U.S. patent application number 17/491956 was filed with the patent office on 2022-04-07 for method of using hydraulic activation chambers for anchoring downhole equipment.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Espen Dahl, Morten Falnes, Gavin Lafferty.
Application Number | 20220106847 17/491956 |
Document ID | / |
Family ID | 1000005928665 |
Filed Date | 2022-04-07 |
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United States Patent
Application |
20220106847 |
Kind Code |
A1 |
Dahl; Espen ; et
al. |
April 7, 2022 |
METHOD OF USING HYDRAULIC ACTIVATION CHAMBERS FOR ANCHORING
DOWNHOLE EQUIPMENT
Abstract
Provided, in one aspect, is an anchor for use with a downhole
tool in a wellbore, a well system, and a method for anchoring a
downhole tool within a wellbore. The anchor, according to this
aspect, may include a base pipe, and two or more hydraulic
activation chambers disposed radially about the base pipe, the two
or more hydraulic activation chambers configured to move from a
first collapsed state to a second activated state to engage with a
wall of a wellbore and laterally and rotationally fix a downhole
tool coupled to the base pipe within the wellbore.
Inventors: |
Dahl; Espen; (Stavanger,
NO) ; Falnes; Morten; (Sola, NO) ; Lafferty;
Gavin; (Peterhead, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
1000005928665 |
Appl. No.: |
17/491956 |
Filed: |
October 1, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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63086912 |
Oct 2, 2020 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 23/01 20130101;
E21B 7/061 20130101 |
International
Class: |
E21B 23/01 20060101
E21B023/01; E21B 7/06 20060101 E21B007/06 |
Claims
1. An anchor for use with a downhole tool in a wellbore,
comprising: a base pipe; and two or more hydraulic activation
chambers disposed radially about the base pipe, the two or more
hydraulic activation chambers configured to move from a first
collapsed state to a second activated state to engage with a wall
of a wellbore and laterally and rotationally fix a downhole tool
coupled to the base pipe within the wellbore.
2. The anchor as recited in claim 1, further including an
expandable medium disposed about the two or more hydraulic
activation chambers, the expandable medium configured to expand
radially via the two or more hydraulic activation chambers to fix
the downhole tool within the wellbore.
3. The anchor as recited in claim 2, wherein the expandable medium
is an expandable non-filter medium.
4. The anchor as recited in claim 1, further including two or more
bridging plates positioned radially about the two or more
expandable chambers, wherein the two or more bridging plates are
configured to extend across at least a gap between outer portions
of the two or more expandable chambers when the two or more
hydraulic activation chambers are in the second activated
state.
5. The anchor as recited in claim 1, further including a plurality
of openings in the base pipe, the plurality of openings configured
to provide fluid communication between the base pipe and the two or
more hydraulic activation chambers to move the two or more
hydraulic activation chambers from the first collapsed state to the
second activated state.
6. The anchor as recited in claim 5, wherein the plurality of
openings are a first plurality of openings, and further including a
second plurality of openings in the base pipe, the second plurality
of openings configured to provide fluid communication between the
base pipe and an annulus surrounding the base pipe when the two or
more hydraulic activation chambers are in the second activated
state.
7. The anchor as recited in claim 6, further including a valve
coupled to the base pipe, the valve having a first setting that
closes fluid communication to the first plurality of openings and
the second plurality of openings, a second setting that only opens
fluid communication to the first plurality of openings, and a third
setting that only opens fluid communication to the second plurality
of openings.
8. The anchor as recited in claim 1, further including an
elastomeric element positioned about the two or more hydraulic
activation chambers.
9. The anchor as recited in claim 8, wherein the elastomeric
element is an annular elastomeric element configured as an annular
seal.
10. The anchor as recited in claim 1, wherein the base pipe has a
length (l.sub.bp) at least 10 times a diameter (d) of the base
pipe, and further wherein the two or more hydraulic activation
chambers extend along at least a portion of the length
(l.sub.bp).
11. The anchor as recited in claim 10, wherein the length
(l.sub.bp) of the base pipe is at least 2 meters long and a length
(l.sub.ac) of the two or more hydraulic activation chambers is at
least 1.5 meters long.
12. The anchor as recited in claim 10, wherein the length
(l.sub.bp) of the base pipe is at least 4 meters long and a length
(l.sub.ac) of the two or more hydraulic activation chambers is at
least 3 meters long.
13. The anchor as recited in claim 10, wherein the length
(l.sub.bp) of the base pipe is at least 10 meters long and a length
(l.sub.ac) of the two or more hydraulic activation chambers is at
least 7.5 meters long.
14. The anchor as recited in claim 1, wherein at least four
hydraulic activation chambers are disposed radially about the base
pipe.
15. A well system, comprising: a wellbore; a downhole tool
positioned within the wellbore; and an anchor coupled to the
downhole tool and positioned within the wellbore, the anchor
including: a base pipe; and two or more hydraulic activation
chambers disposed radially about the base pipe, the two or more
hydraulic activation chambers configured to move from a first
collapsed state to a second activated state to engage with a wall
of the wellbore and laterally and rotationally fix the downhole
tool within the wellbore.
16. The well system as recited in claim 15, wherein the downhole
tool is a lower completion.
17. The well system as recited in claim 16, wherein the lower
completion includes production tubing having a screen assembly.
18. The well system as recited in claim 17, wherein the downhole
tool is coupled to a downhole end of the anchor, and further
wherein the anchor is configured to laterally and rotationally fix
the production tubing having the screen assembly within the
wellbore.
19. The well system as recited in claim 15, wherein the wellbore is
a main wellbore, and further including a lateral wellbore extending
from the main wellbore, wherein the downhole tool forms at least a
portion of a multilateral junction positioned proximate an
intersection between the main wellbore and the lateral
wellbore.
20. The well system as recited in claim 19, wherein the downhole
tool is a whipstock, the anchor laterally and rotationally fixing
the whipstock within the wellbore.
21. The well system as recited in claim 19, wherein the downhole
tool forms at least a portion of a first multilateral junction, the
anchor is a first anchor and the lateral wellbore is a first
lateral wellbore, and further including: a second downhole tool
positioned within the wellbore; and a second anchor coupled to the
second downhole tool and positioned within the wellbore, the second
anchor including; a second base pipe; and a second set of two or
more hydraulic activation chambers disposed radially about the
second base pipe, the second set of two or more hydraulic
activation chambers configured to move from the first collapsed
state to the second activated state to engage with the wall of the
wellbore and laterally and rotationally fix the second downhole
tool within the wellbore.
22. The well system as recited in claim 21, wherein the second
downhole tool forms at least a portion of a second multilateral
junction positioned proximate an intersection between the main
wellbore and a second lateral wellbore.
23. The well system as recited in claim 19, wherein the main
wellbore and the lateral wellbore have a similar open hole
diameter.
24. The well system as recited in claim 19, wherein the whipstock
includes a through bore extending entirely there through.
