U.S. patent application number 17/053895 was filed with the patent office on 2021-09-09 for setting mechanical barriers in a single run.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to David Allen Dockweiler, Garry Martin Howitt, William Ellis Standridge.
Application Number | 20210277736 17/053895 |
Document ID | / |
Family ID | 1000005636685 |
Filed Date | 2021-09-09 |
United States Patent
Application |
20210277736 |
Kind Code |
A1 |
Dockweiler; David Allen ; et
al. |
September 9, 2021 |
SETTING MECHANICAL BARRIERS IN A SINGLE RUN
Abstract
An operation may require isolation of a wellbore using multiple
barriers. A single-run multiple barrier system may be deployed in a
wellbore to position a first barrier at a first depth and a second
barrier at second depth above the first barrier in the wellbore
during a single run of a wellbore tubular string. The first barrier
is coupled to a first miming tool. A wellbore tubular string
segment couples the first miming tool is coupled to the second
barrier. The second barrier is coupled to a second running tool
that couples to the wellbore tubular string. The second barrier is
locked until the first barrier is independently set at the first
depth to prevent the second barrier from being set until the second
depth is reached. Setting both barriers in a single run increases
efficiency in an operation including reducing costs and time for
completion of the operation.
Inventors: |
Dockweiler; David Allen;
(Humble, TX) ; Howitt; Garry Martin; (Midmar,
GB) ; Standridge; William Ellis; (Madill,
OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
1000005636685 |
Appl. No.: |
17/053895 |
Filed: |
June 13, 2018 |
PCT Filed: |
June 13, 2018 |
PCT NO: |
PCT/US2018/037289 |
371 Date: |
November 9, 2020 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/124 20130101;
E21B 23/006 20130101; E21B 23/06 20130101 |
International
Class: |
E21B 23/06 20060101
E21B023/06; E21B 23/00 20060101 E21B023/00; E21B 33/124 20060101
E21B033/124 |
Claims
1. A method of setting a single-run multiple barrier system
comprising: deploying a single-run multiple barrier system on a
wellbore tubular string in a wellbore of a formation, wherein the
single-run multiple barrier system comprises a deep set barrier
system at a distal end of the wellbore tubular string and a shallow
set barrier above the deep set barrier system; determining if a
first depth in the wellbore has been reached by the single-run
multiple barrier system; setting a first isolation device of the
deep set barrier system, wherein the shallow set barrier system
comprises a rupture disk that prevents a lug from moving within a
continuous j-slot to prevent setting of the shallow set barrier
system during setting of the first isolation device; disconnecting
the deep set barrier system from the wellbore tubular string;
retrieving the wellbore tubular string to a second depth; setting a
second isolation device of the shallow set barrier system; and
disconnecting the shallow set barrier system from the wellbore
tubular string.
2. The method of claim 1, wherein setting the second device
comprises: rupturing the rupture disk; allowing the lug to move
within the continuous j-slot; and lifting upward and pushing
downward on the wellbore tubular string.
3. The method of claim 1, wherein the first isolation device is
coupled to a first running tool, and wherein disconnecting the deep
set barrier system from the wellbore tubular string comprises
disengaging the first running tool from the wellbore tubular
string.
4. The method of claim 1, wherein the shallow set barrier system is
coupled to a second running tool, wherein the second running tool
is coupled to the wellbore tubular string, and wherein
disconnecting the shallow set barrier system from the wellbore
tubular string comprises disengaging the second running tool from
the wellbore tubular string.
5. The method of claim 1, further comprising: extending one or more
first projections of one or more first anchors of the deep set
barrier system to contact at least one of the wellbore, an annulus
disposed within the wellbore, and a casing disposed within the
wellbore.
6. The method of claim 1, further comprising: extending one or more
second projections of one or more second anchors of the shallow set
barrier system to contact at least one of the wellbore, an annulus
disposed within the wellbore, and a casing disposed within the
wellbore.
7. The method of claim 1, further comprising: maintaining
positioning of the first isolation device in an annulus of the
wellbore via a first centralizer.
8. The method of claim 1, further comprising: maintaining
positioning of the second isolation device in an annulus of the
wellbore via a second centralizer.
9. The method of claim 1, wherein at least one of the first setting
depth and the second setting depth is based on one or more
parameters of the formation.
10. The method of claim 1, further comprising: retrieving the
wellbore tubular string from the wellbore.
11. A single-run multiple barrier system comprising: a deep set
barrier system, wherein the deep set barrier system comprises a
first isolation device and a first running tool, wherein the first
running tool couples to a first portion of a wellbore tubular
string; a shallow set barrier system, wherein the shallow set
barrier system comprises a second isolation device and second
running tool, wherein the second running tool couples to a second
portion of a wellbore tubular string; and a locking assembly of the
shallow set barrier system, wherein the locking assembly is locked
and unlocked independent of the deep set barrier system.
12. The single-run multiple barrier system of claim 11, wherein the
locking assembly comprises a rupture disk that prevents a lug from
moving within a continuous j-slot to prevent setting of the shallow
set barrier system during setting of the first isolation
device.
13. The single-run multiple barrier system of claim 12, wherein the
lug moves within the continuous j-slot when the rupture disk
ruptures to set the second isolation device.
14. The single-run multiple barrier system of claim 11, wherein the
deep set barrier system further comprises: a first running tool
coupled to the first isolation device and the wellbore tubular
string; and wherein the first running tool disconnects from the
wellbore tubular string to set the first isolation device and
reconnects with the wellbore tubular string to retrieve the first
isolation device.
15. The single-run multiple barrier system of claim 11, where the
shallow set barrier system further comprises: a second running tool
coupled to the second isolation device and the wellbore tubular
string; and wherein the second running tool disconnects from the
wellbore tubular string to set the second isolation device and
reconnects with the wellbore tubular string to retrieve the second
isolation device.
16. The single-run multiple barrier system of claim 11, wherein the
deep set barrier system further comprises: one or more first
anchors; and one or more first projections of the one or more first
anchors, wherein the one or more first projections extend to
contact at least one of the wellbore, an annulus disposed within
the wellbore and a casing disposed within the wellbore.
17. The single-run multiple barrier system of claim 11, wherein the
shallow set barrier system further comprises: one or more second
anchors; and one or more second projections of the one or more
second anchors, wherein the one or more second projections extend
to contact at least one of the wellbore, an annulus disposed within
the wellbore and a casing disposed within the wellbore.
18. The single-run multiple barrier system of claim 11, wherein the
deep set barrier system further comprises a first centralizer.
19. The single-run multiple barrier system of claim 11, wherein the
shallow set barrier system further comprises a second
centralizer.
20. The single-run multiple barrier system of claim 11, wherein the
wellbore tubular string comprises a first wellbore tubular string
segment coupled to the first running tool and the shallow set
barrier system and a second wellbore tubular string segment coupled
to the second running tool, wherein the first running tool
disengages from the first wellbore tubular string segment to set
the deep set barrier system, and wherein the second running tool
disengages from the second wellbore tubular string segment to set
the shallow set barrier system.
Description
TECHNICAL FIELD OF THE INVENTION
[0001] The present invention relates to setting barriers, and more
particularly, to setting multiple barriers at two or more different
depths in a single run in a wellbore.
