shifting
sleeve. Specifically, the
pressure differential is created relative to the pressure in the chamber, and
applies a force on the
shifting element in a desired direction. Such force activates the tool.
[0011] While specific predetermined events are stated above, any event
or signal
communicable to the device may be used to expose at least one surface of the
shifting element to
pressure from the interior of the tubing.
[0012] In a further aspect, the downhole tool comprises an inner sleeve
with a
plurality of sleeve ports. A housing is positioned radially outwardly of the
inner sleeve, with the
housing and inner sleeve partially defining a space radially therebetween. The
space, which is
preferably annular, is occupied by a shifting element, which may be a shifting
sleeve. A fluid
path extends between the interior flowpath of the tool and the space. Thus,
the shifting element
may be nested between the housing and the inner sleeve. A fluid control
device, which is
preferably a burst disk, occupies at least portion of the fluid path.
[0013] When the toe is closed, the shifting sleeve is in a first
position between the
housing ports and the sleeve ports to prevent fluid flow between the interior
flowpath and
exterior of the tool. A control member is installed to prevent or limit
movement of the shifting
sleeve until a predetermined internal tubing pressure or internal flowpath
pressure is reached.
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Such member may be a fluid control device which selectively permits fluid
flow, and thus
pressure communication, into the annular space to cause a differential
pressure across the
shifting sleeve. Any device, including, without limitation, shear pins,
springs, and seals, may be
used provided such device allows movement of the shifting element, such as
shifting sleeve, only
after a predetermined internal tubing pressure or other predetermined event
occurs. In a
preferred embodiment, the fluid control device will permit fluid flow into the
annular space only
after it is exposed to a predetermined differential pressure. When this
differential pressure is
reached, the fluid control device allows fluid flow, the shifting sleeve is
moved to a second
position, the toe is opened, and communication may occur through the housing
and sleeve ports
between the interior flowpath and exterior of the tool.
[0014] In a
further aspect of this disclosure, embodiments of the downhole tool may
be connected in series with one or more other tools to enable fluid pressure
and fluid flow at one
location in a tool string to actuate another tool in the series. Such
embodiments may include a
plurality of similar tools such that actuation of one tool also actuates other
tools in the series.
Such embodiments may include flow lines, separate tubing, annular spaces (such
as between
tools and casing, housing and inner sleeve or mandrel, through a wall of a
housing, inner sleeve
or mandrel, or otherwise), other fluid path defining means, or combinations of
the above, to
transfer fluid pressure from the interior of one tool to pressure chambers
within separate tools,
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thereby creating pressure differentials to effect hydraulic actuation of the
separate tools. The
first tool in such series may be referred to as an initiator tool while the
last tool may be referred
to as a terminator tool. Tools in such a series between the initiator and the
terminator may be
called intermediate tools. Such intermediate tools can receive fluid
communication from a
preceding tool along a fluid conduit distinct from the internal flowpath of
the tubing string and
transmit fluid flow and/or pressure with a subsequent tool along a fluid
conduit also distinct from
the internal flowpath of the tubing string. Some embodiments of such
intermediate tools may
actuate in response to the fluid communication received from the preceding
tool. Further, some
embodiments of tools according to the present disclosure are ported valves,
having ports
allowing fluid communication between the interior and the exterior of the tool
following
actuation, while other embodiments are portless and do not allow such fluid
communication.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0015] FIGS. 1-2 are partial sectional side elevations of a preferred
embodiment in
the closed position.
[0016] FIGS. IA & 2A are enlarged views of windows IA and 2A of FIGS. I
& 2
respectively.
[0017] FIGS. 3-4 are partial sectional side elevations of one embodiment
in the open
position.
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[0018] FIG. 5 is a side sectional elevation of a system incorporating an
embodiment of
the downhole tool described with reference to FIGS. 1-4.
[0019] FIG. 6A & 6B are partial sectional side elevations of an
embodiment tool
having an outlet conduit which is in the closed position.
[0020] FIG 7A is an enlarged view of the bottom connection of the
embodiment tool
of FIGS 1-4.
[0021] FIG. 7B is an enlarged view of a portion of the outlet sub
portion of the
embodiment tool of FIGS 6A & 6B and 8A & 8B.
[0022] FIG. 8A & 8B are partial sectional side elevations of an
embodiment tool
having an outlet conduit which is in the open position.
[0023] FIG. 9 is sectional side elevation of one embodiment of an
intermediate tool in
the closed position.
[0024] FIG. 10A is an enlarged view of the inlet conduit and adjacent
structures of the
embodiment of FIG. 9.
[0025] FIG. 10B is an enlarged view of the outlet conduit and adjacent
structures of
the embodiment of FIG. 9.
[0026] FIG. 1 OC is an enlarged view of the annular space, shifting
sleeve, and
adjacent structures of the embodiment of FIG. 9.
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[0027] FIG. 11 is sectional side elevation of one embodiment of an
intermediate tool
in the open position.
[0028] FIG. 12 is an enlarged view of the annular space, shifting
sleeve, and adjacent
structures of the embodiment of FIG. 11.
[0029] FIG. 13 is sectional side elevation of one embodiment of a
portless burst disk
initiator tool.
[0030] FIG. 14 is sectional side elevation of one embodiment of a plug
seat initiator
tool in the closed position.
[0031] FIG 15A is an enlarged view of the outlet conduit and adjacent
structures of
the embodiment plug seat initiator tool of FIG. 14.
[0032] FIG. 15B is an isometric view of the isolation sleeve of the
embodiment plug
seat initiator tool shown FIG. 14.
[0033] FIG. 16 is sectional side elevation of one embodiment of a plug
seat initiator
tool in the open position.
[0034] FIG 17 is an enlarged view of the outlet conduit and adjacent
structures of the
embodiment plug seat initiator tool of FIG. 16.
[0035] FIG 18 is external view of an embodiment inner sleeve with flow
slots in the
outer surface.
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[0036] FIG. 19 is a side sectional elevation of a system incorporating
an initiator tool,
a terminator tool, and two intermediate tools.
[0037] FIG. 20 is a side sectional elevation of a system incorporating
multiple series
of tools according to the present disclosure.
[0038] FIG. 21 is an enlarged view of the annular space, shifting
sleeve, and adjacent
structures of an embodiment downhole tool having a degradable material fluid
control device in
addition to a burst disk.
[0039] FIG. 22 is an enlarged view of the annular space, shifting
sleeve, and adjacent
structures of an embodiment downhole tool having a degradable material fluid
control device in
the inner sleeve and blocking a fluid path connecting the interior flowpath
with the inlet mandrel
passageway.
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DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
[0040] When used with reference to the figures, unless otherwise
specified, the terms
"upwell," "above," "top," "upper," "downwell," "below," "bottom," "lower," and
like terms are
used relative to the direction of normal production and/or flow of fluids and
or gas through the
tool and wellbore. Thus, normal production results in migration through the
wellbore and
production string from the downwell to upwell direction without regard to
whether the tubing
string is disposed in a vertical wellbore, a horizontal wellbore, or some
combination of both.
Similarly, during the fracing process, fracing fluids and/or gasses move from
the surface in the
downwell direction to the portion of the tubing string within the formation.
Further, the
directional description of a part or component of a tool, such as "top" or
"bottom" connection
refers only to a preferred embodiment thereof and does not limit the
orientation of the tool as
installed in a wellbore except as may be otherwise required by the language of
the claims.
[0041] FIGS. 1-2 depict a preferred embodiment 20, which comprises a top
connection 22 threaded to a top end of ported housing 24 having a plurality of
radially-aligned
housing ports 26. A bottom connection 28 is threaded to the bottom end of the
ported housing
24. The top and bottom connections 22, 28 have cylindrical inner surfaces 23,
29, respectively.
