U.S. patent application number 14/234390 was filed with the patent office on 2014-09-18 for ball check valve integration to icd.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC. Invention is credited to Jean Marc Lopez.
Application Number | 20140262207 14/234390 |
Document ID | / |
Family ID | 51354453 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140262207 |
Kind Code |
A1 |
Lopez; Jean Marc |
September 18, 2014 |
BALL CHECK VALVE INTEGRATION TO ICD
Abstract
A production sleeve assembly for use downhole comprises a fluid
pathway configured to provide fluid communication between an
exterior of a wellbore tubular and an interior of the wellbore
tubular, a flow restriction disposed in the fluid pathway, and a
valve disposed in series with the flow restriction in the fluid
pathway. The valve comprises: a rupture disk and a plug releasably
engaged in the fluid pathway in series with the rupture disk. The
valve is configured to allow production from the exterior of the
wellbore tubular to the interior of the wellbore tubular through
the chamber without producing past the plug once the rupture disk
is actuated.
Inventors: |
Lopez; Jean Marc; (Plano,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC
Houston
TX
|
Family ID: |
51354453 |
Appl. No.: |
14/234390 |
Filed: |
February 15, 2013 |
PCT Filed: |
February 15, 2013 |
PCT NO: |
PCT/US13/26533 |
371 Date: |
January 22, 2014 |
Current U.S.
Class: |
166/114 |
Current CPC
Class: |
E21B 34/08 20130101;
E21B 34/063 20130101; E21B 2200/04 20200501; Y10T 137/7848
20150401; F16K 15/04 20130101; E21B 43/12 20130101 |
Class at
Publication: |
166/114 |
International
Class: |
E21B 34/06 20060101
E21B034/06 |
Claims
1. A production sleeve assembly for use downhole comprising: a
fluid pathway configured to provide fluid communication between an
exterior of a wellbore tubular and an interior of the wellbore
tubular through a chamber; a flow restriction disposed in the fluid
pathway; and a valve disposed in series with the flow restriction
in the fluid pathway, wherein the valve comprises: a rupture disk;
and a plug releasably engaged in the fluid pathway in series with
the rupture disk, wherein the valve is configured to allow
production from the exterior of the wellbore tubular to the
interior of the wellbore tubular through the chamber without
producing past the plug once the rupture disk is actuated.
2. The assembly of claim 1, wherein the flow restriction comprises
at least one of an inflow control device or an autonomous inflow
control device.
3. The assembly of claim 1, wherein the plug comprises a ball.
4. The assembly of claim 1, wherein the valve is configured to
release the plug when the rupture disk is ruptured and the pressure
within the exterior of the wellbore tubular is greater than the
pressure within the interior of the wellbore tubular.
5. The assembly of claim 1, wherein the plug is configured to at
least partially disintegrate or at least partially dissolve in
response to a fluid flow through the chamber.
6. The assembly of claim 1, wherein the rupture disk comprises a
frangible material.
7. The assembly of claim 1, further comprising a seat, wherein the
plug sealingly engages the seat.
8. The assembly of claim 7, wherein the seat, the chamber, and the
plug comprise a ball type check valve.
9. The assembly of claim 7, wherein the seat comprises a weep hole,
and wherein the weep hole is configured to provide choked fluid
communication past the plug.
10. The assembly of claim 7, wherein the seat comprises a portion
of the flow restriction.
11. The assembly of claims 7, wherein the seat is configured to at
least partially erode in response to a production flow from the
exterior of the wellbore tubular into the interior of the wellbore
tubular.
12.-18. (canceled)
19. A method of changing the flow state of a production sleeve
comprising: pressurizing an interior of a wellbore tubular to a
first pressure, wherein the first pressure is greater than a second
pressure in an exterior of the wellbore tubular; actuating a
rupture disk in response to the first pressure, wherein the rupture
disk is disposed in a fluid pathway between the exterior of a
wellbore tubular and the interior of the wellbore tubular;
maintaining the first pressure within the interior of the wellbore
tubular using a plug, wherein the plug is releasably engaged in the
fluid pathway adjacent the rupture disk; decreasing the pressure in
the interior of the wellbore tubular below the second pressure; and
establishing fluid communication between the exterior of the
wellbore tubular and the interior of the wellbore tubular along the
fluid pathway in response to the decreasing of the pressure in the
interior of the wellbore tubular.
20. The method of claim 19, wherein establishing fluid
communication comprises establishing fluid communication through a
flow restriction disposed in the fluid pathway.
21. The method of claim 19, further comprising; maintaining the
first pressure within the interior of the wellbore tubular using
one or more one-way valves, wherein the one or more one-way valves
are configured to allow fluid flow from the exterior of the
wellbore tubular to the interior of the wellbore tubular while
substantially blocking flow from the interior of the wellbore
tubular to the exterior of the wellbore tubular; and bypassing a
flow restriction.
22. The method of claim 19, further comprising: actuating a second
rupture disk in response to the first pressure, wherein the second
rupture disk is disposed in a second fluid pathway between the
exterior of the wellbore tubular and the interior of the wellbore
tubular; and establishing fluid communication between the exterior
of the wellbore tubular and the interior of the wellbore tubular
along the second fluid pathway in response to the decreasing of the
pressure in the interior of the wellbore tubular.
23. (canceled)
24. The method of claims 19, wherein the plug is releasably engaged
with a seat in the fluid pathway.
25. The method of claim 24, further comprising: flowing a fluid
from the exterior of the wellbore tubular to the interior of the
wellbore tubular along the fluid pathway; and eroding at least a
portion of the seat in response to the fluid flowing through the
fluid pathway.
26. The method of claim 24, wherein the seat comprises a portion of
a flow restriction.
27. The method of claim 19, further comprising: flowing a fluid
from the exterior of the wellbore tubular to the interior of the
wellbore tubular along the fluid pathway; and eroding at least a
portion of the plug in response to the fluid flowing through the
fluid pathway.
28. The method of claim 19, further comprising: removing
substantially the entire rupture disk from the fluid pathway in
response to actuating the rupture disk.
Description
BACKGROUND
[0001] Wellbores are sometimes drilled into subterranean formations
to produce one or more fluids from the subterranean formation. For
example, a wellbore may be used to produce one or more
hydrocarbons. Additional components such as water may also be
produced with the hydrocarbons, though attempts are usually made to
limit water production from a wellbore or a specific interval
within the wellbore. Other components such as hydrocarbon gases may
also be limited for various reasons over the life of a
wellbore.
[0002] Where fluids are produced from a long interval of a
formation penetrated by a wellbore, it is known that balancing the
production of fluid along the interval can lead to reduced water
and gas coning, and more controlled conformance, thereby increasing
the proportion and overall quantity of oil or other desired fluid
produced from the interval. Various devices and completion
assemblies have been used to help balance the production of fluid
from an interval in the wellbore. For example, inflow control
devices (ICD's) have been used in conjunction with well screens to
restrict the flow of produced fluid through the screens for the
purpose of balancing production along an interval. For example, in
a long horizontal wellbore, fluid flow near a heel of the wellbore
may be more restricted as compared to fluid flow near a toe of the
wellbore, to thereby balance production along the wellbore.