BACKGROUND
[0002] A wide variety of downhole tools, such as service tools, may
be used within a wellbore in connection with the production of
hydrocarbons and reworking or servicing a well. In many
circumstances an operation may require that multiple barriers be
introduced into a borehole or wellbore and set at different depths
within the wellbore to isolate portions of the wellbore or the
formation. Many operators and government regulations require that a
minimum of two barriers be installed in a wellbore. For example,
several types of operations for a job, including plug and
abandonment and blow-out prevention for a hydrocarbon production,
exploration and recovery site, may be implemented that require that
multiple barriers be installed in the wellbore. Typically, each
barrier must be separately run on a tool string, such as drill pipe
or tubing string, into the wellbore and may require a different
tool to unlock and set the barrier. As an example, a first barrier
may be run into the wellbore with a tool string to a setting depth,
set and the tool string is tripped out of the wellbore. The second
barrier is connected to the tool string, run in the wellbore and
set at a different setting depth and the tool string tripped back
out of the well. Each installation of the barriers requires at
least two trips down the wellbore which increases wear and tear on
equipment and increases risk of mechanical failure both of which
contribute to an increase in overall job completion time and costs
for the overall job as well as increasing risks to the safety of
nearby personnel.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] FIG. 1 is a cross-sectional view of a single-run multiple
barrier system in an operating environment, according to one or
more aspects of the present disclosure.
[0004] FIG. 2 is a cross-sectional view of a single-run multiple
barrier system with the deep set barrier set in an operating
environment, according to one or more aspects of the present
disclosure.
[0005] FIG. 3 is a cross-sectional view of a single-run multiple
barrier system with the shallow set barrier set in an operating
environment, according to one or more aspects of the present
disclosure.
[0006] FIG. 4A is a schematic view of a shallow set barrier of a
single-run multiple barrier system in an unset position, according
to one or more aspects of the present disclosure.
[0007] FIG. 4B is a schematic view of a shallow set barrier of a
single-run multiple barrier system in a set position, according to
one or more aspects of the present disclosure.
[0008] FIG. 5A is a schematic view of a deep set barrier of a
single-run multiple barrier system in an unset position, according
to one or more aspects of the present disclosure.
[0009] FIG. 5B is a schematic view of a deep set barrier of a
single-run multiple barrier system in a set position, according to
one or more aspects of the present disclosure.
[0010] FIG. 6A is a cross-sectional view of a locking slot assembly
for a shallow set barrier system in a locked position, according to
one or more aspects of the present disclosure.
[0011] FIG. 6B is a cross-sectional view of a locking slot assembly
for a shallow set barrier system in an unlocked position, according
to one or more aspects of the present disclosure.
[0012] FIG. 7A is a cross-sectional view of a locking slot assembly
for a shallow set barrier in a locked position, according to one or
more aspects of the present disclosure.
[0013] FIG. 7B is a cross-sectional view of a locking slot assembly
for a shallow set barrier in an unlocked position, according to one
or more aspects of the present disclosure.
[0014] FIG. 8A is a side view of a locking slot assembly for a
shallow set barrier in a locked position, according to one or more
aspects of the present disclosure.
[0015] FIG. 8B is a side view of a locking slot assembly for a
shallow set barrier in an unlocked position, according to one or
more aspects of the present disclosure.
[0016] FIG. 9 is a schematic side view of a mandrel component and
slide lock component of a deep set barrier system, according to one
or more aspects of the present disclosure.
[0017] FIG. 10 is a schematic, cross-sectional side view of a top
adapter and an overshot component of a deep set barrier system,
according to one or more aspects of the present disclosure.
[0018] FIG. 11 is a schematic side view, partially in
cross-section, of a deep set barrier system in a locked
configuration, according to one or more aspects of the present
disclosure.
[0019] FIG. 12 is a schematic side view, partially in
cross-section, of a deep set barrier system in a connected and
locked configuration, according to one or more aspects of the
present disclosure.
[0020] FIG. 13 is a schematic side view, partially in
cross-section, of a deep set barrier system in a connected and
unlocked configuration, according to one or more aspects of the
present disclosure.
[0021] FIG. 14 is a schematic side view, partially in
cross-section, of a deep set barrier system in a released and
unlocked configuration.
[0022] FIG. 15 is a schematic side view, partially in
cross-section, of a deep set barrier system in a released
configuration.
[0023] FIG. 16 is a schematic side view, partially in
cross-section, of the deep set barrier system in a released
configuration.
[0024] FIG. 17 is a flowchart illustrating a method for setting a
single-run multiple barrier system, according to one or more
aspects of the present disclosure.
DETAILED DESCRIPTION
[0025] In the drawings and description that follow, like parts are
typically marked with the same reference numerals. Specific
embodiments are described and are shown in the drawings with the
understanding that the present disclosure is to be considered an
exemplification of the principles of the invention and is not
intended to limit the invention that illustrated and described
herein. It is to be fully recognized that the different teachings
of the embodiments discussed throughout may be employed separately
or in any suitable combination to produce desire results.
[0026] For certain downhole operations, barriers or isolation
devices are required to be run in the wellbore to isolate portions
of the wellbore or the formation. For example, blow-out prevention
(BOP) or abandonment of a well may require that multiple barriers
are run in the wellbore to isolate portions of the wellbore or the
formation. Generally, for barriers deployed on a downhole tool,
once one barrier is set, all barriers attached to tubing string or
wellbore tubular string are set. An operation that requires setting
multiple barriers at different depths requires multiple runs in the
wellbore. For example, a downhole tool comprising a barrier is ran
in the wellbore to a specified depth and when the depth is reached
the barrier is set. The downhole tool is retrieved and another
barrier is ran in the wellbore on the same or different downhole
tool. Again, once the specified depth is reach the barrier is set
and the downhole tool is retrieved. As multiple runs are required
for the setting of multiple barriers, the placement of multiple
barriers at different depths requires significant time which
increases the overall costs of an operation as well as increases
the risk to nearby personnel due to multiple instances of contact
with the equipment.
[0027] The present invention provides increased efficiency for a
downhole operation that requires that multiple barriers or
isolation devices be set in a wellbore to isolate portions of the
wellbore or the formation. Providing a single-run multiple barrier
system with multiple barriers that may be set in a wellbore using a
single-run of a downhole tool alleviates the need for multiple
runs. Setting multiple barriers in a single-run decreases wear and
tear on equipment, reduces time for completion of the operation and
increases safety by minimizing contact by nearby personnel to the
required equipment. For example, a deep set barrier may be
connected to a retrieval tool which is connected to a shallow set
barrier that is also connected to a retrieval tool of a downhole
tool. Both the deep set barrier and the shallow set barrier may be
deployed downhole in a single run as the shallow set barrier is
locked out until after the deep set barrier has been set.
[0028] FIG. 1 is a cross-sectional view of a single-run multiple
barrier system 150 in an operating environment 100, according to
one or more aspects of the present disclosure. The operating
environment 100 comprises a workover or drilling rig 106 (generally
referred to herein as rig 106) positioned at, on or about a surface
104. The rig 106 extends over and around a wellbore 114 that
penetrates a subterranean formation 102. For example, rig 106 may
be positioned and equipped for the discovery, exploration,
production or any combination thereof of hydrocarbons. In one or
more embodiments, rig 106 may be positioned and equipped for
completion or abandonment (or both) or BOP of the wellbore 114. The
wellbore 114 may extend into the subterranean formation 102 at any
angle or deviation from the surface 104.