25. The well system as recited in claim 15, further including an
expandable medium disposed about the two or more hydraulic
activation chambers, the expandable medium configured to expand
radially via the two or more hydraulic activation chambers to fix
the downhole tool within the wellbore.
26. The well system as recited in claim 25, wherein the expandable
medium is an expandable non-filter medium.
27. The well system as recited in claim 15, wherein the wellbore is
an open hole wellbore.
28. A method for anchoring a downhole tool within a wellbore,
comprising: positioning a downhole tool within a wellbore, the
downhole tool having an anchor coupled thereto, the anchor
including: a base pipe; and two or more hydraulic activation
chambers disposed radially about the base pipe; and applying fluid
pressure to the two or more hydraulic activation chambers to move
the two or more hydraulic activation chambers from a first
collapsed state to a second activated state to engage with a wall
of the wellbore and laterally and rotationally fix the downhole
tool within the wellbore.
29. The method as recited in claim 28, further including an
expandable medium disposed about the two or more hydraulic
activation chambers, the expandable medium expanding radially when
applying the fluid pressure to the two or more hydraulic activation
chambers to fix the downhole tool within the wellbore.
30. The method as recited in claim 28, wherein positioning a
downhole tool within a wellbore includes positioning a lower
completion including production tubing having a screen assembly
within a wellbore, the applying laterally and rotationally fixing
the lower completion including the production tubing having the
screen assembly within the wellbore.
31. The method as recited in claim 28, wherein the wellbore is a
main wellbore, and further including a lateral wellbore extending
from the main wellbore, wherein positioning a downhole tool within
a wellbore includes positioning a downhole tool forming at least a
portion of a multilateral junction proximate an intersection
between the main wellbore and the lateral wellbore.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Application Ser. No. 63/086,912, filed on Oct. 2, 2020, entitled
"METHOD OF USING EHS TECHNOLOGY FOR ANCHORING DOWNHOLE EQUIPMENT,"
commonly assigned with this application and incorporated herein by
reference in its entirety.
BACKGROUND
[0002] The unconventional market is very competitive. The market is
trending towards longer horizontal wells to increase reservoir
contact. Multilateral wells offer an alternative approach to
maximize reservoir contact. Multilateral wells include one or more
lateral wellbores extending from a main wellbore. A lateral
wellbore is a wellbore that is diverted from the main wellbore or
another lateral wellbore.
[0003] The lateral wellbores are typically formed by positioning
one or more deflector assemblies at desired locations in the main
wellbore (e.g., an open hole section or cased hole section) with a
running tool. The deflector assemblies are often laterally and
rotationally fixed within the main wellbore using a wellbore
anchor.
BRIEF DESCRIPTION
[0004] Reference is now made to the following descriptions taken in
conjunction with the accompanying drawings, in which:
[0005] FIG. 1 illustrates a schematic view of a well system
designed, manufactured and operated according to one or more
embodiments disclosed herein;
[0006] FIGS. 2A and 2B illustrate one embodiment of an anchor
designed and manufactured according to one or more embodiments of
the disclosure;
[0007] FIGS. 3A through 5B illustrate various different views of an
anchor designed, manufactured and operated according to one or more
embodiments of the disclosure at different operational states;
[0008] FIGS. 6 through 18 illustrate cross-sectional views of a
multilateral well designed, manufactured and operated according to
one or more embodiments of the disclosure;
[0009] FIG. 19 illustrates a cross-sectional view of a multilateral
well designed, manufactured and operated according to one or more
alternative embodiments of the disclosure; and
[0010] FIG. 20 illustrate a high-level reservoir architecture
according to one or more embodiments of the disclosure.
DETAILED DESCRIPTION
[0011] In the drawings and descriptions that follow, like parts are
typically marked throughout the specification and drawings with the
same reference numerals, respectively. The drawn figures are not
necessarily to scale. Certain features of the disclosure may be
shown exaggerated in scale or in somewhat schematic form and some
details of certain elements may not be shown in the interest of
clarity and conciseness. The present disclosure may be implemented
in embodiments of different forms.
[0012] Specific embodiments are described in detail and are shown
in the drawings, with the understanding that the present disclosure
is to be considered an exemplification of the principles of the
disclosure, and is not intended to limit the disclosure to that
illustrated and described herein. It is to be fully recognized that
the different teachings of the embodiments discussed herein may be
employed separately or in any suitable combination to produce
desired results.
[0013] Unless otherwise specified, use of the terms "connect,"
"engage," "couple," "attach," or any other like term describing an
interaction between elements is not meant to limit the interaction
to direct interaction between the elements and may also include
indirect interaction between the elements described. Unless
otherwise specified, use of the terms "up," "upper," "upward,"
"uphole," "upstream," or other like terms shall be construed as
generally away from the bottom, terminal end of a well; likewise,
use of the terms "down," "lower," "downward," "downhole," or other
like terms shall be construed as generally toward the bottom,
terminal end of a well, regardless of the wellbore orientation. Use
of any one or more of the foregoing terms shall not be construed as
denoting positions along a perfectly vertical axis. Unless
otherwise specified, use of the term "subterranean formation" shall
be construed as encompassing both areas below exposed earth and
areas below earth covered by water such as ocean or fresh
water.
[0014] The disclosure describes a new method for anchoring
equipment in a wellbore. The deflector assembly is used to start a
second hole section from the first section, consequently creating
an open hole junction at the deflector assembly. The term "open
hole", as used herein, means that at least that section of the
wellbore includes no casing, thereby exposing the subterranean
formation. The junction may be later completed with a pressure
tight TAML (Technology Advancements of Multi-Laterals) level 5
junction. In certain situations, no cement surrounds the
multilateral junction, but in other situations, cement may surround
at least a portion of the multilateral junction. In one or more
embodiments, both the open hole wellbore anchor and the open hole
deflector assembly can be produced there through.
[0015] Open hole wellbore anchors do exist in the marketplace, but
usually feature an anchoring mechanism that spans a relatively
short distance or with a setting range limiting the application to
wellbores with little variance in internal diameter (ID). A
wellbore anchor designed according to the present disclosure may
have a setting range of 15% or more of the run-in-hole diameter.
For example, if the wellbore anchor were to have a diameter (x)
when run in hole, the expanded diameter (x') could be 1.15.times.
or more (e.g., 8.5'' to 10'' or more). Washed out/caved in areas or
uneven ID in general is often seen when surveying a drilled section
and finding a suitable location/depth for an open hole anchor can
thus be difficult. Furthermore, the traditional open hole wellbore
anchor relies on a certain formation strength of the rock in order
to hold the required axial and torsional loads.