SUMMARY
[0003] In an embodiment, a production sleeve assembly for use
downhole comprises a fluid pathway configured to provide fluid
communication between an exterior of a wellbore tubular and an
interior of the wellbore tubular, a flow restriction disposed in
the fluid pathway, and a valve disposed in series with the flow
restriction in the fluid pathway. The valve comprises: a rupture
disk, and a plug releasably engaged in the fluid pathway in series
with the rupture disk. The valve is configured to allow production
from the exterior of the wellbore tubular to the interior of the
wellbore tubular through the chamber without producing past the
plug once the rupture disk is actuated.
[0004] In an embodiment, a production string for use downhole
comprises a housing disposed about a wellbore tubular, where a
chamber is formed between the housing and the wellbore tubular, a
flow restriction disposed in the chamber, and a valve disposed in a
fluid pathway between the chamber and an interior of the wellbore
tubular. The valve comprises a rupture disk, and a plug disposed
adjacent the rupture disk. The valve is configured to substantially
block fluid flow between the interior of the wellbore tubular and
the chamber in a first state, substantially prevent fluid flow from
the interior of the wellbore tubular into the chamber in a second
state, and allow fluid flow between the chamber and the interior of
the wellbore tubular in a third state.
[0005] In an embodiment, a method of changing the flow state of a
production sleeve comprises pressurizing an interior of a wellbore
tubular to a first pressure, where the first pressure is greater
than a second pressure in an exterior of the wellbore tubular,
actuating a rupture disk in response to the first pressure, where
the rupture disk is disposed in a fluid pathway between the
exterior of a wellbore tubular and the interior of the wellbore
tubular, maintaining the first pressure within the interior of the
wellbore tubular using a plug, where the plug is releasably engaged
in the fluid pathway adjacent the rupture disk, decreasing the
pressure in the interior of the wellbore tubular below the second
pressure, and establishing fluid communication between the exterior
of the wellbore tubular and the interior of the wellbore tubular
along the fluid pathway in response to the decreasing of the
pressure in the interior of the wellbore tubular.
[0006] These and other features will be more clearly understood
from the following detailed description taken in conjunction with
the accompanying drawings and claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] For a more complete understanding of the present disclosure
and the advantages thereof, reference is now made to the following
brief description, taken in connection with the accompanying
drawings and detailed description:
[0008] FIG. 1 is a schematic illustration of a wellbore operating
environment which may support the use of at least one embodiment of
a fluid flow control device.
[0009] FIGS. 2A, 2B, and 2C are partial cross-sectional views of a
well screen assembly comprising an embodiment of a fluid flow
control device.
[0010] FIGS. 3A, 3B, and 3C are partial cross-sectional views of a
well screen assembly comprising another embodiment of a fluid flow
control device.
[0011] FIG. 4 is a partial cross-sectional view of a well screen
assembly comprising still another embodiment of a fluid flow
control device.
[0012] FIGS. 5A and 5B are partial cross-sectional views of a well
screen assembly comprising still another embodiment of a fluid flow
control device.
[0013] FIG. 6 is a partial cross-sectional view of a well screen
assembly comprising still another embodiment of a fluid flow
control device.
[0014] FIG. 7A is a schematic illustration of a well system
comprising multiple fluid flow control devices according to one
embodiment.
[0015] FIG. 7B is a schematic illustration of a well system
comprising multiple fluid flow control devices according to another
embodiment.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0016] In the drawings and description that follow, like parts are
typically marked throughout the specification and drawings with the
same reference numerals, respectively. The drawing figures are not
necessarily to scale. Certain features of the invention may be
shown exaggerated in scale or in somewhat schematic form and some
details of conventional elements may not be shown in the interest
of clarity and conciseness. Specific embodiments are described in
detail and are shown in the drawings, with the understanding that
that present disclosure is to be considered an exemplification of
the principles of the invention, and is not intended to limit the
invention to that illustrated and described herein. It is to be
fully recognized that the different teachings of the embodiments
discussed infra may be employed separately or in any suitable
combination to produce desired results.
[0017] Unless otherwise specified, any use of any form of the terms
"connect," "engage," "couple," "attach," or any other term
describing an interaction between elements is not meant to limit
the interaction to direct interaction between the elements and may
also include indirect interaction between the elements described.
In the following discussion and in the claims, the terms
"including" and "comprising" are used in an open-ended fashion, and
thus should be interpreted to mean "including, but not limited to .
. . ". Reference to up or down will be made for purposes of
description with "up," "upper," "upward," or "above" meaning toward
the surface of the wellbore and with "down," "lower," "downward,"
or "below" meaning toward the terminal end of the well, regardless
of the wellbore orientation. The various characteristics mentioned
above, as well as other features and characteristics described in
more detail below, will be readily apparent to those skilled in the
art with the aid of this disclosure upon reading the following
detailed description of the embodiments, and by referring to the
accompanying drawings.
[0018] Well systems may be used to provide a completion
configuration including one or more flow restrictors intended to
balance production along a section of a wellbore. A flow restrictor
may form a part of a well screen assembly and thereby choke fluid
flow between the subterranean formation and the wellbore interior.
Such a well screen assembly may comprise a fluid pathway in series
with the flow restrictor and the wellbore interior.
[0019] During installation, an actuable device can prevent fluid
flow through the fluid pathway. As described herein, the present
system allows for the actuation, after installation, of the
actuable devices and thereby permits fluid flow through the fluid
pathway without the need for physical intervention into the
wellbore. This can be accomplished by delivering pressurized fluid
into the wellbore to act on the actuable device so to permit fluid
flow between the fluid pathway and the wellbore interior. In such
circumstances, the well screen assembly may comprise a valve (e.g.,
a check valve or other one-way valve) to prevent fluid loss into
the formation due to the pressure differential created by the
pressurized fluid. In some cases, a check valve may be used that at
least partially remains in the flow path during production. As a
result, the check valve remaining in the flow path may interfere
with production flow. Accordingly, an integrated valve may be used
that, upon production, is at least partially removed from the fluid
pathway and thus does not interfere with production flow.
[0020] As disclosed herein, the integrated valve assembly
incorporated in a production sleeve assembly for use in a wellbore
may control fluid communication between the wellbore exterior and
the wellbore tubular interior. The production sleeve assembly may
comprise a chamber, a flow control device, and a fluid pathway
providing fluid flow between the chamber and the wellbore tubular
interior via an opening. The integrated valve assembly can comprise
an actuable device disposed within the opening. The production
sleeve assembly can be installed in the well with the actuable
device in its unactuated configuration. In this configuration,
fluid may be substantially prevented from flowing through fluid
pathway. Once the actuable device has been actuated, fluid flow
through the opening may be allowed. Fluid loss from wellbore
tubular interior to the formation is prevented by an integrated
valve, which is part of the integrated valve assembly. The
integrated valve may comprise a valve seat and a valve plug. The
integrated valve is structurally integrated with the fluid pathway
such that, upon production, the plug becomes disengaged and travels
at least partially into the wellbore tubular interior. Since the
plug becomes at least partially cleared from the fluid pathway,
fluid is permitted to flow through the fluid pathway unobstructed
by the plug. Thus, the integrated valve facilitates set-up of the
production assembly without leaving behind structures that may
impair fluid flow through the production sleeve.
