Note: Descriptions are shown in the official language in which they were submitted.
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Stage Tool for Wellbore Cementing
Field
The invention relates to a tool for wellbore operations and, in particular, a
tool for wellbore
cementing.
Background
In wellbore operations, cementing may be used to control migration of fluids
outside a liner
installed in the wellbore. For example, cement may be installed in the annulus
between the liner
and the formation wall to deter migration of the fluids axially along the
annulus.
Often cement is introduced by flowing cement down through the wellbore liner
to its distal end
and forcing it around the bottom and up into the annulus where it is allowed
to set. Sometimes it
is desirable to introduce cement into the annulus without pumping it around
the bottom end of
the liner. A stage tool may be used for this purpose. A stage tool is a
tubular that can be
installed along the length of the liner and includes a tubular wall defining
an inner tubular
surface and an outer tubular surface and a port between the inner tubular
surface and the outer
tubular surface through which fluid can be passed to cement the annulus along
a length of the
liner,
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Summary
In accordance with a broad aspect, there is provided a method for cementing a
tubing string in a
wellbore, the method comprising: positioning the tubing string with a stage
tool in the wellbore,
an annulus being defined between the stage tool and the wellbore wall;
expelling a plug from
over a cementing port of the stage tool by pressuring up an inner bore of the
stage tool; pumping
cement into the annulus; and closing the cementing port to hold the cement in
the annulus to
provide time for the cement to set.
In accordance with a broad aspect of the present invention, there is provided
a stage tool
comprising: a main body including a tubular wall with an outer surface and an
inner bore
extending from a top end to a bottom end; a cementing port through the tubular
wall providing
fluidic access between the inner bore and the outer surface; a valve for
controlling flow through
the cementing port between the outer surface and the inner bore; and a plug
sealing a circulation
path between the valve and the outer surface, the plug being expellable by
pressure applied from
the inner bore.
It is to be understood that other aspects of the present invention will become
readily apparent to
those skilled in the art from the following detailed description, wherein
various embodiments of
the invention are shown and described by way of illustration. As will be
realized, the invention
is capable for other and different embodiments and its several details are
capable of modification
in various other respects, all without departing from the spirit and scope of
the present invention.
Accordingly the drawings and detailed description are to be regarded as
illustrative in nature and
not as restrictive.
Brief Description of the Drawings
Referring to the drawings, several aspects of the present invention are
illustrated by way of
example, and not by way of limitation, in detail in the figures, wherein:
Figure 1 is a schematic sectional view through a wellbore with a tubing string
installed therein;
Figures 2A to 2F are views of a stage tool according to one aspect of the
present invention in
sequential stages of operation, wherein Figure 2A is an axial sectional view
of a stage tool in a
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run in position, Figure 2B is an axial sectional view of the stage tool of
Figure 2A in a position
activated and ready to be opened for cement circulation through the annulus,
Figure 2C is an
axial sectional view of the stage tool of Figure 2A in an open position for
circulation
therethrough to permit cementing through the annulus, Figure 2D is an axial
sectional view of
the stage tool of Figure 2A in a position closed by a check valve after
dissipation of circulation
pressure, Figure 2E is an axial sectional view of the stage tool of Figure 2A
in a closed and
locked position preventing cement circulation and Figure 2F is an axial
sectional view of the
stage tool of Figure 2A in a closed position, with a back up sleeve closing
against cement
circulation.
Figures 3A to 3E are views of a stage tool according to one aspect of the
present invention in
sequential stages of operation, wherein Figure 3A is an axial sectional view
of a stage tool in a
run in position, Figure 3B is an axial sectional view of the stage tool of
Figure 3A in a position
activated and ready for cement circulation through the annulus, Figure 3C is
an axial sectional
view of the stage tool in a first stage of being closed, Figure 3D is an axial
sectional view of the
stage tool in a second stage of being closed, and Figure 3E is an axial
sectional view of the stage
tool of Figure 3A in a closed position preventing cement circulation.
Figures 4A to 4D are view of a kobe useful in the stage tool of Figure 3A,
wherein Figure 4A is a
side elevation of the original kobe, Figure 4B is an axial section, Figure 4C
is an isometric view
of the original kobe and Figure 4D is an isometric view of the kobe after use.
Detailed Description of Various Embodiments
The description that follows and the embodiments described therein are
provided by way of
illustration of an example, or examples, of particular embodiments of the
principles of various
aspects of the present invention. These examples are provided for the purposes
of explanation,
and not of limitation, of those principles and of the invention in its various
aspects. In the
description, similar parts are marked throughout the specification and the
drawings with the same
respective reference numerals. The drawings are not necessarily to scale and
in some instances
proportions may have been exaggerated in order more clearly to depict certain
features.