[0016] There are no other open hole wellbore anchors that offer the
same wellbore contact (contact area) or setting range as envisaged
with the disclosed wellbore anchor. The contact area is believed to
provide superior axial and torsional ratings. Since the disclosed
wellbore anchor, in at least one embodiment, is activated by
pressurized fluid in two or more separate chambers that spans
several meters or more across the length of the anchor, it is
believed to conform to any irregularities in the wellbore and is
thus less sensitive to an even internal diameter (ID) in the
setting area. Furthermore, by design the disclosed wellbore anchor
will help supporting and stabilizing the formation by exerting
pressure against the wellbore ID, thereby making it less sensitive
to weaker formations compared to a mechanical anchor, which to a
larger degree relies on a competent formation. A wellbore anchor
according to the present disclosure provides the ability to have
communication from tubing to annulus, if required, even after being
set, which is not known in the art. This feature offers the ability
to perform circulation of fluid and/or a return path for pumping
cement operation.
[0017] An alternative setting method could be to have a tail pipe
below the running tool, which straddles the setting ports/valve
assembly of the wellbore anchor. It is envisioned that an
elastomeric element could be added to an alternate wellbore anchor
design if an annular seal would be required.
[0018] The proposed method may prove useful in applications where
equipment such as a whipstock needs to be run through a restriction
and anchored in a larger ID below the restriction (e.g.,
through-tubing applications, where a new lateral is drilled from an
existing production tubing). Downhole equipment is required to pass
through upper completion restrictions and set in the tubing ID
deeper in the well.
[0019] FIG. 1 is a schematic view of a well system 100 designed,
manufactured and operated according to one or more embodiments
disclosed herein. The well system 100 includes a platform 120
positioned over a subterranean formation 110 located below the
earth's surface 115. The platform 120, in at least one embodiment,
has a hoisting apparatus 125 and a derrick 130 for raising and
lowering one or more downhole tools including pipe strings, such as
a drill string 140. Although a land-based oil and gas platform 120
is illustrated in FIG. 1, the scope of this disclosure is not
thereby limited, and thus could potentially apply to offshore
applications. The teachings of this disclosure may also be applied
to other land-based well systems different from that
illustrated.
[0020] As shown, a main wellbore 150 has been drilled through the
various earth strata, including the subterranean formation 110. The
term "main" wellbore is used herein to designate a wellbore from
which another wellbore is drilled. It is to be noted, however, that
a main wellbore 150 does not necessarily extend directly to the
earth's surface, but could instead be a branch of yet another
wellbore. A casing string 160 may be at least partially cemented
within the main wellbore 150. The term "casing" is used herein to
designate a tubular string used to line a wellbore. Casing may
actually be of the type known to those skilled in the art as a
"liner" and may be made of any material, such as steel or composite
material and may be segmented or continuous, such as coiled tubing.
The term "lateral" wellbore is used herein to designate a wellbore
that is drilled outwardly from its intersection with another
wellbore, such as a main wellbore. Moreover, a lateral wellbore may
have another lateral wellbore drilled outwardly therefrom.
[0021] A whipstock 170 according to one or more embodiments of the
present disclosure may be positioned at a location in the main
wellbore 150. Specifically, the whipstock 170 could be placed at a
location in the main wellbore 150 where it is desirable for a
lateral wellbore 180 to exit. Accordingly, the whipstock 170 may be
used to support a milling tool used to penetrate a window in the
main wellbore 150, and once the window has been milled and a
lateral wellbore 180 formed, in some embodiments, the whipstock 170
may be retrieved and returned uphole by a retrieval tool, in some
embodiments in only a single trip.
[0022] In some embodiments, an anchor 190 may be placed downhole in
the wellbore 150 to support and anchor downhole tools, such as the
whipstock 170, for maintaining the whipstock 170 in place while
drilling the lateral wellbore 180. The anchor 190, in accordance
with the disclosure, may be employed in an open-hole section of the
main wellbore 150, or alternatively in cased section of the main
wellbore 150. As such, the anchor 190 may be configured to resist
at least 6,750 newton meters (Nm) (e.g., about 5,000 lb-ft) of
torque. In yet another embodiment, the anchor 190 may be configured
to resist at least 13,500 newton meters (Nm) (e.g., about 10,000
lb-ft) of torque, and in yet another embodiment configured to
resist at least 20,250 newton meters (Nm) (e.g., about 15,000
lb-ft) of torque. Similarly, the anchor 190 may be configured to
resist at least 1814 kg (e.g., about 4,000 lb) of axial force. In
yet another embodiment, the anchor 190 may be configured to resist
at least 4536 kg (e.g., about 10,000 lb) of axial force, and in yet
another embodiment the anchor 190 may be configured to resist at
least 6804 kg (e.g., about 15,000 lb) of axial force. The anchor
190 may include, in some aspects, a base pipe and two or more
activation chambers disposed radially about the base pipe. The two
or more activation chambers may be configured to move from a first
collapsed state while running in hole, to a second activated state
once the anchor 190 is positioned within the main wellbore 150.
[0023] In some embodiments, the anchor 190 may be hydraulically
activated. Once the anchor 190 reaches a desired location in the
main wellbore 150, fluid pressure may be applied to the two or more
hydraulic activation chambers to move the two or more hydraulic
activation chambers from the first collapsed state to the second
activated state and engage a wall of the main wellbore 150. The
anchor 190 may also include, in some embodiments, an expandable
medium positioned radially about the two or more hydraulic
activation chambers. In some aspects, the expandable medium may be
configured to grip and engage the wall of the main wellbore 150
when the two or more hydraulic activation chambers are in the
second activated state.
[0024] In at least one embodiment, the resulting main wellbore 150
has a main wellbore open hole section, and the resulting lateral
wellbore 180 has a lateral wellbore open hole section. Further to
this embodiment, the main wellbore 150 may have a main wellbore
completion located therein, and the lateral wellbore 180 may have a
lateral wellbore completion located therein. Accordingly, in at
least one embodiment, a multilateral junction may be positioned at
an intersection between the main wellbore open hole section of the
main wellbore 150 and the lateral wellbore open hole section of the
lateral wellbore 150. In accordance with one embodiment, the
multilateral junction might include a main bore leg forming a first
pressure tight seal with the main bore completion and a lateral
bore leg forming a second pressure tight seal with the lateral bore
completion such that the main bore completion and the lateral bore
completion are hydraulically isolated from one another. What
results, in one or more embodiments, is an open hole TAML Level 5
pressure tight junction.
[0025] Turning now to FIGS. 2A and 2B, illustrated is one
embodiment of an anchor 200 designed and manufactured according to
one or more embodiments of the disclosure. FIG. 2A illustrates the
anchor 200 in the collapsed state, whereas FIG. 2B illustrates the
anchor 200 in the activated state. The anchor 200, in one
embodiment, may include a base pipe 210. The base pipe 210, in at
least on embodiment, is a metal base pipe. Nevertheless, other
embodiments exist wherein a non-metal base pipe 210 is used.
