Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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FLOW BYPASS DEVICE AND METHOD
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of United States Patent
Application Ser. No.
13/423,154 filed on March 16, 2012 and entitled "Downhole System Incorporating
Valve
Assembly with Resilient Deformable Engaging Element", which claims the benefit
of United
States Provisional Application Ser. No. 61/453,281 filed March 16, 2011 and
entitled
"Multistage Production System Incorporating Downhole Tool with Deformable
Ball" and a
Continuation of U.S. Patent Application Ser. No. 13/694,509 filed on December
12, 2012; all of
which are incorporated by reference herein.
FIELD OF DISCLOSURE
[0002] This disclosure provides methods, systems and devices for re-
directing flow through
tubing in a well, inside other tubing, or other enclosed space.
BACKGROUND
[0003] Tools incorporating valve assemblies having a plug, such as a ball
or dart, and a plug
seat, such as a ball seat or dart seat, have been used for a number of
different operations in wells
for oil gas and other hydrocarbons. These tools may be incorporated into a
string of pipe or
other tubular goods inserted into the well. The valve assemblies provide a
defined location at
which the flow of fluid past may be obstructed and, with the application of a
desired pressure, a
well operator can actuate one or more tools associated with the assembly.
[0004] Remotely operated valve assemblies may be used in the treatment of a
subterranean
formation adjacent to a well. Valves used for this purpose open ports in the
tubing to facilitate
treatment of a selected area or section of the formation. The treatments are
performed by
pumping fluid through the wellhead, into the tubing string and out of the
selectively opened
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ports. Examples of such well treatments include acidizing or fracing.
Acidizing cleans away
acid soluble material near the well bore to open or enlarge the flow path for
hydrocarbons into
the well. Fracing may occur by injecting fluids from the surface through the
wellbore and into
the formation at high pressure to create and force fractures to open wider and
extend further.
The injected frac fluids may contain a granular material, such as sand, which
holds fractures
open after the fluid pressure is reduced. Such granular materials are not
necessarily required,
however. While acidizing and fracing are two examples of treatments that may
be performed
through the valve assemblies, the scope of the present disclosure is not
limited to any particular
formation treatment(s) and may include any other treatment, such as, without
limitation, CO2
injection, treatment with scale inhibitors, iron control agents, corrosion
inhibitors or others.
[0005] Treatments in multiple-stage production wells may require selective
actuation of
downhole tools, such as sleeve assemblies, to control fluid flow from the
tubing string to the
formation. For example, U.S. Pat. No. 7,926,571 entitled Cemented Open Hole
Selective
Fracing System, which is incorporated by this reference, describes a system
using multiple valve
assemblies having ball-and-seat seals, each having a differently sized ball
seat and corresponding
ball. Such ball-and-seat arrangements are operated by placing an appropriately
sized ball into
the well bore and bringing the ball into contact with a corresponding ball
seat. The ball engages
on a section of the ball seat to block the flow of fluids past the valve
assembly. Application of
pressure to the valve assembly, such as through use of fluid pumps at the
surface, may create a
pressure differential across the valve assembly, causing the valve assembly to
"shift" and thereby
open fluid flow the sleeve to the surrounding the formation. Other types of
plugs such as darts,
or any other shape that can be used to selectively operate the valve
assemblies, may also be used
to seal the seat and facilitate the creation of a pressure differential to
shift the valve assembly and
open the sleeve, or actuate a different tool, such as a plug and seat actuated
flapper valve,
associated with the valve assembly.
[0006] If the well or tubing contains multiple plug seats, methods, systems
or apparatuses
must be employed for passing a plug through certain plug seats, including
passing through at
least some plug seats without actuating any devices associated with such
seats. One such method
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is to use a ball, dart or other plug that is small enough so that it will not
seal against any of the
seats it encounters prior to reaching the desired seat. For this reason, the
smallest ball to be used
for the planned operation is the first ball placed into the well or tubing and
the smallest ball seat
is positioned in the well or tubing the furthest from the wellhead. After the
desired treatments
are completed, the direction of fluid flow is reversed so that the treating
fluids and formation
fluids may be produced through the wellhead. Because each plug is smaller than
the seats past
which it traveled, the plugs simply move with the fluids through the
previously passed plug seats
and out of the well.