A fluid path 30 through the wall of the top connection 22 is filled with a
burst disk 32 that will
rupture when a pressure is applied to the interior of the tool 22 that exceeds
a rated pressure.
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[0042] An inner sleeve 34 having a cylindrical inner surface 35 is
positioned between
a lower annular surface 36 of the top connection 22 and an upper annular
surface 38 of the
bottom connection 28. The inner sleeve 34 has a plurality of radially aligned
sleeve ports 40.
Each of the sleeve ports 40 is concentrically aligned with a corresponding
housing port 26. The
inner surfaces 23, 29 of the top and bottom connections 22, 28 and the inner
surface 35 of the
sleeve 35 define an interior flowpath 37 for the movement of fluids into, out
of, and through the
tool. In an alternative embodiment, the interior flowpath may be defined, in
whole or in part, by
the inner surface of the shifting sleeve.
[0043] Although the housing ports 26 and sleeve ports 40 are shown as
cylindrical
channels between the exterior and interior of the tool 20, the ports 26, 40
may be of any shape
sufficient to facilitate the flow of fluid therethrough for the specific
application of the tool. For
example, larger ports may be used to increase flow volumes, while smaller
ports may be used to
reduce cement contact in cemented applications. Moreover, while preferably
concentrically
aligned, each of the sleeve ports 40 need not be concentrically aligned with
its corresponding
housing port 26.
[0044] The top connection 22, the bottom connection 28, an interior
surface 42 of the
ported housing 24, and an exterior surface 44 of the inner sleeve 34 define an
annular space 45,
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which is partially occupied by a shifting sleeve 46 having an upper portion 48
and a lower
locking portion 50 having a plurality of radially-outwardly oriented locking
dogs 52.
[0045] The annular space 45 comprises an upper pressure chamber 53
defined by the
top connection 22, burst disk 32, outer housing 24, inner sleeve 34, the
shifting sleeve 46, and
upper sealing elements 62u. The annular space 45 further comprises a lower
pressure chamber
55 defined by the bottom connection 28, the outer housing 24, the inner sleeve
34, the shifting
sleeve 46, and lower sealing elements 621. Lower pressure chamber 55 may also
be referred to
as a receiving chamber as it functions to receive the shifting sleeve 46
following the creation of a
pressure differential across the shifting sleeve as described below. In a
preferred embodiment,
the pressure within the upper and lower pressure chambers 53,55 is atmospheric
when the tool is
installed in a well (i.e., the burst disk 32 is intact).
[0046] A locking member 58 partially occupies the annular space 45 below
the
shifting sleeve 46 and ported housing 24. When the sleeve is shifted, the
locking dogs 52 engage
the locking member 58 and inhibit movement of the shifting sleeve 46 toward
the shifting
sleeve's first position.
[0047] The shifting sleeve 46 is moveable within the annular space 45
between a first
position and a second position by application of hydraulic pressure to the
tool 20. When the
shifting sleeve 46 is in the first position, which is shown in FIGS. 1-2,
fluid flow from the
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interior to the exterior of the tool through the housing ports 26 and sleeve
ports 40 is impeded by
the shifting sleeve 46 and surrounding sealing elements 62. Shear pins 63 may
extend through
the ported housing 24 and engage the shifting sleeve 46 to prevent unintended
movement toward
the second position thereof, such as during installation of the tool 20 into
the well. Although
shear pins 63 function in such a manner as a secondary safety device,
alternative embodiments
contemplate operation without the presence of the shear pins 63. For example,
the downhole
tool may be installed with the lower pressure chamber containing fluid at a
higher pressure than
the upper pressure chamber, which would tend to move and hold the shifting
sleeve in the
direction of the upper pressure chamber.
[0048] To shift the sleeve 46 to the second position (shown in FIG. 3-
4), a pressure
greater than the rated pressure of the burst disk 32 is applied to the
interior of the tool 20, which
may be done using conventional techniques known in the art. This causes the
burst disk 32 to
rupture and allows fluid to flow through the fluid path 30 to the annular
space 45. In some
embodiments, the pressure rating of the burst disk 32 may be lowered by
subjecting the burst
disk 32 to multiple pressure cycles. Thus, the burst disk 32 may ultimately be
ruptured by a
pressure which is lower than the burst disk's 32 initial pressure rating.
[0049] Following rupture of the burst disk 32, the shifting sleeve 46 is
no longer
isolated from the fluid flowing through the inner sleeve 34. The resultant
increased pressure on
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the shifting sleeve surfaces in fluid communication with the upper pressure
chamber 53 creates a
pressure differential relative to the atmospheric pressure within the lower
pressure chamber 55.
Such pressure differential across the shifting sleeve causes the shifting
sleeve 36 to move from
the first position to the second position shown in FIG. 3-4, provided the
force applied from the
pressure differential is sufficient to overcome the shear pins 63, if present.
In the second
position, the shifting sleeve 46 does not impede fluid flow through the
housing ports 26 and
sleeve ports 40, thus allowing fluid flow between the interior flow path and
the exterior of the
tool. As the shifting sleeve 46 moves to the second position, the locking
member 58 engages the
locking dogs 52 to prevent subsequent upwell movement of the sleeve 46.
[0050] Upper
pressure chamber 53 serves as an inlet chamber, as it receives fluid
flow, and therefore fluid pressure, that passes the burst disk 32 following
rupture. Similarly, the
lower pressure chamber 55 serves as a receiving chamber for receiving the
shifting sleeve 46 as
it moves to the second position in response to the pressure differential
caused by increased fluid
pressure in the upper pressure, or inlet, chamber 53. FIG. 5 shows the
embodiment described
with reference to FIGS. 1-4 in use with tubing 198 disposed into a lateral
extending through a
portion of a hydrocarbon producing formation 200, with the tubing 198 having
various downhole
devices 202 positioned at various stages 204,208,212 thereof. The tubing 198
terminates with a
downhole tool 20 having the features described with reference to FIGS. 1-4 and
a plugging
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member 218 (e.g., bridge plug) designed to isolate flow of fluid through the
end of the tubing
198. Initially, the tool 20 is in the state described with reference to FIGS.
1-2.
[0051] Prior to using the tubing 198, the well operator may undertake a
number of
integrity tests by cycling and monitoring the pressure within the tubing 198
and ensuring
pressure loss is within acceptable tolerances. This, however, can only be done
if the downwell
end of the tubing 198 is isolated from the surrounding formation 200 with the
isolation member
218 closing off the toe of the tubing 198. After testing is complete, the tool
20 may be actuated
as described with reference to FIGS. 3-4 to open the toe end of tubing 198 to
the flow of fluids.
[0052] In another embodiment, downhole tools of the present disclosure
may be
placed in series such that actuation of an embodiment tool facilitates fluid
communication
between the interior flowpath of the actuated tool and least one other tool.
FIGS. 6A-B, 7B and
8A-B depict an embodiment downhole tool 120 for creating such fluid
communication.
Downhole tool 120 comprises a top connection 122 connected to, such as by
threading, an inlet
end of ported housing 124, the ported housing having, in certain embodiments,
a plurality of
radially-aligned housing ports 126. In the embodiment of Fig 6B, bottom
connection is replaced
with outlet sub 128 which is similarly connected to an outlet end of the
ported housing 124. The
top connection 122 and outlet sub 128 have inner surfaces 123,129,
respectively, which may be
cylindrical. A fluid path 130 through the wall of the top connection 122 is
filled with a burst
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disk 132 that will rupture when a pressure exceeding the burst disk's rated
pressure is applied to
the interior of the tool 120.
