U.S. patent application number 16/252887 was filed with the patent office on 2019-07-25 for enhanced downhole packer.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Stephane Briquet, Thomas Chagny, Pierre-Yves Corre, Tudor Palaghita.
Application Number | 20190226337 16/252887 |
Document ID | / |
Family ID | 67299259 |
Filed Date | 2019-07-25 |
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United States Patent
Application |
20190226337 |
Kind Code |
A1 |
Corre; Pierre-Yves ; et
al. |
July 25, 2019 |
Enhanced Downhole Packer
Abstract
An expandable packer assembly for coupling within a tool string
deployable within a wellbore. The expandable packer assembly
includes a guard inlet, a sample inlet surrounded by the guard
inlet, and a sealing member surrounding the sample inlet and
fluidly isolating the sample inlet from the guard inlet when the
sealing member contacts a sidewall of the wellbore.
Inventors: |
Corre; Pierre-Yves;
(Abbeville, FR) ; Briquet; Stephane; (Clamart,
FR) ; Palaghita; Tudor; (Houston, TX) ;
Chagny; Thomas; (Abbeville, FR) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
67299259 |
Appl. No.: |
16/252887 |
Filed: |
January 21, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62620639 |
Jan 23, 2018 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 49/081 20130101;
E21B 33/1272 20130101; E21B 49/10 20130101 |
International
Class: |
E21B 49/10 20060101
E21B049/10; E21B 33/127 20060101 E21B033/127; E21B 49/08 20060101
E21B049/08 |
Claims
1. An apparatus comprising: an expandable packer assembly for
coupling within a tool string deployable within a wellbore, wherein
the expandable packer assembly comprises: a guard inlet; a sample
inlet surrounded by the guard inlet; and a sealing member
surrounding the sample inlet and fluidly isolating the sample inlet
from the guard inlet when the sealing member contacts a sidewall of
the wellbore.
2. The apparatus of claim 1 wherein the expandable packer assembly
comprises a packer having an outer layer, and wherein the sealing
member is detachably connected with the outer layer.
3. The apparatus of claim 1 wherein the expandable packer assembly
comprises a packer having an outer layer, and wherein the sealing
member is manually connectable with and disconnectable from the
outer layer.
4. The apparatus of claim 1 wherein the expandable packer assembly
comprises a packer having an outer layer, wherein the outer layer
comprises a cavity in which the sealing member is received, and
wherein the sealing member comprises a shoulder latching against a
corresponding shoulder of the outer layer to connect the sealing
member to the outer layer.
5. The apparatus of claim 1 wherein the expandable packer assembly
further comprises a support member abutting the sealing member and
inhibiting extrusion of the sealing member when a pressure
differential exists between the sample and guard inlets.
6. The apparatus of claim 5 wherein the sealing member surrounds
the support member.
7. The apparatus of claim 5 wherein the support member comprises a
material that is stiffer than material forming the sealing
member.
8. The apparatus of claim 5 wherein the support member comprises a
plurality of sliding metal members.
9. The apparatus of claim 1 wherein the expandable packer assembly
comprises a packer having an outer layer, and wherein a shoulder
protrudes from the outer layer, abuts the sealing member, and
inhibits extrusion of the sealing member when a pressure
differential exists between the sample and guard inlets.
10. An apparatus comprising: an expandable packer assembly for
coupling within a tool string deployable within a wellbore, wherein
the expandable packer assembly comprises: an expandable packer
having an outer layer; a sample drain at least partially located on
the outer layer and operable to receive formation fluid; a guard
drain at least partially located on the outer layer and surrounding
the sample drain; and a sealing member at least partially located
on the outer layer and surrounding the sample drain, wherein the
sealing member fluidly isolates the sample drain from the guard
drain when the sealing member contacts a sidewall of the wellbore,
and wherein the sealing member is detachably connected with the
outer layer.
11. The apparatus of claim 10 wherein the sealing member is
manually connectable and disconnectable with the outer layer.
12. The apparatus of claim 10 wherein the outer layer comprises a
cavity in which the sealing member is received, and wherein the
sealing member comprises a shoulder latching against a
corresponding shoulder of the outer layer to connect the sealing
member to the outer layer.
13. The apparatus of claim 10 wherein the expandable packer
assembly further comprises a support ring abutting the sealing
member.
14. The apparatus of claim 13 wherein the sealing member surrounds
the support ring.
15. The apparatus of claim 13 wherein the support ring comprises a
plurality of sliding metal members.
16. The apparatus of claim 10 wherein the outer layer comprises a
protruding shoulder abutting the sealing member.
17. An apparatus comprising: an expandable packer assembly for
coupling within a tool string deployable within a wellbore, wherein
the expandable packer assembly comprises: an expandable packer
having an outer layer; a sample drain at least partially located on
the outer layer and operable to receive formation fluid; a guard
drain at least partially located on the outer layer and surrounding
the sample drain; and a sealing member at least partially located
on the outer layer and surrounding the sample drain, wherein the
sealing member fluidly isolates the sample drain from the guard
drain when the sealing member contacts a sidewall of the wellbore,
and wherein the outer layer comprises an external shoulder abutting
the sealing member.
18. The apparatus of claim 17 wherein a drain comprises the sample
drain and guard drain, wherein the drain comprises a cavity in
which the sealing member is received, and wherein the sealing
member comprises a shoulder latching against a corresponding
internal shoulder of the drain to connect the sealing member to the
drain.
19. The apparatus of claim 17 wherein the expandable packer
assembly further comprises a support ring abutting the sealing
member.
20. The apparatus of claim 17 wherein the external shoulder is a
first external shoulder abutting the sealing member on a first
side, and wherein the outer layer comprises a second external
shoulder abutting the sealing member on a second side opposite the
first side.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to and the benefit of U.S.