[0021] Various configurations of the integrated valve assembly are
possible. In some embodiments, the valve seat is integrated within
the fluid pathway such that it serves as a valve seat while the
plug engages therewith, and later as a flow restrictor (e.g., a
nozzle) when fluid flows therethough. In some embodiments, the plug
engages the valve seat such that, upon production, the plug is
released and travels completely into the wellbore tubular interior,
thereby providing a fluid pathway unobstructed by the plug. In some
embodiments, the plug can be at least partially dissolvable upon
contact with the fluid so upon production, the plug dissolves and
thus leaves the fluid pathway unobstructed.
[0022] The integrated valve can be incorporated into a production
sleeve with an actuable device and disposed in series with a flow
restriction. In some embodiments, the production sleeve can
comprise a check valve in series with a flow restriction and one or
more integrated valves in parallel with the check valve, thereby
providing the ability to test well conditions and select an
appropriate flow path based on such testing. In some embodiments,
the production sleeve can comprise a check valve in series with a
flow restriction and one or more integrated valves in parallel with
the check valve, thereby providing the option to decrease the
resistance of the flow path by bypassing the restriction
device.
[0023] The integrated valve assembly can be incorporated into
various embodiments of well system configurations. In some
embodiments, a plurality of well screen assemblies each comprises a
check valve, and one well screen assembly comprises an integrated
valve. In other embodiments, each well screen assembly, in a string
of well screen assemblies, comprises an integrated valve assembly.
In other embodiments, a string of well screen assemblies may
comprise various configurations incorporating check valves and
integrated valve assemblies to provide for opening, enlarging,
and/or bypassing one or more flow paths. Thus, the integrated valve
assembly disclosed herein provides selective adjustment of a fluid
pathway without removing a flow restriction disposed in the fluid
pathway. Furthermore, the integrated valve assembly provides for an
unobstructed fluid flow path.
[0024] Referring to FIG. 1, shown is an example of a wellbore
operating environment, which may support the use of a flow control
device comprising an integrated valve assembly. As depicted, the
operating environment comprises a workover and/or drilling rig 100
that is positioned on the earth's surface and extends over and
around a wellbore 101 that penetrates a subterranean formation for
the purpose of recovering hydrocarbons. The wellbore 101 may be
drilled into the subterranean formation 103 using any suitable
drilling technique. The wellbore 101 extends substantially
vertically away from the earth's surface over a vertical wellbore
portion 101a, deviates from vertical relative to the earth's
surface over a deviated wellbore portion 101b, and transitions to a
horizontal wellbore portion 101c. In alternative operating
environments, all or portions of a wellbore 101 may be vertical,
deviated at any suitable angle, horizontal, and/or curved. The
wellbore 101 may be a new wellbore, an existing wellbore, a
straight wellbore, an extended reach wellbore, a sidetracked
wellbore, a multi-lateral wellbore, and other types of wellbores
for drilling and completing one or more production zones. Further,
the wellbore 101 may be used for both producing wells and injection
wells.
[0025] A wellbore tubular string 102 may be lowered into the
subterranean formation 103 for a variety of drilling, completion,
workover, treatment, and/or production processes throughout the
life of the wellbore. The embodiment shown in FIG. 1 illustrates
the wellbore tubular 102 in the form of a completion assembly
string disposed in the wellbore. It should be understood that the
wellbore tubular 102 is equally applicable to any type of wellbore
tubulars being inserted into a wellbore including as non-limiting
examples drill pipe, casing, liners, jointed tubing, and/or coiled
tubing. Further, the wellbore tubular may operate in any of the
wellbore orientations (e.g., vertical, deviated, horizontal, and/or
curved) and/or types described herein. In an embodiment, the
wellbore 101 may comprise wellbore casing, which may be cemented
into place in the wellbore.
[0026] In an embodiment, the wellbore tubular string 102 may
comprise a completion assembly string comprising one or more
wellbore tubular types and one or more downhole tools (e.g., zonal
isolation devices, screens, production sleeve, valves, etc.). The
one or more downhole tools may take various forms. For example, a
zonal isolation device 106 may be used to isolate the various zones
within a wellbore and may include, but is not limited to, a packer
(e.g., production packer, gravel pack packer, frac-pac packer,
etc.). In an embodiment, the wellbore tubular string 102 may
comprise a plurality of well screen assemblies 104, which may be
disposed within the horizontal wellbore portion. The zonal
isolation devices 106, may be used between various ones of the well
screen assemblies, for example, to isolate different zones or
intervals along the wellbore from each other.
[0027] The workover and/or drilling rig 100 may comprise a derrick
with a rig floor through which the wellbore tubular 102 extends
downward from the drilling rig 100 into the wellbore 101. The
workover and/or drilling rig 100 may comprise a motor driven winch
and other associated equipment for conveying the wellbore tubular
102 into the wellbore 101 to position the wellbore tubular 102 at a
selected depth. While the operating environment depicted in FIG. 1
refers to a stationary workover and/or drilling rig for conveying
the wellbore tubular within a land-based wellbore, in alternative
embodiments, mobile workover rigs, wellbore servicing units (such
as coiled tubing units), and the like may be used to convey the
wellbore tubular 102 within the wellbore 101. It should be
understood that a wellbore tubular 102 may alternatively be used in
other operational environments, such as within an offshore wellbore
operational environment.
[0028] Referring next to FIGS. 2A, 2B, and 2C, therein is depicted
a fluid flow control device 200 incorporating an integrated valve
215 according to the present invention. Fluid flow control device
200 may be suitably coupled to other similar fluid flow control
devices, seal assemblies, production tubulars or other downhole
tools to form a tubing string as described above. Fluid flow
control device 200 includes a sand control screen section 201 and a
flow restrictor section 202. Sand control screen section 201
includes a suitable sand control screen element or filter element.
The filter element is used to separate at least a portion of any
sand and/or other debris from a fluid that generally flows from an
exterior to an interior of the screen assembly. The filter element
may be of the type known as "wire-wrapped," which is made up of a
wire closely wrapped helically about a wellbore tubular, with a
spacing between the wire wraps being chosen to keep sand and the
like that is greater than a selected size from passing between the
wire wraps. Other types of filters (such as sintered, mesh,
pre-packed, expandable, slotted, perforated, etc.) may also be
used. The filter element may also comprise one or more layers of
the filter material. The flow path can be disposed between the
filter portion and the wellbore tubular to allow a fluid passing
through the filter portion to flow along the outer surface of the
wellbore and into the flow control device. In the illustrated
embodiments, a protective outer shroud 203 having a plurality of
perforations 204 may be positioned around the exterior of the
filter medium.
[0029] Flow restriction section 202 may comprise a first end
comprising an access port 210 in fluid communication with the sand
control screen section 201. Flow restriction section 202 may
comprise a flow restriction 205 generally disposed within fluid
pathway 206 between the access port 210 and the one or more
openings 207. The flow restriction 205 is configured to provide a
desired resistance to fluid flow through the flow restriction 205.