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In wellbore operations, as shown in the example of Figure 1, generally a
surface hole is drilled
and surface casing 100 is installed and cemented in place to protect surface
soil and ground water
from wellbore operations and to prevent cave in. Thereafter, an extended
wellbore 101 may be
drilled below the surface casing point 100a to reach a formation of interest
103. Sometimes
further casing is installed below the surface casing. Where operations are to
be conducted using
a liner 104, the liner can extend from a point above the lower most casing
point, in this case
casing point 100a with an active, lower portion of the liner extending out
beyond casing point
100a at the bottom of the cased section of the well.
According to the current invention, a tool, a process and an installation are
described that permit
a liner 104 to be supported in an extended wellbore 101 by stage cementing
below any casing
point 100a, as shown, which may be of the surface casing or a lower section of
casing. The liner,
therefore, can be run in, set and cemented in a well including in an open
hole, uncased section of
the well. The liner 104 has an upper end, a lower end, a tubular wall defining
an inner diameter
and an outer surface and, installed along its length, a stage tool 110, which
separates the string
into an upper portion 104b, above (uphole of) the stage tool, and a lower
portion, below
(downhole of) the stage tool. The stage tool can be positioned at various
locations along the
liner. In Figure 1, stage tool 110 is positioned near the heel of the well,
for example, just
downhole of the heel. In that embodiment, the lower portion of the liner below
the stage tool
may contain active components 108a, 108b, etc. of the liner.
Cement C may be introduced into the annulus 150 to fill a portion of the
annulus along a length
of the liner to cement, and therefore seal off, that portion of the annulus
between the liner and the
open hole wall 101a. The cement may be introduced to fill a selected portion
of the annulus, for
example, to create a column extending back from at least above the stage tool
to the lowest cased
section of the well. In one embodiment, the cement is introduced until it
fills the annulus down
to a point above the active components.
Active components on the liner may take various forms such as, for example,
selected from one
or more of packers, slips, stabilizers, centralizers, fluid treatment
intervals (such as may include
fluid treatment ports, nozzles, port closures, etc.), fluid production
intervals (such as may include
fluid inflow ports, screens, inflow control devices, etc.), etc. For example,
in one embodiment
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active components may include slips 108a, multistage fracturing components
such as sleeve
valves, hydraulic ports 108b (i.e. fracing ports) and packers 108c', 108c for
zone isolation, a
blow out plug 108d, etc.
The liner may be run in and positioned in the well by any of various
procedures. In one
embodiment, during or after running in the liner a fluid may fill, be
introduced to or circulated
through the string. It may be useful to have pressure communication through
the fluid through
the string 104 including below stage tool 110, for example, for circulation or
for pressure
actuation of active components. Sometimes, it is desirable to float in the
liner in which case a
float valve may be useful that pressure isolates the string from the wellbore.
If both circulation
and float properties are of interest, a valve may be of interest.
Once in place, further operations may proceed to set the liner in the
wellbore. The order of
operations may depend on the desired result for the well and the features of
the liner and the
components carried by the liner. In one embodiment, such as that shown in
Figure 1A, the
cementing operation is undertaken first and then the liner is finally
installed by setting the
packers. In an embodiment such as that shown in Figure 1B, the liner may be
secured first by
various means including by slips 108a and/or packers 108c, 108c' in the well.
While the slips or packers may in some embodiments be set by pressuring up the
string, the
string may later be opened to achieve conductivity to the formation. In one
embodiment, the
liner is configured to hold pressure during the setting of the packers, but
can be opened for fluid
conductivity thereafter for fluid treatments to the formation. In one
embodiment, for example,
the liner may be run in with a valve that selectively holds pressure in the
liner or a blow out plug,
which before being expelled, holds pressure in the liner. Alternately, the
liner may include a port
opened by pressure cycling, such that once downhole, the liner can be
pressured up and pressure
released to open the liner. An example of such a pressure cycle valve is shown
in applicants
corresponding application WO 1009/132462, published November 5, 1009.