Provisional Application No. 62/620639, titled "ENHANCED DOWNHOLE
PACKER," filed Jan. 23, 2018, the entire disclosure of which is
hereby incorporated herein by reference.
BACKGROUND OF THE DISCLOSURE
[0002] In the oil and gas industry, many downhole tools include
expandable packers. For example, a packer tool may be positioned at
an intended location within a wellbore, and elastomeric sealing
elements of the packers are radially expanded to seal against the
wellbore wall or a casing lining the wellbore.
SUMMARY OF THE DISCLOSURE
[0003] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify indispensable
features of the claimed subject matter, nor is it intended for use
as an aid in limiting the scope of the claimed subject matter.
[0004] The present disclosure introduces an apparatus that includes
an expandable packer assembly for coupling within a tool string
deployable within a wellbore. The expandable packer assembly
includes a guard inlet, a sample inlet surrounded by the guard
inlet, and a sealing member surrounding the sample inlet and
fluidly isolating the sample inlet from the guard inlet when the
sealing member contacts a sidewall of the wellbore.
[0005] The present disclosure also introduces an apparatus that
includes an expandable packer assembly for coupling within a tool
string deployable within a wellbore, the expandable packer assembly
including an expandable packer, a sample drain, a guard drain, and
a sealing member. The expandable packer has an outer layer. The
sample drain is at least partially located on the outer layer and
receives formation fluid. The guard drain is at least partially
located on the outer layer and surrounds the sample drain. The
sealing member is at least partially located on the outer layer and
surrounds the sample drain. The sealing member fluidly isolates the
sample drain from the guard drain when the sealing member contacts
a sidewall of the wellbore. The sealing member is detachably
connected with the outer layer.
[0006] The present disclosure also introduces an apparatus that
includes an expandable packer assembly for coupling within a tool
string deployable within a wellbore, the expandable packer assembly
including an expandable packer, a sample drain, a guard drain, and
a sealing member. The expandable packer has an outer layer. The
sample drain is at least partially located on the outer layer and
receives formation fluid. The guard drain is at least partially
located on the outer layer and surrounds the sample drain. The
sealing member is at least partially located on the outer layer and
surrounds the sample drain. The sealing member fluidly isolates the
sample drain from the guard drain when the sealing member contacts
a sidewall of the wellbore. The outer layer comprises an external
shoulder abutting the sealing member.
[0007] These and additional aspects of the present disclosure are
set forth in the description that follows, and/or may be learned by
a person having ordinary skill in the art by reading the material
herein and/or practicing the principles described herein. At least
some aspects of the present disclosure may be achieved via means
recited in the attached claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The present disclosure is understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0009] FIG. 1 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0010] FIG. 2 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0011] FIG. 3 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0012] FIG. 4 is a perspective view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0013] FIG. 5 is a front view of at least a portion of an example
implementation of a focused sampling drain according to one or more
aspects of the present disclosure.
[0014] FIG. 6 is a front view of at least a portion of an example
implementation of a focused sampling drain according to one or more
aspects of the present disclosure.
[0015] FIGS. 7 and 8 are schematic end and sectional views of at
least a portion of an example implementation of apparatus according
to one or more aspects of the present disclosure.
[0016] FIGS. 9 and 10 are schematic front and sectional views of at
least a portion of an example implementation of apparatus according
to one or more aspects of the present disclosure.
[0017] FIG. 11 is a sectional view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0018] FIG. 12 is a sectional view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
DETAILED DESCRIPTION
[0019] It is to be understood that the following disclosure
provides many different examples for different features and other
aspects of various implementations. Specific examples of components
and arrangements are described below to simplify the present
disclosure. These are merely examples, and are not intended to be
limiting. In addition, the present disclosure may repeat reference
numerals and/or letters in the various examples. This repetition is
for simplicity and clarity, and does not in itself dictate a
relationship between the various implementations described
below.
[0020] FIG. 1 is a schematic view of an example wellsite system 100
to which one or more aspects of the present disclosure may be
applicable. The wellsite system 100 may be onshore or offshore. In
the example wellsite system 100 shown in FIG. 1, a wellbore 104 is
formed in one or more subterranean formations 102 by rotary
drilling. Other example systems within the scope of the present
disclosure may also or instead utilize directional drilling.
Although some elements of the wellsite system 100 are depicted in
FIG. 1 and described below, it is to be understood that the
wellsite system 100 may include other components in addition to, or
instead of, those presently illustrated and described.
[0021] As shown in FIG. 1, a drill string 112 suspended within the
wellbore 104 comprises a bottom hole assembly (BHA) 140 that
includes or is coupled with a drill bit 142 at its lower end. The
surface system includes a platform and a support structure 110
(e.g., a mast, a derrick) positioned over the wellbore 104. The
platform and support structure 110 may comprise a rotary table 114,
a kelly 116, a hook 118, and a rotary swivel 120. The drill string
112 may be suspended from a lifting gear (not shown) via the hook
118, with the lifting gear being coupled to the support structure
110 rising above the surface. An example lifting gear includes a
crown block affixed to the top of the mast, a vertically traveling
block to which the hook 118 is attached, and a cable passing
through the crown block and the vertically traveling block. In such
an example, one end of the cable is affixed to an anchor point,
whereas the other end is affixed to a winch to raise and lower the
hook 118 and the drill string 112 coupled thereto. The drill string
112 comprises one or more types of tubular members, such as drill
pipes, threadedly attached one to another, perhaps including wired
drilled pipe.
[0022] The drill string 112 may be rotated by the rotary table 114,
which engages the kelly 116 at the upper end of the drill string
112. The drill string 112 is suspended from the hook 118 in a
manner permitting rotation of the drill string 112 relative to the
hook 118. Other example wellsite systems within the scope of the
present disclosure may utilize a top drive system to suspend and
rotate the drill string 112, whether in addition to or instead of
the illustrated rotary table system.