The flow restriction 205 may be selected to provide a resistance
for balancing the production along an interval. Various types of
flow restrictions can be used with the flow control device
described herein. In the embodiment shown in FIGS. 2A, 2B, and 2C,
the flow restriction 205 comprises a nozzle that comprises a
central opening (e.g., an orifice) configured to cause a specified
resistance and pressure drop in a fluid flowing through the flow
restriction. The central opening 208 may have a variety of
configurations from a rounded cross-section, to a cross-section in
which one or more of the first edge or the second edge comprises a
sharp-squared edge. In general, the use of a squared edge at either
the first edge and/or the second edge may result in a greater
pressure drop through the orifice than other shapes. Further, the
use of a squared edge may result in a pressure drop through the
flow restrictor that depends on the viscosity of the fluid passing
through the flow restriction. The use of a squared edge may result
in a greater pressure drop through the flow restrictor for an
aqueous fluid than a hydrocarbon fluid, thereby presenting a
greater resistance to flow for any water being produced relative to
any hydrocarbons (e.g., oil) being produced. Thus, the use of a
central opening comprising a squared edge may advantageously resist
the flow of water as compared to the flow of hydrocarbons. In some
embodiments described herein, a plurality of nozzle type flow
restrictions may be used in series.
[0030] The flow restriction 205 may also comprise one or more
restrictor tubes. The restrictor tubes generally comprise tubular
sections with a plurality of internal restrictions (e.g.,
orifices). The internal restrictions are configured to present the
greatest resistance to flow through the restrictor tube. The
restrictor tubes may generally have cylindrical cross-sections,
though other cross-sectional shapes are possible. The restrictor
tubes may be disposed within the fluid pathway with the fluid
passing through the interior of the restrictor tubes, and the
restrictor tubes may generally be aligned with the longitudinal
axis of the wellbore tubular within the fluid pathway. The
plurality of internal restrictions may then provide the specified
resistance to flow.
[0031] Other suitable flow restrictions may also be used including,
but not limited to, narrow flow tubes, annular passages, bent tube
flow restrictors, helical tubes, and the like. Narrow flow tubes
may comprise any tube having a ratio of length to diameter of
greater than about 2.5 and providing for the desired resistance to
flow. Similarly, annular passages comprise narrow flow passages
that provide a resistance to flow due to frictional forces imposed
by surfaces of the fluid pathway. A bent tube flow restrictor
comprises a tubular structure that forces fluid to change direction
as it enters and flows through the flow restrictor. Similarly, a
helical tube flow restrictor comprises a fluid pathway that forces
the fluid to follow a helical flow path as it flows through the
flow restrictor. The repeated change of momentum of the fluid
through the bent tube and/or helical tube flow restrictors
increases the resistance to flow and can allow for the use of a
larger flow passage that may not clog as easily as the narrow flow
passages of the narrow flow tubes and/or annular passages. Each of
these different flow restriction types may be used to provide a
desired resistance to flow and/or pressure drop for a fluid flow
through the flow restrictor. Since the resistance to flow may
change based on the type of fluid, the type of flow restriction may
be selected to provide the desired resistance to flow for one or
more type of fluid.
[0032] The flow restriction 205 can be subject to erosion and/or
abrasion from fluids passing through the flow restriction.
Accordingly, the flow restriction 205, or at least those portions
contacting the fluid flow can be formed from any suitable erosion
and/or abrasion resistant materials. Suitable materials may
comprise various hard materials such as various steels, tungsten,
niobium, vanadium, molybdenum, silicon, titanium, tantalum,
zirconium, chromium, yttrium, boron, carbides (e.g., tungsten
carbide, silicon carbide, boron carbide), nitrides (e.g., silicon
nitride, boron nitride), oxides, silicides, alloys thereof, and any
combinations thereof. In an embodiment, one or more of these hard
materials may form a portion of a composite material. For example,
the hard materials may form a particulate or discontinuous phase
useful in resisting erosion and/or abrasion, and a matrix material
may bind the hard particulate phase. Suitable matrix materials may
comprise copper, nickel, iron, cobalt, alloys thereof, and any
combination thereof. Since machining hard, abrasion, erosion and/or
wear resistant materials is generally both difficult and expensive,
the flow restrictions may be formed from a metal in a desired
configuration and subsequently one or more portions of the flow
restriction may be treated to provide the desired abrasion, erosion
and/or wear resistance. Suitable surface treatments used to provide
erosion and/or abrasion resistance can include, but are not limited
to, carburizing, nitriding, heat treating, and any combination
thereof. In embodiments in which erosion and/or abrasion is not a
concern, additional suitable materials such as various polymers may
also be used.
[0033] Returning to the embodiment of FIGS. 2A, 2B, and 2C, the
flow restriction 205 may be fixedly engaged within the fluid
pathway 206. For example, the flow restriction 205 may be press
fitted, snap fitted, shrunk-fit, bonded (e.g., adhered, soldered,
welded, brazed, etc.), and/or integrally formed with the housing
209 so as to not be removable from the housing. In some contexts
this may be referred to as being permanently installed within the
housing 209. In an embodiment in which multiple fluid pathways are
disposed in the housing about the wellbore tubular, one or more
flow restrictions may be disposed in each fluid pathway. The design
and type of flow restriction 205 may change for each of the one or
more flow restrictions disposed in each fluid pathway. For example,
the type of flow restrictions in each fluid pathway may each be the
same or different.
[0034] In an embodiment, the design of each of the one or more flow
restrictions 205 disposed in each fluid pathway may also be the
same or different. In an embodiment as shown in FIGS. 2A, 2B, and
2C, where the flow restriction 205 comprises a nozzle type flow
restriction, the configuration (e.g., size, cross-sectional shape,
etc.) of the central opening 208 may determine the resistance to
flow and pressure drop through each flow restriction 205. Each of
the flow restrictions disposed in each fluid pathway may have a
differently sized central opening, thereby providing some flow
restrictions with a lower resistance to flow (e.g., using larger
central openings) than other flow restrictions with a higher
resistance to flow (e.g., using smaller central openings). A
combination of flow restrictions comprising large openings and flow
restrictions comprising small openings may then be used to provide
a desired total flow resistance and/or flow rate through the flow
control device. It should be appreciated that many various numbers
of different sized openings may be provided, and in an embodiment,
each flow restriction 205 may have a differently sized restriction.
Further, one or more additional flow restrictions 205 may be
disposed in line with the flow restrictions. In an embodiment, the
total or overall flow rate and resistance to flow through the flow
control device may be a function of the combination of each of the
individual flow rates and resistances as provided by the plurality
of flow restrictions disposed in the plurality of fluid pathways.
The ability to use combinations of flow restrictions having
different resistances to fluid flow may allow a wide range of total
flow rates and resistances to flow to be selected for a given flow
control device, thereby providing for the ability to balance
production along an interval.
[0035] In the embodiment depicted in FIG. 2A, an actuable device
211 may be disposed within an opening 207 and in series with one or
more flow restrictions 205 in the tubular interior flow path 212.