In some frac operations, packers 108c, 108c' are carried on the liner. The
packers may be open
hole packers or take other forms. The packers are set to create annular seals
between the liner
and the wellbore wall for zone isolation. In some frac operations, the packers
intended for zone
isolation during wellbore treatments are set in a substantially horizontal
section of the well,
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downhole of the heel. In such systems it may be beneficial, as shown, to
create a cement column
from at least adjacent the uppermost packer 108c' to a point above the lower
most casing point,
for example to the top of the liner. This may isolate the annulus between the
liner and the
formation at the heel of the horizontal well and may provide stability to the
hole. Of course, if
stage tool 110 is positioned downhole of uppermost packer 108c' the annulus
can be cemented to
a point below the uppermost packer for example, down to the location of the
stage tool, as
desired.
Stage tool 110 includes one or more ports 122 and a valve to control flow
through the ports from
the annulus to the inner bore. The valve may be operated to open the ports to
permit fluid flows
with the cement to flow therethrough to achieve circulation to the string
inner bore 104b from
annulus 150.
After the stage tool's circulation ports are opened, cement may be pumped by
fluid circulation as
provided through ports 122. In the illustrated embodiment, cement is pumped
from above down
through the annulus 150 toward the stage tool, in what is called a reverse
cementing operation.
In particular, since the circulation flow is down through the annulus and up
through the liner, this
is the reverse of a standard flow direction for circulation and the cement can
be placed in the
annulus without requiring it to be pumped through or even into the string. In
one embodiment, a
spacer is pumped first, followed by a cement slurry. After an appropriate
amount of cement has
been pumped to accommodate a selected portion of the annulus, for example
extending down
from a casing point 100a to the stage tool, to the uppermost packer 108c' or
having passed all the
way to stage tool 110 and perhaps even through ports 122 into the liner, the
circulation is stopped
and the cement may be held in the annulus until it sets. While various means
may be employed
to maintain the cement in the annulus, generally the stage tool includes a
closure that closes the
ports. The stage tool and its components such as the valve may take various
forms. For
example, the stage tool may include a mechanical closure installed therein,
such as a sleeve
and/or a check valve that can be manipulated remotely or directly to seal off
ports 122.
In one embodiment, therefore, a wellbore may be stage cemented by use of a
stage tool with flow
in a reverse direction. For example, a method for cementing a tubing string in
a wellbore having
a heel transitioning from a substantially vertical section to a substantially
horizontal section, may
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include: introducing cement to the annulus to flow down to a selected depth,
which may be at
least the heel and/or possibly just above the uppermost packer on the string
and/or all the way to
the stage tool; allowing the cement to flow through the annulus by opening a
stage tool to create
a circulation path from the annulus into the tubing string; and holding the
cement in the annulus
to provide time for the cement to set, The amount of cement can be selected to
substantially fill
the selected portion of the annulus without injecting much or any cement into
the inner bore. For
example, the circulation path can be closed before the cement passes from the
annulus into the
tubing string.
In one embodiment, the method may include running into a wellbore with a
string that includes
at least one fracing port below the uppermost packer and after cementing, a
fracturing fluid
treatment is conducted through the string and out through the at least one
fracing port to treat the
formation accessed by the at least one fracing port.
In one embodiment, the method may include activating and/or opening ports 122
of the stage
tool by pressuring up on the string, Pressuring up may include substantially
the entire string or
just a portion of the string (i.e. a portion above a seat). Pressuring up may
be solely to activate or
open the valve or may be used for other purposes in the string such as the
setting of one or more
packers. Pressuring up may drive a piston by creating a pressure differential
across a piston.
In one embodiment, holding the cement in the annulus includes allowing a valve
to close and to
thereby seal the cement in the annulus. In one embodiment, closing the valve
to seal the cement
in the annulus includes dissipating a pressure differential where annular
pressure had been higher
than tubing pressure, which may include pressuring up on the inner diameter of
the string or
reducing annular pressure. In another embodiment, closing the valve to seal
the cement in the
annulus includes pressuring up on the inner diameter of the string.
The valve operates relative to a port through the tubing string wall. The
valve may control fluid
flow from the annulus through the port and upwardly through the inner diameter
toward surface.
Alternately or in addition, the valve may control fluid flow downwardly
through the inner
diameter and through the port toward the annulus.
The valve may include a lock that positively locks the valve in the closed
position.
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In one embodiment, the valve may include a backup closure that can be closed
to seal the cement
in the annulus.
Referring to Figures 2A to 2F, a stage tool 210 for use to stage cement a
wellbore liner is shown.
The stage tool may be installed in a tubular string. This stage tool includes
a port, a one way
check valve for the port, used, when activated, to open the port to fluid flow
therethrough in
response to reverse circulation and a releasable lock that holds the one-way
check valve in an
inoperable position until the valve is activated.