[0053] An inner sleeve 134 having a cylindrical inner surface 135 is
positioned
between a lower annular surface 136 of the top connection 122 and an upper
annular surface 138
of the outlet sub 128. The inner sleeve 134 may have a plurality of radially
aligned sleeve ports
140. One or more of the sleeve ports 140 may be aligned with a corresponding
housing port 126.
The inner surfaces 123, 129 of the top connection 122 and outlet sub 128 and
the inner surface
135 of the inner sleeve 134 define an interior flowpath 137 for the movement
of fluids into, out
of, and through the tool. In an alternative embodiment, the interior flowpath
137 may be
defined, in whole or in part, by the inner surface of the shifting sleeve 146.
[0054] Although the housing ports 126 and sleeve ports 140 are shown as
cylindrical
channels between the exterior and interior of the tool 120, the housing ports
126 and sleeve ports
140 may be of any shape sufficient to facilitate the flow of fluid
therethrough for the specific
application of the tool. For example, larger ports may be used to increase
flow volumes, while
smaller ports may be used to reduce cement contact in cemented applications or
to equalize or
otherwise regulate the fluid flow when multiple stages are being treated
simultaneously through
a plurality of tools, such as through a plurality of open downhole tools of
the present disclosure.
Housing ports may also have nozzles to control the flow rate through the
ports, such as to enable
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the operator to equalize flow rates through the ports of multiple tools open
to fluid flow at the
same time. Moreover, while preferably concentrically aligned, each of the
sleeve ports 140 need
not be concentrically aligned with its corresponding housing port 126 but the
ports will generally
be arranged to allow for fluid flowing through the sleeve ports 140 to
effectively flow through
the housing ports 126 as well. The top connection 122, the outlet sub 128, an
interior surface
142 of the ported housing 124, and an exterior surface 144 of the inner sleeve
134 define an
annular space 145, which is partially occupied by a shifting sleeve 146.
Shifting sleeve 146 has
an upper portion 148 and a lower portion, such as lower locking portion 150
having a plurality of
radially-outwardly oriented locking dogs 152, which may be ratcheting teeth.
The locking dogs
152 may be directly milled, cut or otherwise placed into the shifting sleeve
146 or may be placed
on a ring or other component that is connected to or engaged with shifting
sleeve 146.
[0055] The
annular space 145 comprises an inlet chamber 153, also referred to as an
upper pressure chamber defined by the top connection 122, burst disk 132,
outer housing124,
inner sleeve 134, the shifting sleeve 146, and upper sealing elements 162u.
The annular space
145 further comprises a receiving chamber 155 defined by the outlet sub 128,
the outer housing
124, the inner sleeve 134, the shifting sleeve 146, and lower sealing elements
166. Receiving
chamber 155 may also be referred to as a lower pressure chamber. In a
preferred embodiment,
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the pressure within the inlet and receiving chambers (153, 155) is atmospheric
when the tool is
installed in a well (i.e., the burst disk 132 is intact).
[0056] A locking member 158 partially occupies the annular space 145
below the
shifting sleeve 146, i.e. in the receiving chamber 155. When the sleeve is
shifted, the locking
dogs 152 engage the locking member 158 and inhibit movement of the shifting
sleeve 146
toward the shifting sleeve's first position.
[0057] In the embodiment of Figs. 6 and 8, outlet sub 128 comprises an
outlet
flowline connection 170 and an outlet sub flowpath 174, as more clearly shown
in FIG. 7B.
Further, the outlet sub 128 and inner sleeve 134 at least partially define a
mandrel flowpath 172
connected to outlet sub flowpath 174 by outlet radial groove 176. Mandrel
flowpath 172 may
include longitudinal grooves (not shown) in either inner sleeve 134 or outlet
sub 128, though
such grooves are not required and sufficient flow may be obtained by allowing
fluid to pass
between the inner sleeve 134 and the outlet sub 128 without such grooves. It
will be appreciated
that in the embodiment of Figure 6B, receiving chamber 155 is in fluid
communication with
mandrel flowpath 172, outlet connection flowpath 164, and outlet flowline
connection 170.
Collectively, mandrel flowpath 172, radial groove 176 and outlet sub flowpath
174 comprise one
embodiment of an outlet conduit 180. Flow tubing, not shown, may be connected
to the outlet
flowline connection 170, and thereby the outlet conduit 180, on one end and a
separate device,
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such as another downhole tool, on the flow tubing's other end, thereby
bringing such other
device, or desired portion thereof, into fluid communication with the
receiving chamber 155.
[0058] The shifting sleeve 146 is moveable within the annular space 145
between a
first position and a second position by application of hydraulic pressure to
the tool 120. When
the shifting sleeve 146 is in the first position, which is shown in FIGS. 6A
and 6B, fluid flow
from the interior to the exterior of the tool through the housing ports 126
and sleeve ports 140 is
impeded by the shifting sleeve 146 and surrounding sealing elements 162 and
166. Shear pins
163 may extend through the ported housing 124 and engage the shifting sleeve
146 to prevent
unintended movement toward the second position thereof, such as during
installation of the tool
120 into the well. Although shear pins 163 function in such a manner as a
secondary safety
device, alternative embodiments contemplate operation without the presence of
the shear pins
163. For example, the downhole tool may be installed with the receiving
chamber 155 with a
spring, collet ring, or other device to hold the shifting sleeve 146 in the
first position until
actuation as described below.
[0059] To shift the sleeve 146 to the second position (shown in FIG. 8A-
8B), a
pressure greater than the rated pressure of the burst disk 132 is applied to
the interior of the tool
120, which may be done using conventional techniques known in the art. This
causes the burst
disk 132 to rupture and allows fluid to flow through the fluid path 130 to the
annular space 145,
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and specifically the inlet chamber 153. In some embodiments, the pressure
rating of the burst
disk 132 may be lowered by subjecting the burst disk 132 to multiple pressure
cycles. Thus, the
burst disk 132 may ultimately be ruptured by a pressure which is lower than
the burst disk's 132
initial pressure rating.
[0060] Following rupture of the burst disk 132, the shifting sleeve 146
is no longer
isolated from the fluid flowing through the inner sleeve 134. The resultant
increased pressure on
the shifting sleeve 146 surfaces in fluid communication with the inlet chamber
153 creates a
pressure differential relative to the atmospheric pressure within the
receiving chamber 155. Such
pressure differential across the shifting sleeve 146 causes the shifting
sleeve 146 to move from
the first position to the second position shown in FIG. 8A-8B, provided the
force applied from
the pressure differential is sufficient to overcome the shear pins 163, if
present. In the second
position, the shifting sleeve 146 does not impede fluid flow through the
housing ports 126 and
sleeve ports 140, thus allowing fluid flow between the interior flow path and
the exterior of the
tool. As the shifting sleeve 146 moves to the second position, the locking
member 158 engages
the locking dogs 152 to prevent subsequent upwell movement of the shifting
sleeve 146.
[0061] Movement of shifting sleeve 146 from the first position to the
second position
establishes fluid communication between the interior flowpath 137 of downhole
tool 120 and a
second device via flow tubing connected to the outlet flowline connection 170.
Specifically,
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seals 166 are positioned to engage the shifting sleeve when the shifting
sleeve is in the first
position in order to prevent fluid communication between the interior flowpath
137 and the
receiving chamber 155 through the ports 140. When the shifting sleeve 146
moves to the
second position, as in FIGS 8A-8B, seals 166 no longer engage the shifting
sleeve 146 and fluid
communication between the interior flowpath 137 and the receiving chamber 155
is established.