[0029] The rig 106 may comprise a derrick 108 and a rig floor 110
through with a wellbore tubular string extends downward from the
drilling rig 106 into the wellbore 114. The rig 106 may comprise a
motor 116 that drives a mechanism 118. Mechanism 118 may comprise a
winch, a drum, a crank or any other device suitable for deploying
and retrieving wellbore tubular string 120 in and out of wellbore
114. In one or more embodiments, the wellbore 114 may comprise a
casing 128 or any other liner that extends the length of the
wellbore 114 to form an annulus 126.
[0030] Wellbore tubular string 120 may comprise one or more
sections including, but not limited to, one or more portions such
as wellbore tubular string segment 120A and wellbore tubular string
segment 120B. Wellbore tubular string 120 may comprise a drill
pipe, tool string, tubing string, work string, tubing, drill string
or any other piping that is coupled together to deploy one or more
downhole tools within the wellbore 114, for example, single-run
multiple barrier system 150. In one or more embodiments, the
single-run multiple barrier system 150 is deployed in an annulus
126. Wellbore tubular string segment 120A may couple to a
single-run multiple barrier system 150. Wellbore tubular string 120
may comprise any number of portions, segments or lengths coupled
together to form wellbore tubular string 120. Any number of
downhole tools may be coupled to wellbore tubular string 120.
Wellbore tubular string 120 deploys the single-run multiple barrier
system 150 to the required depth in the wellbore 114. For example,
wellbore tubular string segment 120A may couple to one or more
other segments of wellbore tubular string 120 and wellbore tubular
string segment 120B may couple to one or more other segments of
wellbore tubular string 120. Any one or more segments of wellbore
tubular string 120 may be threaded or coupled to any one or more
other segments of wellbore tubular string 120, one or more
single-run multiple barrier systems 150, one or more other downhole
tools or any combination thereof.
[0031] In one or more embodiments, single-run multiple barrier
system 150 may comprise a deep set barrier system 112B at a distal
end of the wellbore tubular string 120 and a shallow set barrier
system 112A above the deep set barrier system 112B (collectively
referred to as barrier systems 112), wellbore tubular string
segment 120A and wellbore tubular string segment 120B. In one or
more embodiments, single-run multiple barrier system 150 may
comprise any number of barrier systems 112. While a single wellbore
tubular string segment 120A and a single wellbore tubular string
segment 120B are illustrated in FIG. 1, the present disclosure
contemplates any number of wellbore tubular string segments 120A
and 120B. Shallow set barrier system 112A comprises a running tool
122A and an isolation device 124A, for example, a shallow set
barrier. Deep set barrier system 112B comprises a running tool 122B
and an isolation device 124B, for example a deep set barrier. In
one or more embodiments, isolation devices 124A and 124B may
comprise a bridge plug, a packer, a barrier valve or any other
isolation device. In one or more embodiments, wellbore tubular
string segment 120A couples to a running tool 122A and wellbore
tubular string segment 120E couples to a running tool 122B and
shallow set barrier system 112A, where running tools 122A and 122B
are collectively referred to as running tools 122. Running tool
122A couples to an isolation device 124A and running tool 122B
couples to an isolation device 124B, where isolation devices 124A
and 124B are collectively referred to as isolation devices 124.
Wellbore tubular string segment 120B couples the isolation device
124A to the running tool 122B.
[0032] FIG. 2 is a cross-sectional view of a single-run multiple
barrier system 150 with a deep set barrier system 112B set in an
operating environment 200, according to one or more aspects of the
present disclosure. Operating environment 200 is similar to
operating environment 100 except that the deep set barrier system
112B has been disengaged from wellbore tubular string segment 120B
or set at the required, specified or selected depth in wellbore
114.
[0033] FIG. 3 is cross-sectional view of a single-run multiple
barrier system 150 with the shallow set barrier system 112A set in
an operating environment 300, according to one or more aspects of
the present disclosure. Operating environment 300 is similar to
operating environments 100 and 200 except that the shallow set
barrier system 112A has been disengaged from wellbore tubular
string segment 120A or set at the required, specified or selected
depth in wellbore 114.
[0034] While the operating environment depicted in FIGS. 1-3 refer
to a stationary rig 106 for conveying the wellbore tubular string
120 comprising the single-run multiple barrier system 150 within a
land-based wellbore 114, 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
string 120 comprising the single-run multiple barrier system 150
within the wellbore 114. It should be understood that a wellbore
tubular string 120 comprising the single-run multiple barrier
system 150 may alternatively be used in other operating
environments, such as within an offshore wellbore operating
environment. For example, workover or drilling rig 106 may be
located offshore and wellbore 114 may be a subsea wellbore.
[0035] FIG. 4A is a schematic view of a shallow set barrier or
isolation device 124A of a single-run multiple barrier system, such
as single-run multiple barrier system 150, in an unset position
according to one or more aspects of the present disclosure. The
isolation device 124A is shown disposed or positioned in an annulus
126 formed by casing 128 in wellbore 114. In one or more
embodiments, isolation device 124A may be disposed or positioned in
an uncased wellbore 114. The shallow set barrier system 112A may
comprise an isolation device 124A. In one or more embodiments,
isolation device 124A may comprise any one or more of a top
connector 402A a bottom connector 402B, a rupture disk 412, a
rubber element 410, an anchor 406 and a centralizer 404. In one or
more embodiments, any one or more of a top connector 402A, a bottom
connector 402B, a rupture disk 412, a rubber element 410, an anchor
406 and a centralizer 404 may couple to the isolation device 124A
directly or indirectly. Top connector 402A couples the isolation
device 124A to running tool 122A. Bottom connector 402B couples the
isolation device 124A to one or more wellbore tubular segments 120,
a downhole tool or any other device. One or more anchors 406 may
comprise or couple to one or more projections 408. Centralizer 404
aids in maintaining positioning of the isolation device 124A in the
annulus 126.
[0036] FIG. 4B is a schematic view of a shallow set barrier or
isolation device 124A of a single-run multiple barrier system, such
as single-run multiple barrier system 150, in a set position,
according to one or more aspects of the present disclosure. FIG. 4B
is similar to FIG. 4A except that the rupture disk 412 in FIG. 4A
has ruptured to set the isolation device 124A. One or more anchors
408 are actuated such that one or more projections 408 secure the
isolation device 124A to the casing 128 in the wellbore 114. In one
or more embodiments, once the required depth is reached, the one or
more projections 408 of the one or more anchors 406 may be extended
to contact or couple to the wellbore 114, annulus 126, casing 128,
any other structure within wellbore 114 or any combination thereof
to secure the isolation device 124A to the wellbore 114. The rubber
element 410 is compressed to form a seal against the casing 128 to
isolate a portion of the annulus 126. For example, the portion of
the annulus 126 below rubber element 410 is isolated from fluid
flow from above the rubber element 410 and the portion of the
annulus 126 above the rubber element is isolated from fluid flow
from below the rubber element 410. The isolation device 124A may be
set according to any one or more embodiments described below with
respect to FIGS. 6A-8B.