In certain embodiments, the actuable device 211 may be a pressure
actuated device that is actuated responsive to an increase in
pressure at or above a predetermined level in the interior flow
path 212. For example, the actuable device 211 may be a rupture
disk, burst disk, or shear pin that provides for one-time use. In
the case of a rupture disk, a membrane or actuable disk of the
rupture disk can be engineered to fail at a predetermined pressure
differential threshold across the actuable disk such that exposing
the actuable disk to a pressure differential at or above the
threshold opens the fluid pathway that was blocked by the rupture
disk. Use of such a rupture disk enables a single opening event and
may not allow for resealing without replacing the actuable device.
It should be noted, however, by those skilled in the art that other
types of actuable devices may alternatively be used, such devices
including, but not limited to, valves, sliding sleeves, removable
plugs and the like. In addition, other methods of actuating a
device or otherwise establishing communication through the base
pipe can be used including, but not limited to, hydraulic control
systems, electrical actuators, punch tools and the like. As shown
in FIG. 2C, once actuable device 211 has been actuated, fluid flow
through opening 207 may be allowed. Accordingly, fluid flow control
device 200 may be operated from a no flow configuration (shown in
FIG. 2A) to a flow enabled configuration (shown in FIG. 2C) by
actuating the actuable device 211.
[0036] An integrated valve 215 may be disposed within the housing
209 and may form, together with the actuable device 211, an
integrated valve assembly. In an embodiment, the integrated valve
215 comprises a plug 213 component and a valve seat 214 component
adjacent the opening 207. The valve seat 214 component may form a
portion of an opening 216 (e.g., an orifice) that is integrated
within the fluid pathway 206 such that it serves as a valve seat
while the plug 213 engages therewith (depicted in FIG. 2B), and
later as a flow restrictor (e.g., an orifice type flow restrictor,
a nozzle type flow restrictor, a narrow tube, etc.) when fluid
flows therethrough (depicted in FIG. 2C). The plug 213 may be
configured to engage with the valve seat 214 such that the plug 213
at least partially blocks the opening 216. As a result, the
engagement of the valve 215 prevents fluid loss into the formation
103 when pressure within interior flow path 212 exceeds that of the
formation 103, for example during actuation of the actuable device
211.
[0037] As shown in FIGS. 2A, 2B, and 2C, an integrated valve 215
can comprise a plug 213 shaped as a ball, which engages the valve
seat 214 by becoming seated therein. However, those skilled in the
art will recognize that other types of plugs may be used. For
example, the plug 213 can comprise a temporary plug that sealingly
engages the valve seat 214. In such configuration, the plug 213 can
include a weep hole therethrough to allow a pressure differential
to form across the actuable device and thus enable actuation
thereof.
[0038] In operation, fluid flow control device 200 is installed
within the well with the actuable device 211 in its unactuated
configuration (as shown in FIG. 2A). In this configuration,
substantially no fluid is able to flow through fluid flow control
device 200. Upon actuation, the pressurized fluid within the
interior flow path 212 may create a pressure differential across
the actuable device 211 above a threshold, thereby causing its
actuable device 211 to fail. The actuation of the actuable device
211 thus permits fluid flow through the opening 207. Upon actuation
of the actuable device 211, when the pressure within the interior
flow path 212 exceeds that within the fluid flow control device
200, the plug 213 becomes engaged (e.g., sealingly engaged) in the
valve seat 214, thereby preventing fluid loss into the formation
103. When the pressure within the fluid flow control device 200
exceeds that within the interior flow path 212 (e.g., during
production), the plug 213 can be released from valve seat 214 (as
depicted in FIG. 2C). As can be seen from FIGS. 2A-2C, the plug 213
may be configured to travel from the valve seat 214 at least
partially through the opening 207 and into the interior flow path
212. In an embodiment, upon production the plug 213 is entirely
released through the opening 207. Since the plug 213 completely
clears the fluid pathway, the fluid may be allowed to travel to the
interior flow path 212 unobstructed by the plug 213.
[0039] Referring next to FIGS. 3A, 3B, and 3C, therein is depicted
an embodiment wherein at least one component of the integrated
valve assembly 211, 313, 214 at least partially dissolves or
erodes. In some embodiments, a component may dissolve upon contact
with a fluid, such as a hydrocarbon fluid, an aqueous fluid, and/or
a solvent. In some embodiments, a component may erode throughout
exposure to materials, such as an abrasive or erosive material in a
fluid (e.g., sand or proppant in a fluid). In the particular
embodiment illustrated in FIGS. 3A, 3B, and 3C, the at least one
component of the integrated valve assembly 211, 313, 214 that
dissolves or erodes comprises a plug 313 that dissolves upon
contact with a hydrocarbon fluid.
[0040] A dissolving or eroding plug 313 may provide various
benefits. For example, the ability to dissolve may serve as a
precautionary feature to ensure the plug 313 is released from the
fluid flow control device 300. Thus, even when the plug 313 is
dimensioned to pass through the opening 207, in an event where the
plug 313 does not make its way out from within the housing 209, the
plug 313 may at least partially dissolve upon contact with the
fluid. As another example, the ability to dissolve or erode may
serve to maintain the interior flow path 212 clear of obstructions
or at least with a reduced amount of obstructions. In such cases,
even when the plug 313 successfully passes through the opening 207,
the plug 313 may dissolve or erode within the interior flow path
212, which may limit the amount of debris in the wellbore. As
another example, and as depicted in FIGS. 3A-3C, the ability to
dissolve provides a plug 313 with the capability to change its size
according to its functionality. For example, those skilled in the
art can appreciate that if the actuation of the actuable device
requires a substantially high pressure, then a relatively small
sized actuable device 211 may be used. However, it may be
beneficial to include a larger valve seat/nozzle 214 for an
effective flow path during production. By configuring the plug 313
to dissolve, the plug 313 can be large enough to engage the valve
seat 214 during actuation of the device (as shown in FIG. 3B), and
later decrease in size in order to travel through the opening 207
subsequent actuation of actuable device 211 (as shown in FIG.
3C).
[0041] Other features of the integrated valve 211, 313, 214,
besides or in addition to the plug 313, may dissolve or erode. For
example, the valve seat 214 may dissolve or erode. Since the valve
seat 214 serves as a valve seat while the plug 313 engages
therewith, and may later serve as a nozzle when fluid flows through
the opening 216, its dimensions may be altered according to its
changing functionality. For example, when valve seat 214 operates
as a valve seat, the opening 216 may be dimensioned small enough to
maintain a sealing engagement with the plug 313. Upon production,
however, the valve seat 214 may serve as a nozzle and the valve
seat 214 may dissolve or erode so that the size of the opening 216
increases in size fluid flow, thereby facilitating fluid flow
therethrough.
[0042] Additionally, one or more portions of the actuable device
211 may be configured to dissolve or erode, which can serve various
beneficial outcomes. For example, a dissolving or eroding actuable
device 211 may serve as a precautionary feature to ensure that the
plug 313 is successfully released from the fluid flow control
device 300. Therefore, in the event that the pressurized fluid does
not succeed in fully actuating the actuable device 211, the
actuable device 211 may at least partially dissolve or erode,
thereby releasing the plug 313 into the interior flow path 212. As
another example, the ability of the actual device 211 to dissolve
or erode may serve to limit the amount of debris within the
interior flow path 212. Thus, even if the actuable device 211
clears the opening 207 without the need to dissolve or erode, it
may travel to the interior flow path 212 where it dissolves or
erodes therein. As a result, the dissolving or eroding capability
may prevent contamination of the interior flow path 212.