Because receiving chamber 155 is in fluid communication with the flow tubing
via the outlet
conduit 180 and outline flowline connector 170, fluid communication is thereby
established from
interior flowpath 137 to a tool connected to the opposing end of the flow
tubing.
[0062] FIGS 7A and 7B show differences between the bottom sub of FIG 2
(in FIG
7A) and the outlet sub of FIG 6B (in FIG 713), showing the changes made to
facilitate the
presence of the outlet conduit of embodiment tool 120.
[0063] FIGS 9-12 depict another embodiment downhole tool 375, configured
to
actuate in response to fluid pressure received through flow tubing
communicating fluid pressure
from a remotely positioned device such as tool 120 of FIG 6A-6B. Such downhole
tool 375,
may be referred to as an intermediate tool. Intermediate tools are configured
such that fluid
pressure may be transmitted from it to an additional tool or other device via
flow tubing
connected to an outlet flowline connector.
22
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[0064] One embodiment intermediate tool 375 is shown in FIG 9.
Intermediate tool
375 comprises an inlet sub 350 connected, such as by threading, to an inlet
end of ported housing
345 having a plurality of radially-aligned housing ports 325. An outlet sub
355 is similarly
connected to an outlet end of ported housing 345. The inlet sub 350 and outlet
sub 355 have
cylindrical inner surfaces 390 and 392. An inner sleeve or mandrel 340 having
a cylindrical
inner surface 394 is positioned between inlet sub annular surface 382 and
outlet sub annular
surface 380. The inner sleeve or mandrel 340 has a plurality of radially-
aligned sleeve ports 327
aligned, such as concentrically aligned, with a corresponding housing port
325.
[0065] The inner surfaces 390, 392 of the inlet sub 350 and outlet sub
355 and the
inner surface 394 of the inner sleeve 340 define an interior flowpath 337 for
the movement of
fluids into, out of, and through the tool 375. In an alternative embodiment,
the interior flowpath
337 may be defined, in whole or in part, by the inner surface of the shifting
sleeve 310. Inlet sub
350, outlet sub 355, an interior surface 401 of ported housing 345, and an
exterior surface 400 of
the inner sleeve or mandrel 340 define an annular space 315 (indicated by the
bracket in FIGS
10C and 12), which is partially occupied by shifting sleeve 310.
[0066] As will be appreciated from the foregoing description,
intermediate tool 375 is
similar to the other downhole tool embodiments described herein (see, e.g. FIG
1, item 20 and
FIG 6, item 120) having a similar nested sleeve moveable from a first position
to a second
23
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position in response to fluid pressure applied to an end of the sleeve.
However, instead of the
burst disk filled passageway (Fig I item 30, FIG 6 item 130) allowing fluid
communication
between the interior flowpath (FIG 1, item 37 and FIG 6, item137) and the
inlet, or upper,
pressure chamber (FIG 1, item 53 and FIG 6, item 153) the intermediate tool
receives fluid flow
and pressure from a flow tube exterior to the tubing string via inlet flowline
connector 300,
connected to the inlet sub 355, which is in fluid communication with inlet
pressure chamber 353
via an inlet conduit 303. Such arrangement enables communication of fluid and
pressure from
the exterior flow tub to engage inner sleeve 310 to move inner sleeve 310 from
a first position to
a second position (e.g. from a closed position to an open position). Thus,
rather than actuating in
response to fluid pressure in internal flow path 337, intermediate tool 375 is
actuated by fluid
pressure communicated to it from outside the tool.
[0067] Receiving chamber 354 is in fluid communication with outlet flow
line
connector 322 through outlet conduit 318. Seals (313, 314) discussed in more
detail below,
prevent fluid communication between the inlet pressure chamber 353 and
receiving chamber 354
on the one hand, and the interior flowpath 337 and the exterior of the tool on
the other hand.
[0068] Figures 10A, 10B, and 10C are enlarged views of inlet, outlet,
and center
portions, respectively, of downhole tool 375. In the embodiment shown in FIG
10A, inlet
conduit 303 comprises inlet housing passageway 301, inlet radial groove 305,
and inlet mandrel
24
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passageway 307. Radial groove 305 provides the necessary depth to connect the
longitudinal
passages, inlet housing passage 301 and inlet mandrel passage 307, despite the
different radii at
which the longitudinal passages lie. Inlet mandrel passageway 307 connects to
inlet pressure
chamber 353 bringing inlet pressure chamber 353, and thereby one end of
shifting sleeve 310,
into fluid communication with inlet conduit 303 and the external flow line.
Seals 312 in inlet sub
350 engage the ported housing 345 to prevent fluid communication between the
inlet pressure
chamber 353 and the exterior of the tool. Seals 311u on mandrel 340 engage the
inlet sub 350 to
prevent fluid communication between the inlet conduit 303 and the interior
flowpath 337.
[0069] With reference to FIG 10B, outlet conduit 318 comprises outlet
housing
passageway 320, outlet radial groove 319, and outlet mandrel passageway 317.
Radial groove
319 provides the necessary depth to connect the longitudinal passages, outlet
housing passage
320 and outlet mandrel passage 317, despite the different radii at which the
longitudinal passages
lie. Outlet mandrel passage 317 connects to receiving chamber 354 bringing
receiving chamber
354 into fluid communication with outlet conduit 318 and any external flow
line. Seals 316 in
outlet sub 355 engage the ported housing 345 to prevent fluid communication
with the exterior
of the tool. Seals 311/ on mandrel 340 engage the outlet sub 355 to prevent
fluid
communication between the outlet conduit 318 and the interior flowpath 337. It
will be
appreciated that other configurations for these, or other inlet and outlet
conduits of the present
CA 02865667 2014-10-02
disclosure are possible and such conduits may comprise any of one or more
conduits,
passageways, sections of tubing, grooves, channels, or other flowpaths to
allow fluid
communication between the inlet 300 or outlet 322 flowline connectors and
inlet pressure
chamber 353 or receiving chamber 354, respectively. Such alternate conduits
are within the
scope of embodiments contemplated herein.
[0070] FIG. IOC shows an expanded view of the shifting sleeve 310,
annular space
315 and adjacent structures. Inlet sub 350, ported housing 345, mandrel 340,
shifting sleeve
310, housing ports 325, and outlet sub 355 are positioned as described above
with reference to
Figure 9. Inlet mandrel passageway 307 connects to inlet pressure chamber 353
and outlet
mandrel passageway 317 connects to receiving chamber 354.
[0071] A plurality of inlet sleeve seals 313 and outlet sleeve seals 314
in the mandrel
and the ported housing engage sliding sleeve 310 to prevent fluid
communication around sliding
sleeve's 310 interior side¨adjacent to the mandrel 340¨and exterior
side¨adjacent to the
ported housing 345. Inlet sleeve seals 313 engage the sliding sleeve 310 on
the inlet side of
sleeve ports 327 and housing ports 325 while outlet sleeve seals engage the
sliding sleeve 310 on
the outlet side of the sleeve ports 327 and the housing ports 325. Inlet
sleeve seals 313 prevent
fluid communication between inlet pressure chamber 353 and both the housing
ports 325 and the
26
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sleeve ports 327. Outlet sleeve seals 314 prevent fluid communication between
the receiving
chamber 354 and both the housing ports 325 and sleeve ports 327.
[0072] Shear pin 330 may be included to engage the shifting sleeve 310
and mandrel
340, holding the shifting sleeve 310 in place. Other retention elements, such
as collets, shear
rings, springs, or other elements may be included to hold the shifting sleeve
310 in the first
position until a predetermined pressure differential is created across the
shifting sleeve 310.