[0026] In the embodiment of FIGS. 2A ad 2B, the base pipe 210 does
not include openings connecting the interior of the base pipe 210
with the exterior of the base pipe 210. However, in yet other
embodiments, a plurality of openings may exist between the interior
of the base pipe 210 and the exterior of the base pipe 210. For
example, a first plurality of openings could be used to provide
fluid communication between the base pipe 210 and the two or more
hydraulic activation chambers to move the two or more hydraulic
activation chambers from the first collapsed state to the second
activated state. In yet another embodiment, a second plurality of
openings could be used to provide fluid communication between the
base pipe 210 and an annulus surrounding the base pipe 210 when the
two or more hydraulic activation chambers are in the second
activated state.
[0027] While not shown in FIGS. 2A and 2B, in certain embodiments,
the anchor 200 may include a valve coupled to the base pipe 210. In
at least one embodiment, the valve has a first setting that closes
fluid communication to the first plurality of openings and the
second plurality of openings, a second setting that only opens
fluid communication to the first plurality of openings, and a third
setting that only opens fluid communication to the second plurality
of openings.
[0028] Two or more hydraulic activation chambers 220 may be
positioned radially about the base pipe 210. In some embodiments,
the two or more hydraulic activation chambers 220 may be generally
linearly aligned with one another. As used herein, generally
linearly aligned may mean the two or more hydraulic activation
chambers 220 may be linearly aligned within 10 percent of their
length. In other embodiments, the two or more hydraulic activation
chambers 220 may be substantially linearly aligned with each other,
wherein the two or more two or more hydraulic activation chambers
220 may be linearly aligned within 5 percent of their length. In
still other embodiments, the two or more hydraulic activation
chambers 220 may be ideally linearly aligned, wherein the two or
more two or more hydraulic activation chambers 220 may be linearly
aligned within 1 percent of their length.
[0029] In other embodiments, the two or more hydraulic activation
chambers 220 may be generally angularly aligned, substantially
angularly aligned, or ideally angularly aligned with one another.
The term "generally angularly aligned" as used herein, means that
the two or more hydraulic activation chambers 220 are within 10
degrees of parallel with one another. The term "substantially
angularly aligned" as used herein, means that the two or more
hydraulic activation chambers 220 are within 5 degrees of parallel
with one another. The term "ideally angularly aligned" as used
herein, means that the two or more hydraulic activation chambers
220 are within 2 degrees of parallel with one another.
[0030] The two or more hydraulic activation chambers 220 may be
configured to move from the first collapsed state shown in FIG. 2A
to the second activated state shown in FIG. 2B to engage a wall of
a wellbore. In some embodiments, when in the second activated
state, the two or more hydraulic activation chambers 220 may be
operable to handle at least 20.7 Bar (about 300 psi) of internal
pressure in the second activated state to engage the wall of a
wellbore. In some embodiments, when in the second activated state,
the two or more hydraulic activation chambers 220 may be operable
to handle at least 27.6 Bar (about 400 psi) of internal pressure in
the second activated state to engage the wall of a wellbore. In
some embodiments, when in the second activated state, the two or
more hydraulic activation chambers 220 may be operable to handle at
least 51.7 Bar (about 750 psi) of internal pressure in the second
activated state to engage the wall of a wellbore. In some
alternative embodiments, when in the second activated state, the
two or more hydraulic activation chambers 220 may be operable to
handle at least 68 Bar (about 1000 psi) of internal pressure in the
second activated state to engage the wall of a wellbore.
[0031] In some embodiments, the anchor 200 may include an
expandable medium 230, which may be positioned radially about the
two or more hydraulic activation chambers 220. In certain
embodiments, the expandable medium 230 may be configured to split
apart or deform as the two or more hydraulic activation chambers
220 expand into the second activated state such that the expandable
medium 230 may thereafter engage and dig into the wall of the
wellbore. In at least one embodiment, the expandable medium 230 is
an exterior sleeve. In at least one other embodiment, the
expandable medium 230 is a non-filter medium, and thus does not
function to filter sand or other similar particulate matter.
[0032] The expandable medium 230 may include openings 235 therein.
The openings 235, in certain embodiments, allow for the expandable
medium 230 to easily expand. The general size and shape of the
openings 235 may vary greatly and remain within the scope of the
disclosure. In at least one embodiment, the openings 235 are larger
than the opening in a typical sand screen. For example, the
openings 235 might have a mesh value of at least about 36 (e.g.,
485 .mu.m) or greater. In yet another embodiment, the openings 235
might have a mesh value of at least about 20 (e.g., 850 .mu.m) or
greater, or in yet another embodiment the openings 235 might have a
mesh value of at least about 10 (e.g., 2,000 .mu.m) or greater.
[0033] The expandable medium 230, in certain other embodiments, may
include a textured surface on an outer surface thereof for engaging
the wall of the wellbore. In certain instances, the textured
surface has a plurality of undulations, crenellations,
corrugations, ridges, depressions, or other surface variations
where the radial amplitude of the surface variation is at least
about 1 mm (e.g., about 0.04 inches). In yet another embodiment,
the radial amplitude of the surface variation is at least about
1.25 mm (e.g., about 0.05 inches), and in yet another embodiment
the radial amplitude of the surface variation is between about 1.25
mm (e.g., about 0.06 inches) and about 25 mm (e.g., about 1.0
inches). Any known or hereafter discovered method for creating the
textured surface is within the scope of the disclosure. The
expandable medium 230 may comprise metals, carbide, polymers, and
other materials used in downhole tool applications.
[0034] In some embodiments, an elastomeric element 237 may be
positioned about the two or more hydraulic activation chambers 220,
whether directly about the two or more hydraulic activation
chambers 220, about the expandable medium 230, or form all or part
of the expandable medium 230. In yet another embodiment, the
elastomeric element 237 is an annular elastomeric element
configured as an annular seal. The elastomeric element 237 (e.g.,
swellable elastomer in some embodiments) may be activated by
temperature alone, fluid existing in the wellbore, completion fluid
inserted into the wellbore, or any combination of the above. In an
alternative embodiment, the elastomeric element 237 may be
activated by a dedicated well treatment run to pump activation
fluid to the elastomeric element 237.
[0035] In certain embodiments, two or more bridging plates 240 may
be positioned radially about the two or more hydraulic activation
chambers 220. The two or more bridging plates 240 may be configured
to extend across at least a gap between outer portions of the two
or more hydraulic activation chambers 220 when the two or more
hydraulic activation chambers 220 are in the second activated state
as shown in FIG. 2B. The two or more bridging plates 240 may be
configured, in some aspects, to provide support for the expandable
medium 230 positioned about the two or more hydraulic activation
chambers 220. While it is illustrated that the two or more bridging
plates 240 include openings therein, other embodiments may exist
wherein the two or more bridging plates 240 do not include openings
therein. Although not shown in the illustrated embodiment, certain
embodiments of the two or more bridging plates 240 may include
protrusions or a textured surface which may engage the wall of the
wellbore, and in some embodiments, the protrusions may extend
through the openings 235 in the expandable medium 230.