The stage tool further may include a final lock for locking the check valve in
a closed position
and/or a backup closing sleeve that closes the port to fluid flow after use of
the check valve.
For example, the stage tool may include a tubing body installable in a string,
a port through the
wall of the tubing body and a one way check valve for the port, such as one
including a spring
loaded valve body in the form of a sleeve or a rod (for example, a poppet),
used to open the port
to fluid flow therethrough in response to reverse circulation (from the outer
surface to the inner
diameter). The stage tool may further include a releasable lock in the form of
an expellable plug.
The releasable lock initially releasably locks the check valve in the inactive
position. The
expellable plug is hydraulically actuatable to activate, and in this
embodiment release, the check
valve for operation. The stage tool may further include a final closing sleeve
operable to provide
a back up closure for the port.
Stage tool 210 may include a tubular body including a wall 211 with an outer
surface 212, an
inner bore 214 defined by an inner surface 216 of the wall, a first end 218
and a second end 220.
A port 222 extends through the wall and is openable (Figure 2C) and closable
(Figures 2A, 2B,
2D to 2F) to open and close, respectively, the stage tool to circulation
through the port.
Stage tool 210 may be intended for use in wellbore applications for actuation
to permit
cementing of a portion of the annulus behind a borehole liner along a length
of the liner,
generally spaced from the liner's distal end. The tubular body may be formed
of materials useful
in wellbore applications such as of pipe, liner, casing, etc. and may be
incorporated as a portion
of a tubing string or in another wellbore string. Bore 214 may be in
communication with the
inner bore of a tubing string such that pressures may be controlled therein
and fluids may be
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communicated from surface, such as for wellbore treatment therethrough. The
tubular body may
be formed in various ways to be incorporated in a tubular string. For example,
the tubular
segment may be formed integral or connected by permanent means, such as
welding, with
another portion of the tubular string. Alternately, the ends 218, 220 of the
tubular body may be
formed for engagement in sequence with adjacent tubulars in a string. For
example, the ends
may be formed as threaded pins or boxes to allow threaded engagement with
adjacent tubulars.
A valve body 224 is positioned to act as a closure for port 222 and is
moveable relative to the
port to manipulate it between the open and the closed positions. Valve body
224 may carry or
ride over seals 223 that provide a pressure seal between valve body 224 and
wall 211 to seal
against migration of fluid through port 222 past the valve body.
Valve body 224 acts as a one way check valve. Valve body 224, when activated,
is biased to a
closed position, but may be moved by fluid pressure to open. Thus, port 222
can be opened and
closed without the need to run in a manipulation string or line to open or
close it. Valve body
224 is spring-loaded with a biasing spring 226 such that it is normally in a
position closing port
222, but can be moved to open the port when the annular pressure P1 is greater
than the tubing
pressure P2 with a differential sufficient to overcome the bias in spring 226.
Thus, valve body
224 may be opened by reverse flow from the annulus to the tubing string such
that fluid can pass
through port 222 inwardly from annulus 250 to inner bore 214, with valve body
224 acting as a
one way check valve and resisting flow outwardly through the ports of the
stage tool.
Valve body 224 may be secured adjacent the port to be positionable, when
active, to sense the
pressure differential P1 vs P2 with annular pressure on one side of seals and
tubing pressure on
the other side of seals. In the illustrated embodiment, check valve body 224
is also positionable
such that this pressure differential is not sensed, In the illustrated
embodiment, valve body 224
is installed in an external chamber 225 (sometimes also called a pocket)
defined between wall
212 and wall 225a. The chamber has an active space in the circulation path
between port 222
and an open end 225b wherein seals 223 on the valve body can reside. Wall 225a
also forms a
closed end of the chamber which is positioned adjacent port 222 but
diametrically opposite open
end 225b, The closed end doesn't have an opening to the exterior of the tool
and defines an
inactive area for the valve body. When the seals of the valve body are in this
inactive area, the
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valve body is inactive as seals 223 are not exposed to a pressure
differential. In the inactive
position, valve body 224 can be held from moving in the pocket and may be held
with seals 223
in the inactive area. When activated, the valve body can slide in the chamber
as driven by spring
226 and, when seals 223 are in the active area, the valve body may be driven
by pressure. The
valve body is secured against removal from chamber 225 by stops 227 that
reduce the space
across the chamber to a dimension through which valve body 223 cannot pass.
There may be an equalization port 228 through wall 211 into chamber 225 in the
inactive area to
avoid the formation of a pressure lock behind the valve body.