[0023] The surface system may further include drilling fluid or mud
126 stored in a pit or other container 128 formed at the wellsite.
The drilling fluid 126 may be oil-based mud (OBM) or water-based
mud (WBM). A pump 130 delivers the drilling fluid 126 to the
interior of the drill string 112 via a hose or other conduit 122
coupled to a port in the rotary swivel 120, causing the drilling
fluid to flow downward through the drill string 112, as indicated
in FIG. 1 by directional arrow 132. The drilling fluid exits the
drill string 112 via ports in the drill bit 142, and then
circulates upward through the annulus region between the outside of
the drill string 112 and the sidewall 106 of the wellbore 104, as
indicated in FIG. 1 by directional arrows 134. In this manner, the
drilling fluid 126 lubricates the drill bit 142 and carries
formation cuttings up to the surface as it is returned to the
container 128 for recirculation.
[0024] The BHA 140 may comprise one or more specially made drill
collars near the drill bit 142. Each such drill collar may comprise
one or more devices permitting measurement of downhole drilling
conditions and/or various characteristic properties of the
subterranean formation 102 intersected by the wellbore 104. For
example, the BHA 140 may comprise one or more
logging-while-drilling (LWD) modules 144, one or more
measurement-while-drilling (MWD) modules 146, a rotary-steerable
system and motor 148, and perhaps the drill bit 142. Other BHA
components, modules, and/or tools are also within the scope of the
present disclosure, and such other BHA components, modules, and/or
tools may be positioned differently in the BHA 140 than as depicted
in FIG. 1.
[0025] The LWD modules 144 may comprise one or more devices for
measuring characteristics of the formation 102, including for
obtaining a sample of fluid from the formation 102. The MWD modules
146 may comprise one or more devices for measuring characteristics
of the drill string 112 and/or the drill bit 142, such as for
measuring weight-on-bit, torque, vibration, shock, stick slip, tool
face direction, and/or inclination, among other examples. The MWD
modules 146 may further comprise an apparatus 147 for generating
electrical power to be utilized by the downhole system, such as a
mud turbine generator powered by the flow of the drilling fluid
126. Other power and/or battery systems may also or instead be
employed. One or more of the LWD modules 144 and/or the MWD modules
146 may be or comprise at least a portion of a packer tool as
described below.
[0026] The wellsite system 100 also includes a data processing
system that can include one or more, or portions thereof, of the
following: the surface equipment 190, control devices and
electronics in one or more modules of the BHA 140 (such as a
downhole controller 150), a remote computer system (not shown),
communication equipment, and other equipment. The data processing
system may include one or more computer systems or devices and/or
may be a distributed computer system. For example, collected data
or information may be stored, distributed, communicated to a human
wellsite operator, and/or processed locally or remotely.
[0027] The data processing system may, individually or in
combination with other system components, perform the methods
and/or processes described below, or portions thereof. Methods
and/or processes within the scope of the present disclosure may be
implemented by one or more computer programs that run in a
processor located, for example, in one or more modules of the BHA
140 and/or the surface equipment 190. Such programs may utilize
data received from the BHA 140 via mud-pulse telemetry and/or other
telemetry means, and/or may transmit control signals to operative
elements of the BHA 140. The programs may be stored on a tangible,
non-transitory, computer-usable storage medium associated with the
one or more processors of the BHA 140 and/or surface equipment 190,
or may be stored on an external, tangible, non-transitory,
computer-usable storage medium that is electronically coupled to
such processor(s). The storage medium may be one or more known or
future-developed storage media, such as a magnetic disk, an
optically readable disk, flash memory, or a readable device of
another kind, including a remote storage device coupled over a
communication link, among other examples.
[0028] FIG. 2 is a schematic view of another example wellsite
system 200 to which one or more aspects of the present disclosure
may be applicable. The wellsite system 200 may be onshore or
offshore. In the example wellsite system 200 shown in FIG. 2, a
tool string 204 is conveyed into the wellbore 104 via a conveyance
means 208, which may be or comprise a wireline, a slickline, or a
fluid conduit, such as coiled tubing, completion tubing, a liner,
or a casing. As with the wellsite system 100 shown in FIG. 1, the
example wellsite system 200 of FIG. 2 may be utilized for
evaluation of the wellbore 104 and/or the formation 102 penetrated
by the wellbore 104.
[0029] The tool string 204 is suspended in the wellbore 104 from
the lower end of the conveyance means 208, which may be a
multi-conductor logging cable spooled on a surface winch (not
shown). The conveyance means 208 may include at least one conductor
that facilitates data communication between the tool string 204 and
surface equipment 290 disposed on the surface. The surface
equipment 290 may have one or more aspects in common with the
surface equipment 190 shown in FIG. 1.
[0030] The tool string 204 and conveyance means 208 may be
structured and arranged with respect to a service vehicle (not
shown) at the wellsite. For example, the conveyance means 208 may
be connected to a drum (not shown) at the wellsite surface, such
that rotation of the drum may raise and lower the tool string 204.
The drum may be disposed on a service vehicle or a stationary
platform. The service vehicle or stationary platform may further
contain the surface equipment 290.
[0031] The tool string 204 comprises one or more elongated housings
encasing or otherwise carrying various electronic components and
modules schematically represented in FIG. 2. For example, the
illustrated tool string 204 includes several modules 212, at least
one of which may be or comprise at least a portion of a packer tool
as described below. Other implementations of the downhole tool
string 204 within the scope of the present disclosure may include
additional or fewer components or modules relative to the example
implementation depicted in FIG. 2.
[0032] The wellsite system 200 also includes a data processing
system that can include one or more, or portions thereof, of the
following: the surface equipment 290, control devices and
electronics in one or more modules of the tool string 204 (such as
a downhole controller 216), a remote computer system (not shown),
communication equipment, and other equipment. The data processing
system may include one or more computer systems or devices and/or
may be a distributed computer system. For example, collected data
or information may be stored, distributed, communicated to a human
wellsite operator, and/or processed locally or remotely.