[0073] Locking portion 407 partially occupies receiving chamber 354
below the
shifting sleeve 310 and may comprise a plurality of mandrel teeth 403
configured to engage
opposing ring teeth on a locking ring connected to shifting sleeve 310. When
the sleeve 310 is
shifted, ring teeth 335 engage mandrel teeth 403 along exterior surface 400 of
mandrel 340 and
inhibit movement of the shifting sleeve 310 back towards its first, e.g.
closed, position.
[0074] The shifting sleeve 310 of downhole tool 375 is moveable within
the annular
space 315 between a first position, which is shown in FIGS. 9-10, and a second
position, which
is shown FIGS. 11-12, by application of hydraulic pressure through connection
300 and inlet
conduit 303, to the end of shifting sleeve 310. Increased pressure on the
shifting sleeve 310
surfaces in fluid communication with the inlet pressure chamber 353 creates a
pressure
differential relative to the atmospheric pressure within the receiving chamber
354. Such pressure
differential across the shifting sleeve 310 causes the shifting sleeve 310 to
move from the first
27
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position to the second position, provided the force applied from the pressure
differential is
sufficient to overcome the shear pins 330, if present. In the second position,
the shifting sleeve
310 does not impede fluid flow through the housing ports 325 and sleeve ports
327, thus
allowing fluid flow between the interior flow path 337 and the exterior of the
tool. As the
shifting sleeve 310 moves to the second position, the mandrel teeth 403 of
locking portion 407
engage the ring teeth 335 to prevent subsequent upwell movement of the
shifting sleeve 310.
[0075] FIG. 11 shows the intermediate tool 375 with the shifting sleeve
310 in the
second position, which may be referred to as the open position or the actuated
position. In the
second position, shifting sleeve 310 has moved into receiving chamber 354 and
thereby enlarges
inlet chamber 353. In this position, shifting sleeve 310 no longer prevents
fluid communication
between interior flowpath 337 and the exterior of the tool through the sleeve
ports 327 and
housing ports 325.
[0076] Further, movement of shifting sleeve 310 from the first position
to the second
position establishes fluid communication between the interior flowpath 337 of
intermediate tool
375 and outlet flowline connection 322, via outlet conduit 318. FIG 12 is an
expanded view of
the tool of FIG 11 showing the shifting sleeve 310 and adjacent structures.
Seals 314 are
positioned to engage the shifting sleeve 310 when the shifting sleeve 310 is
in the first position
in order to prevent fluid communication between the interior flowpath 337 and
the receiving
28
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chamber 354 through the ports 327. When the shifting sleeve 310 moves to the
second position,
seals 314 no longer engage the shifting sleeve 310 and fluid communication
between the interior
flowpath 337 and the receiving chamber 354, and thereby to outlet conduit 318
is established by
fluid communication around the internal¨adjacent to the mandrel 340¨and
external¨adjacent
to the ported housing 345¨surfaces of shifting sleeve 310. Thus, fluid
pressure, and fluid flow,
may be communicated out of the intermediate tool 375 to actuate an additional
tool or tools via
flow tubing connected to outlet flowline connection 322.
[0077] It
will be appreciated that a downhole tool such as in illustrated in FIGS 9-12
may be modified such that it is not in fluid communication with an additional
tool through an
outlet connection. Such a tool may be described as a terminator tool.
Modifications to
manufacture a terminator tool may include placing a plug in the outlet
flowline connection 322
rather than connecting outlet flowline connection 322 to flow tubing.
Alternatively, outlet sub
355 may be replaced with an alternative connector sub, such as bottom sub 28
of the
embodiment illustrated in FIG 2 and FIG 7A. Further, receiving chamber 354 can
remain in
fluid isolation from the interior flowpath 337 and inlet pressure chamber 353
by positioning inlet
sleeve seals 314, or other seals, such that the seals remain engaged with
shifting sleeve 310 when
shifting sleeve 310 is in the second position.
29
CA 02865667 2014-10-02
[0078] Alternative embodiments of downhole tools according to the
present disclosure
are also possible. In contrast to the ported valves shown FIGS 1-4 and 6-12,
FIG 13 illustrates a
version of a burst disk initiator 475 without either ports or a shifting
sleeve. The burst disk
initiator 475 of FIG 13 is a tubular having an interior wall 415 defining an
internal flowpath 437,
and an outlet conduit connecting the internal flowpath 437 with an outlet
flowline connection
484. Outlet conduit includes a passageway 480 through interior wall 415
connected to a housing
passage 488. Burst disk 482 in passageway 480 prevents fluid communication
between interior
flowpath 437 and the outlet flowline connector 484 via outlet conduit. Fluid
pressure in interior
flowpath 437 ruptures burst disk 482 when the fluid pressure exceeds the burst
disk's 482 rated
pressure, allowing fluid communication between interior flowpath 437 and a
flowline connected
to the outlet flowline connector 484 and thereby to another tool, such as the
intermediate tool
375 illustrated in FIGS 9-12.
[0079] Systems as described herein may also include a plug actuated
initiator tool,
such as the tool illustrated in FIGS 14-17. FIG 14 shows an embodiment
initiator tool 575
actuated by a pressure differential created across a plug seat 562. Such a
plug seat initiator tool
generally has an outlet conduit 503, a sliding sleeve 510, and a plug seat 562
connected to the
sliding sleeve 510. Sliding sleeve 510 is configured with a first position and
a second position,
such that in the first position, the sliding sleeve 510 prevents fluid
communication between the
CA 02865667 2014-10-02
interior flowpath 537 and the outlet conduit 503 and in the second position
allows fluid
communication therebetween.
[0080] The embodiment plug seat initiator tool of FIG 14 comprises an
outlet sub 550
connected to a ported housing 545, which may have a plurality of ports 525
therethrough. The
tool 575 may further comprise a plug seat housing 560 connecting ported
housing 545 and
bottom sub 555. Isolation sleeve 580 lies interior to outlet sub 550 and
ported housing 545,
engaging a lower annular shoulder 582 of outlet housing 550 and an interior
surface of ported
housing 545. Isolation sleeve 580 has a profile 582 with an enlarged radius
for receiving and
sealing against sliding sleeve 510. Plug seat 562 may be connected to sliding
sleeve 510 by seat
carrier 564. In some embodiments, plug seat 562 or seat carrier 564 may have a
locking ring 565
with outwardly oriented teeth or dogs to engage opposing teeth 507a on the
interior of plug seat
housing 560. Some embodiments may have a sleeve, such as cement sleeve 566, to
prevent
cement or other debris from accumulating below the plug seat 562 and seat
carrier 564, thereby
preventing the plug seat 562, seat carrier 564, and sliding sleeve 510 moving
to the second, or
open, position. Cement sleeve may have outwardly oriented teeth or dogs 568
configured to
engage teeth or dogs 507b on an inner surface of bottom connection 555.
[0081] One or more shear pins 530 may be connected to the ported housing
545 and
the sliding sleeve 510 to prevent movement of the sliding sleeve 510 from the
first position to the
31
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second position until sufficient force is applied to the sliding sleeve 510,
such as by a pressure
differential across the plug seat 562, to break the one or more shear pins
530. Shear pins may be
placed in additional or other locations, such as connecting the plug seat
housing with the seat
carrier, or other location, to maintain or help maintain the shifting sleeve
in the first position.
Further, it will be appreciated that other devices, such as collets, shear
rings, springs, or other
devices, may be employed to hold the shifting sleeve 510 in the first position
until sufficient
force is applied to overcome such restriction.