While chamber 225 is shown here as a cylindrical side pocket, it is to be
understood that it could
be annularly formed extending fully or partly around wall 211 and in which
case the valve body
may be a sleeve.
The check valve may include a lock to positively lock valve body 224 in a port
closed position
with seals in active position. For example in the illustrated embodiment, the
lock may include a
lock ring 229a formed to catch on a ridge (sometimes called an upset) 229b.
While here valve
body 224 carries lock ring 229a, it may be installed on either the valve body
or the chamber,
While lock ring 229a is normally biased outwardly to catch on and limit
movement past ridge
229b, lock ring 229a is collapsible if sufficient force is applied to move
past the ridge. The
surface of ridge 229b may be ramped, gradually increasing in height, such that
it is easier to ride
thereover (i.e. side 229b') or the surface may have an abrupt height change to
create a stop wall
over which lock ring 229b cannot readily pass. In this embodiment, the locking
side 229b" of
the ridge is abruptly angled to prevent lock ring 229a from returning over the
ridge once it has
passed into the locked position.
Spring 228 has insufficient force to drive the valve body into the locked
position relative to ridge
229b. However, valve body 224 may be driven from the activated position into
the locked
position by pressuring up on the inner bore. Pressuring on the inner bore
renders P2 greater than
P1. This differential is communicated to the valve body through port 222 and
port 228 and is
sensed across seals 223. This drives the valve body up until it is stopped by
stops 227.
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Valve body 224 is initially inactive, for example, during run in of the tool
such that it is not
affected by pressure differentials. However, the valving operation of valve
body 224 may be
activated when its operation is required. For example, valve body 224 may be
releasably locked
in an inactive position, but may be unlocked to act as a check valve when such
operation is
required. In this embodiment, the releasable lock for maintaining the inactive
state of valve body
224 is provided by plug 230. The plug normally holds valve body 224 in an
inactive position,
but movement of the plug can release valve body 224 for check valve operation.
Plug 230 for
example, is secured by a shear pin 231 in a position holding valve 224 in an
inactive position,
where it cannot move and the seals are in the inactive area. However, plug 230
can be moved to
free valve body 224 for movement. Plug 230 can be moved by overcoming the
holding force of
pin 231. In this embodiment, plug 230 is expellable from chamber 225 to
activate valve body
224.
Plug 230 is positioned in chamber 225 and seals the circulation path from port
222 to open end
225b and thus, when in place, isolates external pressure from the check valve.
Plug 230 itself,
however, can feel pressure differentials thereacross between annular pressure
and tubing pressure
and can act as a piston and be expelled through the open end when P2 is
sufficiently greater than
P1 to overcome pin 231.
Plug 230 also serves to close port 222 when valve body 224 is inactive. Plug
230 may include
seals 226 to ensure that pressure differentials are sensed across the plug and
to prevent fluid
leakage between outer surface 212 and bore 214. The plug can be sized to catch
against stop 227
to resist further movement of the plug, if P1 becomes greater than P2.
While plug 230 may be moveable by various means, hydraulic means permits the
activation of
valve body 224 entirely remotely, simply by pressuring up on the inner bore
214.
Once released from its inactive position, valve body 224 is responsive to
fluid pressure
differentials between P1 and P2 and only allows one way flow inwardly when
P1>P2. The stage
tool may include a final closing sleeve 246 to act as a back-up seal for port
222. Final closing
sleeve 246 may be normally offset from port 222 but is moveable to cover the
port. Sleeve 246
may be moveable in various ways, as by a remote system, such as hydraulics,
electronics,
motors, etc. or by engagement by a shifting tool.
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Final closing sleeve 246 may include seals 258 to seal the interface between
sleeve 246 and wall
216 to prevent leaks therebetween. A lock such as a body lock ring or ratchet
may be employed
between sleeve 246 and wall 211 to lock sleeve 246 against movement towards
reopening.
Having thus described the components of the example stage tool 210, the
operation of that stage
tool will be described. Stage tool 210 may be manipulated between a plurality
of positions. As
shown by the drawings, the stage tool may be manipulated between a first, run
in position
(Figure 2A), a second, cementing port openable position (Figures 28 to 2D) and
a third,
cementing port-closed position (Figure 2E). The stage tool 210 may also be
manipulated to a
contingency closed position (Figure 2F).
The stage tool may be run into and set in the hole in a condition as shown in
Figure 2A and may
be manipulated as shown in Figure 28 to an active condition shown in Figures
2C and 2D for
stage cementing an annulus about the stage tool. Stage tool 210 allows cement
to be introduced
through the annulus and allows reverse circulation, arrows C, of annular
fluids from the annulus
into the tubing string though inner bore 214 and then back up toward surface.