[0037] FIG. 5A is a schematic view of a deep set barrier or
isolation device 124B of a single-run multiple barrier system, such
as single-run multiple barrier system 150, in an unset position,
according to one or more aspects of the present disclosure. The
isolation device 124B is shown disposed or positioned in an annulus
126 formed by casing 128 in wellbore 114. In one or more
embodiments, isolation device 124B may be disposed or positioned in
an uncased wellbore 114. In one or more embodiments, isolation
device 124B may comprise any one or more of a top connector 502A, a
bottom connector 502B, a running tool 122B, a rubber element 510,
an anchor 506 and a centralizer 504. In one or more embodiments,
any one or more of a top connector 502A, a bottom connector 502B, a
running tool 122B, a rubber element 510, an anchor 506 and a
centralizer 504 may couple directly or indirectly to the isolation
device 124B. Top connector 502A is similar to top connector 402A of
FAG. 4A. Top connector 504A couples the isolation device 124B to
running tool 122B. Bottom connector 504B couples the isolation
device 124B to one or more wellbore tubular strings 120, a downhole
tool or another device or terminates the isolation device 124B. One
or more anchors 506 may comprise or couple to one or more
projections 508 similar to the one or more anchors 406 and one or
more projections 408 of FIG. 3A. Centralizer 504 is similar to
centralizer 404 of FIG. 4A and aids in maintaining position of the
isolation device 124B in the annulus 126.
[0038] FIG. 5B is a schematic view of a deep set barrier or
isolation device 124B of a single-run multiple barrier system, such
as single-run multiple barrier system 150, in a set position,
according to one or more aspects of the present disclosure. FIG. 5B
is similar to FIG. 5A except that the isolation device 124B is in
the set position. In one or more embodiments, once the required
depth is reached, the one or more projections 508 of the one or
more anchors 506 may be extended to contact or couple to the
wellbore 114, annulus 126, casing 128 or any combination thereof.
The rubber element 510 is compressed to form a seal against the
casing 128 to isolate a portion of the annulus 126 as discussed
above with respect to FIG. 4B. Isolation device 124B may be set
according to any one or more embodiments described below with
respect to FIGS. 9 and 10.
[0039] With respect to FIGS. 6A and 6B, the locking slot assembly
of the present invention is shown and generally designated by the
numeral 610. FIG. 6A is a cross-sectional view of a locking
assembly 610 for a shallow set barrier system 112A in a locked
position, according to one or more aspect of the present
disclosure. FIG. 6B is a cross-sectional view of a locking assembly
610 in an unlocked position, according to one or more aspects of
the present disclosure. Locking assembly 610 is disposed adjacent
to a lower end of a downhole tool (shown in FIG. 7A), for example,
running tool 122A of FIGS. 1-3 and 4A. Shallow set barrier system
112A may connect to a tool string (not shown). For example, as
illustrated in FIG. 1, running tool 122A may connect to wellbore
tubular string 120. The entire tool string or wellbore tubular
string 120 may be positioned in a wellbore, for example, wellbore
114 of FIGS. 1-4B. The wellbore may be defined by a casing (not
shown), such as casing 128 of FIGS. 1-4B, and may be vertical,
horizontal or deviated to any degree.
[0040] Locking assembly 610 is illustrated at a distal end of the
shallow set barrier system 112A. Shallow set barrier system 112A
may include, or be attached to or otherwise coupled to, an inner,
actuating mandrel 614, which may be connected or coupled to the
wellbore tubular string 120. Locking assembly 610 may include the
actuating mandrel 614, attached at a lower end to bottom adapter
616. Actuating mandrel 614 and at least a portion of bottom adapter
616 may be situated within a fluid chamber case 618, a lock 620 or
both. The fluid chamber case 618 and the lock 620 may be removably
attached, fixedly attached, or even integrally formed with one
another. Alternatively, fluid chamber case 618 and lock 620 may be
separate.
[0041] At least one fluid chamber 622 may be situated between
actuating mandrel 614 and lock 620. Fluid chamber 622 may be sealed
via one or more seals 624, along with a rupture disk 626, such as
rupture disk 412 of FIG. 4A, situated in the lock 620. Air at
atmospheric pressure may initially fill the fluid chamber 622. As
the shallow set barrier system 112A is lowered into the well bore,
hydrostatic pressure outside the shallow set barrier system 112A
increases. Once the hydrostatic pressure reaches a predetermined
value, the rupture disk 626 may rupture. After the rupture disk 626
has ruptured, the fluid outside the shallow set barrier system 112A
will enter the shallow set barrier system 112A through a port 628
formed therein. The resulting increased pressure within the fluid
chamber 622 will cause the fluid chamber 622 to expand (as shown in
FIG. 6B). This expansion causes the longitudinal movement of the
lock 620 with respect to the actuating mandrel 614, thus
"unlocking" the locking assembly 610. The locking assembly 610 is
locked and unlocked independent of the slide lock 950 of the deep
set barrier system 112B discussed below. FIGS. 8A and 8B, which
will be discussed below, further show the locked position and
unlocked position respectively.
[0042] Referring now to FIGS. 7A and 7B, shown therein is an
alternate embodiment of the locking assembly 610. FIG. 7A is a
cross-sectional view of a locking assembly 610 for a shallow set
barrier system 112A in a locked position, according to one or more
aspects of the present disclosure. FIG. 7B is a cross-sectional
view of a locking assembly 610 for a shallow set barrier system
112A in an unlocked position, according to one or more aspects of
the present disclosure. This embodiment has no rupture disk 626.
Instead, one or more shear pins 630 to prevent the lock 620 from
moving until adequate pressure is present. A spring 632 may be
included to keep the locking assembly 610 in an unlocked position.
While the spring 632 shown is a coil spring, the spring 632 may be
any biasing member. Likewise, the shear pin 630 may be a screw,
spring, or any other shearable member. Other than the use of a
rupture disk 626, a spring 632, or both the embodiment of FIGS. 7A
and 7B functions similarly to the embodiment of FIGS. 6A and 6B. An
increase in pressure causes the lock 620 to move longitudinally
with respect to the actuating mandrel 614, resulting in the
unlocking of the locking assembly 610 (as shown in FIG. 7B).
[0043] FIG. 8A is a side view of a locking assembly 610 for a
shallow set barrier system 112A in a locked position, according to
one or more aspects of the present invention. FIG. 8B is a side
view of a locking slot assembly for a shallow set barrier system
112A in an unlocked position, according to one or more aspects of
the present disclosure. One or more lugs 634 may extend from a lug
rotator ring 636 into a continuous slot 638 in a sleeve 640, thus
providing locking assembly 610. As previously discussed, pressure
may cause the lock 620 to become unlocked. In the locked position,
a locking portion 642 of the lock 620 occupies space within the
slot 638, keeping the lugs 634 in a run-in-hole position, and
preventing the lugs 634 from moving relative to the slot 638. As
the lock 620 moves downwardly because of increased pressure, the
locking portion 642 moves out of the slot 638, allowing the lugs
634 to move relative to the slot 638 if there is an upward or
downward force acting on the sleeve 640.
[0044] In the run-in-hole, locked position, the lock 620 is in an
upward position, in which lugs 634 are engaged with locking portion
642 of the lock 620. As the tool string is lowered into well bore,
the locking assembly 610 will remain in the locked position shown
in FIGS. 6A, 7A, and 8A, with the lock 620 preventing relative
longitudinal movement of the lug rotator ring 36 with respect to
the sleeve 640.
[0045] Once pressure is applied and the locking assembly 610 is
unlocked (as shown in FIGS. 6B, 7B, and 8B), the locking assembly
610 may be actuated, allowing the lug rotator ring 636 to move
longitudinally with respect to the sleeve 640. In other words, the
shallow set barrier system 112A may be set by pushing downward on
the wellbore tubular string 120, running tool 122A or both, which
lowers lug 634. While any type of slot 638 may be used, the
embodiment shown uses a J-slot, and in particular, shows a
continuous J-slot. Depending on the specific application and the
type of slot, setting the tool may involve pushing downward on the
wellbore tubular string 120 multiple times. Thus, when a continuous
J-slot is used, running tool 122A may be set by up and down motion
alone. This may prevent the operator from cycling through the slot
and setting shallow set barrier system 1122A prematurely.