[0082] Outlet sub 550, isolation sleeve 580, sliding sleeve 510, plug
seat 562, cement
sleeve 566, and bottom sub 555 each has a generally tubular inner surface 590,
596, 594, 595,
598, and 592 respectively, which together define an interior flowpath 537
through initiator tool
575.
[0083] FIG 15A shows an expanded view of the region of the embodiment
initiator
tool 575 including and adjacent to the isolation sleeve 580. The arrangement
of outlet sub 550,
ported housing 545, isolation sub 580 and sliding sleeve 510 is as described
for FIG 14. Outlet
conduit 503 comprises a housing passageway 501, longitudinal groove 585 and
gap 584. Gap
584 may be very small and, in some embodiments, may be the available flowpath
remaining
between the isolation mandrel 580 and the ported housing 545 after assembly of
the tool 575.
Seals 511 prevent fluid communication with the interior flowpath 537 and
outlet conduit around
32
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the isolation mandrel 580. Further, sleeve seals 513 prevent fluid
communication with the outlet
conduit 503 around the sliding sleeve 510 when the sliding sleeve 510 is in
the closed position.
[0084] Figure 15B shows the isolation sleeve 580 with a plurality of
longitudinal
grooves 585 which make up a portion of the outlet conduit 503.
[0085] A pressure differential created across the plug seat
562¨typically by applying
fluid pressure to the interior of tubing string while plug seat 562 is engaged
with an appropriately
sized ball, dart, or other suitable plug¨will shift the sleeve 510 from the
first position to the
second position, shown in FIGS 16-17. Sliding sleeve 510 has moved
sufficiently within the plug
seat initiator tool 575 that fluid flowing through interior flowpath 537 may
pass through gap 584,
establishing fluid communication between the interior flowpath 337, outlet
conduit 503 and any
flowline connected to outlet connector 500, thereby creating fluid
communication with another
tool, such as an intermediate tool or a terminator tool, to which such
flowline may also be
connected. It will be appreciated that outlet connector 500, or any of the
connectors may be a
threaded connection milled into the tool, welded into the tool, or any other
means of connecting a
flow line to the tool to permit fluid communication. Further, the sliding
sleeve 510 may also be
shifted sufficiently to allow fluid communication between the interior
flowpath 537 and the
exterior of the initiator tool 575 through ports 525, when present.
33
CA 02865667 2014-10-02
[0086] In certain embodiments, the inner sleeve may be configured to
improve fluid
flow, and pressure communication around the shifting sleeve after the shifting
sleeve has moved
to the second position. For example, flow, and pressure communication, may be
restricted by
close tolerances between the inner sleeve and shifting sleeve and between the
shifting sleeve and
housing. One embodiment inner sleeve 834 for flow improvement is shown in FIG
18. Flow
slots 816 are cut longitudinally along the outer surface of inner sleeve 834.
When assembled
into a valve such as valve 120 (FIG 6A-B), the slots 816 are isolated from the
sleeve ports 840
by the engagement of the shifting sleeve 146 with seals 1621, which lie in
seal grooves 862.
Further, the slots may cross the teeth 852 as shown, where such teeth are used
to engage locking
ring teeth, such as in the arrangement described with respect to the
embodiments of FIGS 9-1 I.
Such slots allow for better flow
[0087] Based on the above description of certain embodiments, systems
may be
assembled by combining initiator, intermediate, and terminator downhole tools
in series. One
embodiment series is illustrated by FIG 19. Tubing string 610 is shown in a
horizontal section,
or lateral, extending through a portion of a hydrocarbon producing formation
600. It will be
appreciated that tools of the present invention may also be used in vertical
or deviated sections of
wells. An initiator tool 620, such as downhole tool 120 of FIGS 6-8,
intermediate tools (630a,
630b) such as tool 375 illustrated in FIGS 9-12, and a terminator tool 640 are
placed as desired
34
CA 02865667 2014-10-02
along the tubing, such as to place ported valves as desired along the
formation, or to place an
initiator tool sufficiently upwell of the toe to reduce the risk that residual
cement in the tubing,
(e.g. from a cement tail remaining in the toe) will not prevent actuation of
the initiator. Flow
lines 650a-c connect the outlet flowline connector of initiator tool 620 with
the inlet flowline
connector of intermediate tool 630a; the outlet flowline connector of
intermediate tool 630a with
the inlet flowline connector 630b; and the outlet flowline connector 630b with
inlet flowline
connector of terminator tool 640. It will be appreciated that an initiator
tool may be paired with
a terminator tool without intermediate tools therebetween. Further, a
terminator tool is not
strictly necessary, as some intermediate tools, such as intermediate tool 375,
will open as desired
even where the outlet flowline connector is open to the exterior of the tubing
string or is
connected to flowline that is open to the exterior of the tubing string.
[0088] When
the burst disk of initiator tool 620 (e.g. FIG 6, item 132) is ruptured by
fluid pressure in the interior of the tubing string, the initiator tool is
actuated and the shifting
sleeve (e.g. FIG 6, item 146) moves from the first position to the second
position, bringing the
initiator tool 620 outlet flowline connection into fluid communication with
the interior of tubing
string 610. Flow line 650a transmits fluid pressure, and fluid flow, from the
initiator tool's 620
outlet flowline connection to the first intermediate tool 630a through its
inlet flowline connection
and inlet conduit to the first intermediate tool's 630a inlet pressure chamber
(e.g. FIG 9, item
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353) and shifting sleeve (e.g. FIG 9, item 310). When the fluid pressure
transmitted thereby
applies sufficient force to the shifting sleeve to shear the shear pins, (e.g.
FIG 9, item 330), the
shifting sleeve moves to the second position, allowing fluid communication via
housing ports
and sleeve ports between the interior and the exterior of the tubing string
610.
[0089] Similarly to the initiator tool 620, movement of the shifting
sleeve of
intermediate tool 630a to the second position allows fluid communication
between the interior
flowpath and outlet flowline connector (e.g. FIG 9, item 322) of intermediate
tool 630a via its
receiving chamber (e.g. FIG 9, item 354) and outlet conduit. In this manner,
fluid pressure from
receiving chamber of intermediate tool 630a may be transmitted to shifting
sleeve of
intermediate tool 630b via flow line 650b, inlet flowline connector of
intermediate tool 630b and
the inlet conduit of intermediate tool 630b, thereby actuating intermediate
tool 630b with fluid
pressure transmitted from receiving chamber of the first intermediate tool
630a. Further,
additional stages 660a-b may be added to the tubing by the inclusion of other
sleeves or valves
such as traditional plug actuated frac valves or other devices.
[0090] Intermediate tools may be strung together in series as desired.
While the
illustration in FIG 19 shows two intermediate tools, large numbers of
intermediate tools in series
are possible because the next tool may be actuated from the interior flowpath
of the immediately
previous tool and does not necessarily rely on flow through the inlet conduit
of the previous tool.
36
CA 02865667 2014-10-02
Typically, the last tool in the series will be a terminator tool, which has an
inlet conduit but either
has no outlet conduit the outlet conduit is plugged or the receiving chamber
remains sealed to
prevent fluid communication with the internal flowpath.
[00911 Multiple series of tools according to the embodiments encompassed
herein are
possible by placing a plurality of selectively actuatable initiator tools,
responsive to different
actuation triggers, along the tubing string. Each initiator tool is connected
to a series of
intermediate and terminator tools, such that each series opens in response to
the particular trigger
of its associated initiator tool. Such an arrangement is illustrated in FIG
20. Tubing string 710
penetrates a subterranean formation 700, such as a hydrocarbon bearing
formation. Selectively
actuatable initiator tools 720a, 720b, 720c are placed in series with at least
one terminator tool
740a, 740b, 740c. One or more intermediate tools 730a, 730b may be placed
between the
initiator and terminator tools.