The stage tool acts
to permit only flow inwardly to inner bore 214, when pressure P1 is sufficient
to overcome the
force of spring 226. When the pressure P1 is insufficient, spring 226 forces
the valve into a
closed position, to close off communication between the annulus and the inner
bore of the tool
and, thus, holding the cement in the annulus. After the introduction of cement
to the annulus
formed between the tool and the wellbore wall down to a selected level, the
tool may be
manipulated to a condition shown in Figure 2E to positively lock stage tool in
a closed position.
For contingency, back up sleeve 246 may be moved to also close port 222
(Figure 2F).
In summary, the stage tool may be installed in a tubing string and run into
the wellbore with the
port closed by a removable closure, in this embodiment plug 230, which also
holds a check valve
in an inactive state. Once in position, port 222 is rendered openable by
hydraulic actuation, here
by blowing out plug 230, to provide fluid communication between the annulus
about the tool and
inner bore 214. The stage tool can be located just above an uppermost packer
on a treatment
string, such that the annulus can be cemented between the upper end of the
string and a point just
above the uppermost packer. Cement is then introduced to annulus and can be
pumped down the
annulus as permitted by circulation through port 222 into inner bore 214. When
sufficient
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cement is introduced to fill the annulus along a selected length, port 222 is
closed to stop
circulation from the annulus into bore 214. This, then, holds the cement in
the annulus and time
is allowed for the cement to set. The amount of cement introduced can be
selected to
substantially fill the selected portion of the annulus without injecting much
or any cement into
inner bore 214.
To elaborate, tool 210 may be installed in a tubular string with its inner
bore 214 in
communication with the inner diameter of the tubing string. The tool will be
run into the
wellbore with ports 222 closed. Figure 2A shows the position of the components
of stage tool
210 during run in. Once in position, valve body 224 can be activated to
operate as a check valve
by removing its releasable lock. This may be accomplished by pressuring up the
tubing string.
In one embodiment, the process to set the tubing string in the hole, as by
setting of packers, slips,
etc, is also by pressuring up and, as such, the operations to set the string
in the well and to
activate the valve body may occur at the same time. This may include dropping
a ball that lands
in a toe-end of the string to pressure up substantially the entire string.
This may set one or more
packers on the string in addition to triggering valve body 224 to the active
position by removing
plug 230 (Figure 2B).
For example, inner bore 214 can be pressured up relative to the annulus about
stage tool 210 to
overcome the holding force of pin 231 and to blow plug 230 out of the chamber,
as shown by
arrow E. Removal of plug 230 renders port 222 openable and activates check
valve body 224.
Plug 230 is expelled outwardly by pump pressure, such that it is out of the
way of cementing
flows. Plug 230 may be released entirely from the stage tool into the annulus.
The plug 230, when in place in the stage tool, seals off a cement circulation
path from annulus to
port 322, but when removed, the cement circulation path is opened through open
end 225b, the
active area of chamber and port 322 to inner bore 314.
After the stage tool is activated, cement can be pumped down the annulus 250
which creates a
pressure P1>P2 sufficient to overcome the check valve and, in particular, to
move valve body
224 against the bias of spring 226 to permit circulation, arrows C, through
port 222 and into bore
214 toward surface.
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Valve body 224 resists flow in an opposite direction relative to arrows C
through port 222 due to
the bias in spring 226. In this active position, closing movement of the valve
body is stopped
when lock ring 229a hits ridge 229b. Spring 226 cannot apply sufficient force
to move lock ring
229a over the ridge.
Once the annulus pressure P1 is reduced, Figure 2D, such as when the cement
job is interrupted
or completed, the valve body 224 shuts. This prevents further flow through
port 224, unless
pressure is increased again in annulus 250. The bias in spring 226 can be
sufficient to resist the
opening of valve body 224 by the weight of the cement, absent pump pressure.
The amount of cement introduced can be selected to substantially fill a
selected portion of the
annulus at least uphole of the stage tool without injecting much or any cement
through port 222
into inner bore 214. The method may include pumping leading fluids ahead of
the cement, the
fluids being pumped down the annulus to clean the annulus and/or open the
check valve to flow
through the port from the annulus to the inner diameter ahead of the cement.
The fluids may
include, for example, mud. In such an embodiment, the circulation through port
allowing the
cementing of the annulus can be accomplished by the leading fluids and
circulation may be
stopped before the cement begins to pass through port 222.