[0043] As another example, an actuable device 211 may dissolve or
erode in order to provide an opening 207 that enlarges over time.
In such case, actuation of the actuable device 211 may allow the
plug 313 to travel into the interior flow path 212. However, a
portion of the actuable device 211 may endure the actuation and
remain within the opening 207, thereby providing the opening 207
with a first dimension. Afterwards, the remaining portion of the
actuable device 211 may dissolve or erode, thereby providing the
opening 207 with a second, larger dimension. As a result, the flow
path through the opening 207 increases throughout the life of the
assembly, providing a choked flow rate at the beginning of
production and providing an increasing flow rate thereafter.
[0044] In an embodiment of fluid flow control device 400, as shown
in FIG. 4, a check valve 428 may be disposed in series with a flow
restriction 417, and a first integrated valve 414, 416 and at least
one second integrated valve 418, 420 may be disposed in parallel
with the check valve 428. In the FIG. 4 embodiment, actuable
devices 411, 412, 413 are in series with the check valve 428 and
with each integrated valve. For example, each actuable device may
actuate at a different pressure differential 414, 416 & 418,
420. By way of example only, the first actuable device 411 in
series with the check valve may fail at a first pressure
differential (e.g., 1,000 psi), the second actuable device 412 in
series with the first integrated valve 414, 416 may fail at a
second pressure differential (e.g., 2,000 psi), and the third
actuable device 413 in series with the second integrated valve 418,
420 may fail at a third pressure differential (e.g., 3,000 psi);
wherein the second pressure differential is greater than the first
pressure differential, and the third pressure differential is
greater than the second pressure differential.
[0045] In operation, the check valve provides means for testing the
conditions within the assembly so the user can determine the
appropriate flow path configuration and open fluid pathways
accordingly. For example, the user may provide 1,000 psi of fluid
pressure differential across the first actuable device to actuate
the first actuable device and test the conditions within the
assembly. If, upon testing, the user determines the appropriate
fluid pathway is one requiring a higher fluid resistance, then at
least 2,000 psi of fluid pressure differential can be delivered
downstream to actuate the second actuable device and not actuate
the third actuable device. Alternatively, if, upon testing, the
user determines the appropriate fluid pathway is one requiring a
lower fluid resistance, then at least 3,000 psi of fluid pressure
differential can be delivered downstream to open both the second
and the third openings. As is apparent to one of ordinary skill in
the art, the assembly can comprise various arrangements comprising
various quantities and/or types of check valves and integrated
valve structures.
[0046] Referring next to FIGS. 5A and 5B, therein depicted is an
embodiment of fluid flow control device 500 comprising a check
valve 528 in series with a first actuable device 511, and an
integrated valve 215 in series with a second actuable device 512.
The second actuable device 512 comprises a different actuation
threshold, which may be greater or less than the actuation
threshold of the first actuable device 511. Also, the actuation
threshold for the second actuable device 512 may increase at larger
diameters. For example, as illustrated in FIGS. 5A and 5B, the
first actuable device 511 can be configured to actuate at about a
1,000 psi pressure differential; while the second actuable device
512 has a first diameter D1 configured to actuate at about a 2,000
psi pressure differential, has a second diameter D2 configured to
actuate at about a 3,000 psi pressure differential; and has a third
diameter D3 configured to fail at about 4,000 psi pressure
differential.
[0047] In an embodiment, the check valve 528 may provide a means
for testing the conditions within the wellbore 101, which may allow
for the determination the appropriate flow path configuration. For
example, the user may provide 1,000 psi of fluid pressure
differential across the first actuable device 511 to actuate the
first actuable device 511 and test the conditions within wellbore
101. If, upon testing, the user determines the appropriate fluid
pathway is one requiring a higher fluid resistance, about 2,000 psi
of fluid pressure differential can be delivered downstream to
actuate second actuable device at the second diameter D2 and thus
create a smaller opening. Alternatively, if upon testing, the user
determines the appropriate fluid pathway is one requiring lower
fluid resistance, about 4,000 psi of fluid pressure differential
can be delivered to actuate the second actuable device at the third
diameter D3 and thus create a larger opening.
[0048] As shown in FIG. 5A, in some embodiments flow restriction
519 may be configured integrally with the integrated valve seat
518. In other embodiments, flow restriction may be configured as a
separate unit and in series with the integrated valve seat and
nozzle. Such incorporation between the integrated valve and the
flow restriction may apply to any of the various embodiments of the
current disclosure.
[0049] Over the life of the well, it may become desirable to change
the resistance to flow associated with the fluid flow path. In such
circumstances, the user may selectively tailor the flow path
resistance by altering the flow path configuration during
production. Referring now to FIG. 6, therein depicted is an
embodiment of a fluid flow control device 600 comprising one or
more check valves 628, 629 in series with a flow restrictions 605,
606, and one or more integrated valves 618 in parallel with the
flow restrictions 605, 606. More particularly, FIG. 6 illustrates
an embodiment comprising two check-valves 628, 629 each in series
with first and second flow restriction 605 606, and one integrated
valve 618 in parallel with both the first and second flow
restrictions 605, 606. The first actuable device 611 is in series
with the first check valve 628 and is configured to actuate at a
first pressure differential (e.g., 1,000 psi), the second actuable
device 612 is in series with the second check valve 629 and is
configured to actuate at a second pressure differential (e.g.,
2,000 psi), and the third actuable device 613 is in series with the
integrated valve 618 and is configured to actuate at a third
pressure differential (e.g., 3,000 psi), wherein the second
pressure differential is greater than the first pressure
differential, and the third pressure differential is greater than
the second pressure differential.
[0050] In operation, the first pressure differential (e.g., 1,000
psi) may be delivered to the system, thereby rupturing the first
actuable device 611 and creating a flow path through both first and
second flow restrictions 605, 606. At a later time, when it becomes
desirable to increase the flow, the fluid pressure differential may
again be increased above the second pressure differential (e.g.,
2,000 psi). Consequently, the second actuable device 612 will
rupture, creating a flow path through the second restriction device
606 and substantially bypassing the first flow restriction 605.
Subsequently, the third pressure differential (e.g., 3,000 psi) may
be delivered to rupture the third actuable device 613. Thus, both
the first and second flow restrictions 605, 606 will be bypassed
and the fluid will flow through opening in the valve seat 619. As
seen in FIG. 6, the third actuable device is in series with
integrated valve 618. As a result, upon production, the fluid flow
path will become at least partially unobstructed by the plug
620.
[0051] Referring now to FIGS. 7A and 7B, shown are exemplary well
systems 700, 800 intended to illustrate the various configurations
in which to possibly incorporate the integrated valve assembly. The
system may comprise a plurality of well screen assemblies
comprising various configurations. The well screen assemblies may
each be configured so to provide an appropriate pressure drop,
according to their placement in the wellbore and according to other
conditions affecting fluid flow. Thus, within a system comprising a
plurality of well screen assemblies, some of the assemblies may
provide a large pressure drop while other assemblies may be closed,
open or provide a lower pressure drop. In an embodiment, some of
the assemblies may allow the user to selectively adjust the flow
resistance by altering the flow path configuration.