[0092] In FIG. 20, first series includes first initiator 720a is fluidly
connected to first
intermediate tool 730a via flow line 750a connected to first initiator tool's
outlet flow line
connector and first intermediate tools inlet flow line connector. First
intermediate tool 730a is
further connected first terminator tool 740 via flowline 750b connected to
first intermediate
tool's outlet flowline connector and first terminator tools inlet flow line
connector.
37
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[0093] Similarly to the first series, second series includes second
initiator 720b,
second intermediate 730b, and second terminator 740b tools connector by
flowlines 750c and
750d. Third series includes third initiator 720c and third terminator 740c
tools connected by
flowline 750e.
[0094] The series are actuated in a desired order by use of the
appropriate trigger at
the desired time. For example, each initiator 720a-c may be a plug seat
initiator, such as initiator
575 of FIG 14, configured to engage different sized plugs. In such
configuration, initiator 720a,
which is the most distal from the wellhead through the tubing string 710, will
have a plug seat
configured to engage a plug that passes through initiators 720b and 720c
without engaging, or
only minimally engaging their respective plug seats. Such first plug is
capable of actuating the
first series of tools connected to initiator 720a without actuating the second
or third series of
tools connected to initiators 720b or 720c. Thus, the region of the
subterranean formation
adjacent to the ported valves of the first series may be treated while the
tools of the second series
and third series remain closed or otherwise not actuated.
[0095] A second plug, which may be larger than the first plug, then
engages the plug
seat of initiator 720b actuating the second series of tools 720b, 730b, 740b.
Second plug passes
through third initiator 720c without actuating the third series 720c and 740c,
such as because the
second plug is too small to create sufficient pressure differential across the
third initiator tool's
38
CA 02865667 2014-10-02
750c plug seat to actuate the third series. Further, engagement of the second
plug on initiator
tool 720b prevents fluid communication through the tubing string to the first
series of tools
connected to initiator 720a. Thus, such second plug allows treatment of the
formation adjacent
to the ported valves of the second series while preventing fluid flow through
the ported valves of
the first series and leaving the tools of the third series not actuated. A
third plug may then
engage the plug seat of and actuate the third initiator tool 720c and thereby
actuate the third
series. The engagement of the third plug on the third initiator tool's plug
seat may also serve to
prevent fluid flow therethrough, thereby allowing treatment of the
subterranean formation
adjacent to the ported valves of the third series while preventing fluid flow
to the ported valves
of the second series and the first series.
[0096] It will be appreciated that flapper valves or other valves may be
incorporated
into the tubing string such that plugs do not have to prevent fluid
communication to previously
actuated series, individual ported valves, perforations, or other structures.
The use of flapper
valves is contemplated within the scope of the invention as claimed.
[0097] Other methods of selectively actuating plug seat operated valves
are also
known. For example, the initiator tool may comprise a j-slot sleeve and pin
assembly or other
indexing element, such that the sliding sleeve will not move to the second
position until a desired
number of pressure cycles have been created across the indexing element. Such
indexing
39
CA 02865667 2014-10-02
element may be paired with an expandable c-ring or other expandable plug seat
that releases the
plug after generation of the desired pressure differential. Thus, by using
plug seat initiators with
an indexing element and expandable plug seat, multiple series of tools of the
present disclosure
may be actuated by using plugs of the same size.
[0098] Plug seat initiators may be mixed with burst disk initiators or
other initiators in
a single tubing string. For example, initiator tool 720a may be a burst disk
initiator, either a
ported valve version (such as initiator tool 120 of FIG 6) or a portless
version (such as initiator
tool 475 of FIG 13) actuated by the application of pressure to the interior of
the tubing string 710
according to known methods, allowing treatment of the subterranean formation
adjacent to the
ported valves of the first series. The second and third initiator tools 720b,
720c may be plug seat
initiator tools. In such an arrangement, the first initiator tool, and
therefore the first series, is
actuated by applying pressure above the rated pressure of the burst disk in
first initiator tool.
Such increased pressure would not actuate the plug seat initiators of the
second or third series,
allowing treatment of the first series.
[0099] After treatment of the first series, engagement of an appropriate
plug on the
plug seat of initiator tool 720b both actuates the second series and isolates
the open ported valves
of the first series from fluid flow occurring at the second series, as
described above. Similarly,
the third, and subsequent, series of ported valves are actuated, and adjacent
areas of subterranean
CA 02865667 2014-10-02
formations are treated, by engagement of subsequent plugs on the plug seats of
those series'
initiator tools according to known methods.
[00100] The downhole tool may be placed in positions other than the toe of the
tubing,
provided that sufficient internal flowpath pressure can be applied at a
desired point in time to
create the necessary pressure differential on the shifting sleeve. In certain
embodiments, the
internal flowpath pressure must be sufficient to rupture the burst disk, shear
the shear pin, or
otherwise overcome a pressure sensitive control element. However, other
control devices not
responsive to pressure may be desirable for the present device when not
installed in the toe.
[00101] The downhole tool as described may be adapted to activate tools
associated
with the tubing rather than to open a flow path from the interior to the
exterior of the tubing.
Such associated tools may include a mechanical or electrical device which
signals or otherwise
indicates that the burst disk or other flow control device has been breached.
Such a device may
be useful to indicate the pressures a tubing string experiences at a
particular point or points along
its length. In other embodiments, the device may, when activated, trigger
release of one section
of tubing from the adjacent section of tubing or tool. For example, the
shifting element may be
configured to mechanically release a latch holding two sections of tubing
together. Any other
tool may be used in conjunction with, or as part of, the tool of the present
disclosure provided
that the inner member selectively moves within the space in response to fluid
flow, such as
41
CA 02865667 2014-10-02
changes in fluid pressure, fluid volume, velocity, pressure cycles, or the
like, through the interior
flowpath. Numerous such alternate uses will be readily apparent to those who
design and use
tools for oil and gas wells.
[00102] FIG 21 shows an alternative embodiment tool according to the present
disclosure. The arrangement of the top connection 922, ported housing 924,
inner sleeve 910,
shifting sleeve 946 and bottom connection (not shown) are the same as for the
embodiment
described with reference to FIGS 1-4. Interior surfaces of inner sleeve, top
connection, and
bottom connection at least partially define an interior flowpath through the
downhole tool. The
embodiment of FIG 21 also has a fluid path comprising a top connection passage
930, a
longitudinal passage 954, which may be a groove machined into the top
connection, and an
upper pressure chamber 953 portion of the annular space. The fluid path
connects the interior
flowpath with the upper pressure chamber 953 between the inner sleeve 910 and
the ported
housing 924 and adjacent to an end of the shifting sleeve 946.
[00103] The fluid path of the embodiment of FIG 21 includes two fluid control
devices
preventing fluid flow therethrough. A burst disk 932 is disposed in the top
connection passage
930 and prevents fluid communication between interior flowpath and the
longitudinal passage
954. A degrading member 933 is disposed between the longitudinal passage 954
and the upper
pressure chamber 953. In certain embodiments, the degrading member may be a
magnesium bar
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of suitable size. Seals 963 engage the degrading member 933 and either or both
of the inner
sleeve 910 and ported housing 924 to create a seal for preventing the flow of
fluids around the
degrading member 933.