[0033] The data processing system may, whether individually or in
combination with other system components, perform the methods
and/or processes described below, or portions thereof. Methods
and/or processes within the scope of the present disclosure may be
implemented by one or more computer programs that run in a
processor located, for example, in one or more modules 212 of the
tool string 204 and/or the surface equipment 290. Such programs may
utilize data received from the downhole controller 216 and/or other
modules 212 via the conveyance means 208, and may transmit control
signals to operative elements of the tool string 204. The programs
may be stored on a tangible, non-transitory, computer-usable
storage medium associated with the one or more processors of the
downhole controller 216, other modules 212 of the tool string 204,
and/or the surface equipment 290, or may be stored on an external,
tangible, non-transitory, computer-usable storage medium that is
electronically coupled to such processor(s). The storage medium may
be one or more known or future-developed storage media, such as a
magnetic disk, an optically readable disk, flash memory, or a
readable device of another kind, including a remote storage device
coupled over a communication link, among other examples.
[0034] Although FIGS. 1 and 2 illustrate example wellsite systems
100 and 200, respectively, which convey a downhole tool/string into
the wellbore 104, other example implementations consistent with the
scope of this disclosure may utilize other conveyance means to
convey tools/strings into the wellbore 104. Additionally, other
downhole tools within the scope of the present disclosure may
comprise components in a non-modular construction also consistent
with the scope of this disclosure.
[0035] FIG. 3 is a schematic view of at least a portion of an
example implementation of an expandable packer tool 300 configured
to be deployed or conveyed within a wellbore according to one or
more aspects of the present disclosure. The packer tool 300 may be
implemented as one or more of the LWD modules 144 or MWD modules
146 shown in FIG. 1, and/or one or more of the modules 212 shown in
FIG. 2, and may thus be conveyed within the wellbore via a
wireline, a slickline, a drill string, coiled tubing, completion
tubing, a liner, a casing, and/or other conveyance means. As
described below, the packer tool 300 is an assembly of a plurality
of components operating together in a coordinated manner and, thus,
may also be referred to as a packer assembly.
[0036] The expandable packer tool 300 comprises a first end
assembly 310 at a first end of the packer tool 300, and a second
end assembly 312 at an opposing second end of the packer tool 300.
The end assemblies 310, 312 may be or comprise connector
assemblies, such as may be configured to couple the packer tool 300
within a tool string. For example, the end assembly 310 may be
coupled with a first (e.g., uphole) portion 302 of the tool string,
and the end assembly 312 may be coupled with a second (e.g.,
downhole) portion 304 of the tool string. The tool string may be
the BHA 140 shown in FIG. 1, the tool string 204 shown in FIG. 2,
and/or other tool strings within the scope of the present
disclosure.
[0037] A mandrel 314 (e.g., a tube) extends between the end
assemblies 310, 312. The first and/or second end assembly 310, 312
may be connected (e.g., fixedly or slidably) with the mandrel 314,
and at least a portion of the first and/or second end assembly 310,
312 may extend around the mandrel 314. An expandable (e.g.,
flexible, elastic) packer 316 is disposed around the mandrel 314,
and may be sealingly connected with one or both of the end
assemblies 310, 312. In a fully retracted state of the packer 316,
an inner surface of the packer 316 may be disposed against and/or
in contact with an outer profile (e.g., surface) of the mandrel
314. In an expanded state of the packer 316, the inner surface of
the packer 316 may be disposed away from the outer profile of the
mandrel 314, and an outer surface of the packer 316 may be disposed
against a sidewall of the wellbore/casing to fluidly seal a portion
of the wellbore/casing and/or to maintain the packer tool 300 in
position within the wellbore/casing. The mandrel 314 comprises a
fluid port 318 on an outer surface of the mandrel 314, and a
flowline 320 extending within the mandrel 314 and in fluid
communication with the port 318. The port 318 may be fluidly
connected with an inner portion of the packer 316, such as may
permit inflation and deflation of the packer 316.
[0038] The tool string may comprise a pump for expanding and
retracting the packer 316. For example, the upper tool string
portion 302 may comprise a fluid pump 306 fluidly connected with a
flowline 308 extending within the upper tool string portion 302.
Coupling the end assembly 310 with the upper tool string portion
302 may also fluidly connect the flowlines 308, 320, thereby
fluidly connecting the pump 306 with the flowline 320 and the port
318. Accordingly, during downhole operations, the pump 306 may pump
a fluid into the packer 316 via the flowlines 308, 320 and the port
318 to expand the packer 316 away from the mandrel 314 against the
sidewall of the wellbore/casing. The pump 306 may also pump the
fluid out of the packer 316 via the flowlines 308, 320 and the port
318 to retract the packer 316 away from the sidewall of the
wellbore/casing toward and into contact with the mandrel 314.
Although not shown, the packer tool 300 may comprise multiple
instances of the port 318 distributed circumferentially around the
mandrel 314 (i.e., around an outer surface of the mandrel 314),
with each port being fluidly connected with an inner portion of the
packer 316 and with the flowline 320, such as may permit inflation
and deflation of the packer 316.
[0039] The packer 316 also includes drains 330 for focused
sampling. Each focused sampling drain 330 includes a sample inlet
or drain 332 and a guard inlet or drain 334, separated by an
elongated, ring-shaped portion of rubber and/or other material
forming the packer 316. The sample and guard drains 332, 334
conduct fluid from the formation into corresponding flowlines 336
embedded within the packer 316 or otherwise inside the packer 316.