[0036] While the embodiment of FIGS. 2A and 2B illustrate the
existence of the expandable medium 230 and the two or more bridging
plates 240, other embodiments exist wherein the two or more
hydraulic activation chambers 220 are fixed to the base pipe 210.
In such an embodiment, the two or more hydraulic activation
chambers 220 are unencumbered, and thus may engage directly with
the wellbore when in the second activated state illustrated in FIG.
2B.
[0037] Turning to FIGS. 3A through 5B, illustrated are various
different views of an anchor 300 designed, manufactured and
operated according to one or more embodiments of the disclosure at
different operational states. FIGS. 3A and 3B illustrate a partial
sectional view and a cross-sectional view, respectively, of the
anchor 300 at a run-in hole state, FIGS. 4A and 4B illustrate a
partial sectional view and a cross-sectional view, respectively, of
the anchor 300 when a first plurality of opening are in fluid
communication with the two or more hydraulic activation chambers,
and FIGS. 5A and 5B illustrate a partial sectional view and a
cross-sectional view, respectively, of the anchor 300 when a second
plurality of opening are in fluid communication with an annulus
surrounding the base pipe.
[0038] The anchor 300 illustrated in FIGS. 3A through 5B initially
includes a base pipe 310, and two or more hydraulic activation
chambers 320 (e.g., at least four hydraulic activation chambers in
one embodiment) disposed radially about the base pipe 310, the two
or more hydraulic activation chambers 320 configured to move from a
first collapsed state (e.g., as shown in FIGS. 3A and 3B) to a
second activated state (e.g., as shown in FIGS. 4A through 5B) to
engage with a wall of a wellbore and laterally and rotationally fix
a downhole tool coupled to the base pipe 310 within the wellbore.
In the illustrated embodiment, the base pipe 310 has a length
(l.sub.bp) at least 10 times a diameter (d) of the base pipe 310,
and the two or more hydraulic activation chambers extending along
at least a portion of the length (l.sub.bp). In yet another
embodiment, the length (l.sub.bp) of the base pipe 310 is at least
2 meters long and a length (l.sub.ac) of the two or more hydraulic
activation chambers 320 is at least 1.5 meters long. In at least
one other embodiment, the length (l.sub.bp) of the base pipe 310 is
at least 4 meters long and the length (l.sub.ac) of the two or more
hydraulic activation chambers 320 is at least 3 meters long. In yet
another embodiment, the length (l.sub.bp) of the base pipe 310 is
at least 10 meters long and the length (l.sub.ac) of the two or
more hydraulic activation chambers 320 is at least 7.5 meters
long.
[0039] The base pipe 310, in at least one embodiment, includes a
first plurality of openings 312, the first plurality of openings
312 configured to provide fluid communication between the base pipe
310 and the two or more hydraulic activation chambers 320 to move
the two or more hydraulic activation chambers 320 from the first
collapsed state (e.g., shown in FIGS. 3A and 3B) to the second
activated state (e.g., shown in FIGS. 4A through h5B). The base
pipe, in at least one other embodiment, includes a second plurality
of openings 314, the second plurality of openings 314 configured to
provide fluid communication between the base pipe 310 and an
annulus 316 surrounding the base pipe 310 when the two or more
hydraulic activation chambers 320 are in the second activated
state.
[0040] In the illustrated embodiment of FIGS. 3A through 5B, the
anchor 300 additionally includes a valve 318 coupled to the base
pipe 310. The valve 318, in one or more embodiments, includes a
first setting that closes fluid communication to the first
plurality of openings 312 and the second plurality of openings 314,
a second setting that only opens fluid communication to the first
plurality of openings 312, and a third setting that only opens
fluid communication to the second plurality of openings 314. While
the valve 318 has been illustrated as a sliding sleeve valve in
FIGS. 3A through 5B, other types of valves may be used and remain
within the scope of the disclosure.
[0041] With reference to FIGS. 3A and 3B, the valve 318 is at the
first setting, wherein fluid communication to the first plurality
of openings 312 and the second plurality of openings 314 is closed,
and thus fluid 350 may bypass the anchor 300. Accordingly, the two
or more hydraulic activation chambers 320 remain in the first
collapsed state.
[0042] With reference to FIGS. 4A and 4B, the valve 318 is at the
second setting, wherein fluid communication is only open to the
first plurality of openings 312. Accordingly, fluid 360 may enter
the two or more hydraulic activation chambers 320 and move them to
the second activated state. In at least one embodiment, the fluid
360 plastically deforms the two or more hydraulic activation
chambers 320, such that they may remain in the second activated
state regardless of the setting of the valve 318. In yet another
embodiment, the valve 318 moves from the second state to either of
the first state or the third state while the two or more hydraulic
activation chambers 320 are under pressure. Accordingly, the
pressurized fluid 360 may be trapped within the two or more
hydraulic activation chambers 320, thereby keeping them in the
second activated state.
[0043] With reference to FIGS. 5A and 5B, the valve 318 is at the
third setting, wherein fluid communication is only open to the
second plurality of openings 314. Accordingly, fluid 370 may move
between the base pipe 310 and the annulus 316 surrounding the base
pipe 310 when the two or more hydraulic activation chambers 320 are
in the second activated state.
[0044] Turning now to FIGS. 6 through 18, illustrated are
cross-sectional views of a multilateral well 600 designed,
manufactured and operated according to one or more embodiments of
the disclosure. The multilateral well 600 illustrated in the
embodiment of FIG. 6 includes a larger uphole casing section 610
and a smaller downhole casing section 620. The multilateral well
600 additionally includes an open hole main wellbore 630. For
example, in the illustrated embodiment of FIG. 6, a drilling
assembly 640 including a drill bit 650 is being deployed within the
multilateral well 600 to form the main wellbore 630.
[0045] Turning to FIG. 7, illustrated is the multilateral well 600
of FIG. 6 after positioning a downhole tool 700 within the main
wellbore 630 using a downhole conveyance 780. The downhole tool
700, in one or more embodiments, includes a main bore completion
710 (e.g., including a sand screen 712 and one or more main bore
completion sealing elements 714). The downhole tool 700
additionally includes an anchor 720. The anchor 720, in one or more
embodiments, may be similar to one or more of the anchors discussed
above with regard to FIGS. 1 through 5B. Accordingly, the anchor
720 may include a base pipe, and two or more hydraulic activation
chambers disposed radially about the base pipe, the two or more
hydraulic activation chambers configured to move from a first
collapsed state to a second activated state to engage with a wall
of a wellbore (e.g., main wellbore 630) and laterally and
rotationally fix the downhole tool 700 therein. In the illustrated
embodiment, the anchor 720 is coupled uphole of the main bore
completion 710, and is in the radially retracted state.
