U.S. patent application number 15/778640 was filed with the patent office on 2018-11-29 for systems and methods for an expandable packer.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Pierre-Yves Corre, Patrice Milh.
Application Number | 20180340420 15/778640 |
Document ID | / |
Family ID | 54848512 |
Filed Date | 2018-11-29 |
United States Patent
Application |
20180340420 |
Kind Code |
A1 |
Milh; Patrice ; et
al. |
November 29, 2018 |
Systems and Methods for an Expandable Packer
Abstract
The present disclosure relates to a downhole packer assembly
that includes an inner packer and a drain coupled to the inner
packer. The drain includes a sample inlet, a guard inlet, and a
seal disposed between the sample inlet and the guard inlet. The
seal is configured to move into a space between the sample inlet
and the guard inlet based on hydrostatic pressure
Inventors: |
Milh; Patrice; (Rancho
Cucamonga, CA) ; Corre; Pierre-Yves; (Abbeville,
FR) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
54848512 |
Appl. No.: |
15/778640 |
Filed: |
October 18, 2016 |
PCT Filed: |
October 18, 2016 |
PCT NO: |
PCT/US2016/057453 |
371 Date: |
May 24, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/1216 20130101;
E21B 34/06 20130101; E21B 49/10 20130101; E21B 33/127 20130101 |
International
Class: |
E21B 49/10 20060101
E21B049/10; E21B 33/12 20060101 E21B033/12; E21B 33/127 20060101
E21B033/127; E21B 34/06 20060101 E21B034/06 |
Foreign Application Data
Date |
Code |
Application Number |
Nov 26, 2015 |
EP |
15290293.8 |
Claims
1. A downhole packer assembly, comprising: an inner packer; and a
drain coupled to the inner packer, wherein the drain comprises: a
sample inlet; a guard inlet; and a seal disposed between the sample
inlet and the guard inlet, wherein the seal is configured to move
into a space between the sample inlet and the guard inlet based on
hydrostatic pressure.
2. The downhole packer assembly of claim 1, wherein the seal is
configured to move into the space between the sample inlet and the
guard inlet as a difference between the hydrostatic pressure and a
drawdown pressure increases.
3. The downhole packer assembly of claim 1, wherein the seal is
configured to leave the space between the sample inlet and the
guard inlet as a difference between the hydrostatic pressure and a
drawdown pressure decreases.
4. The downhole packer assembly of claim 1, wherein the seal is
configured to improve sealing performance as the hydrostatic
pressure increases.
5. The downhole packer assembly of claim 1, wherein the seal is
coupled to a source of fluid at the hydrostatic pressure.
6. The downhole packer assembly of claim 5, comprising a valve
configured to control a flow of the fluid at the hydrostatic
pressure.
7. The downhole packer assembly of claim 5, wherein the seal
comprises an inflatable seal configured to inflate with the
fluid.
8. The downhole packer assembly of claim 7, wherein the inflatable
seal comprises a first innermost sealing layer, a second
anti-extrusion layer surrounding the first innermost sealing layer,
a third mechanical layer surrounding the second anti-extrusion
layer, and a fourth external skin layer surrounding the third
mechanical layer.
9. The downhole packer assembly of claim 7, wherein the inflatable
seal comprises an inner mechanical layer, an outer mechanical layer
surrounding the inner mechanical layer, and an external skin layer
surrounding the outer mechanical layer.
10. The downhole packer assembly of claim 9, wherein the external
skin layer comprises a shape that is configured to fill the space
when the inflatable seal is inflated.
11. The downhole packer assembly of claim 5, wherein the seal
comprises a piston seal, wherein the piston seal comprises: a
piston configured to be moved into the space by the fluid; and a
sealing layer coupled to an external surface of the piston and
configured to seal against a wall of a wellbore.
12. The downhole packer assembly of claim 11, comprising a stop
configured to block the piston from moving completely out of a
piston chamber.
13. The downhole packer assembly of claim 1, comprising an outer
skin, wherein the inner packer is disposed within the outer skin
such that inflation of the inner packer is configured to expand the
outer skin.
14. The downhole packer assembly of claim 1, wherein the drain
comprises a second seal surrounding the guard inlet, wherein the
second seal is configured to move into a second space surrounding
the guard inlet based on hydrostatic pressure.