[0007] Valve assemblies, which rely solely on the size of the plug and the
seat opening for
selecting the tool to actuate, significantly limit the number of valves that
can be used in a given
tubing string. In such systems each ball size is only able to actuate a single
valve and, generally,
each plug must have a diameter of at least .125 inches larger than the
immediately preceding
plug. Thus, the size of the liner restricts the number of valve assemblies
with differently-sized
ball seats.
[0008] Devices and assemblies have been introduced to increase the number
of valve
assemblies that may be actuated by a single plug, such as a ball, dart, or
other plug. Such
devices and assemblies include those described in United States application
Ser. No. 12/702,169,
filed Feb. 28, 2010 and entitled "Downhole Tool With Expandable Seat;" United
States App.
Ser. No. 13/423,154, filed March 16, 2012 and entitled "Downhole System and
Apparatus
Incorporating Valve Assembly With Resilient Deformable Engaging Element;" and
United
States App. Ser. No. 13/423,158, filed March 16, 2012 and entitled "Multistage
Production
System Incorporating Downhole Tool With Collapsible or Expandable C-Ring,"
each of which is
incorporated herein by reference. The devices, methods, and assemblies
described in these
applications, however, place one or more plugs downstream of plug seats with
openings smaller
than the diameter or other cross sectional dimension of the plug. When the
fluid flow is
reversed, i.e., fluid begins flowing toward the wellhead, such plugs may seat
on the back or
outlet side of a previously passed plug seat, blocking the reverse flow. The
methods for
removing such blockages, such as drilling out the tubing string, are both time
consuming and
expensive. Therefore, there exists a need for cost effective and time
efficient devices and/or
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methods for circumventing such blockages and thereby allowing the flow of
fluids from the well
bore to the surface.
BRIEF SUMMARYOF CERTAIN EMBODIMENTS
[0009] The present disclosure describes systems, methods, and apparatuses
for allowing fluid
flow to bypass such a blockage. Further, the bypass of such present disclosure
is not limited to
blockages caused by plugs traveling upstream. Rather, the bypass may operate
in response to
any event or events that limit flow and/or create a pressure differential at a
pre-identified point in
the tubing string.
[0010] In some embodiments of the present disclosure, it is desirable that
the flow bypass
remain closed until a pre-determined triggering event has occurred. Such
triggering events
include, without limitation, shifting of a valve assembly in response to a
pressure differential
across that valve assembly. Therefore, the present disclosure further
encompasses valve
assemblies including a sequencing mechanism which prevents fluid from flowing
through the
bypass assembly until after the pre-determined triggering event has occurred.
The sequencing
mechanism may be a locking assembly configured for use in a tubing string to
prevent actuation
of one or more tools until after the lock is released. Further, the locking
mechanism may be used
in connection with the flowback bypass of the present disclosure, though the
locking mechanism
of the present disclosure is in no way limited to use with the flowback bypass
or any other
specific tool, method, or assembly.
[0011] Embodiments of this disclosure generally provide devices, methods
and systems for
use in a tubing string. An apparatus of the present disclosure may comprise a
housing, with an
interior passage for the flow of fluids, an obstruction in the interior
passage, and a flow bypass
around the obstruction. The obstruction is preferably a plug seat, but may be
any feature of the
tubing or apparatus that may obstruct, or cooperate with fluids or solids in
the tubing to obstruct,
fluid flow towards the wellhead. In other words, the obstruction may not
prevent fluid flow by
itself, but instead define a location at which fluid flow may be blocked
during operations
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performed using, in, or on the tubing string. The flow bypass may be blocked
by a barrier, and
the barrier may be held in place, either wholly or partially, by a locking
mechanism. In certain
embodiments, such locking mechanism is released in response to a particular
event, such as a
predetermined pressure differential created across the plug seat, preferably
with the higher
pressure occurring on the wellhead side of the plug seat. The bypass is then
allowed to open in
response to a pressure differential across the plug seat in the opposite
direction.