[0046] The downhole tool 700 may additionally include an anchor
setting tool 730. The anchor setting tool 730, in one or more
embodiments, may include a check valve, shearable ball-seat,
flapper valve, rupture disc or similar device for setting the
anchor 720. The downhole tool may additionally include a whipstock
740 (e.g., an open hole whipstock with pre-installed running tool)
having a through bore extending entirely therethrough. The
whipstock 740, as those skilled in the art appreciate, may be used
(e.g., along with a drill bit) to drill a lateral wellbore off of
the main wellbore 630. In at least one embodiment, the downhole
tool 700 additionally includes a swivel 750. The swivel 750, in one
or more embodiments, allows for the orientation of the whipstock
740 without turning the entire main bore completion 710.
[0047] The downhole conveyance 780 illustrated in FIG. 7 includes a
circulation sub 785, as well as a work-string orientation tool
(WOT) or measuring while drilling tool (MWD) 790. The WOT or MWD
790 may be used to enable a tool face reading of the whipstock 740
for orientation purposes.
[0048] Turning to FIG. 8, illustrated is the multilateral well 600
of FIG. 7 after orienting the whipstock 740. For example, when at
depth, fluid could flow through the circulation sub 785 to obtain a
whipstock 740 tool face orientation. In at least one embodiment,
such as that shown, the whipstock 740 is oriented to a high side of
the main wellbore 630. Nevertheless, other orientations are within
the scope of the disclosure
[0049] Turning to FIG. 9, illustrated is the multilateral well 600
of FIG. 8 after activating/deploying the anchor 720. The anchor 720
may be activated/deployed by first setting its valve to its second
position, and then pressuring up on the two or more hydraulic
activation chambers to move the two or more hydraulic activation
chambers from their first collapsed state to their second activated
state. In at least one embodiment, a pre-determined activation
pressure is maintained for a period of time to fully activate the
anchor 720.
[0050] In at least one embodiment, an optional push/pull test may
be performed on the anchor 720 to confirm that it is fully
activated. Thereafter, pressure may be applied to the downhole
conveyance 780 to release it from the whipstock 740. Thereafter,
the downhole conveyance 780 may be pulled out of the main wellbore
630.
[0051] Turning to FIG. 10, illustrated is the multilateral well 600
of FIG. 9 after deploying a drilling assembly 1040 including a
drill bit 1050 within the multilateral well 600 to form a lateral
rat hole 1030. The lateral rat hole 1030 is formed, in at least one
embodiment, by deflecting the drill bit 1050 off of the whipstock
740. The lateral rat hole 1030, in at least one embodiment, is a
pocket run in the formation to ensure successful
sidetrack/departure in an open hole scenario.
[0052] Turning to FIG. 11, illustrated is the multilateral well 600
of FIG. 10 after deploying the drilling assembly 1040 including the
drill bit 1050 (or an alternative drilling assembly including an
alternative drill bit) to complete a lateral wellbore 1130 within
the multilateral well 600. The lateral wellbore 1130 may be drilled
to depth as planned. In one or more embodiments, the lateral
wellbore 1130 may extend up to 10,000 meters from the main wellbore
630. As shown in FIG. 11, the main wellbore 630 includes a main
wellbore open hole section 1150, and the lateral wellbore 1130
includes a lateral wellbore open hole section 1160.
[0053] Turning to FIG. 12, illustrated is the multilateral well 600
of FIG. 11 after positioning a downhole tool 1200 within the
lateral wellbore 1130 using a downhole conveyance 1280. The
downhole tool 1200, in one or more embodiments, includes a lateral
bore completion 1210 (e.g., including a sand screen 1212 and one or
more main bore completion sealing elements 1214). The downhole tool
1200 may additionally include an anchor 1220. The anchor 1220, in
one or more embodiments, may be similar to one or more of the
anchors discussed above with regard to FIGS. 1 through 5B.
Accordingly, the anchor 1220 may include a base pipe, and two or
more hydraulic activation chambers disposed radially about the base
pipe, the two or more hydraulic activation chambers configured to
move from a first collapsed state to a second activated state to
engage with a wall of a wellbore (e.g., lateral wellbore 1130) and
laterally and rotationally fix the downhole tool 1200 therein. In
the illustrated embodiment, the anchor 1220 is coupled uphole of
the lateral bore completion 1210, and is in the radially retracted
state.
[0054] Turning to FIG. 13, illustrated is the multilateral well 600
of FIG. 12 after activating/deploying the anchor 1220. The anchor
1220 may be activated/deployed by first setting its valve to its
second position, and then pressuring up on the two or more
hydraulic activation chambers to move the two or more hydraulic
activation chambers from their first collapsed state to their
second activated state. In at least one embodiment, a
pre-determined activation pressure is maintained for a period of
time to fully activate the anchor 1220.
[0055] Turning to FIG. 14, illustrated is the multilateral well 600
of FIG. 13 after employing a downhole conveyance 1480 to wash down
and clean out the whipstock 740 bore. In at least one embodiment,
the downhole conveyance 1480 is the same downhole conveyance as
used to position the downhole tool 1200 within the lateral wellbore
1130. In other embodiments, however, they are different tools.
[0056] Turning to FIG. 15, illustrated is the multilateral well 600
of FIG. 14 after positioning a multilateral junction 1500 at an
intersection between the main wellbore open hole section 1150 and
the lateral wellbore open hole section 1160. The multilateral
junction 1500, in the illustrated embodiment, includes a main bore
leg 1510 for engaging with the main bore completion 710 (e.g., by
stabbing into the whipstock 740 in one embodiment) and a lateral
bore leg 1515 for engaging with the lateral bore completion
1210.
[0057] Coupled uphole of the multilateral junction 1500, in one or
more embodiments, is another anchor 1520. The anchor 1520, in one
or more embodiments, may be similar to one or more of the anchors
discussed above with regard to FIGS. 1 through 5B. Accordingly, the
anchor 1520 may include a base pipe, and two or more hydraulic
activation chambers disposed radially about the base pipe, the two
or more hydraulic activation chambers configured to move from a
first collapsed state to a second activated state to engage with a
wall of a wellbore (e.g., main wellbore 630) and laterally and
rotationally fix the multilateral junction 1500 therein. In the
illustrated embodiment, the anchor 1520 is coupled uphole of the
multilateral junction 1500, and is in the radially retracted
state.
[0058] Turning to FIG. 16, illustrated is the multilateral well 600
of FIG. 15 after activating/deploying the anchor 1520. The anchor
1520 may be activated/deployed by first setting its valve to its
second position, and then pressuring up on the two or more
hydraulic activation chambers to move the two or more hydraulic
activation chambers from their first collapsed state to their
second activated state. In at least one embodiment, a
pre-determined activation pressure is maintained for a period of
time to fully activate the anchor 1520.