[0046] For retrieval, the tool string or wellbore tubular string
120 is simply pulled upwardly out of the wellbore 114. This will
cause the lug 634 to re-engage the slot 638. Additionally, as the
pressure outside the shallow set barrier system 112A, and thus, the
pressure within the fluid chamber 622 is reduced, the lock 620 may
move back into the locked position, preventing any subsequent
relative movement of the lug rotator ring 636 with respect to the
sleeve 640.
[0047] While the application of pressure is disclosed above as one
triggering event to allow the lug 634 to move within the slot 638,
other events may also occur to allow the lug 634 to move within the
slot 638. In this case, the lock 620 may be configured to allow the
lug 634 to move within the slot after the triggering event has
occurred, so long as a predetermined condition is maintained. For
example, but not by way of limitation, the triggering event may be
a timer reaching a predetermined value, and the predetermined
condition may be that the timer has not yet reached a second
predetermined value.
[0048] FIG. 9 is a schematic side view of a mandrel component and a
slide lock component of a barrier system, for example, deep set
barrier system 112B of FIGS. 1-3, according to one or more aspects
of the present disclosure. The deep set barrier system 112B may
comprise a mechanical locking system 902. In one or more
embodiments, the deep set barrier system 112B may comprise a
mandrel extension 920, a mandrel 930, a slide lock 950, a spring
mandrel 960, and a spring housing 980 where the top adapter 910 and
overshot 940 as illustrated in FIG. 10 are removed. The mandrel 930
may include one or more sets 938 of external lugs 935 spaced
circumferentially about the mandrel 930. In one embodiment, the
mandrel 930 comprises four (4) sets 938 of external lugs 935,
spaced at 90-degree intervals circumferentially about the mandrel
930, and each set 938 comprises ten (10) longitudinally spaced
external lugs 935.
[0049] FIG. 10 is a schematic, cross-sectional side view of a top
adapter 910 and an overshot 940 component of a deep set barrier
system 112B, according to one or more aspects of the present
invention. The top adapter 910 and the overshot 940 are
disconnected from the remaining components of the deep set barrier
system 112B. The overshot 940 includes one or more sets 948 of
internal lugs 945 spaced apart circumferentially about the overshot
940. In an embodiment, the number and location of the internal lugs
945 on the overshot 940 corresponds directly to the number and
location of the external lugs 935 on the mandrel 930. However, in
other embodiments, a different number of internal lugs 945 and
external lugs 935 may be provided, so long as the lugs 945, 935
interact to form a releasable connection.
[0050] Further, the internal lugs 945 and the external lugs 935 are
adapted to engage as to support weight below the releasable
connection. The size and number of engaging lugs 945, 935, and more
specifically, the total cross-sectional area of engagement of the
lugs 945, 935, determines the quantity of weight that can be
supported by the deep set barrier system 112B, including, but not
limited to, the running tool 122B. In one embodiment, four (4) sets
948, 938 of ten (10) lugs 945, 935 are provided on the overshot 940
and the mandrel 930 respectively; the sets 948, 938 are spaced
apart at 90-degree intervals circumferentially; the lugs 945, 935
are each approximately 1/2-inch wide and 1/4-inch high; and the
deep set barrier system 112B is adapted to support several hundred
tons of weight, for example, 500 tons of weight. Assuming the same
size of engaging lugs 945, 935, the amount of weight that can be
supported by the deep set barrier system 112B changes linearly with
the quantity of lugs 945, 935 provided. For example, if the
embodiment described above included only half as many lugs 945,
935, the deep set barrier system 112B would be adapted to support
250 tons of weight, and if the embodiment described above included
twice as many lugs 945, 935, the deep set barrier system 112B would
be adapted to support 1,000 tons of weight. Similarly, assuming the
same quantity of engaging lugs 945, 935, the amount of weight that
can be supported by the device 100 changes linearly with the size
of the lugs 945, 935 provided. For example, if the embodiment
described above included the same quantity of lugs 945, 935 but the
lugs 945, 935 were only half the size, the device 100 would be
adapted to support 250 tons of weight, and if the embodiment
described above included the same quantity of lugs 945, 935 but the
lugs 945, 935 were twice the size, the deep set barrier system 112B
would be adapted to support 1,000 tons of weight.
[0051] As best depicted in FIG. 9 and FIG. 10, to aid with
alignment of the overshot 940 as it is being lowered over the
mandrel 930 for retrieval of the deep set barrier system 112B from
the wellbore 114, at least one set 938 of external lugs 935
comprises a tapered upper surface 936 on the uppermost external lug
935. This tapered upper surface 936 corresponds to the shape of at
least one angled alignment key 949 on the overshot 940. Thus, the
interaction between the tapered upper surface 936 on the uppermost
external lug 935 and the angled alignment key 949 guides the
overshot 940 into proper alignment so that the overshot 940 can
further be lowered over the mandrel 930.
[0052] Referring again to FIG. 9, in an embodiment, the mandrel 930
further comprises one or more J-slots 937 configured to receive at
least one angled guide key 947 on the overshot 940 as the overshot
940 is being lowered over the mandrel 930. The J-slot 937 is shown
partially covered by the slide lock 950 in FIG. 2. The interaction
between the J-slots 937 and the angled guide keys 947 imparts a
rotation of less than 360 degrees in a first direction to the
overshot 940 as it is being lowered longitudinally over the
stationary mandrel 930. In the embodiments shown herein, the
interaction between the J-slots 937 and the angled guide keys 947
imparts a maximum of a 90-degree rotation to the overshot 940. Such
rotation causes the internal lugs 945 and the external lugs 935 to
interact to form a releasable connection with the wellbore tubular
string 120. Thus, the J-slots 937 act as rotational guide slots. In
addition, the J-slots 937 may comprise V-shaped entrances 939
corresponding to the shape of the angled guide keys 947, thereby
facilitating entry of the guide keys 947 into the J-slots 937. In
another embodiment of the deep set barrier system 112B, the mandrel
930 does not include J-slots 937. In this embodiment, the overshot
940 is lowered to a known position with respect to the mandrel 930,
such as by engaging a shoulder, and then the overshot 40 is rotated
less than 360 degrees in a first direction with respect to the
mandrel 930.
[0053] To disengage the internal lugs 945 from the external lugs
935, a 45-degree rotation opposite of the first direction is
applied to the wellbore tubular string 120 from the surface of the
wellbore 114, thereby rotating the overshot 940 with respect to the
mandrel 930. To ensure that the overshot 940 is not over-rotated
with respect to the mandrel 930 during release, the mandrel 930 may
comprise a rotational stop 934 that extends between at least two of
the external lugs 935 to act as a barrier for preventing the
internal lugs 945 from reconnecting and reengaging with the
external lugs 935.
[0054] FIG. 11 is a partial schematic side view, partially in
cross-section, of a deep set barrier system 112B in a locked
configuration, according to one or more aspects of the present
disclosure. Referring first to the run-in operating sequence, FIG.
