U.S. patent application number 13/434099 was filed with the patent office on 2013-10-03 for method and system for running barrier valve on production string.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is Raymond A. Frisby, Donald Lauderdale, Roy N. Nelson, Jeffrey S. Phillips. Invention is credited to Raymond A. Frisby, Donald Lauderdale, Roy N. Nelson, Jeffrey S. Phillips.
Application Number | 20130255961 13/434099 |
Document ID | / |
Family ID | 48091882 |
Filed Date | 2013-10-03 |
United States Patent
Application |
20130255961 |
Kind Code |
A1 |
Frisby; Raymond A. ; et
al. |
October 3, 2013 |
METHOD AND SYSTEM FOR RUNNING BARRIER VALVE ON PRODUCTION
STRING
Abstract
A completion system, including a lower completion initially
fluidly open. A production string is included having a removable
plug configured to impede fluid flow through the production string.
The removable plug is run in with the production string. An
intermediate completion assembly is included that couples the lower
completion to the production string. The intermediate completion
assembly has a packer device and a barrier valve. The packer device
is operatively arranged to be set by pressurizing fluid in the
production string against the removable plug. The barrier valve is
operatively arranged for selectively impeding fluid flow between
the production string and the lower completion after the removable
plug is removed. A method of completing a borehole is also
included.
Inventors: |
Frisby; Raymond A.;
(Houston, TX) ; Phillips; Jeffrey S.; (The
Woodlands, TX) ; Nelson; Roy N.; (Houston, TX)
; Lauderdale; Donald; (Cypress, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Frisby; Raymond A.
Phillips; Jeffrey S.
Nelson; Roy N.
Lauderdale; Donald |
Houston
The Woodlands
Houston
Cypress |
TX
TX
TX
TX |
US
US
US
US |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
48091882 |
Appl. No.: |
13/434099 |
Filed: |
March 29, 2012 |
Current U.S.
Class: |
166/373 ;
166/106; 166/192; 166/376 |
Current CPC
Class: |
E21B 43/04 20130101;
E21B 33/127 20130101; E21B 34/06 20130101; E21B 34/14 20130101;
E21B 33/12 20130101; E21B 43/26 20130101 |
Class at
Publication: |
166/373 ;
166/192; 166/106; 166/376 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 34/06 20060101 E21B034/06 |
Claims
1. A completion system, comprising: a lower completion initially
fluidly open; a production string having a removable plug
configured to impede fluid flow through the production string, the
removable plug being run in with the production string; and an
intermediate completion assembly coupling the lower completion to
the production string, the intermediate completion assembly having
a packer device and a barrier valve, the packer device operatively
arranged to be set by pressurizing fluid in the production string
against the removable plug, the barrier valve operatively arranged
for selectively impeding fluid flow between the production string
and the lower completion after the removable plug is removed.
2. The completion system of claim 1, wherein the removable plug is
operatively arranged to be removed by exposure to a downhole
fluid.
3. The completion system of claim 1, wherein the downhole fluid
comprises brine, acid, water, oil, or a combination including at
least one of the foregoing.
4. The completion system of claim 1, wherein the production string
comprises an artificial lift system.
5. The completion system of claim 1, wherein the production string
includes at least one component prohibiting passage of a plugging
implement therethrough.
6. The completion system of claim 1, wherein the barrier valve is
operatively arranged to be transitionable to an open position when
engaged with the upper completion string and transitioning to a
closed position via the upper completion string when the upper
completion string is pulled out of the borehole.
7. The completion system of claim 1, further comprising a
subsequent intermediate assembly stacked with the intermediate
completion assembly, the subsequent intermediate assembly having a
subsequent barrier valve and a subsequent packer device for
functionally replacing the intermediate completion assembly.
8. The completion system of claim 7, wherein the intermediate
completion assembly is engaged between the subsequent intermediate
assembly and the lower completion and the subsequent intermediate
assembly is engaged between the intermediate completion assembly
and the production string.