[0059] Turning to FIG. 17, illustrated is the multilateral well 600
of FIG. 16 after coupling an intermediate liner 1700 to an uphole
end of the multilateral junction 1500. The intermediate liner 1700,
in the illustrated embodiment, includes a first set of one or more
intermediate liner sealing elements 1710, a second set of one or
more intermediate liner sealing elements 1730, and main wellbore
screen assembly 1720 positioned between the first set of sealing
elements 1710 and the second set of sealing elements 1730. In at
least one embodiment, the first set of sealing elements 1710 and
the second set of sealing elements 1730 seal an annulus between the
intermediate liner 1700 and the main wellbore open hole section
1150.
[0060] What results in FIG. 17, is an open-hole pressure tight TAML
level 5 junction. For example, the multilateral junction 1500 is
entirely positioned in the main wellbore open hole section 1150
and/or the lateral wellbore open hole section 1160. Moreover, in at
least one embodiment, no cement surrounds the multilateral junction
1500, and in at least one other embodiment no cement exists in
either of the main wellbore open hole section 1150 or the lateral
wellbore open hole section 1160.
[0061] Furthermore, in at least one embodiment, the main bore leg
1510 of the multilateral junction 1500 forms a first pressure tight
seal with the main bore completion 710, and the lateral bore leg
1515 of the multilateral junction 1500 forms a second pressure
tight seal with the lateral bore completion 1210. Additionally, in
at least one embodiment, a pressure tight seal exists entirely
around the multilateral junction 1500, as a result of the one or
more main bore completion sealing elements 714 sealing an annulus
between the main bore completion 710 and the main wellbore open
hole section 1150, the one or more lateral bore completion sealing
elements 1214 sealing an annulus between the lateral bore
completion 1210 and the lateral wellbore open hole section 1160,
and the one or more intermediate liner sealing elements 1710, 1730
sealing an annulus between the intermediate liner 1700 and the main
wellbore open hole section 1150.
[0062] Turning to FIG. 18, illustrated is the multilateral well 600
of FIG. 17 after positioning intelligent completion components
within the main wellbore 630. FIG. 18 additionally illustrates the
commingled flow paths of the main bore completion 710, the lateral
bore completion 1210, and the intermediate liner 1700.
[0063] Turning now to FIG. 19, illustrated is a cross-sectional
view of a multilateral well 1900 designed, manufactured and
operated according to one or more alternative embodiments of the
disclosure. The multilateral well 1900 is similar in many respects
to the multilateral well 600 of FIGS. 6 through 18. Accordingly,
like reference numbers have been used to indicate similar, if not
identical, features. The multilateral well 1900 differs, for the
most part, from the multilateral well 600, in that the multilateral
well 1900 includes a second lateral wellbore 1910 having a second
lateral wellbore open hole section 1915. The second lateral
wellbore 1910, in at least one embodiment, includes a downhole tool
1920 positioned therein, the downhole tool 1920 including a second
lateral bore completion 1930 (e.g., including a sand screen and one
or more main bore completion sealing elements) and an anchor 1940.
The anchor 1940, in one or more embodiments, may be similar to one
or more of the anchors discussed above with regard to FIGS. 1
through 5B. The multilateral well 1900 additionally includes a
second multilateral junction 1950 positioned proximate an
intersection between the main wellbore 630 and a second lateral
wellbore 1910. The multilateral well 1900 may additionally include
one or more multilateral junction sealing elements 1960 sealing an
annulus between the second multilateral junction 1950 and the main
wellbore open hole section 1150.
[0064] Turning now to FIG. 20, illustrated is a high-level
reservoir architecture 2000 according to one or more embodiments of
the disclosure. The high-level reservoir architecture 2000
illustrated in FIG. 20 depicts multiple instances of open-hole
pressure tight TAML level 5 junctions, for example at one or more
of the twigs thereof. Furthermore, the high-level reservoir
architecture illustrates that the main wellbore and the lateral
wellbores may have similar open hole diameters thereof.
[0065] Aspects disclosed herein include:
[0066] A. An anchor for use with a downhole tool in a wellbore, the
anchor including: 1) a base pipe; and 2) two or more hydraulic
activation chambers disposed radially about the base pipe, the two
or more hydraulic activation chambers configured to move from a
first collapsed state to a second activated state to engage with a
wall of a wellbore and laterally and rotationally fix a downhole
tool coupled to the base pipe within the wellbore.
[0067] B. A well system, the well system including: 1) a wellbore;
2) a downhole tool positioned within the wellbore; and 3) an anchor
coupled to the downhole tool and positioned within the wellbore,
the anchor including: a) a base pipe; and b) two or more hydraulic
activation chambers disposed radially about the base pipe, the two
or more hydraulic activation chambers configured to move from a
first collapsed state to a second activated state to engage with a
wall of the wellbore and laterally and rotationally fix the
downhole tool within the wellbore.
[0068] C. A method for anchoring a downhole tool within a wellbore,
the method including: 1) positioning a downhole tool within a
wellbore, the downhole tool having an anchor coupled thereto, the
anchor including: a) a base pipe; and b) two or more hydraulic
activation chambers disposed radially about the base pipe; and 2)
applying fluid pressure to the two or more hydraulic activation
chambers to move the two or more hydraulic activation chambers from
a first collapsed state to a second activated state to engage with
a wall of the wellbore and laterally and rotationally fix the
downhole tool within the wellbore.
[0069] D. A well system, the well system including: 1) a main
wellbore, the main wellbore having a main wellbore open hole
section; 2) a lateral wellbore extending from the main wellbore,
the lateral wellbore having a lateral wellbore open hole section;
3) a main bore completion located within the main wellbore and a
lateral bore completion located within the lateral wellbore; and 4)
a multilateral junction positioned at an intersection between the
main wellbore open hole section of the main wellbore and the
lateral wellbore open hole section of the lateral wellbore, the
multilateral junction including a main bore leg forming a first
pressure tight seal with the main bore completion and a lateral
bore leg forming a second pressure tight seal with the lateral bore
completion such that the main bore completion and the lateral bore
completion are hydraulically isolated from one another.
[0070] E. A method for forming a well system, the method including:
1) forming a main wellbore, the main wellbore having a main
wellbore open hole section; 2) forming a lateral wellbore extending
from the main wellbore, the lateral wellbore having a lateral
wellbore open hole section; 3) placing a main bore completion
within the main wellbore and placing a lateral bore completion
within the lateral wellbore; and 4) positioning a multilateral
junction at an intersection between the main wellbore open hole
section of the main wellbore and the lateral wellbore open hole
section of the lateral wellbore, the multilateral junction
including a main bore leg forming a first pressure tight seal with
the main bore completion and a lateral bore leg forming a second
pressure tight seal with the lateral bore completion such that the
main bore completion and the lateral bore completion are
hydraulically isolated from one another.