11 depicts the deep set barrier system 112B in a connected, locked,
and weight-supporting configuration. In particular, the internal
lugs 945 on the overshot 940 and the external lugs 935 on the
mandrel 930 are shown interacting to form a releasable connection,
and the upper surfaces 943 of the internal lugs 945 are shouldered
against the lower surfaces 993 of the external lugs 935, thereby
reflecting that the deep set barrier system 112B is supporting
weight. Further, a guide key 947 on the overshot 940 is shown
disposed within a J-slot 937 on the mandrel 930, and the slide lock
950 is in its uppermost, locked position, covering a portion of the
J-slot 937. The slide lock 950 is biased to the locked position by
a spring 970 disposed in the spring cavity 975 within the spring
housing 980. In this locked position, the slide lock 950 prevents
disconnection of the overshot 940 from the mandrel 930 during
run-in.
[0055] FIG. 12, is a partial schematic side view, partially in
cross-section, of a deep set barrier system 112B in a connected and
locked configuration, according to one or more aspects of the
present disclosure. Once the deep set barrier system, for example,
deep set barrier system 112B, is lowered to the specified,
required, selected or desired depth, a deep set depth, force may be
applied from the surface 104 through the wellbore tubular string
120 to manipulate the deep set barrier system 112B and particularly
the isolation device 124B. FIG. 5 depicts the deep set barrier
system 112B positioned to transfer force from the wellbore tubular
string 120B to the isolation device 124B. As force is applied
through the wellbore tubular string 120, the overshot 940 is forced
downwardly with respect to the mandrel 930 until the lower surfaces
946 of the internal lugs 945 are shouldered against the upper
surfaces 996 of the external lugs 935, thereby transferring force
to the isolation device 124B. As shown in FIG. 12, the guide key
947 on the overshot 940 has moved downwardly within the J-slot 937
on the mandrel 930, but the slide lock 950 is still biased by the
spring 970 to its uppermost, locked position.
[0056] FIGS. 13-16 depict the sequence for unlocking the deep set
barrier system 112B and rotating the overshot 940 by less than 360
degrees opposite of the first direction with respect to the mandrel
930 to allow removal of the top adapter 910 and overshot 940 from
the wellbore 114. Referring first to FIG. 13 which is a partial
schematic side view, partially in cross-section, of a deep set
barrier system 112B in a connected and unlocked configuration,
according to one or more aspects of the present disclosure. After
the one or more isolation devices 124B have been manipulated and
set in the wellbore 114, the slide lock 950 may be forced
downwardly to unlock the deep set barrier system 112B by applying a
differential pressure across the slide lock 950 against biasing
spring 970. As there is no fluid flowing through the flow bore 990
in the deep set barrier system 112B, a differential pressure can be
applied across the slide lock 950 against the spring 970 by
pressuring up the annulus 126 formed between the deep set barrier
system 112B and the casing 128. When no pressure is applied to the
annulus 126, the spring 970 expands to bias the slide lock 950
upwardly to the locked position. However, because the spring
chamber 975 is in fluid communication with the device flow bore 990
via ports 965 in the spring mandrel 960, once pressure is applied
to the annulus 126, a differential pressure is created across the
slide lock 950, thereby allowing the slide lock 950 to overcome the
bias of the spring 970 and move downwardly to the unlocked position
shown in FIG. 13 wherein the J-slot 937 is fully visible. Thus, in
one embodiment, the slide lock 950 is biased to respond to pressure
in the annulus 126.
[0057] In another embodiment, the slide lock 950 may be biased to
respond to differential pressure created by applying pressure to
the flow bore 990 rather than applying pressure to the annulus 126.
Again, because the spring chamber 975 is in fluid communication
with the flow bore 990 via ports 965 in the spring mandrel 960, by
pressuring up the fluid within the flow bore 990, a differential
pressure is created across the slide lock 950, thereby allowing the
slide lock 950 to overcome the bias of the spring 970 and move
downwardly to the unlocked position shown in FIG. 13. Thus, in the
alternative embodiment, the slide lock 940 is biased to respond to
tubing pressure.
[0058] Once the deep set barrier system 112B is unlocked, and with
the lower surface 946 of the internal lugs 945 shouldered against
the upper surface 996 of the external lugs 935, an opposite
rotation may be applied to the wellbore tubular string 120, thereby
causing the top adapter 910 and overshot 940 to rotate opposite of
the first direction with respect to the mandrel 930. The rotation
will be less than 360 degrees, and in the embodiments depicted
herein where four (4) interacting sets of lugs 938, 948 are
positioned 90 degrees apart circumferentially, the rotation will be
45 degrees. As shown in FIG. 14, as this 45-degree opposite
rotation is applied, the internal lugs 945 disengage from and move
out of alignment with the external lugs 935 to a released position.
Further, as the opposite rotation is applied, the rotational stop
934 will provide a barrier to prevent reconnection of the internal
lugs 945 with the external lugs 935.
[0059] Once the overshot 940 is released from the mandrel 930, the
top adapter 910 and the overshot 940 are removable from the
remaining components of the deep set barrier system 112B as shown
in FIG. 15. After the top adapter 910 and overshot 940 are removed,
the mandrel extension 920, the mandrel 930, the slide lock 950, the
spring mandrel 960, the spring 970, and the spring housing 980 are
still connected to the isolation device 124B within the wellbore
114 as shown in FIG. 16.
[0060] FIGS. 11-16, when viewed in reverse order, also depict a
retrieval operating sequence for the deep set barrier system 112B,
wherein the top adapter 910 and the overshot 940 are run back into
the wellbore 114 to reconnect with the mandrel 930 to withdraw the
deep set barrier system 112B including the isolation device 124B
and running tool 122B from the wellbore 114. Referring first to
FIG. 16, a partial schematic side view, partially in cross-section,
of the deep set barrier system 112B comprising the mandrel
extension 920, the mandrel 930, the slide lock 950, the spring
mandrel 960, the spring 970, and the spring housing 980 are shown
connected to the isolation device 124B within the wellbore 114. The
slide lock 950 moved upwardly over the J-slot 937 in response to
the spring 970 force since pressure was removed from the annulus
126.
[0061] FIG. 15 is a partial schematic side view, partially in
cross-section, of a deep set barrier system 112B in a released
configuration. As the top adapter 910 and overshot 940 are lowered
over the mandrel extension 920 and mandrel 930, the angled
alignment key 949 on the overshot 940 will engage the upper tapered
surface 936 of the external lugs 935 on the mandrel 930. This
engagement will cause the overshot 940 to rotate into proper
alignment with the mandrel 390 so that the sets 948 of internal
lugs 945 will fit between the sets 938 of external lugs 935 as the
overshot 940 continues moving downwardly. Therefore, regardless of
the position of the overshot 940 as it is being run into the
wellbore 114, the upper tapered surface 936 on the external lugs
935 will interact with the angles on the alignment key 949 to
properly align the overshot 940 with respect to the mandrel
930.
[0062] Further, in an embodiment, the alignment key 949 has a
longitudinal length that exceeds the distance between two of the
lugs 935 on the mandrel 930. Therefore, because the angled
alignment key 949 will not fit between two lugs 935 on the mandrel
930, the overshot 940 and mandrel 390 cannot form a partial
connection. Instead, the overshot 940 must be lowered completely
over the mandrel 930 so that when the overshot 940 is rotated to
form the releasable connection, the sets 948 of lugs 945 on the
overshot 940 and the sets 938 of lugs 935 on the mandrel 930 are
fully engaged, and the angled alignment key 949 is positioned below
the lowermost mandrel lug 935.