9. The completion system of claim 8, wherein the production string
includes a first tool operatively arranged for enabling the
subsequent barrier valve to transition between open and closed
positions and the subsequent intermediate assembly is arranged with
a second tool for holding the barrier valve in its open position
while the subsequent intermediate completion assembly is engaged
with the first intermediate assembly.
10. The completion system of claim 1, wherein the intermediate
completion assembly includes a shroud enclosing a housing of the
barrier valve.
11. A method of completing a borehole comprising: running a
production string having a removable plug disposed therewith
downhole, an intermediate completion assembly disposed with the
production string; coupling the production string to a lower
completion with the intermediate completion assembly, the lower
completion initially fluidly open; impeding fluid flow between the
production string and the lower completion with the removable plug;
setting a packer device by pressurizing fluid in the production
string against the removable plug; removing the removable plug; and
impeding fluid flow between the production string and the lower
completion with a barrier valve of the intermediate completion
assembly.
12. The method of claim 11, further comprising exposing the
removable plug to a downhole fluid for removing the removable
plug.
13. The method of claim 11, wherein the downhole fluid comprises
brine, acid, water, oil, or a combination including at least one of
the foregoing.
14. The method of claim 11, wherein the production string comprises
an artificial lift system.
15. The method of claim 11, wherein the production string includes
at least one component prohibiting passage of a plugging implement
therethrough.
16. The method of claim 11, wherein the barrier valve is
operatively arranged to be transitionable to an open position when
engaged with the upper completion string and transitioning to a
closed position via the upper completion string when the upper
completion string is pulled out of the borehole.
17. The method of claim 11, further comprising running in a
subsequent intermediate assembly and stacking the subsequent
intermediate assembly with the intermediate completion assembly,
the subsequent intermediate assembly having a subsequent barrier
valve and a subsequent packer device for functionally replacing the
intermediate completion assembly.
18. The system of claim 17, wherein the intermediate completion
assembly is engaged between the subsequent intermediate assembly
and the lower completion and the subsequent intermediate assembly
is engaged between the intermediate completion assembly and the
production string.
19. The system of claim 18, wherein the production string includes
a first tool operatively arranged for enabling the subsequent
barrier valve to transition between open and closed positions and
the subsequent intermediate assembly is arranged with a second tool
for holding the barrier valve in its open position while the
subsequent intermediate completion assembly is engaged with the
first intermediate assembly.
Description
BACKGROUND
[0001] Current practice for completing downhole structures,
particularly deepwater wells, involves stimulating, hydraulic
fracturing, frac packing and/or gravel packing one or more zones
and then landing a fluid isolation valve, typically a ball valve
system, above the treated zones. The fluid isolation valve
temporarily blocks fluid flow so that an upper completion string
can be run and connect the treated zones to surface for enabling
production after the fluid isolation valve is opened. Although such
systems do generally work for their intended purposes, they are not
without limitations. For example, these known ball-type fluid
isolation valves do not provide an efficient and reliable system
for periodically replacing portions of the upper completion, and
may require wireline intervention, hydraulic pressuring, or the
running and/or manipulation of a designated tool to control the
fluid isolation valve. For example, artificial lift systems (e.g.,
electric submersible pumping systems or ESPs), are increasingly
desirable, particularly for use in deepwater wells. Accordingly,
advances in downhole valve technology, at times referred to as
"mechanical barriers", particularly for deepwater wells and/or for
enabling more reliable and efficient replacement of upper
completion systems and components, are always well received by the
industry.
SUMMARY
[0002] A completion system, including a lower completion initially
fluidly open; a production string having a removable plug
configured to impede fluid flow through the production string, the
removable plug being run in with the production string; and an
intermediate completion assembly coupling the lower completion to
the production string, the intermediate completion assembly having
a packer device and a barrier valve, the packer device operatively
arranged to be set by pressurizing fluid in the production string
against the removable plug, the barrier valve operatively arranged
for selectively impeding fluid flow between the production string
and the lower completion after the removable plug is removed.