15. The downhole packer assembly of claim 10, wherein the downhole
packer assembly is configured for conveyance within a wellbore by
at least one of a wireline or a drillstring.
16. A method, comprising: providing a packer assembly having an
inner packer and a drain coupled to the inner packer, wherein the
drain comprises: a sample inlet; a guard inlet; and a seal disposed
between the sample inlet and the guard inlet; positioning the
packer assembly in a wellbore; inflating the inner packer until the
drain is adjacent a wall of the wellbore; moving the seal into a
space between the sample inlet and the guard inlet based on
hydrostatic pressure; collecting a first formation fluid through
the sample inlet; and collecting a second formation fluid through
the guard inlet, wherein the seal blocks mixing of the first and
second formation fluids in the space.
17. The method of claim 16, comprising moving the seal into the
space between the sample inlet and the guard inlet as a difference
between the hydrostatic pressure and a drawdown pressure
increases.
18. The method of claim 16, comprising improving sealing
performance of the seal as the hydrostatic pressure increases.
19. The method of claim 16, comprising inflating the seal with
fluid at the hydrostatic pressure.
20. The method of claim 16, comprising moving a piston of the seal
with fluid at the hydrostatic pressure.
Description
BACKGROUND OF THE DISCLOSURE
[0001] Wellbores or boreholes may be drilled to, for example,
locate and produce hydrocarbons. During a drilling operation, it
may be desirable to evaluate and/or measure properties of
encountered formations and formation fluids. In some cases, a
drillstring is removed and a wireline tool deployed into the
borehole to test, evaluate and/or sample the formations and/or
formation fluid(s). In other cases, the drillstring may be provided
with devices to test and/or sample the surrounding formations
and/or formation fluid(s) without having to remove the drillstring
from the borehole.
[0002] Formation evaluation may involve drawing fluid from the
formation into a downhole tool for testing and/or sampling. Various
devices, such as probes and/or packers, may be extended from the
downhole tool to isolate a region of the wellbore wall, and thereby
establish fluid communication with the subterranean formation
surrounding the wellbore. Fluid may then be drawn into the downhole
tool using the probe and/or packer. Within the downhole tool, the
fluid may be directed to one or more fluid analyzers and sensors
that may be employed to detect properties of the fluid while the
downhole tool is stationary within the wellbore.
SUMMARY
[0003] The present disclosure relates to a downhole packer assembly
that includes an inner packer and a drain coupled to the inner
packer. The drain includes a sample inlet, a guard inlet, and a
seal disposed between the sample inlet and the guard inlet. The
seal is configured to move into a space between the sample inlet
and the guard inlet based on hydrostatic pressure.
[0004] The present disclosure also relates to a method including
providing a packer assembly having an inner packer and a drain
coupled to the inner packer. The drain includes a sample inlet, a
guard inlet, and a seal disposed between the sample inlet and the
guard inlet. The method also includes positioning the packer
assembly in a wellbore, inflating the inner packer until the drain
is adjacent a wall of the wellbore, moving the seal into a space
between the sample inlet and the guard inlet based on hydrostatic
pressure, collecting a first formation fluid through the sample
inlet, and collecting a second formation fluid through the guard
inlet. The seal blocks mixing of the first and second formation
fluids in the space.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] 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.