The focused sampling drains 330 (and perhaps at least a portion of
one or more of the flowlines 336) may be imbedded within one or
more outer layers 338 of the packer 316, and may thus move radially
outward while the packer 316 is expanded, whether such expansion is
via inflation of the packer 316 itself or via inflation of an
internal bladder 340 located between the mandrel 314 and the packer
316.
[0040] FIG. 4 is a perspective view of an example implementation of
the packer tool 300 shown in FIG. 3, and designated in FIG. 4 by
reference number 400. The packer tool 400 includes an outer layer
440 (e.g., an outer skin) that is expandable in the wellbore/casing
to form a seal with the surrounding wellbore/casing wall. The
packer tool 400 further includes an inner, inflatable bladder 442
disposed within an interior of the outer layer 440. The inner
bladder 442 (e.g., inner packer) may be selectively expanded by
fluid delivered via an inner mandrel 444, such as via the flowlines
308, 320 of the mandrel 314 described above. End portions of the
packer tool 400 (such as the end portions 310, 312 described above)
may include mechanical fittings 446 mounted around the inner
mandrel 444 and engaged with axial ends 448 of outer layer 440.
[0041] The outer layer 440 includes one or more focused sampling
drains 450 (such as the focused sampling drains 330 described
above) through which formation fluid is collected when the outer
layer 440 is expanded against the surrounding wellbore/casing wall.
The focused sampling drains 450 may be embedded radially into the
outer layer 440, such as into a cylindrical, elastomeric sealing
portion 452 selected for hydrocarbon based applications (e.g.,
nitrile rubber (NBR), hydrogenated nitrile butadiene rubber (HNBR),
fluorocarbon rubber (FKM), etc.).
[0042] One or more aspects pertain to the sealing portion 452 of
the outer layer 440, such as to optimize sealing efficiency while
permitting focused sampling (i.e., guard and sample) on a
continuous ring. Conventionally, the outer rubber layer has been
made of a thick rubber cylinder, with embedded flowlines and drains
bonded to rubber. However, such arrangements can lead to excessive
elongation of the rubber, which can increase the level of stress on
bonding interfaces between the drains and the surrounding rubber,
and potentially increasing the risk of failure due to bonding
issues. The present disclosure introduces a packer with optimized
flow and operational performance.
[0043] As described above, the packer is carried on the
sampling/packer tool 300, 400 having one or more hydraulic pumps.
Well fluid is pumped to inflate the packer so that the sealing
portion 452 contacts and seals a portion of the wellbore/casing.
Fluid is then drawn from the subterranean formation within the
sealed portion of the wellbore/casing by operating the same pump
(via valving) or another pump to create a pressure drop (drawdown)
that urges reservoir fluid from the formation. The drawdown pump is
connected to the focused sampling drains 450 so that the drawdown
pressure is transmitted to the formation through the focused
sampling drains 450.
[0044] Because the packer is inflatable or otherwise expandable,
dimensions of the drains are optimized via a compromise between
fluid efficiency (bigger drains provide better sampling efficiency)
and elongation capabilities (smaller drains have less impact on the
ability of the packer to inflate). The present disclosure thus
pertains to enhancing the shape of the outer rubber layer in order
to maximize packer sampling and geometrical symmetry while ensuring
adequate (if not best) sealing efficiency and lowering peeling
forces acting on the rubber bonding interfaces.
[0045] As described above, the outer rubber layer is composed of a
sealing element made of NBR, HNBR, FKM, and/or other elastomeric
materials. The sample and guard zones or drains 332, 334 and at
least a portion of one or more of the flowlines 336 are embedded
within the sealing portion 452 in a manner permitting focused
sampling. The center, sample drain 332 of each focused sampling
drain 330, 450 collects reservoir fluid, while the external, guard
drain 334 of each focused sampling drain 330, 450 protects the
sample drain 332 from mud invasion. Both sample and guard drains
332, 334 of each focused sampling drain 330, 450 are sealed by an
elastomeric portion 335 having a shape that protects against
extrusion. Each focused sampling drain 330, 450 can be made in a
manner permitting the sample drain 332 part to move freely relative
to the guard drain 334, such as may permit better conformance to
the surface of the wellbore/casing.
[0046] FIG. 5 is a schematic view of an example implementation of
the focused sampling drains 330, 450 described above, and
designated in FIG. 5 by reference number 500. The focused sampling
drain 500 includes a rubber portion 502 that seals against the
surrounding wellbore/casing to fluidly isolate the sample inlet or
drain 504 within the guard inlet or drain 506. FIG. 5 also depicts
flowlines extending from the focused sampling drain 500, such as a
guard flowline 508 extending from the guard inlet 506 and a sample
flowline 510 extending from the sample inlet 504. The flowlines
508, 510 may be substantially similar to (or the same as) the
flowlines described above.
[0047] FIG. 6 is a schematic view of another example implementation
of the focused sampling drain 500 shown in FIG. 5, and designated
in FIG. 6 by reference number 520. The focused sampling drain 520
depicted in FIG. 6 is substantially similar to (or the same as) the
focused sampling drain 500 depicted in FIG. 5, except that the
focused sampling drain 520 includes a screen (e.g., a filter) 522
set in (or at the surface of) the sample inlet 504 and another
screen 524 set in (or at the surface of) the guard inlet 506.
Implementations within the scope of the present disclosure may
include one, both, or neither of the screens 522, 524. The screens
522, 524 may aid in protecting the flowlines 508, 510 from mud
invasion and subsequent plugging. In implementations including both
screens 522, 524, the screens 522, 524 may have the same or
different mesh/grid sizes. For example, the guard inlet 506 may be
more prone to plugging, so the guard screen 524 may have a larger
mesh/grid size than the sample screen 522. Other means for
filtering the sample/guard inlets 504/506 are also within the scope
of the present disclosure.