[0003] A method of completing a borehole including running a
production string having a removable plug disposed therewith
downhole, an intermediate completion assembly disposed with the
production string; coupling the production string to a lower
completion with the intermediate completion assembly, the lower
completion initially fluidly open; impeding fluid flow between the
production string and the lower completion with the removable plug;
setting a packer device by pressurizing fluid in the production
string against the removable plug; removing the removable plug; and
impeding fluid flow between the production string and the lower
completion with a barrier valve of the intermediate completion
assembly.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] The following descriptions should not be considered limiting
in any way. With reference to the accompanying drawings, like
elements are numbered alike:
[0005] FIG. 1 is a partial cross-sectional view of a completion
system in which an intermediate assembly is being engaged with a
lower completion;
[0006] FIG. 1A is an enlarged view of the area circled in FIG.
1;
[0007] FIG. 2 is a partial cross-sectional view of the completion
system of FIG. 1 in which the intermediate assembly is engaged with
the lower completion;
[0008] FIG. 3 is a partial cross-sectional view of the completion
system of FIG. 1 in which a barrier valve of the intermediate
assembly is closed for testing a packer of the intermediate
assembly;
[0009] FIG. 3A is an enlarged view of the area circled in FIG.
3;
[0010] FIG. 4 is a partial cross-sectional view of the completion
system of FIG. 1 in which a fluid isolation valve for the lower
completion is opened;
[0011] FIG. 5 is a partial cross-sectional view of the completion
system of FIG. 1 in which a work string on which the intermediate
assembly was run-in is pulled out, thereby closing the barrier
valve of the intermediate assembly;
[0012] FIG. 6 is a partial cross-sectional view of the completion
system of FIG. 1 in which a production string is being run-in for
engagement with the intermediate assembly;
[0013] FIG. 7 is a partial cross-sectional view of the completion
system of FIG. 1 in which the production string is engaged with the
intermediate assembly for opening the barrier valve and enabling
production from the lower completion;
[0014] FIG. 8 is a partial cross-sectional view of the completion
system of FIG. 1 in which the production string has been pulled
out, thereby closing the barrier valve of the intermediate assembly
and a subsequent intermediate assembly is being run-in for
engagement with the original intermediate assembly;
[0015] FIG. 9 is a partial cross-sectional view of the completion
system of FIG. 1 in which the subsequent intermediate assembly is
stacked on the original intermediate assembly;
[0016] FIG. 10 is a partial cross-sectional view of a completion
system according to another embodiment disclosed herein; and
[0017] FIG. 11 is a partially cross-sectional view of a completion
system according to another embodiment disclosed herein.
DETAILED DESCRIPTION
[0018] A detailed description of one or more embodiments of the
disclosed apparatus and method are presented herein by way of
exemplification and not limitation with reference to the
Figures.
[0019] Referring now to FIG. 1, a completion system 10 is shown
installed in a borehole 12 (cased, lined, open hole, etc.). The
system 10 includes a lower completion 14 including a gravel or frac
pack assembly 16 (or multiples thereof for multiple producing
zones) that is isolated from an upper completion 18 of the system
10 by a fluid loss or fluid isolation valve 20. The gravel or frac
pack assembly 16 and the valve 20 generally resemble those known
and used in the art. That is, the gravel or frac pack assembly 16
enables the fracturing of various zones while controlling sand or
other downhole solids, while the valve 20 takes the form of a ball
valve that is transitionable between a closed configuration (shown
in FIG. 1) and an open configuration (discussed later) due to
cycling the pressure experienced by the valve 20 or other
mechanical means, e.g., through an intervention with wireline or
tubing. Of course, known types of fluid loss valves other than ball
valves could be used in place of the valve 20. Additionally, it is
to be appreciated that the lower completion 14 could include
components and assemblies other than, or in addition to, the frac
pack and/or gravel pack assembly 16, such as for enabling
stimulation, hydraulic fracturing, etc.