[0006] FIG. 1 is a schematic front elevation view of an embodiment
of a well system having a packer assembly through which formation
fluids may be collected, according to aspects of the present
disclosure;
[0007] FIG. 2 is an orthogonal view of one example of the packer
assembly illustrated in FIG. 1, according to an embodiment of the
present disclosure;
[0008] FIG. 3 is an orthogonal view of one example of an outer
layer that can be used with the packer assembly, according to an
embodiment of the present disclosure;
[0009] FIG. 4 is a view similar to that of FIG. 3 but showing
internal components of the outer layer, according to an embodiment
of the present disclosure;
[0010] FIG. 5 is a front view of a drain of a packer assembly
according to an embodiment of the present disclosure;
[0011] FIG. 6 is a cross-sectional view of a drain of a packer
assembly with an inflatable seal according to an embodiment of the
present disclosure;
[0012] FIG. 7 is a cross-sectional view of a drain of a packer
assembly with an inflatable seal in a sealing position according to
an embodiment of the present disclosure;
[0013] FIG. 8 is a cross-sectional view of a portion of a drain of
a packer assembly with an inflatable seal according to an
embodiment of the present disclosure;
[0014] FIG. 9 is a cross-sectional view of an inflatable four-layer
seal according to an embodiment of the present disclosure;
[0015] FIG. 10 is a cross-sectional view of an inflatable two-layer
seal according to an embodiment of the present disclosure;
[0016] FIG. 11 is a cross-sectional view of an external layer of an
inflatable seal according to an embodiment of the present
disclosure;
[0017] FIG. 12 is a cross-sectional view of a drain of a packer
assembly with a piston seal according to an embodiment of the
present disclosure; and
[0018] FIG. 13 is a cross-sectional view of a drain of a packer
assembly with two inflatable seals in a sealing position according
to an embodiment of the present disclosure.
DETAILED DESCRIPTION
[0019] It is to be understood that the following disclosure
provides many different embodiments, or examples, for implementing
different features of various embodiments. Specific examples of
components and arrangements are described below to simplify the
present disclosure. These are, of course, 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 the purpose of simplicity and
clarity and does not in itself dictate a relationship between the
various embodiments and/or configurations discussed. Moreover, the
formation of a first feature over or on a second feature in the
description that follows may include embodiments in which the first
and second features are formed in direct contact, and may also
include embodiments in which additional features may be formed
interposing the first and second features, such that the first and
second features may not be in direct contact.
[0020] The present disclosure relates to systems and methods for an
expandable packer, such as an expandable packer assembly used as
part of a downhole tool disposed in a wellbore. In certain
embodiments, formation fluid samples are collected through an outer
layer of the packer assembly and conveyed to a desired collection
location. In addition, the packer assembly may include an
expandable sealing element that enables the packer assembly to
better support the formation in a produced zone at which formation
fluids are collected. In certain embodiments, the packer assembly
expands across an expansion zone, and formation fluids can be
collected from the middle of the expansion zone, i.e. between axial
ends of the outer sealing layer. The formation fluid collected is
directed along flowlines, e.g. along flow tubes, having sufficient
inner diameter to allow operations in a variety of environments.
Formation fluid can be collected through one or more drains. For
example, separate drains can be disposed along the circumference of
the packer assembly to establish collection zones. Each drain may
include a sampling zone and a guard zone that enables focused
sampling. Separate flowlines can be connected to the sampling and
guard zones to enable the collection of unique formation fluid
samples.
[0021] In certain embodiments, the packer assembly includes several
components or layers, such as an outer skin and an inner packer
disposed within the outer skin such that inflation of the inner
packer causes the outer skin to expand. In addition, a drain may be
coupled to the outer skin and the drain may include a sample inlet,
a guard inlet, and a seal disposed between the sample inlet and the
guard inlet. The seal may be configured to move into a space
between the sample inlet and the guard inlet based on hydrostatic
pressure (i.e., the borehole pressure). During operation of the
packer assembly, the sample inlet may be used to collect a first
formation fluid (e.g., uncontaminated formation fluid) and the
guard inlet may be used to collect a second formation fluid (e.g.,
contaminated formation fluid). After the seal has moved into the
space between the sample and guard inlets, the seal may block
mixing of the first and second formation fluids in the space. Thus,
embodiments of the seal help the packer assembly to collect
relatively uncontaminated formation fluid that is representative of
the fluid in the formation. In addition, the disclosed embodiments
of the seal may provide improved sealing performance as the
hydrostatic pressure increases. Further, embodiments of the seal
may provide improved sealing when the walls of the wellbore possess
irregularities.