If desired, after the cementing job is done, valve body 224 can be locked in a
closed position. To
do so, the tubing string can be pressured up to cause P2 to exceed P1. The
seals, being
positioned in the active area between port 222 and open end 225b of the
pocket, feel the pressure
differential P2>P1 and drive the valve body toward open end 225b. The pressure
differential
may be sufficient to move lock ring 229a over ridge 229b. Stop 227 prevents
the valve body
from being expelled from chamber. Due to the abrupt angle on surface 229" and
the outward
bias of lock ring 229a, it cannot be pushed back over ridge 229b and is, thus,
locked in a closed
position relative to port 222 (Figure 2E).
Also, if desired, final closing sleeve 246 can be moved over port 222 to
prevent further flow
through the port in either direction and to act as a back-up for sleeve 224.
This may include
engaging final closing sleeve 246 to move it to a cementing port-closed
position (Figure 2F),
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After the cement is installed and set, wellbore operations may proceed. In the
embodiment of
Figures 2, the tubing string inner bore is open and by selection of the inner
diameter of sleeve
246 may be fully open to the drift diameter. In some embodiments, wellbore
operations may
include wellbore fluid treatments such as stimulation including fracturing. In
such an
embodiment, string manipulations may be necessary below the stage tool. For
example, fluid
treatment ports may be opened below the stage tool through which treatment
fluids will be
communicated, sometimes under pressure to the formation. In one embodiment,
for example a
fracing operation may be carried out on a formation accessed through the
wellbore below the
stage tool. Fracturing fluids under pressure may be introduced through the
tubing string, passing
through inner bore 214 of tool 210, and injecting the fluids under pressure
out from the tubing
string through fracing ports downhole of the stage tool, In some instances,
string manipulation
may include pressuring up the string inner bore including bore 214 of the
stage tool. In some
instances, tools, free or connected to strings, must be passed through the
string inner bore
including bore 214 of the stage tool.
Another stage tool 310 is shown in Figures 3A to 3E, That stage tool 310 also
contains a pump
out plug 320 to control activation of the stage tool's cementing port 322.
However, in this
embodiment, once plug 320 is pumped out, the cementing port is entirely open
to flows in either
direction, While there is no check valve illustrated in this embodiment, one
could be employed
if desired. Stage tool 310 however, does have a closure that can be set to
close the port when
desired, As with the stage tool of Figure 2A, this stage tool 310 also can be
closed by hydraulics
without launching a plug into the string.
For example, the stage tool 310 has a cementing port closure operable through
electronics. The
side pocket cementer may be installed in a stage tool anywhere along the
string.
The tool allows run in with the cementing port closed, cementing of the
annulus of a well by
opening the cementing port 322 and closing the port with a pressure signal.
The port has a valve
that controls the open and closed condition of the port.
The port is in the liner wall 311 and opens into a side pocket 325 on the
wall, As will be
appreciated, a side pocket can be annularly formed and accommodate a sleeve
type valve, or a
side pocket can be formed as a non-annular, roughly cylindrical form and
accommodate a poppet
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type valve. The side pocket 325 forms therewithin a channel extending between
port 322 and the
exterior of the stage tool at an open end 325a of the side pocket.
The port's valve is normally closed, for example during installation of the
liner (Figure 3A). The
valve is then openable and then is recloseable. The valve includes a plug 320
held in the channel
by a shear pin 331. The plug is in communication on one side with the tubing
pressure and on
the other with the annular pressure and can therefore be affected by a
pressure differential set up
between the tubing string and the annulus. An end 320a of the plug 320 holds a
valve body in
the form of a piston 324 in place in the channel. Piston 324 is in
communication on one side with
tubing pressure and, on the other communicates with a chamber 352 at
atmospheric pressure,
which is normally always lower than both tubing and annular pressures.
As shown in Figure 3B, applied tubing pressure P2 through port 322 shears the
pin 331 pushing
the plug 320 from pocket 325 through open end 325a and out into the annulus.
This provides a
communication path through port 322 and the pocket from the tubing ID to the
annulus open to
outer surface 312 of the stage tool wall. Cement that is pumped down the
tubing will exit the
port and cement the annulus. Reverse cementing is also possible as the port
322 is fully open
when plug 320 is removed.
Once plug 320 is removed, piston 324 is also activated, since it is no longer
held in place by end
320a.