[0048] The intermediate rubber portion 502 in FIGS. 5 and 6 may be
protected against extrusion by the structure of the focused
sampling drain 500, 520, such as to be able to establish the
pressure differential utilized during focused sampling operations,
perhaps including a pressure differential between the sample inlet
504 and the guard inlet 506. An example of such structure is
depicted in FIGS. 7 and 8. FIG. 7 is a schematic end view of the
focused sampling drain 520, and FIG. 8 is a schematic sectional
view of the focused sampling drain 520. Both views show the outer
rubber layer 440/452, the rubber portion 502 separating the
sampling zone 504 and the guard zone 506, the sampling screen 522,
and the guard screen 524. Both views also show anti-extrusion
shoulders or other structures 550 shaped to protect the rubber
portion 502. The structures 550 may be or comprise a portion of the
outer layer 440, 452 protruding outwardly and abutting the rubber
portion 502 on one or opposing sides to support the rubber portion
502 in position. Thus, one of the structures 550 may surround the
rubber portion 502 on the guard zone 506 side (i.e., outer side) of
the rubber portion 502 and the other structure 550 may be located
on the sampling zone 504 side (i.e., inner side) of the rubber
portion 502 and, thus, be surrounded by the rubber portion 502.
FIG. 8 also depicts how the guard zone 506 may be separated from
the sample zone 504 by part of the rubber forming the outer layer
440/452.
[0049] However, the rubber portion 502 may not be sufficiently
protected against extrusion, because the focused sampling drain 520
may not be sufficiently compliant to adequately conform to the
uneven surface of the surrounding wellbore/casing. The present
disclosure also introduces one or more aspects that may address
this issue. For example, the rubber portion 502 may be removable,
so that it can be replaced between jobs and thus increase product
lifetime.
[0050] Alternatively (or additionally), the rubber portion
separating the guard and sample inlets may be configured as a
compliant, anti-extrusion system, such as by utilizing compliant,
extrusion-resistant materials. The anti-extrusion system may be
made in a material that may aid in ensuring compliance to the
wellbore/casing, including free displacement in the direction
perpendicular to the external surface of the drain, and extrusion
resistance in the form of mechanical resistance in the direction
parallel to the surface of the drain. An example of such material
is carbon fibers embedded in rubber.
[0051] Another example is to embed segmented metallic
reinforcements. FIGS. 9 and 10 depict such an example
implementation of the rubber portion 502, designated in FIGS. 9 and
10 by reference number 600. FIG. 9 is an external view of the
sealing pad assembly 600 (looking from the reservoir to the sealing
pad assembly 600), and FIG. 10 is a sectional view as indicated in
FIG. 9.
[0052] The metallic reinforcement may be made of vertical metallic
parts 602, set side-by-side and free to move vertically. A rubber
sealing layer 604 surrounds the sliding metal parts 602. An
optional rubber layer 606 may interpose the sliding metal parts 602
and the sealing layer 604. An optional outer rubber layer 608 may
surround the sealing layer 604. As depicted in FIG. 10, the outer
surfaces of the layers 604, 606, 608 may protrude above the outer
surface 603 of the sliding metal parts 602.
[0053] A gap between the sliding metal parts 602 may exist when the
packer is set against the wellbore/casing. The optional layer 606
may aid in reducing (or eliminating) resulting extrusion of the
sealing layer 604. The layer 606 may be reinforced, such as via
embedded carbon fibers, other fibers, and/or other reinforcing
materials. The outer layer 608 may similarly be reinforced. Thus,
the layers 606, 608 may be or comprise sealing layers and/or
support layers configured to prop or otherwise support the sealing
layer 604, thereby protecting the sealing layer 604 against
extrusion.
[0054] The metallic sliding parts 602 may each be a
vertically-extending metallic member, although other shapes may
also be utilized to also provide compliance to the wellbore/casing
and still provide anti-extrusion means. The sliding parts 602 may
be manufactured via machining, 3D printing, and/or other means.
[0055] FIG. 11 is a side sectional view of a portion of a focused
sampling (or sealing) drain 700 that may be implemented as part of
a packer tool assembly according to one or more aspects of the
present disclosure. The focused sampling drain 700 may comprise one
or more features and/or modes of operation of the focused sampling
drains 330, 450, 500, 520 described above and shown in one or more
of FIGS. 3-8.
[0056] The focused sampling drain 700 may comprise a sealing member
702 (e.g., a sealing pad or portion) having a predetermined shape
such that it can be inserted in the focused sampling drain 700,
provide sealing when the focused sampling drain 700 is against a
formation, and can be removed after a job and replaced by another
sealing member for a future job. The sealing member 702 may
comprise an elongated, generally ring-shaped geometry extending
around a sample inlet or drain 704 of the focused sampling drain
700 and configured to seal against the sidewall of a surrounding
wellbore/casing, such as to fluidly isolate the sample drain 704
from a guard inlet or drain 706 of the focused sampling drain
700.
[0057] The sealing member 702 may be at least partially embedded
within a drain 712 (e.g., outer rubber layer, outer skin) of the
focused sampling drain 700 and/or the packer assembly. The sealing
member 702 may be disposed at least partially within a chamber or
cavity 715 shaped or otherwise configured to accommodate the
sealing member 702 and, thus, support, retain, and/or maintain the
sealing member 702 in connection with the drain 712. The
cross-sectional shape or profile of the cavity 715 may follow,
outline, and/or trace the cross-sectional shape or profile (e.g.,
outer surface 718) of at least a portion of the sealing member
702.