[00104] In operation, fluid pressure us applied to rupture the burst disk
allowing fluid
flow, and fluid pressure from the interior flowpath through the top connection
passage 930and
into the longitudinal passage 954. The fluid in the flowpath is an appropriate
fluid for affecting
the degrading member 933 as desired. For example, if the degrading member 933
is a
magnesium bar, the fluid in the internal flowpath may be hydrochloric acid or
other solution that
dissolves or otherwise degrades magnesium. In such embodiment, bursting of the
burst disk will
allow the hydrochloric acid, or other fluid suitable for degrading magnesium,
to pass through top
connection passage 930 and longitudinal passage 954 to reach the degradable
member 933,
starting the degradation process.
[00105] FIG 22 illustrates an embodiment downhole tool utilizing a degradable
member as a secondary fluid control device for actuating a shifting sleeve.
The embodiment of
FIG 22 has a top connection 1022, ported housing 1024 with ports 1026, inner
sleeve 1010,
shifting sleeve 1046, bottom connection 1055 and shear pin 1063 generally
according to the
arrangement described with respect to the embodiment of FIGS. 9 and 10C above.
The primary
fluid path for applying fluid pressure to the shifting sleeve 1046 comprises
an inlet port, inlet
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CA 02865667 2014-10-02
groove (each not shown) and inlet mandrel passageway 1007, thus allowing the
shifting sleeve to
move from a first position to a second position in response fluid pressure
received from outside
the embodiment downhole tool via flow tubing or other fluid source. In certain
embodiments
Outlet mandrel passageway 1017 allows fluid to exit the outlet pressure
chamber once the
shifting sleeve 1046 is moved to the open position. It will be appreciated
that a secondary fluid
control devices may be used with embodiments having a receiving chamber, e.g.
that do not have
an outlet conduit, and with device that do not have an inlet chamber,
including, but not limited
to, the embodiment of FIG 1.
[00106] Degradable member 1033 is disposed in an inner sleeve passage 1030
preventing fluid flow from the interior flowpath to the end of shifting sleeve
1046. In normal
operation, degradable member1033 remains intact and fluid does not flow
through the inner
sleeve passage 1030. It will be appreciated that the degradable member 1033
may be a threaded
member such as a plug, screw, or similar element. However, if the shifting
sleeve fails to move
to the second position as desired, the degrading element may be exposed to an
appropriate liquid
in order to open the inner sleeve passage 1030. For example, coil tubing may
extend from the
wellhead to place straddle packers on either side of the downhole tool. Acid
or other suitable
solvent could be introduced to the downhole tool to degrade the degradable
member 1033 and
pressure applied to the downhole tool to open the sleeve. Further, because of
the presence of the
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CA 02865667 2014-10-02
straddle packers, the formation adjacent to the downhole tool may selectively
fractured or
otherwise treated through the coil tubing once the shifting sleeve is open.
[00107] The degradable member may be used as a timer during which the tubing
string
may be pressure tested up to the pressure rating of the seal containing a
degradable member.
While the degradation is occurring, pressure can be applied to a tubing string
in which the
downhole tool is installed to test the integrity of the tubing installation.
When the degradation
has progressed sufficiently to allow pressure to the upper pressure chamber,
the shifting sleeve
opens to create communication between the interior flowpath and the exterior
of the tool. For
degradable members comprising material that degrade at the ambient well
temperature, the timer
essentially starts upon installation of the downhole tool into the well. Such
materials are known
in the art and certain materials are described in U.S. Patent Publication No.
20120181032, filed
by Naedler et al on January 13, 2012, the descriptions of said materials being
incorporated by
reference herein. Other suitable materials are currently known in the art.
Assemblies that
comprise either of or both a material that degrades in response to the ambient
well temperature
and a second material not degradable solely in response to the ambient well
temperature are also
envisioned.
[00108] The degradable member may be matched to its environment and the fluid
to
which it is exposed in order to speed up or slow down the degradation process,
e.g. to set the
CA 02865667 2014-10-02
timer. Rupturing of the burst disk starts the timer by initiating the
degradation process. For
example, a magnesium rod degradation member may be thicker to increase the
time needed for
degradation sufficient to open the fluid path to occur. Further, the solvent
strength, such as the
concentration of hydrochloric acid, may be adjusted to increase or decrease
the rate of
degradation as desired. This allows for estimation or selection of the minimum
and maximum
times required before the degradable member allows fluid to flow from the
longitudinal passage
954 to the upper pressure chamber, thereby moving the shifting sleeve from the
first position to
the second position. In addition, the degradable member may be part of an
assembly comprising
multiple parts such as threaded elements, seals, gaskets or other members
provided that the
assembly prevents fluid flow through a fluid path until the degradable member
is exposed to a
fluid
[00109] The downhole tool may be placed in positions other than the toe of the
tubing,
provided that sufficient interior flowpath pressure can be applied at a
desired point in time to
create the necessary pressure differential on the shifting sleeve. In certain
embodiments, the
interior flowpath pressure must be sufficient to rupture the burst disk, shear
the shear pin, or
otherwise overcome a pressure sensitive control element. However, other
control devices not
responsive to pressure may be desirable for the present device when not
installed in the toe.
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CA 02865667 2014-10-02
[00110] The downhole tool as described may be adapted to activate tools
associated
with the tubing rather than to open a flow path from the interior to the
exterior of the tubing.
Such associated tools may include a mechanical or electrical device which
signals or otherwise
indicates that the burst disk or other flow control device has been breached.
Such a device may
be useful to indicate the pressures a tubing string experiences at a
particular point or points along
its length. In other embodiments, the device may, when activated, trigger
release of one section
of tubing from the adjacent section of tubing or tool. For example, the
shifting element may be
configured to mechanically release a latch holding two sections of tubing
together. Any other
tool may be used in conjunction with, or as part of, the tool of the present
disclosure provided
that the inner member selectively moves within the space in response to fluid
flow through the
flowpath 830. Numerous such alternate uses will be readily apparent to those
who design and
use tools for oil and gas wells.
[00111] It will be appreciated that the term "degrade" as used herein, as well
as its
various grammatical forms, is intended to have a broad meaning encompassing
melting,
dissolution, chemical alteration, corrosion, or other change to a degrading
element of
embodiments of the present disclosure. Such changes will be based, at least in
part, on
temperature or on the characteristics of fluid to which the degrading member
is exposed, other
than the fluid pressure. Further, while fluid pressure may, and in certain
cases will, effect or
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CA 02865667 2014-10-02
accelerate the failure of a degrading member, such member will typically
experience melting,
dissolution, chemical alteration, corrosion or similar effect as a precursor
to such failure.
[00112] Still further, while embodiment degradable members include balls,
plugs, disks
and rods, other degradable members are possible.
[00113] The illustrative embodiments are described with the shifting sleeve's
first
position being "upwell" or closer to the wellhead in relation to the shifting
sleeve's second
position, the downhole tool could readily be rotated such that the shifting
sleeve's first position is
-downwell" or further from the wellhead in relation to the shifting sleeve's
second position. In
addition, the illustrative embodiments provide possible locations for the flow
path, fluid control
device, shear pin, inner member, and other structures, those or ordinary skill
in the art will
appreciate that the components of the embodiments, when present, may be placed
at any
operable location in the downhole tool.
[00114] The present disclosure includes preferred or illustrative embodiments
in which
specific tools are described. Alternative embodiments of such tools can be
used in carrying out
the invention as claimed and such alternative embodiments are limited only by
the claims
themselves. Other aspects and advantages of the present invention may be
obtained from a study
of this disclosure and the drawings, along with the appended claims.
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