[0012] A method of the present disclosure may include engaging a first plug
on an uphole
side of a first plug seat in a first sleeve assembly and opening, at least
partially, a first set of ports
located on the first sleeve assembly. Further, a second plug may be engaged on
a downhole side
of the first plug seat, and opening, at least partially, a second set of ports
on the first sleeve
assembly, wherein at least part of a fluid flow passes through the second set
of ports to exit the
first sleeve assembly, bypasses the first plug seat and re-enters the first
sleeve assembly at the
first set of ports.
[0013] In another embodiment, a system includes a first plug engaging an
uphole side of a
first plug seat in a first sleeve assembly. Further, the system includes a
first set of ports at least
partially opened on the first sleeve assembly. Further still, the system
includes a change,
subsequent to the first set of ports being opened, of a fluid flow to upstream
in the tubing string.
Yet further, the system includes a second plug engaging a downhole side of the
first plug seat,
and a second set of ports at least partially opened on the first sleeve
assembly, wherein the fluid
flow bypasses the first plug seat.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] So that the manner in which the above recited features, advantages
and objects of the
present invention are attained and can be understood in detail, a more
particular description of
the invention, briefly summarized above, may be had by reference to the
embodiments thereof
which are illustrated in the appended drawings.
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[0015] It is to be noted, however, that the appended drawings illustrate
only typical
embodiments of this invention and are therefore not to be considered limiting
of its scope, for the
invention may admit to other equally effective embodiments.
[0016] FIG. 1 depicts a cross sectional view of an example embodiment of a
first sleeve
assembly that may be found in a tubing string, such as in a well for oil, gas,
or other
hydrocarbons.
[0017] FIG. 2 depicts an enlarged portion of the example embodiment from
FIG. 1.
[0018] FIG. 3 depicts another enlarged portion of the example embodiment
from FIG. 1.
[0019] FIG. 4a depicts a tubing string installed in a well, showing the
relative locations of a
a first sleeve assembly and a second sleeve assembly.
[0020] FIG. 4b conceptually illustrates a cross section from the first
sleeve assembly of FIG
4a. example embodiment of a first sleeve assembly and a second sleeve
assembly, each of
which have various features, including a first plug that moves through the
second sleeve
assembly's plug seat and is stuck on the inlet of the first sleeve assembly's
plug seat in the tubing
string and in accordance with this disclosure.
[0021] FIG 4c conceptually illustrates a cross section from the second
sleeve assembly if
FIG 4a.
[0022] FIG 5a depicts a flowback bypass device after the plug seat and
first sleeve have been
shifted by a differential pressure created across the plug seat.
[0023] FIG 5b depicts an enlargement of a portion of the flowback device
from FIG 5a to
further highlight certain aspects of the device.
[0024] FIG 6. depicts a tubing string installed in a well, showing the
relative locations of a
first sleeve assembly and a second sleeve assembly, the locations of plugs
used to seal against
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the plug seats of the sleeve assemblies and direction of fluid flow effecting
the movement of the
plugs within the tubing string.
[0025] FIG 7 depicts a flowback bypass device with a plug engaged on the
outlet or
downhole side of the plug seat. The second set of ports are open due to the
pressure differential
caused by such engagement and fluid is bypassing the plug set by exiting the
device through the
second set of ports and re-entering the device through the first set of ports.
DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS
[0026] The following is a detailed description of example embodiments of
the invention
depicted in the accompanying drawings. The amount of detail offered is not
intended to limit the
anticipated variations of embodiments; on the contrary, the intention is to
cover all
modifications, equivalents, and alternatives falling within the spirit and
scope of the present
disclosure as defined by the appended claims. The detailed descriptions below
are designed to
make such embodiments obvious to a person of ordinary skill in the art.
[0027] Generally speaking, methods and systems for use in a tubing string
are contemplated.