[0063] Referring now to FIG. 14, as the overshot 940 continues to
be lowered with respect to the mandrel 930, the angled guide key
947 will extend into the J-slot 937 via the V-shaped opening 939
while mechanically engaging a tapered upper surface 952 on the
slide lock 50, thereby forcing the slide lock 950 downwardly to an
unlocked position against the force of the spring 970. Thus, when
reconnecting the overshot 940 to the mandrel 930, no pressure is
required to be applied to the annulus 126 or to the flow bore 990
to cause the slide lock 950 to move downwardly against the spring
970 in response to differential pressure. Instead, only the
mechanical force of the angled guide key 947 acting on the tapered
upper surface 952 of the slide lock 950 is required. In an
alternative embodiment, the slide lock 950 may be actuated
electromechanically, such as by using a downhole motor to retract
the slide lock 950 in response to a tripped switch, for
example.
[0064] As the overshot 940 continues moving downwardly in a
longitudinal direction, the guide key 947 traverses the J-slot 937,
and the angled shape of the J-slot 937 will thereby impart a
maximum 990-degree rotation in the first direction to the overshot
940. As shown in FIG. 13, as the guide key 947 moves toward the
lowermost point in the J-slot 937, the internal lugs 945 of the
overshot 940 are rotated to interact with and engage the external
lugs 935 on the mandrel 930. Once the guide key 947 is no longer
engaging the slide lock 950 to mechanically force it down, the
slide lock 950 will return to the uppermost, locked position shown
in FIG. 12, in response to the bias force of the spring 970.
[0065] The running tool 122B is now reconnected and locked so that
the isolation device 124B can be retrieved from the wellbore 114.
When the deep set barrier system 112B is in the configuration shown
in FIG. 12, the isolation device 124B may be released from the
casing 128, thereby transferring weight to the interacting and
engaging lugs 945, 935. This will allow the overshot 940 to be
raised up with respect to the mandrel 930 so that the upper surface
943 of the internal lugs 945 shoulder against the lower surface 993
of the external lugs 935 as shown in FIG. 11. Still referring to
FIG. 11, when the deep set barrier system 112B is in a
weight-supporting position, in one embodiment, the guide key 947 is
positioned within a vertical portion of the J-slot 937 so that the
guide key 947 does not support any weight. Thus, the guide key 947
is not required to have the same strength as the lugs 935, 945. As
shown in FIG. 11, the connected, locked, and weight-supporting deep
set barrier system 112B is configured to retrieve the isolation
device 124B from the wellbore 114.
[0066] Thus, deep set barrier system 112B comprises a releasable,
weight-supporting connection via interacting and engaging lugs 935,
945 that can be designed to support large quantities of weight,
such as 500 tons, for example. Further, the deep set barrier system
112B facilitates easy release from an isolation device 124B, such
as when operating from a floating offshore rig, because the lugs
935, 945 are disconnected via a 45-degree opposite rotation of the
overshot 940 with respect to the mandrel 930. When reconnecting the
lugs 935, 945, a 45-degree rotation in the first direction may be
imparted automatically via a guide key 947 interacting with a
J-slot 937. The deep set barrier system 112B may further comprise
several safety features, such as a slide lock 950 that requires
multiple actions to open in the run-in position, thereby preventing
inadvertent disconnection, an alignment key 949 having a length
that prevents a partial connection between the lugs 945 of the
overshot 940 and the lugs 935 of the mandrel 930, and a rotational
stop 934 that prevents inadvertent re-connection during release of
the overshot 940 from the mandrel 930.
[0067] FIG. 17 is a flowchart illustrating a method for setting a
single-run multiple barrier system, for example, single-run
multiple barrier system 150 of FIGS. 1-3, according to one or more
aspects of the present disclosure. At Step 1102, a single-run
multiple barrier system 150 is deployed in a wellbore 114. As
discussed with respect to FIG. 1, the single-run multiple barrier
system 150 may comprise multiple barrier systems 112, for example,
shallow set barrier system 112A and deep set barrier system 112B.
In one or more embodiments, a distal end of a wellbore tubular
string 120 is coupled to the single-run multiple barrier system
150. In one or more embodiments, each component of the single-run
multiple barrier system 150 is coupled to the wellbore tubular
string 120 one by one as the wellbore tubular string 120 is ran in
the wellbore 114. For example, as wellbore tubular string 120 is
lowered into the wellbore 114, a deep set barrier system 112B is
coupled to wellbore tubular string segment 120B, wellbore tubular
string segment 120B is coupled to shallow set barrier system 112A,
shallow set barrier system 112A is coupled to wellbore tubular
string segment 120A and wellbore tubular string segment 120A is
coupled to one or more other segments of wellbore tubular string
120. The single-run multiple barrier system is initially deployed
with the shallow set barrier system 112A and the deep set barrier
system 112B in a locked configuration such that the isolation
device 124A and the isolation device 124B are not inadvertently set
during deployment of the single-run multiple barrier system 150 to
a specified, required or desired depth in the wellbore 114. For
example, the shallow set barrier system 112A may be locked as
discussed above with respect to FIGS. 6A, 7A and 8A and deep set
barrier system 112B may be locked as discussed above with respect
to FIG. 9 and FIG. 10. In one or more embodiments, the shallow set
barrier system 112A comprises a hydraulic locking feature that
prevents the isolation device 124A from being set until a specified
hydrostatic pressure is reached at the specified shallow set depth
while the deep set barrier system 112B comprises a mechanical
locking system 902 that prevents the isolation device 124B from
being set until the specific deep set depth has been reached.
[0068] At step 1106, it is determined if the setting depth for the
deep set barrier system 112B has been reached. The setting depth
may be based on one or more parameters of the formation 102, the
wellbore 114 or any other parameter or combination thereof. The
depth of each component of the single-run multiple barrier system
150 as it is deployed into the wellbore 114 may be determined by
any one or more techniques for determining depth in a wellbore 114.
For example, the length of each segment of wellbore tubular string
120 and any downhole tool attached to the wellbore tubular string
may be known such that as the wellbore tubular string 120 is ran in
the wellbore 114, the depth of the distal end of or any portion
along the wellbore tubular string 120 is known
[0069] At step 1112, once the setting depth for the deep set
barrier system 112B has been reached, deployment of the wellbore
tubular string 120 is stopped or halted and the isolation device
124B (for example, the deep set barrier) is set. For example,
actuation of motor 116 and winch 118 of FIG. 1 may be stopped,
halted or suspended. As the shallow set barrier system 112A remains
locked during deployment of the single-run multiple barrier system
150, the isolation device 124B may be set independently of the
isolation device 124A. For example, the isolation device 124B may
be set according to any one or more embodiments discussed above
with respect to FIGS. 9 and 10 while the isolation device 124A
remains locked as discussed above with respect to FIGS. 6A, 7A and
8A. In one or more embodiments, the isolation device 124B is
mechanically set with rotation of the wellbore tubular string 120,
up and down movement of the wellbore tubular string 120 or any
other manipulation of the wellbore tubular string 120.
[0070] At step 1118, the deep set barrier system 112B is
disconnected from the wellbore tubular string segment 120B. For
example, running tool 122B may be disconnected from wellbore
tubular string segment 120B as discussed below with respect to
FIGS. 13-16. In one or more embodiments, the running tool 122B may
be mechanically, hydraulically, or mechanically and hydraulically
disconnected from the wellbore tubular string segment 120B.