[0058] One or more portions of the drain 712 may protrude outwardly
above the surface of the drain 712 in the form of one or more
shoulders 714, 716 abutting the sealing member 702 on one or
opposing sides to further support the sealing member 702 in
position. One shoulder 716 may surround the sealing member 702 on
the guard drain 706 side (i.e., outer side) of the sealing member
702 and the other shoulder 714 may be located on the sample drain
704 side (i.e., inner side) of the sealing member 702 and, thus, be
surrounded by the sealing member 702. The shoulders 714, 716 may
form or define at least a portion of the cavity 715 accommodating
the sealing member 702. One or more of the shoulders 714, 716 may
prevent, inhibit, or reduce extrusion (e.g., movement and/or
deformation) of the sealing member 702 in a direction parallel to
the sample and guard drains 704, 706 (or the drain 712), as
indicated by arrows 720, such as when a pressure differential is
being established between the sample and guard drains 704, 706,
thereby permitting the intended pressure differential to be
established, such as during focused sampling operations. For
example, during drawdown, the shoulders 714, 716 may prevent,
inhibit, or reduce extrusion of the sealing member 702 in a
direction toward the sample drain 704.
[0059] The sealing member 702 may comprise a sealing portion 708
configured to contact and seal against the sidewall of the
surrounding wellbore/casing and an anchor portion 710 configured to
connect or otherwise maintain the sealing member 702 in an intended
position with respect to the drain 712. The sealing portion 708 may
protrude out of the cavity 715 above an outer surface of the drain
712 and the anchor portion 710 may be embedded or otherwise
disposed within the cavity 715 beneath the outer surface of the
drain 712. The shoulders 714, 716 of the drain 712 may be referred
to as external shoulders 714, 716 supporting the external sealing
portion 708 of the sealing member 702. The drain 712 defining the
cavity 715 may also or instead comprise one or more internal
protrusions or shoulders 724 configured to support the internal
anchor portion 710 of the sealing member 702 in an intended
position. For example, the anchor portion 710 may comprise one or
more protrusions or shoulders 722 configured to latch against or
otherwise abut the one or more of the internal shoulders 724. The
shoulders 722 may extend outwardly away from each other and the
shoulders 724 may extend inwardly toward each other and/or with
respect to the cavity 715. Accordingly, the anchor portion 710 may
anchor, latch, or otherwise mechanically connect the sealing member
702 to the drain 712. The anchor portion 710 may, thus, prevent,
inhibit, or reduce movement and/or extrusion of the sealing member
702 in the direction parallel to the sample and guard drains 704,
706, as indicated by arrows 720, such as when a pressure
differential is being established between the sample and guard
drains 704, 706.
[0060] Material forming the sealing member 702 may be or comprise
an elastomeric material, such as NBR, HNBR, and/or FKM, among other
examples. The material forming the sealing member 702 may also or
instead be or comprise a mixture or combination of an elastomeric
and thermoplastic material. The material forming the sealing member
702 may also or instead be reinforced, such as via embedded carbon
fibers, other fibers, and/or other reinforcing materials. For
example, the material forming the anchor portion 710 may comprise
or be reinforced with thermoplastic material, carbon fibers, other
fibers, a metal, and/or other reinforcing materials, such as to
increase mechanical strength or stiffness of the anchor portion
710.
[0061] The sealing member 702 may be manually inserted into the
cavity 715, such as by pressing or pushing the sealing member 702
into the cavity 715 by hand or with a tool such that the shoulders
722 of the anchor portion 710 are located below or otherwise
latched against the shoulders 724 of the drain 712. The sealing
member 702 may be manually pulled out of or otherwise removed from
the cavity 715 after a job by hand or with a tool.
[0062] FIG. 12 is a side sectional view of a portion of a focused
sampling (or sealing) drain 750 that may be implemented as part of
a packer tool assembly according to one or more aspects of the
present disclosure. The focused sampling drain 750 may comprise one
or more features and/or modes of operation of the focused sampling
drains 330, 450, 500, 520, 700 described above and shown in one or
more of FIGS. 3-8 and 11, including where indicated by same
numerals.
[0063] The focused sampling drain 750 may comprise a sealing member
752 (e.g., a sealing pad or portion) having a predetermined shape
such that it can be inserted in the focused sampling drain 750,
provide sealing when the focused sampling drain 750 is against a
formation, and can be removed after a job and replaced by another
sealing member for a future job. The sealing member 752 may
comprise an elongated ring-shaped or otherwise rounded (e.g.,
elliptical, superelliptical, oval, etc.) geometry extending around
a sample inlet or drain 704 of the focused sampling drain 750 and
configured to seal against the sidewall of a surrounding
wellbore/casing, such as to fluidly isolate the sample drain 704
from a guard inlet or drain 706 of the focused sampling drain 750.
However, the sealing member 752 may instead comprise generally
circular geometry.
[0064] The focused sampling drain 750 may comprise one or more
backup or support members 754, 756, each contacting or other
otherwise abutting the sealing portion 708 of the sealing member
752 on a corresponding side of the sealing member 752. The support
members 754, 756 may comprise an elongated ring-shaped or otherwise
rounded geometry following or tracing the sealing member 752. Thus,
the support member 756 may surround the sealing member 752 on the
guard drain 706 side (i.e., outer side) of the sealing member 752
and/or the support member 754 may be located on the sample drain
704 side (i.e., inner side) of the sealing member 752 and, thus, be
surrounded by the sealing member 752. Each support member 754, 756
may be located between and abutting the sealing portion 708 and a
corresponding shoulder 714, 716 of the drain 712. Each support
member 754, 756 may be disposed within a corresponding chamber,
channel, or cavity surrounded on each side by the sealing member
752 and the drain 712, thereby latching or otherwise maintaining
each support member 754, 756 in position against the sealing member
752. For example, the sealing portion 708 may surround each support
member 754, 756 on two sides (e.g., upper and inner sides) and the
drain 712, including the shoulders 716, may surround each support
member 754, 756 on two sides (e.g., lower and outer sides).