The methods and systems permit mechanical control of fluid flow from a
wellhead to a
formation through use of at least two plugs, such as plugs, balls or darts,
wherein the plugs are
optionally dissimilar. Further, the methods and systems provide for a flow
bypass around a plug
that may be trapped in the tubing string. The fluid, of course, may comprise
treating fluids,
hydrocarbons, water, impurities or other mined substances, for example, which
may be carried to
the wellhead through use of solutions under pressure. The substances
comprising the fluid may
or may not be completely or partially dissolved, and may exist in one or more
physical states of
gas, liquid, or solid.
[0028] Turning to the drawings, FIG. 1 depicts a sleeve assembly 100 having
two sleeves,
namely a first sleeve 110 and a second sleeve 120. The sleeves 110, 120 lie
within a housing
105 with upper housing ports 130 and lower housing ports 140, such that
shifting the first sleeve
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110 along the longitudinal axis of the tubing string will open the upper
housing ports 130 and
shifting the second sleeve 120 along the longitudinal axis of the tubing
string will open the lower
housing ports 140. In the illustrated embodiment, the housing ports 130, 140
are opened by
shifting the first sleeve 110 or second sleeve 120, respectively, completely
off of the effected
housing ports 130, 140. Such depiction is illustrative and not limiting; any
method for opening
the upper housing ports 130 and lower housing ports 140, such as shifting a
sleeve to align sleeve
ports with the housing ports, is within the scope of the present disclosure.
The sleeve assembly
100 has a plug seat 160, that may engage an appropriate plug such as a ball,
dart, plug, or other
blocking and/or sealing device. Further, the shape of the plug seat 160 may
vary in some
embodiments from the shapes illustrated in this disclosure provided that a
plug seat 160 may
accomplish the system and methods disclosed herein.
[0029] In the illustrated embodiment, the housing 105 comprises multiple
sections, including
a crossover section 180. The various sections of the housing of the
illustrated embodiment are
present for purposes of assembling the tool and are not required as part of
the present disclosure.
Thus, the housing of the illustrated embodiments may be of one piece of or a
plurality pieces.
[0030] The embodiment of FIG 1 is further depicted in FIGS. 2 and 3. FIG. 2
generally
depicts the embodiment device on one side of the crossover 180, while FIG 3
generally shows
the embodiment of FIG. 1 on the other side from crossover 180.
[0031] Turning to FIG 2, shear pins 101 engage housing 105 and the first
sleeve 110 to
control movement of the first sleeve. Further, the plug seat 160, first sleeve
110 and locking
sleeve 170 and, if present, plug seat carrier 161 are interconnected such that
they move as unit
inside the housing. Thus, when a pressure differential is created across the
plug seat 160, the
force of the pressure differential is transferred to the shear pins 101 via
the first sleeve 110 and
the shear pins 101 can be, and typically are, configured to break when the
pressure differential
across the plug seat 160 exceeds a desired pressure. In other words, the shear
pins 101 prevent
the first sleeve 110, plug seat 160, and locking sleeve 170 from shifting
until a desired pressure
differential is created across the plug seat 160. While the shear pins 101 are
illustrated to
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connect the first sleeve 110 with the housing 105, the shear pin may penetrate
any portion of the
first sleeve 110, plug seat 160, plug seat carrier 161, or locking sleeve 170
provided that the
shear pin prevents movement of the plug seat 160 and/or first sleeve 110 when
intact and does
not interfere with operation of the tool once it has broken. While such shear
pins are present are
desirable for certain embodiments of the present disclosure, use of shear pins
or other devices for
preventing movement of the first sleeve 110, plug seat 160, and locking sleeve
170 are not
required for the apparatus and method of the present disclosure.
[0032] Plug seat 160 comprises an inlet 162 and an outlet 164. The inlet
162 generally
comprises the surface of the plug seat 160 that fluids, a plug, or other
materials will first
encounter when travelling from a well head or from fluid pumps positioned at
an end of the
tubing string. The inlet 162 will also typically function as the plug seat 160
surface against
which a plug traveling from the well will form a seal. It will be apparent
that, in the illustrated
embodiment, the illustrated shear pins 101 will generally be broken as a
result of a pressure
differential across the plug seat 160 where the fluid pressure is higher at
the inlet 162 than at the
outlet 164.