[0071] At step 1124, once the deep set barrier system 112B has been
disconnected from the wellbore tubular string 120, the wellbore
tubular string 120 is retracted or picked up to dispose or position
the shallow set barrier system 112A at a specified, determined,
required or selected depth, a shallow set depth. For example, motor
116 and winch 118 of FIG. 1 may be actuated to pull, retrieve or
retract one or more segments of the wellbore tubular string 120
from the wellbore 114.
[0072] At step 1130, it is determined if the setting depth for the
shallow set barrier system has been reached. The setting depth may
be based on one or more parameters of the formation 102, the
wellbore 114 or any other parameter or combination thereof. The
depth of each component of the single-run multiple barrier system
150 as it is retracted, retrieved, picked up or pulled from the
wellbore 114 may be determined by any one or more techniques for
determining depth in a wellbore as discussed above with respect to
step 1106.
[0073] At step 1136, once the setting depth for the shallow set
barrier system 112B has been reached, deployment of the wellbore
tubular string 120 is halted or stopped and the isolation device
124A (for example, the shallow set barrier) is set. For example,
actuation of motor 116 and winch 118 of FIG. 1 may be halted,
stopped or suspended. In one or more embodiments, the isolation
device 124A may be set according to any one or more embodiments
discussed above with respect to FIGS. 6B, 7B and 8B. In one or more
embodiments, the isolation device 124A is set by applying annulus
pressure to the wellbore 114 which ruptures a disk, for example,
rupture disk 412 of FIG. 4A or rupture disk 626 of FIG. 6A, to
unlock a J-slot, for example, slot 638 of FIGS. 8A and 8B, to set
the isolation device 124A as discussed above.
[0074] At step 1142, once the isolation device 124A has been set,
the running tool 122A is disconnected from the wellbore tubular
string segment 120A. For example, the running tool 122A may be
disconnected from the wellbore tubular string segment 120A
hydraulically, mechanically, or both. In one or more embodiments,
the shallow set barrier system 112A including the running tool 122A
is disconnected from the wellbore tubular string segment 120A in a
similar manner as discussed above with respect to the deep set
barrier system 112B.
[0075] At step 1148, any remaining segments of the wellbore tubular
string 120 are retracted, retrieved or tripped out of the wellbore
114. One or more other steps may be initiated once the wellbore
tubular string 120 has been tripped out of the wellbore 114 to
complete a given operation.
[0076] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. Also, the terms in the claims have their
plain, ordinary meaning unless otherwise explicitly and clearly
defined by the patentee.
[0077] In one or more embodiments, a method of setting a single-run
multiple barrier system comprises deploying a single-run multiple
barrier system on a wellbore tubular string in a wellbore of a
formation, wherein the single-run multiple barrier system comprises
a deep set barrier system at a distal end of the wellbore tubular
string and a shallow set barrier above the deep set barrier system,
determining if a first depth in the wellbore has been reached by
the single-run multiple barrier system, setting a first isolation
device of the deep set barrier system, wherein the shallow set
barrier system comprises a rupture disk that prevents a lug from
moving within a continuous j-slot to prevent setting of the shallow
set barrier system during setting of the first isolation device,
disconnecting the deep set barrier system from the wellbore tubular
string, retrieving the wellbore tubular string to a second depth,
setting a second isolation device of the shallow set barrier
system, disconnecting the shallow set barrier system from the
wellbore tubular string. In one or more embodiments, setting the
second device comprises rupturing the rupture disk, allowing the
lug to move within the continuous j-slot and lifting upward and
pushing downward on the wellbore tubular string. In one or more
embodiments, the first isolation device is coupled to a first
running tool, and wherein disconnecting the deep set barrier system
from the wellbore tubular string comprises disengaging the first
running tool from the wellbore tubular string. In one or more
embodiments, the shallow set barrier system is coupled to a second
running tool, wherein the second running tool is coupled to the
wellbore tubular string, and wherein disconnecting the shallow set
barrier system from the wellbore tubular string comprises
disengaging the second running tool from the wellbore tubular
string. In one or more embodiments, the method further comprises
extending one or more first projections of one or more first
anchors of the deep set barrier system to contact at least one of
the wellbore, an annulus disposed within the wellbore, and a casing
disposed within the wellbore. In one or more embodiments, the
method further comprises extending one or more second projections
of one or more second anchors of the shallow set barrier system to
contact at least one of the wellbore, an annulus disposed within
the wellbore, and a casing disposed within the wellbore. In one or
more embodiments, the method further comprises maintaining
positioning of the first isolation device in an annulus of the
wellbore via a first centralizer. In one or more embodiments, the
method further comprises maintaining positioning of the second
isolation device in an annulus of the wellbore via a second
centralizer. In one or more embodiments, at least one of the first
setting depth and the second setting depth is based on one or more
parameters of the formation. In one or more embodiments, the method
further comprises retrieving the wellbore tubular string from the
wellbore.
[0078] In one or more embodiments, a single-run multiple barrier
system comprises a deep set barrier system, wherein the deep set
barrier system comprises a first isolation device and a first
running tool, wherein the first running tool couples to a first
portion of a wellbore tubular string, a shallow set barrier system,
wherein the shallow set barrier system comprises a second isolation
device and second running tool, wherein the second running tool
couples to a second portion of a wellbore tubular string, and a
locking assembly of the shallow set barrier system, wherein the
locking assembly is locked and unlocked independent of the deep set
barrier system. In one or more embodiments, the locking assembly
comprises a rupture disk that prevents a lug from moving within a
continuous j-slot to prevent setting of the shallow set barrier
system during setting of the first isolation device. In one or more
embodiments, the lug moves within the continuous j-slot when the
rupture disk ruptures to set the second isolation device. In one or
more embodiments, the deep set barrier system further comprises a
first running tool coupled to the first isolation device and the
wellbore tubular string and wherein the first running tool
disconnects from the wellbore tubular string to set the first
isolation device and reconnects with the wellbore tubular string to
retrieve the first isolation device. hi one or more embodiments,
the shallow set barrier system further comprises a second running
tool coupled to the second isolation device and the wellbore
tubular string and wherein the second running tool disconnects from
the wellbore tubular string to set the second isolation device and
reconnects with the wellbore tubular string to retrieve the second
isolation device. In one or more embodiments, the deep set barrier
system further comprises one or more first anchors and one or more
first projections of the one or more first anchors, wherein the one
or more first projections extend to contact at least one of the
wellbore, an annulus disposed within the wellbore and a casing
disposed within the wellbore. In one or more embodiments, the
shallow set barrier system further comprises one or more second
anchors and one or more second projections of the one or more
second anchors, wherein the one or more second projections extend
to contact at least one of the wellbore, an annulus disposed within
the wellbore and a casing disposed within the wellbore. In one or
more embodiments, the deep set barrier system further comprises a
first centralizer. In one or more embodiments, the shallow set
barrier system further comprises a second centralizer. In one or
more embodiments the wellbore tubular string comprises a first
wellbore tubular string segment coupled to the first running tool
and the shallow set barrier system and a second wellbore tubular
string segment coupled to the second running tool, wherein the
first running tool disengages from the first wellbore tubular
string segment to set the deep set barrier system, and wherein the
second running tool disengages from the second wellbore tubular
string segment to set the shallow set barrier system.
* * * * *