[0020] The system 10 also includes a work string 22 that enables an
intermediate completion assembly 24 to be run in. Essentially, the
assembly 24 is arranged for functionally replacing the valve 20.
That is, while the valve 20 remains physically downhole, the
assembly 24 assumes or otherwise takes off at least some
functionality of the valve 20, i.e., the assembly 24 provides
isolation of the lower completion 14 and the formation and/or
portion of the borehole 12 in which the lower completion 14 is
positioned. Specifically, in the illustrated embodiment, the
assembly 24 in the illustrated embodiment is a fluid loss and
isolation assembly and includes a barrier valve 26 and a production
packer or packer device 28. By packer device, it is generally meant
any assembly arranged to seal an annulus, isolation a formation or
portion of a borehole, anchor a string attached thereto, etc. The
barrier valve 26 is shown in more detail in FIG. 1A. Initially, as
shown in FIGS. 1 and 1A, a shifting tool 30 holds a sleeve 32 of
the barrier valve 26 in an open position by an extension 34 of the
shifting tool 30 that extends through the packer 28. The term
"shifting tool" is used broadly and encompasses seal assemblies and
devices that allow relative movement or shifting of the sleeve 32
other than the tool 30 as illustrated. When the sleeve 32 is in its
open position, a set of ports 36 in the sleeve 32 are axially
aligned with a set of ports 38 in a housing or body 40 of the
barrier valve 26, thereby enabling fluid communication through the
barrier valve 26. Of course, movement of the sleeve 32 for enabling
fluid communication is not limited to axial, although this
direction of movement conveniently corresponds with the direction
of movement of the work string 22. In the illustrated embodiment, a
shroud 44 is radially disposed with the barrier valve 26 for
further controlling and/or regulating the flow rate, pressure, etc.
of fluid, i.e., by redirecting fluid flow from the lower completion
14 out into the chamber formed by the shroud 44, and back into the
barrier valve 26 via the ports 36 and 38 when the valve 26 is open.
In the illustrated embodiment, the extension 34 of the shifting
tool 30 (and/or the sleeve 32) includes a releasable connection 46
for enabling releasable or selective engagement between the tool 30
and the sleeve 32. For example, the connection 46 could be formed
by a collet, spring-loaded or biased fingers or dogs, etc.
[0021] A method of assembling and using the completion 10 according
to one embodiment is generally described with respect to FIGS. 1-9.
As illustrated in FIG. 1, the work string 22 with the assembly 24
is initially run in for connection to the lower completion 14,
thereby providing a fluid pathway to surface and enabling
production. For example, while circulating fluids in the borehole
12, the assembly 24 can be properly positioned by lowering the work
string 22 until circulation stops. After noting the location and
slacking off on the work string, the assembly 24 is landed at the
lower completion 14, as shown in FIG. 2. Once landed at the lower
completion 14, the production packer 28 is set, e.g., via hydraulic
pressure in the work string 22, thereby isolating and anchoring the
assembly 24. At this point, the barrier valve 26 is open and an
equalizing port 48 between the interior of the work string 22 and
an annulus 50 is closed by the extension 34 of the shifting tool
30.
[0022] As illustrated in FIG. 3, the work string 22 can then be
pulled out in order to axially misalign the ports 36 and 38, which
closes the barrier valve 26. That is, as shown in more detail in
FIG. 3A, communication through the port 38 and into the barrier
valve 26 is prevented by a pair of seal elements 52 sealed against
the sleeve 32. As also shown in more detail in FIG. 3A, pulling out
the work string 22 slightly also opens the equalizing port 48,
enabling the packer 28 to be tested on the annulus 50 and/or down
the work string 22.
[0023] As depicted in FIG. 4, by again slacking off on the work
string 22, the barrier valve 26 re-opens (e.g., taking the
configuration shown in FIG. 1A) and pressure can be cycled in the
work string 22 for opening the fluid loss valve 20. Next, as shown
in FIG. 5, the work string 22 is pulled out of the borehole 12.