[0033] Additional features of the embodiment illustrated by FIG. 1 include
opposing sets of a
complimentary wicker teeth 150a, 150b wherein a first set of teeth 150a is
associated with the
locking sleeve 170 and a second set of teeth 150b is associated with the
second sleeve 120. The
sleeve's 120, 170 incorporation of complimentary set of teeth 150 is not
consequential; only the
ability of the sleeves to engage upon movement of either or both of the
sleeves 170, 120 is
required. Upon actuation of the sleeve assembly 100, typically by creating a
pressure differential
across the plug seat 160, the inner sleeve assembly comprising plug seat 160,
first sleeve 110,
and locking sleeve 170 move 115 toward second sleeve 120, opening the first
housing ports 130
and, contemporaneously, causing the first set of teeth 150a and the second set
of teeth 150b of
the complimentary wicker teeth 150 to engage and bring the second sleeve 120
into mechanical
communication with the plug seat 160. In alternate embodiments, however, the
second sleeve
120 may move in coordination with the first sleeve 110 to engage the first
150a and second 150b
sets of the complimentary set of teeth 150, or such first 150a and second 150b
sets may become
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engaged through the movement of the second sleeve 120 without or apart from
movement by the
first sleeve 110.
[0034] As shown in FIG 3, the locking sleeve 170 may be adjacent to, and in
this
embodiment, overlapping the second sleeve 120. Further, the locking sleeve 170
is in
communication with the housing 105 through the locking assembly 600. In the
illustrated
embodiment, locking assembly 600 comprises a moveable bar 610, also referred
to as a housing
lock, a ball 620, and a stationary bar 630, also referred to as a sleeve lock.
The ball 620 rests
against an outer surface of locking sleeve 170, between sleeve lock 630 and
housing lock 610.
The size of ball 620 is sufficiently large that, when resting on the outer
surface 172 of locking
sleeve 170, the ball engages sleeve lock 630, and housing lock 610, preventing
movement of
housing lock 610. Because the second sleeve 120 is connected to housing lock
610, this
arrangement prevents movement of the second sleeve 120. Further, the locking
sleeve comprises
a recessed surface 174 positioned such that actuation of the tool moves the
recessed surface 174
towards the ball 620.
[0035] With reference to FIG. 4, a first plug 225 may move 235 in the fluid
flow direction
215 in a tubing string, such as, for example, in a well for water, or for oil,
gas, or other
hydrocarbons. The first plug 225, for instance, may have been passed, e.g.,
dropped, from a
wellhead 255 and passed through a first sleeve assembly 205 arranged to
provide a fluid flow
bypass, such as the sleeve assembly of FIG I. The plug 225 has a larger cross
sectional area than
the opening of a plug seat 260 in first sleeve assembly 205 and thus plug seat
260 may be an
expandable plug seat or an expandable split ring plug seat, or the plug 225 is
configured to
extrude through the plug seat 260 while retaining its ability to seal against
later engaged plug
seats. When the first plug 225 engages at the first plug seat 260, pumping
into the tubing string
may create a differential pressure across the plug seat 260. When the
differential pressure is
sufficiently high, the plug 225 is forced through the plug seat 260, creating
the condition of the
tubing string illustrated by FIG 4. In some embodiments, a shear pin (101 in
FIG 1) does not
break at the pressure required to extrude the plug 225 through plug seat 260.
In the illustrated
embodiment, the plug 225 therefore is moved between the first sleeve assembly
205 and second
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sleeve assembly 210, without shifting the plug seat or otherwise actuating the
tool of first sleeve
assembly 205. In other embodiments, a slotted sleeve or other guide element
may be used to
facilitate passing of the plug 225 through the plug seat, through an
expandable plug seat or
through an expandable c-ring plug seat without opening the first set of ports
(130 FIG 1) or
without leaving the first ports open after the plug has passed.
[0036] It will be appreciated that a shear pin may be included that will
break at a pressure
below the pressure required for the plug to extrude and that the plug will
actuate the tool prior to
moving between the first sleeve assembly and second sleeve assembly. Such an
arrangement is
within the scope of the present disclosure.