[0052] Turning now to FIG. 7A, therein depicted is an embodiment
comprising a plurality of well screen assemblies 701, 702, and 703,
each comprising a check valve 728, 729, and 730 in series with a
restriction device 721, 722, and 723 and an actuable device 717,
718, and 719, and a well screen assembly 704 comprising an
integrated valve 215 in series with a restriction device 724 and an
actuable device 720. The plurality of well screen assemblies is
configured such that the well screen assembly 704 comprising the
integrated valve 215 also comprises the actuable device 720 with
the highest actuation threshold. For example, the actuable devices
may be rupture disks. In such an embodiment, first actuable device
717 may actuate at a first actuation threshold (e.g., about a 1,000
psi pressure differential), the second actuable device 718 may
actuate at a second actuation threshold (e.g., at about a 2,000 psi
pressure differential), the third actuable device 719 may actuate
at a third actuation threshold (e.g., at about a 3,000 psi pressure
differential), and a fourth actuable device 720 may actuate at a
fourth actuation threshold (e.g., at about a 4,000 psi pressure
differential).
[0053] In operation, the first actuation threshold (e.g., about a
1,000 psi pressure differential) may be delivered to the system,
thereby actuating the first rupture disk 717 and creating a flow
path through the first well screen assembly 701. At a later time,
when it becomes desirable to increase the fluid flow, the second
actuation threshold may be delivered to the system (e.g., about a
2,000 psi pressure differential). Consequently, the second rupture
disk 718 may actuate, creating a flow path through both the first
701 and the second 702 well screen assemblies. This same process
may be repeated to actuate the third rupture disk 719. At a
subsequent time, the fourth actuation threshold (e.g., about a
4,000 psi pressure differential) may be delivered to actuate the
fourth rupture disk 720. Thus, fluid communication may be
established through fluid pathway. As seen in FIG. 7A, the fourth
rupture disk 720 is in series with an integrated valve 215. As a
result, upon production through well screen assembly, the fluid
flow path may become at least partially unobstructed by the plug
213. Therefore, the integrated valve 215 may provide an at least
partially unobstructed flow path at the time when improving the
flow rate is desired.
[0054] Turning to FIG. 7B, therein depicted is an embodiment of a
plurality of well screen assemblies 801, 802, and 803, wherein each
well screen assembly 801, 802, and 803 comprises an integrated
valve 843, 848 & 844, 849 & 845, 850 in series with a
restriction device 828, 851, 852 and an actuable device 818, 819,
820. The actuable devices 818, 819, 820 may each be rupture disks
that actuate upon the delivery of the same or similar actuation
threshold thereto. In operation, the user may deliver the actuation
threshold (e.g., a common pressure differential), thereby rupturing
all of the rupture disks 818, 819, 820. Because each integrated
valve 843, 848 & 844, 849 & 845, 850 is directly proximate
the corresponding opening 860-862, the engagement of the plugs
843-845 with the valve seats 848-850 during actuation of actuable
devices 818-820 ensures that the pressure of the fluid is preserved
along the wellbore tubular string. As a result, the system
facilitates the actuation of numerous actuable devices 818-820
along one or more portions of a wellbore tubular string using a
single actuation threshold. Furthermore, the integrated valves 843,
848 & 844, 849 & 845, 850 may provide an at least partially
unobstructed flow path upon production.
[0055] In operation, the fluid flow control device may be installed
within the well with each actuable device in its unactuated
configuration. In this configuration, fluid communication through
the fluid pathway may be prevented. To enable fluid communication
through fluid flow path, the wellbore tubular interior may be
pressurized to create a first pressure, wherein the first pressure
is greater than a second pressure in an exterior of the wellbore
tubular. Such pressurization creates a pressure differential across
an actuable device disposed in the fluid pathway between the
exterior of the wellbore tubular and the interior of the wellbore
tubular. When the pressure differential is at or above a pressure
differential threshold, the actuable device may be actuated. In
order to maintain the first pressure within the wellbore tubular
interior, the plug releasably engages a valve seat in the fluid
pathway. Such engagement between plug and valve seat may also
prevent fluid loss into the formation.
[0056] Subsequent to the actuation of the actuable device, the
pressure within the wellbore tubular interior may decrease such
that the pressure within the wellbore tubular interior is less than
the pressure within the wellbore exterior. As a result, fluid may
flow from the wellbore exterior to the wellbore tubular interior
via fluid pathway. The plug that is engaged with the seat may be
released from the valve seat in response to the fluid flow from the
formation to the interior of the wellbore tubular. The plug, valve
seat, actuable device, and opening may be configured such that,
upon release of the plug, the plug disengages the valve seat and
travels at least partially through the opening into the wellbore
tubular interior. Since the plug at least partially clears the
fluid pathway, the fluid produces at least partially unobstructed
by the plug.
[0057] The valve seat may be integrated with the fluid pathway such
that it functions as a valve seat when the plug engages therewith
and later, upon production, it functions as a flow restrictor
(e.g., a nozzle) for the fluid to flow therethrough. The flow
restrictor configuration may comprise a central opening (e.g., an
orifice) that is integrated within the fluid pathway such that it
causes a specified resistance and pressure drop in the fluid
flowing through the flow restrictor.
[0058] It may be desirable to decrease the pressure drop created by
the flow restrictors over time to account for the decline in
reservoir pressure due to depletion of the reservoir. Accordingly,
the valve seat/nozzle may be at least partially erodible. In this
embodiment, as the valve seat/nozzle erodes, the orifice expands,
thereby decreasing the pressure drop in the fluid flowing through
the flow restrictor. Accordingly, by establishing a fluid pathway
that gradually decreases its resistance, this embodiment allows for
the progressive reduction in the pressure drop experienced by
fluids passing therethrough.
[0059] Having described various systems and methods herein, various
embodiments may include, but are not limited to:
[0060] In a first embodiment, a production sleeve assembly for use
downhole comprises a fluid pathway configured to provide fluid
communication between an exterior of a wellbore tubular and an
interior of the wellbore tubular through a chamber, a flow
restriction disposed in the fluid pathway, and a valve disposed in
series with the flow restriction in the fluid pathway. The valve
comprises a rupture disk, and a plug releasably engaged in the
fluid pathway in series with the rupture disk. The valve is
configured to allow production from the exterior of the wellbore
tubular to the interior of the wellbore tubular through the chamber
without producing past the plug once the rupture disk is actuated.