Piston 324 is sized and intended as a closure for port 322. However, even
though it is activated
it cannot move to close the port until it is signaled to do so. In particular,
the applied pressure
that removed piston 320 and the subsequent flow of cement creates a
hydrostatic pressure greater
than that in the atmospheric chamber and that pressure differential holds
piston 324 in place. In
fact, piston 324 may be pushed against a spring 326. The spring may collapse
to bias the piston
against the pressure that is higher than atmospheric, but the pressure
differential (hydrostatic
pressure vs atmospheric pressure) holds the piston from advancing into channel
325 toward port
322.
The closing of port 322 by piston 324 is controlled by a controller 354. When
it is time to close
the port, a pressure signal is transmitted down the tubing and is communicated
to controller 354,
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here through a port 355 (Figure 3C). This signal could be a maximum pressure
(greater than the
pressure to shear pin 331) or a plurality of pressure pulses. A sensor in
controller 354 senses this
pressure signal and opens chamber 352 to tubing pressure such that the
pressures are equalized
across piston (Figure 3D). The spring now has the power to push the piston
over the port 322
closing the communication between the tubing and the annulus. The force in
spring 326 may
then act on piston 324 and bias it into a plugging position in channel 325
over the port (Figure
3B). This closes the port against further flow.
Controller can take various forms. In the illustrated embodiment, controller
354 includes a
circuit board and a battery and a releasable plug in the form of a meltable
kobe 356. When the
sensor senses the signal, it communicates with the circuit board and the
circuit board in turn
activates the batteries that heat a wire 358 configured to melt the kobe
material and open the
kobe end 356' to expose a channel 356" to conduct fluid pressure P2 to chamber
352. In this
embodiment, the meltable material is plastic and the wire is wrapped around
the plastic kobe
356. This burns the end of the plastic kobe and allows tubing pressure behind
the piston 324,
equalizing the pressure in the atmospheric chamber 352 and, as noted above,
allows piston 324
to be moved, arrow M, by spring 326 to close the port (Figure 3E).
The described valve works with either forward or reverse flows, provided there
is an initial
forward flow to remove piston 320.
One meltable plastic of interest is polyphenylene sulfide (available as Ryton
TM), but other
plastics are useful as well. A meltable kobe 456 is shown in Figures 4A to 4D.
The kobe
includes an inner bore 460 defined by side walls. There is an opening to the
bore at a base end
462. The bore is closed by a closed end 464. The kobe is installed by its base
end 462 in a
mount such that a fluid can enter bore 460. The kobe remains closed as long as
side walls and
end 464 remain intact. However, the kobe can be opened to permit fluid flow
through bore 460
by creating an opening in the side walls or end 464.
As clearly shown in Figure 4B, a wire 458 is wrapped around side walls in an
area through
which bore 460 extends. When required, wire 458 operates as a thermal knife
relative to the
material of the kobe's side walls. The wire may be of nichrome or other
electrical resistance
wire. The wire may be applied externally, as shown, in multiple wraps or a U-
shaped wrap or
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the wire may be embedded, In operation, electricity is supplied to the wire
which heats it to a
temperature suitable to soften and degrade the plastic to break open the
closed end 464. The
internal pressure within bore 460 assists the opening of closed end 464, as
the pressure may
move the melted plastic away. Finally the plastic of the closed end yields and
a leak path is
formed to release the internal pressure from bore 460 to the chamber.
While the above-noted embodiment, employs a tubing pressure fluctuation signal
sensed by a
pressure sensor and a meltable Robe, it will be appreciated that other
embodiments could be
employed wherein the kobe is destroyed by other means such as acid. In such an
embodiment,
for example, an amount of acid is conveyed with the circulating flow to signal
the closing of the
port.
The previous description of the disclosed embodiments is provided to enable
any person skilled
in the art to make or use the present invention. Various modifications to
those embodiments will
be readily apparent to those skilled in the art, and the generic principles
defined herein may be
applied to other embodiments. Thus, the present invention is not intended to
be limited to the
embodiments shown herein, but is to be accorded the full scope consistent with
the claims,
wherein reference to an element in the singular, such as by use of the article
"a" or "an" is not
intended to mean "one and only one" unless specifically so stated, but rather
"one or more". All
structural and functional equivalents to the elements of the various
embodiments described
throughout the disclosure that are known or later come to be known to those of
ordinary skill in
the art are intended to be encompassed by the elements of the claims.
Moreover, nothing
disclosed herein is intended to be dedicated to the public regardless of
whether such disclosure is
explicitly recited in the claims. No claim element is to be construed under
the provisions of 35
USC 112, sixth paragraph, unless the element is expressly recited using the
phrase "means for"
or "step for".