Pulling out the work string 22 first shifts the sleeve 32 into its
closed position (e.g., as shown in FIG. 3A) for the barrier valve
26. Then due to the packer 28 anchoring the assembly 14, continuing
to pull out the work string 22 disconnects the tool 30 from the
sleeve 32 at the releasable connection 46.
[0024] In order to start production, a production string 54 is run
and engaged with the assembly 24 as shown in FIGS. 6 and 7. The
production string 54 includes a shifting tool 56 similar to the
tool 30, i.e., arranged with a releasable connection to selectively
open and close the barrier valve 26 by manipulating the sleeve 32.
In this way, the production string 54 is first landed at the
assembly 24 and the tool 30 extended through the packer 28 for
shifting the sleeve 32 to open the barrier valve 26. Once the
barrier valve 26 is opened, a tubing hanger supporting the
production string 54 is landed and fluid from the downhole zones,
i.e., proximate to the frac or gravel pack assembly 16, can be
produced. In the illustrated embodiment the production string 54
takes the form of an artificial lift system, particularly an ESP
system for a deepwater well, which are generally known in the art.
However, it is to be appreciated that the current invention as
disclosed herein could be used in non-deepwater wells, without
artificial lift systems, with other types of artificial lift
systems, etc.
[0025] Workovers are a necessary part of the lifecycle of many
wells. ESP systems, for example, are typically replaced about every
8-10 years, or some other amount of time. Other systems, strings,
or components in the upper completion 18 may need to be similarly
removed or replaced periodically, e.g., in the event of a fault,
damage, corrosion, etc. In order to perform the workover, reverse
circulation may be performed by closing a circulation valve 58 and
shifting open a hydraulic sliding sleeve 60 of the production
string 54. Advantageously, if the production string 54 or other
portions in the upper completion 18 (i.e., up-hole of the assembly
24) needs to be removed, removal of that portion will
"automatically" revert the barrier valve 26 to its closed position,
thereby preventing fluid loss. That is, the same act of pulling out
the upper completion string, e.g., the production string 54, the
work string 22, etc., will also shift the sleeve 32 into its closed
position and isolate the fluids in the lower completion. This
eliminates the need for expensive and additional wireline
intervention, hydraulic pressure cycling, running and/or
manipulating a designated shifting tool, etc. The packer 28 also
remains in place to maintain isolation. This avoids the need for
expensive and time consuming processes, such as wireline
intervention, which may otherwise be necessary to close a fluid
loss valve, e.g., the valve 20.
[0026] A replacement string, e.g., a new production string
resembling the string 54, can be run back down into the same
intermediate completion assembly, e.g., the assembly 24.
Alternatively, if a long period of time has elapsed, e.g., 8-10
years as indicated above with respect to ESP systems, it may
instead be desirable to run in a new intermediate completion
assembly, as equipment wears out over time, particularly in the
relatively harsh downhole environment. For example, as shown in
FIGS. 8 and 9 an additional or subsequent intermediate completion
assembly 24' is run in on a work string 22' for engagement with the
original assembly 24. As noted above with respect to the valve 20,
the subsequent assembly 24' essentially functionally replaces the
original assembly 24. That is, the subsequent assembly 24'
substantially resembles the original assembly 24, including a
barrier valve 26' for preventing fluid loss, a production packer
28' for reestablishing isolation, and a sleeve 32' that is
manipulated by a shifting tool 30' on the work string 22'. It
should be appreciated that the aforementioned components associated
with the assembly 24' include prime symbols, but otherwise utilize
the same base reference numerals as corresponding components
described above with respect to the assembly 24, and the above
descriptions generally apply to the corresponding components having
prime symbols and of the assembly 24' (even if unlabeled), unless
otherwise noted.