[0065] Material forming the support members 754, 756 may be or
comprise a material having a greater stiffness than the material
forming the sealing member 752. The material forming the support
members 754, 756 may be or comprise, for example, a thermoplastic
material or a mixture or combination of an elastomeric and
thermoplastic material. The material forming the support members
754, 756 may also or instead be reinforced, such as via embedded
technical fibers, carbon fibers, other fibers, and/or other
reinforcing materials. The material forming the support members
754, 756 may also or instead be or comprise a metal. Accordingly,
each support members 754, 756 may further prevent, inhibit, or
reduce extrusion (e.g., movement and/or deformation) of the sealing
member 752 in the direction parallel to the sample and guard drains
704, 706, as indicated by arrows 720, such as when a pressure
differential is being established between the sample and guard
drains 704, 706. For example, during drawdown, one or both backup
members 754, 756 may prevent, inhibit, or reduce extrusion of the
sealing member 752 in a direction toward the sample drain 704.
[0066] In view of the entirety of the present disclosure, including
the figures and the claims, a person having ordinary skill in the
art will readily recognize that the present disclosure introduces
an apparatus comprising an expandable packer assembly for coupling
within a tool string deployable within a wellbore, wherein the
expandable packer assembly comprises: a guard inlet; a sample inlet
surrounded by the guard inlet; and a sealing member surrounding the
sample inlet and fluidly isolating the sample inlet from the guard
inlet when the sealing member contacts a sidewall of the
wellbore.
[0067] The expandable packer assembly may comprise a packer having
an outer layer, and the sealing member may be detachably connected
with the outer layer.
[0068] The expandable packer assembly may comprise a packer having
an outer layer, and the sealing member may be manually connectable
with and disconnectable from the outer layer.
[0069] The expandable packer assembly may comprise a packer having
an outer layer, the outer layer may comprise a cavity in which the
sealing member is received, and the sealing member may comprise a
shoulder latching against a corresponding shoulder of the outer
layer to connect the sealing member to the outer layer.
[0070] The expandable packer assembly may comprise a support member
abutting the sealing member and inhibiting extrusion of the sealing
member when a pressure differential exists between the sample and
guard inlets. The sealing member may surround the support member.
The support member may comprise a material that is stiffer than
material forming the sealing member. The support member may
comprise a plurality of sliding metal members.
[0071] The expandable packer assembly may comprise a packer having
an outer layer, and a shoulder may protrude from the outer layer,
abut the sealing member, and/or inhibit extrusion of the sealing
member when a pressure differential exists between the sample and
guard inlets.
[0072] The present disclosure also introduces an apparatus
comprising an expandable packer assembly for coupling within a tool
string deployable within a wellbore, wherein the expandable packer
assembly comprises: an expandable packer having an outer layer; a
sample drain at least partially located on the outer layer and
operable to receive formation fluid; a guard drain at least
partially located on the outer layer and surrounding the sample
drain; and a sealing member at least partially located on the outer
layer and surrounding the sample drain, wherein the sealing member
fluidly isolates the sample drain from the guard drain when the
sealing member contacts a sidewall of the wellbore, and wherein the
sealing member is detachably connected with the outer layer.
[0073] The sealing member may be manually connectable and
disconnectable with the outer layer.
[0074] The outer layer may comprise a cavity in which the sealing
member is received, and the sealing member may comprise a shoulder
latching against a corresponding shoulder of the outer layer to
connect the sealing member to the outer layer.
[0075] The expandable packer assembly may comprise a support ring
abutting the sealing member. The sealing member may surround the
support ring. The support ring may comprise a material that is
stiffer than material forming the sealing member. The support ring
may comprise a plurality of sliding metal members.
[0076] The outer layer may comprise a protruding shoulder abutting
the sealing member.
[0077] The present disclosure also introduces an apparatus
comprising an expandable packer assembly for coupling within a tool
string deployable within a wellbore, wherein the expandable packer
assembly comprises: an expandable packer having an outer layer; a
sample drain at least partially located on the outer layer and
operable to receive formation fluid; a guard drain at least
partially located on the outer layer and surrounding the sample
drain; and a sealing member at least partially located on the outer
layer and surrounding the sample drain, wherein the sealing member
fluidly isolates the sample drain from the guard drain when the
sealing member contacts a sidewall of the wellbore, and wherein the
outer layer comprises an external shoulder abutting the sealing
member.
[0078] The sealing member may be detachably connected with the
outer layer.
[0079] The sealing member may be manually connectable and
disconnectable with the outer layer.
[0080] A drain may comprise the sample drain, the guard drain, and
a cavity in which the sealing member is received, and the sealing
member may comprise a shoulder latching against a corresponding
internal shoulder of the drain to connect the sealing member to the
drain.
[0081] The expandable packer assembly may comprise a support ring
abutting the sealing member. The sealing member may surround the
support ring. The support ring may comprise a material that is
stiffer than material forming the sealing member. The support ring
may comprise a plurality of sliding metal members.
[0082] The external shoulder may protrude outwardly from an outer
surface of the outer layer.
[0083] The external shoulder may be a first external shoulder
abutting the sealing member on a first side, and the outer layer
may comprise a second external shoulder abutting the sealing member
on a second side opposite the first side.
[0084] The foregoing outlines features of several embodiments so
that a person having ordinary skill in the art may better
understand the aspects of the present disclosure. A person having
ordinary skill in the art should appreciate that they may readily
use the present disclosure as a basis for designing or modifying
other processes and structures for carrying out the same functions
and/or achieving the same benefits of the implementations
introduced herein. A person having ordinary skill in the art should
also realize that such equivalent constructions do not depart from
the spirit and scope of the present disclosure, and that they may
make various changes, substitutions and alterations herein without
departing from the spirit and scope of the present disclosure.
[0085] The Abstract at the end of this disclosure is provided to
permit the reader to quickly ascertain the nature of the technical
disclosure. It is submitted with the understanding that it will not
be used to interpret or limit the scope or meaning of the
claims.
* * * * *