[0037] The first plug 225 may encounter a second assembly 210, which,
generally speaking,
will not allow the plug 225 to pass further through the tubing string. For
example, the passage
through a second plug seat 265 in the second assembly 210 may be too small for
extrusion of the
plug 225 at the pressure differentials created across the plug 225 and second
plug seat 265. The
second assembly 210 may be a second sleeve assembly, a plug and plug seat
actuated flapper
valve, any other plug and plug seat actuated tool, a blind plug seat with no
associated tool, or any
other device for stopping travel of the plug 225 through the tubing string.
[0038] FIG. 5a and 5b depict the illustrative embodiment of FIG 1 engaged
with a second
plug 327. FIG 5b is an enlargement of FIG 5a in the region containing and
adjacent to the second
sleeve 320 of FIG 5a. In this embodiment, the second plug 327 seals against
the plug seat 360
to facilitate creation of a pressure differential sufficient to break the
shear pins 301. The second
plug 327 may be larger than the first plug (225 FIG 2) or may be made of a
different material.
For example, and by way of illustration, not limitation, the at least one
shear pin 301 may be
configured to break at a desired pressure differential across the plug seat
360. Any desired
pressure differential may be chosen provided only that such pressure
differential may not be so
high that the pressure differential is difficult to impossible to reach
without extruding or breaking
the available plugs and may not be so low that the at least one shear pin will
break at a pressure
differential below which any of the selected plugs will extrude. The at least
one shear pin 301 of
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the present disclosure is preferably selected to break at pressures between
400 and 1800 psi and
more preferably selected to break between 800 and 1400 psi.. A first plug that
extrudes through
plug seat 360 at a pressure of below 1400 psi, such as 800 to 1100 psi, may be
selected, thereby
allowing the first plug to pass plug seat 360 without breaking the at least
one shear pin 301.
[0039] A second plug may then engage the plug seat 360. The second
plug may be selected
such that it will not extrude through plug seat 360 until the pressure
differential across the plug
seat 360 exceeds the pressure required to break the at least one shear pin
301. Therefore, rather
than extrude the second plug through the plug seat 360, the at least one shear
pin 301 is broken
allowing the plug seat 360 as well as the attached first sleeve 310 and the
locking section 370 to
move in the downward direction. This movement of plug seat 360 and first
sleeve 310 opens the
first set of ports 330 thereby creating fluid communication between the
passageway through the
assembly and the exterior of the assembly and facilitating treatment of the
adjacent formation.
The second sleeve 320 remains closed in this embodiment so that fluid may not
flow around the
ball seat and back into the tubing string rather than into the adjacent
formation or other areas to
be treated. The first plug 225 and second plug 327 of the illustrative
embodiment may each be
selected based on their respective sizes relative to the plug seats, the
material or materials from
which a selected plug is manufactured, combinations of the above, or any other
factor provided
that the selected plug performs the desired function of sealing against the
plug seat 360 and
either extruding through the plug seat 360 at a pressure differential
insufficient to break the at
least one shear pin 301 or maintaining its seal with plug seat 360 up to at
least a pressure
differential sufficient to break the at least one shear pin 301. .
[0040] When locking sleeve 370 shifts, the recessed surface 374 is
brought adjacent to the
ball 620 of locking mechanism 600, such that ball 620 now has sufficient
clearance to fit
between recessed surface 374 and the stationary bar 630, unlocking the locking
mechanism.
Further, the locking sleeve 370 and second sleeve 320 are now interlocked
through adjoining
their complimentary portions of wicker teeth 350, connecting these two
sleeves. It will be
apparent that any adjoining method or system is acceptable and is not limited
to teeth as
described herein. For example, the sleeves 310, 320 may permanently or
temporarily interlock
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by use of retaining rings, locking rings, gears, or any other method of
joining the ends upon
movement of the locking sleeve 370 relative to the second sleeve 320.
[0041] Moving on to FIG. 6, the first plug 425 and the second plug 427
are in motion as a
result of fluids flowing 450 from the well toward the wellhead 455, i.e. the
fluid flow is reversed,
or the well is flowed back or produced after treatment is finished. Here, the
plugs 425, 427 are
no longer engaged with the plug seats in the second assembly 410 and first
assembly 405
respectively, because reversal of the fluid flow occurred, for example, by
opening a valve at the
wellhead to alleviate pressure and/or collect fracing and production fluids.