[0027] Unlike the assembly 24, the assembly 24' has a shifting tool
62 for shifting the sleeve 32 of the original assembly 24 in order
to open the barrier valve 26, which was closed by the shifting tool
56 when the production string 54 was pulled out. As long as the
assembly 24' remains engaged with the assembly 24, the tool 62 will
mechanically hold the barrier valve 26 in its open position. In
this way, the assembly 24' can be stacked on the assembly 24 and
the barrier valve 26' will essentially take over the fluid loss
functionality of the barrier valve 26 of the assembly 24 by holding
the barrier valve 26 open with the tool 62. It is to be appreciated
that any number of these subsequent assemblies 24' could continue
to be stacked on each other as needed. For example, a new one of
the assemblies 24' could be stacked onto a previous assembly
between the acts of pulling out an old upper completion or
production string and running in a new one. In this way, the newly
run upper completion or production string will interact with the
uppermost of the assemblies 24' (as previously described with
respect to the assembly 24 and the production string 54), while all
the other intermediate assemblies are held open by the shifting
tools of the subsequent assemblies (as previously described with
respect to the assembly 24 and the shifting tool 62).
[0028] The shifting tool 30' also differs from the shifting tool 30
to which it corresponds. Specifically, the shifting tool 30'
includes a seat 64 for receiving a ball or plug 66 that is dropped
and/or pumped downhole. By blocking flow through the seat 64 with
the plug 66, fluid pressure can be built up in the work string 22'
suitable for setting and anchoring the production packer 28'. That
is, pressure was able to be established for setting the original
packer 28 because the fluid loss valve 20 was closed, but with
respect to FIGS. 8 and 9 the valve 20 has since been opened and
fluid communication established with the lower completion 14 as
described previously.
[0029] After setting the packer 28', the string 22' can be pulled
out, thereby automatically closing the sleeve 32' of the barrier
valve 26' as previously described with respect to the assembly 24
and the work string 22 (e.g., by use of a releasable connection).
As previously noted, the original barrier valve 26 remains opened
by the shifting tool 62 of the subsequent assembly 24'. As the
assembly 24' has essentially taken over the functionality of the
original assembly 24 (i.e., by holding the barrier valve 26
constantly open with the tool 62), a new production string, e.g.,
resembling the production string 54, can be run in essentially
exactly as previously described with respect to the production
string 54 and the assembly 24, but instead engaged with the
assembly 24'. That is, instead of manipulating the barrier valve
26, the shifting tool (e.g., resembling the tool 56) of the new
production string (e.g., resembling the string 54) will shift the
sleeve 32' of the barrier valve 26' open for enabling production of
the fluids from the downhole zones or reservoir.
[0030] It is again to be appreciated that any number of the
assemblies 24' can continue to be run in and stacked atop one
another. For example, this stacking of the assemblies 24' can occur
between the acts of pulling out an old production string and
running a new production string, with the pulling out of each
production string "automatically" closing the uppermost one of the
assemblies 24' and isolating the fluid in the lower completion 14.
In this way, any number of production strings, e.g., ESP systems,
can be replaced over time without the need for expensive and time
consuming wireline intervention, hydraulic pressure cycling,
running and/or manipulation of a designated shifting tool, etc.
Additionally, the stackable nature of the assemblies 24, 24', etc.,
enables the isolation and fluid loss hardware to be refreshed or
renewed over time in order to minimize the likelihood of a part
failure due to wear, corrosion, aging, etc.
[0031] It is noted that the fluid loss valve 20 can be substituted,
for example, by the assembly 24 being run in on a work string
resembling the work string 22' as opposed to the work string 22.
For example, as shown in FIG. 10, a modified system 10a includes
the assembly 24 being run in on the work string 22'. In this way,
fluid pressure suitable for setting the original packer 28 can be
established by use of the ball seat 64 and the plug 66 instead of
the valve 20. Accordingly, as illustrated in FIG. 10, the fluid
loss valve 20 is rendered unnecessary or redundant by use of the
system 10a, as the plug 66 and the seat 64 of the work string 22'
enable suitable pressurization for setting the packer 28, and the
tool 30' of the work string 22' enables control of the barrier
valve 26 such that the assembly 24 can completely isolate the lower
completion 14. After isolating the lower completion 14, a
production string, e.g., the string 54, subsequent intermediate
assemblies, etc., can be run in and interact with the assembly 24
as described above.