In a second embodiment, the flow restriction of the first
embodiment may comprise at least one of an inflow control device or
an autonomous inflow control device. In a third embodiment, the
plug of the first or second embodiment may comprise a ball. In a
fourth embodiment, the valve of any of the first to third
embodiments may be configured to release the plug when the rupture
disk is ruptured and the pressure within the exterior of the
wellbore tubular is greater than the pressure within the interior
of the wellbore tubular. In a fifth embodiment, the plug of any of
the first to fourth embodiments may be configured to at least
partially disintegrate or at least partially dissolve in response
to a fluid flow through the chamber. In a sixth embodiment, the
rupture disk of any of the first to fifth embodiments may comprise
a frangible material. In a seventh embodiment, the assembly of any
of the first to sixth embodiments may also include a seat, and the
plug may sealingly engage the seat. In an eighth embodiment, the
seat, the chamber, and the plug of the seventh embodiment may
comprise a ball type check valve. In a ninth embodiment, the seat
of the seventh or eighth embodiments may comprise a weep hole, and
the weep hole may be configured to provide choked fluid
communication past the plug. In a tenth embodiment, the seat of any
of the seventh to ninth embodiments may comprise a portion of the
flow restriction. In an eleventh embodiment, the seat of any of the
seventh to tenth embodiments may be configured to at least
partially erode in response to a production flow from the exterior
of the wellbore tubular into the interior of the wellbore
tubular.
[0061] In a twelfth embodiment, a production string for use
downhole comprises a housing disposed about a wellbore tubular, a
chamber formed between the housing and the wellbore tubular, a flow
restriction disposed in the chamber, and a valve disposed in a
fluid pathway between the chamber and an interior of the wellbore
tubular. The valve comprises: a rupture disk, and a plug disposed
adjacent the rupture disk. The valve is configured to substantially
block fluid flow between the interior of the wellbore tubular and
the chamber in a first state, substantially prevent fluid flow from
the interior of the wellbore tubular into the chamber in a second
state, and allow fluid flow between the chamber and the interior of
the wellbore tubular in a third state. In a thirteenth embodiment,
the valve of the twelfth embodiment may be configured to transition
from the first state to the third state in response to a pressure
increase in the interior of the wellbore tubular. In a fourteenth
embodiment, the valve of the twelfth or thirteenth embodiments may
be in series with the flow restriction. In a fifteenth embodiment,
the production string of the fourteenth embodiment may also include
at least one one-way valve in series with the flow restriction, and
the at least one one-way valve may be configured to allow fluid
flow from the exterior of the wellbore tubular to the interior of
the wellbore tubular while substantially preventing flow from the
interior of the wellbore tubular to the exterior of the wellbore
tubular. In a sixteenth embodiment, the production string of the
twelfth or thirteenth embodiments may also include at least one
one-way valve in series with the flow restriction, and the one-way
valve may be configured to allow flow from the exterior of the
wellbore tubular to the interior of the wellbore tubular while
substantially preventing flow from the interior of the wellbore
tubular to the exterior of the wellbore tubular, and the valve may
be disposed in parallel with the flow restriction. In a seventeenth
embodiment, the valve of the sixteenth embodiment may be configured
to provide a flow path bypassing the flow restriction when the
valve is in the third state. In an eighteenth embodiment, the
production string of any of the twelfth to seventeenth embodiments
may also include a filter media, and a fluid pathway into the
chamber may pass through the filter media.
[0062] In a nineteenth embodiment, a method of changing the flow
state of a production sleeve comprises pressurizing an interior of
a wellbore tubular to a first pressure, wherein the first pressure
is greater than a second pressure in an exterior of the wellbore
tubular, actuating a rupture disk in response to the first
pressure, maintaining the first pressure within the interior of the
wellbore tubular using a plug, decreasing the pressure in the
interior of the wellbore tubular below the second pressure, and
establishing fluid communication between the exterior of the
wellbore tubular and the interior of the wellbore tubular along the
fluid pathway in response to the decreasing of the pressure in the
interior of the wellbore tubular. The rupture disk is disposed in a
fluid pathway between the exterior of a wellbore tubular and the
interior of the wellbore tubular, and the plug is releasably
engaged in the fluid pathway adjacent the rupture disk. In a
twentieth embodiment, establishing fluid communication in the
nineteenth embodiment may comprise establishing fluid communication
through a flow restriction disposed in the fluid pathway. In a
twenty first embodiment, the method of the nineteenth or twentieth
embodiments may also include maintaining the first pressure within
the interior of the wellbore tubular using one or more one-way
valves, and bypassing a flow restriction. The one or more one-way
valves may be configured to allow fluid flow from the exterior of
the wellbore tubular to the interior of the wellbore tubular while
substantially blocking flow from the interior of the wellbore
tubular to the exterior of the wellbore tubular. In a twenty second
embodiment, the method of any of the nineteenth to twenty first
embodiments may also include actuating a second rupture disk in
response to the first pressure, and establishing fluid
communication between the exterior of the wellbore tubular and the
interior of the wellbore tubular along the second fluid pathway in
response to the decreasing of the pressure in the interior of the
wellbore tubular. The second rupture disk may be disposed in a
second fluid pathway between the exterior of the wellbore tubular
and the interior of the wellbore tubular. In a twenty third
embodiment, the method of any of the nineteenth to twenty first
embodiments may also include actuating a second rupture disk in
response to the first pressure, and the second rupture disk may be
disposed in the fluid. In a twenty fourth embodiment, the plug of
the nineteenth to twenty third embodiments may be releasably
engaged with a seat in the fluid pathway. In a twenty fifth
embodiment, the method of the twenty fourth embodiment may also
include flowing a fluid from the exterior of the wellbore tubular
to the interior of the wellbore tubular along the fluid pathway,
and eroding at least a portion of the seat in response to the fluid
flowing through the fluid pathway. In a twenty sixth embodiment,
the seat of the twenty fourth or twenty fifth embodiments may
comprise a portion of a flow restriction. In a twenty seventh
embodiment, the method of any of the nineteenth to twenty fourth
embodiments may also include flowing a fluid from the exterior of
the wellbore tubular to the interior of the wellbore tubular along
the fluid pathway, and eroding at least a portion of the plug in
response to the fluid flowing through the fluid pathway. In a
twenty eighth embodiment, the method of any of the nineteenth to
twenty seventh embodiments may also include removing substantially
the entire rupture disk from the fluid pathway in response to
actuating the rupture disk.
[0063] At least one embodiment is disclosed and variations,
combinations, and/or modifications of the embodiment(s) and/or
features of the embodiment(s) made by a person having ordinary
skill in the art are within the scope of the disclosure.
Alternative embodiments that result from combining, integrating,
and/or omitting features of the embodiment(s) are also within the
scope of the disclosure. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a
numerical range with a lower limit, R.sub.l, and an upper limit,
R.sub.u, is disclosed, any number falling within the range is
specifically disclosed. In particular, the following numbers within
the range are specifically disclosed:
R=R.sub.l+k*(R.sub.u-R.sub.l), wherein k is a variable ranging from
1 percent to 100 percent with a 1 percent increment, i.e., k is 1
percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50
percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97
percent, 98 percent, 99 percent, or 100 percent. Moreover, any
numerical range defined by two R numbers as defined in the above is
also specifically disclosed. Use of the term "optionally" with
respect to any element of a claim means that the element is
required, or alternatively, the element is not required, both
alternatives being within the scope of the claim. Use of broader
terms such as comprises, includes, and having should be understood
to provide support for narrower terms such as consisting of,
consisting essentially of, and comprised substantially of.
Accordingly, the scope of protection is not limited by the
description set out above but is defined by the claims that follow,
that scope including all equivalents of the subject matter of the
claims. Each and every claim is incorporated as further disclosure
into the specification and the claims are embodiment(s) of the
present invention.
* * * * *