It will be appreciated
that the direction of fluid flowing 450 towards the well head will case the
first ball 425 to engage
the first assembly 405 on the outlet (FIG 2 164) of the plug seat (FIG 2 160).
[0042] Finally, with reference with FIG. 7, subsequent to reversing
the fluid flow, the first
plug 525, formerly engaged on the plug seat (265 FIG. 4) of second assembly
(210 FIG 2, 410
FIG 6), moves upstream and engages on the downhole, or outlet, side of the
plug seat 560
located in the first sleeve assembly (405 FIG 6). The first plug's 525 new
engagement blocks the
flow of fluid through the tubing string to the wellhead. However, blocking the
flow of reservoir
fluids causes a pressure differential across the plug seat 560, thereby
exerting force on the second
inner sleeve assembly and the now connected second sleeve 520. This pressure
causes the inner
sleeve assembly and second sleeve 520 to shift, opening a second set of ports
540. The travel of
the combined first sleeve 510, plug seat 560, locking sleeve 570, and second
sleeve 520 is
limited by engagement of a shoulder 576 of the moveable bar 610 with the
stationary bar 630 so
that the first set of ports 530 are not closed, or are not closed entirely by
movement of the first
sleeve 510. As a result, the fluid flow 520 bypasses the blockage occurring at
the first plug 525
engaged on the outlet 564 of plug seat 560. Instead, the fluid flows according
to the path
partially defined by the second set of ports 540, the annulus between an
exterior of the second
sleeve assembly 500 and the geologic formation into which the tubing string is
installed, and the
first set of ports 530 first sleeve assembly 500. It will be appreciated that
the path for fluid flow
defined by the annulus, first set of ports 530, and second set of ports 540
avoids and otherwise
circumvents the blockage caused by engagement of the plug 525 on the outlet
564 of plug seat
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560. Once the fluid reenters the tubing string at first set of ports 530, it
then may continue
flowing through the tubing string toward the wellhead.
[0043] The embodiment locking mechanism illustrated in the figures is shown
such that the
moveable bar moves parallel to the longitudinal axis of the tubing string upon
release of the lock.
However, the locking bar, moveable bar, bolt, and stationary bar may also be
arranged to prevent
rotational movement around a circumference or perimeter of the tubing string.
Further, the
direction in which the locking bar moves does not necessarily dictate the
direction of movement
the locking bar prevents, e.g., a locking bar may hold a tab in place to
prevent rotation movement
of the locked piece.
[0044] Further, it will be appreciated that the ball 620 acts as a bolt,
cam, or similar restrictor
element of a lock to create communication between the generally moveable
housing lock 610
and the generally stationary sleeve lock 630, thereby immobilizing the sleeve
lock 610. Other
bolts or cams, including dogs, collets, pins, bars, or other structure, may be
substituted for the
ball 620 provided that such structure engages or otherwise causes mechanical
communication
between a stationary element and a moveable element, and is removeable from
such engagement
or communication upon movement of the support structure or support element.
[0045] Additionally, the illustrated embodiments show the obstruction in
the passageway is
bypassed by flowing fluids along the exterior of the tubing, but other
arrangements are within the
scope of the present disclosure. For example, the bypass around the
obstruction in the
passageway may be contained within the housing, between a valve seat and the
housing, or other
arrangement that provides fluid communication around the obstruction.
[0046] The embodiments of the present disclosure may be used in both open
hole and
cemented tubing strings. In cemented tubing applications, the well treatments
may be used to
mechanically break, dissolve, or otherwise create a flow path through the
cement connecting the
first and second at least one ports along the outside of the assembly. In
other embodiments, the
first and second at least one port may be connected.
CA 02854073 2014-06-11
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[0047]
While the foregoing is directed to example embodiments of the present
disclosure,
other and further embodiments of the invention may be devised without
departing from the basic
scope thereof, and the scope thereof is determined by the claims that follow.