[0032] As another example, a modified system 10b is illustrated in
FIG. 11. The system 10b is similar to the system 10a in that a
separate fluid isolation valve for the lower completion 14, e.g.,
the valve 20, is not necessary and instead the system 10b can be
run in for initially isolating the lower completion 14. Unlike the
system 10a, the system 10b is capable of being run-in immediately
on the production string 54 without the need for the work string
22' of the system 10a. Specifically, the system 10b is run-in with
a plug 66' already located in a shifting tool 56' of the production
string 54. The tool 56' resembles the tool 56 with the exception of
being arranged to hold the plug 66' therein for blocking fluid flow
therethrough. By running the plug 66' in with the system 10b, the
plug 66' does not need to be dropped and/or pumped from surface, as
this would be impossible for various configurations of the
production string 54, e.g., if the string 54 includes ESPs or other
components or assemblies that would obstruct the pathway of a
dropped plug down through the string. The plug 66' is arranged to
be degradable, consumable, disintegrable, corrodible, dissolvable,
chemically reactable, or otherwise removable so that once it has
been used for providing the hydraulic pressure necessary to set the
packer 28, the plug 66' can be removed and enable production
through the string 54. In one embodiment the plug 66' is made from
a dissolvable or reactive material, such as magnesium or aluminum
that can be removed in response to a fluid deliverable or available
downhole, e.g., acid, brine, etc. In another embodiment, the plug
66' is made from a controlled electrolytic material, such as made
commercially available by Baker Hughes, Inc. under the tradename
IN-TALLIC.RTM.. Once the plug 66' is removed, the system 10b would
function as described above with respect to the system 10.
[0033] It is thus noted that the current invention as illustrated
in FIGS. 1-9 is suitable as a retrofit for systems that are in need
of a workover, i.e., need to have the upper completion replaced or
removed, but already includes a valve resembling the fluid loss
valve 20 (e.g., a ball valve or some other type of valve used in
the art that requires wireline intervention, hydraulic pressure
cycling, the running and/or manipulation of designated shifting
tools, etc., in order to transition between open and closed
configurations). Alternatively stated, the system 10 enables
downhole isolation of a lower completion for performing a workover,
i.e., removal or replacement of an upper completion, without the
need for time consuming wireline or other intervention.
[0034] In view of the foregoing it is to be appreciated that new
completions can be installed with a valve, e.g., the fluid loss
valve 20, that requires some separate intervention and/or operation
to close the valve during workovers, or, alternatively, according
to the systems 10a or 10b, which not only initially isolate a lower
completion, e.g., the lower completion 14, but additionally include
a barrier valve, e.g., the barrier valve 26, that automatically
closes upon pulling out the upper completion, as described
above.
[0035] While the invention has been described with reference to an
exemplary embodiment or embodiments, it will be understood by those
skilled in the art that various changes may be made and equivalents
may be substituted for elements thereof without departing from the
scope of the invention. In addition, many modifications may be made
to adapt a particular situation or material to the teachings of the
invention without departing from the essential scope thereof
Therefore, it is intended that the invention not be limited to the
particular embodiment disclosed as the best mode contemplated for
carrying out this invention, but that the invention will include
all embodiments falling within the scope of the claims. Also, in
the drawings and the description, there have been disclosed
exemplary embodiments of the invention and, although specific terms
may have been employed, they are unless otherwise stated used in a
generic and descriptive sense only and not for purposes of
limitation, the scope of the invention therefore not being so
limited. Moreover, the use of the terms first, second, etc. do not
denote any order or importance, but rather the terms first, second,
etc. are used to distinguish one element from another. Furthermore,
the use of the terms a, an, etc. do not denote a limitation of
quantity, but rather denote the presence of at least one of the
referenced item.
* * * * *