[0071] Aspects A, B, C, D and E may have one or more of the
following additional elements in combination: Element 1: further
including an expandable medium disposed about the two or more
hydraulic activation chambers, the expandable medium configured to
expand radially via the two or more hydraulic activation chambers
to fix the downhole tool within the wellbore. Element 2: wherein
the expandable medium is an expandable non-filter medium. Element
3: further including two or more bridging plates positioned
radially about the two or more expandable chambers, wherein the two
or more bridging plates are configured to extend across at least a
gap between outer portions of the two or more expandable chambers
when the two or more hydraulic activation chambers are in the
second activated state. Element 4: further including a plurality of
openings in the base pipe, the plurality of openings configured to
provide fluid communication between the base pipe and the two or
more hydraulic activation chambers to move the two or more
hydraulic activation chambers from the first collapsed state to the
second activated state. Element 5: wherein the plurality of
openings are a first plurality of openings, and further including a
second plurality of openings in the base pipe, the second plurality
of openings configured to provide fluid communication between the
base pipe and an annulus surrounding the base pipe when the two or
more hydraulic activation chambers are in the second activated
state. Element 6: further including a valve coupled to the base
pipe, the valve having a first setting that closes fluid
communication to the first plurality of openings and the second
plurality of openings, a second setting that only opens fluid
communication to the first plurality of openings, and a third
setting that only opens fluid communication to the second plurality
of openings. Element 7: further including an elastomeric element
positioned about the two or more hydraulic activation chambers.
Element 8: wherein the elastomeric element is an annular
elastomeric element configured as an annular seal. Element 9:
wherein the base pipe has a length (l.sub.bp) at least 10 times a
diameter (d) of the base pipe, and further wherein the two or more
hydraulic activation chambers extend along at least a portion of
the length (l.sub.bp). Element 10: wherein the length (l.sub.bp) of
the base pipe is at least 2 meters long and a length (l.sub.ac) of
the two or more hydraulic activation chambers is at least 1.5
meters long. Element 11: wherein the length (l.sub.bp) of the base
pipe is at least 4 meters long and a length (l.sub.ac) of the two
or more hydraulic activation chambers is at least 3 meters long.
Element 12: wherein the length (l.sub.bp) of the base pipe is at
least 10 meters long and a length (l.sub.ac) of the two or more
hydraulic activation chambers is at least 7.5 meters long. Element
13: wherein at least four hydraulic activation chambers are
disposed radially about the base pipe. Element 14: wherein the
downhole tool is a lower completion. Element 15: wherein the lower
completion includes production tubing having a screen assembly.
Element 16: wherein the downhole tool is coupled to a downhole end
of the anchor, and further wherein the anchor is configured to
laterally and rotationally fix the production tubing having the
screen assembly within the wellbore. Element 17: wherein the
wellbore is a main wellbore, and further including a lateral
wellbore extending from the main wellbore, wherein the downhole
tool forms at least a portion of a multilateral junction positioned
proximate an intersection between the main wellbore and the lateral
wellbore. Element 18: wherein the downhole tool is a whipstock, the
anchor laterally and rotationally fixing the whipstock within the
wellbore. Element 19: wherein the downhole tool forms at least a
portion of a first multilateral junction, the anchor is a first
anchor and the lateral wellbore is a first lateral wellbore, and
further including: a second downhole tool positioned within the
wellbore; and a second anchor coupled to the second downhole tool
and positioned within the wellbore, the second anchor including; a
second base pipe; and a second set of two or more hydraulic
activation chambers disposed radially about the second base pipe,
the second set of two or more hydraulic activation chambers
configured to move from the first collapsed state to the second
activated state to engage with the wall of the wellbore and
laterally and rotationally fix the second downhole tool within the
wellbore. Element 20: wherein the second downhole tool forms at
least a portion of a second multilateral junction positioned
proximate an intersection between the main wellbore and a second
lateral wellbore. Element 21: wherein the main wellbore and the
lateral wellbore have a similar open hole diameter. Element 22:
wherein the whipstock includes a through bore extending entirely
there through. Element 23: further including an expandable medium
disposed about the two or more hydraulic activation chambers, the
expandable medium configured to expand radially via the two or more
hydraulic activation chambers to fix the downhole tool within the
wellbore. Element 24: wherein the expandable medium is an
expandable non-filter medium. Element 25: wherein the wellbore is
an open hole wellbore. Element 26: further including an expandable
medium disposed about the two or more hydraulic activation
chambers, the expandable medium expanding radially when applying
the fluid pressure to the two or more hydraulic activation chambers
to fix the downhole tool within the wellbore. Element 27: wherein
positioning a downhole tool within a wellbore includes positioning
a lower completion including production tubing having a screen
assembly within a wellbore, the applying laterally and rotationally
fixing the lower completion including the production tubing having
the screen assembly within the wellbore. Element 28: wherein the
wellbore is a main wellbore, and further including a lateral
wellbore extending from the main wellbore, wherein positioning a
downhole tool within a wellbore includes positioning a downhole
tool forming at least a portion of a multilateral junction
proximate an intersection between the main wellbore and the lateral
wellbore. Element 29: further including one or more main bore
completion sealing elements sealing an annulus between the main
bore completion and the main wellbore open hole section. Element
30: further including one or more lateral bore completion sealing
elements sealing an annulus between the lateral bore completion and
the lateral wellbore open hole section. Element 31: further
including an intermediate liner coupled with an uphole end of the
multilateral junction, the intermediate liner including one or more
intermediate liner sealing elements sealing an annulus between the
intermediate liner and the main wellbore open hole section. Element
32: wherein the one or more intermediate liner sealing elements are
a first set of one or more intermediate liner sealing elements, and
further including a second set of one or more intermediate liner
sealing elements sealing the annulus between the intermediate liner
and the main wellbore open hole section, the second set of one or
more intermediate liner sealing elements laterally offset from the
first set of one or more intermediate liner sealing elements.
Element 33: further including a main wellbore screen assembly
positioned between the first set of one or more intermediate liner
sealing elements and the second sets of one or more intermediate
liner sealing elements. Element 34: wherein no cement surrounds the
multilateral junction. Element 35: wherein the lateral wellbore is
a first lateral wellbore and the lateral bore completion is a first
lateral bore completion, and further including a second lateral
wellbore extending from the main wellbore, the second lateral
wellbore having a second lateral wellbore open hole section and a
second lateral bore completion. Element 36: wherein the
multilateral junction is a first multilateral junction and the
intersection is a first intersection, and further including a
second multilateral junction positioned at a second intersection
between the main wellbore open hole section of the main wellbore
and the second lateral wellbore open hole section of the second
lateral wellbore, the second multilateral junction including a
second main bore leg forming a third pressure tight seal with the
first multilateral junction and a fourth lateral bore leg forming a
fourth pressure tight seal with the second lateral bore completion.
Element 37: further including one or more multilateral junction
sealing elements sealing an annulus between the second multilateral
junction and the main wellbore open hole section.
[0072] Those skilled in the art to which this application relates
will appreciate that other and further additions, deletions,
substitutions and modifications may be made to the described
embodiments.
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