[0022] Referring generally to FIG. 1, one embodiment of a well
system 20 is illustrated as deployed in a wellbore 22. The well
system 20 includes a conveyance 24 employed to deliver at least one
packer assembly 26 downhole. In many applications, the packer
assembly 26 is deployed by conveyance 24 in the form of a wireline,
but conveyance 24 may have other forms, including tubing strings,
for other applications. In the illustrated embodiment, the packer
assembly 26 is used to collect formation fluids from a surrounding
formation 28. The packer assembly 26 is selectively expanded in a
radially outward direction to seal across an expansion zone 30 with
a surrounding wellbore wall 32, such as a surrounding casing or
open wellbore wall. When the packer assembly 26 is expanded to seal
against wellbore wall 32, formation fluids can be flowed into the
packer assembly 26, as indicated by arrows 34. The formation fluids
are then directed to a flowline, as represented by arrows 35, and
produced to a collection location, such as a location at a well
site surface 36. As described in detail below, the packer assembly
26 may include a seal configured to move into a space between a
sample inlet and a guard inlet based on hydrostatic pressure.
[0023] Referring generally to FIG. 2, one embodiment of the packer
assembly 26 is illustrated, which may have an axial axis or
direction 37, a radial axis or direction 38, and a circumferential
axis or direction 39. In this embodiment, packer assembly 26
includes an outer layer 40 (e.g., outer skin) that is expandable in
the wellbore 22 to form a seal with surrounding wellbore wall 32
across expansion zone 30. The packer assembly 26 further includes
an inner, inflatable bladder 42 disposed within an interior of
outer layer 40. In one example, the inner bladder 42 (e.g., inner
packer) is selectively expanded by fluid delivered via an inner
mandrel 44. Furthermore, packer assembly 26 includes a pair of
mechanical fittings 46 that are mounted around inner mandrel 44 and
engaged with axial ends 48 of outer layer 40.
[0024] With additional reference to FIG. 3, outer layer 40 may
include one or more windows or drains 50 through which formation
fluid is collected when outer layer 40 is expanded against
surrounding wellbore wall 32. Drains 50 may be embedded radially
into a sealing element 52 of outer layer 40. By way of example,
sealing element 52 may be cylindrical and formed of an elastomeric
material selected for hydrocarbon based applications, such as
nitrile rubber (NBR), hydrogenated nitrile butadiene rubber (HNBR),
and fluorocarbon rubber (FKM). A plurality of tubular members,
tubes, or flowlines 54 may be operatively coupled with drains 50
for directing the collected formation fluid in an axial 37
direction to one or both of the mechanical fittings 46. As further
illustrated in FIG. 4, flowlines 54 may be aligned generally
parallel with a packer axis 56 that extends through the axial ends
of outer layer 40.
[0025] FIG. 5 is a front view of an embodiment of the drain 50 of
the packer assembly 26. The illustrated embodiment includes a
sampling zone 70, a seal 72 surrounding the sampling zone, and a
guard zone 74 surrounding the seal 72. As shown in FIG. 5, the seal
72 divides the drain 50 into the sampling and guard zones 70 and
74. The embodiment of the drain 50 may be used for guarded or
focused sampling. Fluid collected in the sampling zone 70 is
relatively less contaminated by filtrate than fluid collected in
the guard zone 74. Thus, focused sampling may be used to achieve
more representative samples of formation fluid in less time than
non-focused sampling. As shown in FIG. 5, the drain 50 may have an
elongated shape. In other embodiments, the drain 50 may have other
shapes, such as, but not limited to, a circular shape, an oval
shape, an elliptical shape, a square shape, a rectangular shape, or
a polygonal shape. In certain embodiments, the seal 72 is
configured with a shape substantially matching that of the drain.
For example, the seal 72 may be configured as an oval or circular
ring.
[0026] FIG. 6 is a cross-sectional view of an embodiment of the
drain 50 of the packer assembly 26 taken along line 6-6 of FIG. 5.
As shown in FIG. 6, the seal 72 is disposed within the outer layer
40 (e.g., outer skin). In the illustrated embodiment, the seal 72
is configured as an inflatable seal. Specifically, the inflatable
seal 72 includes an interior 90 surrounded by one or more layers
92. As described in detail below, a fluid at hydrostatic pressure
may be introduced into the interior 90 to inflate the inflatable
seal 72. The inflatable seal 72 shown in FIG. 6 is in an
un-inflated or deflated state. In addition, the inflatable seal 72
is at least partially disposed in a seal groove 94 that at least
partially contains or holds the seal 72. In the illustrated
embodiment, the drain 50 includes a sampling inlet 96 configured to
collect fluid from the sampling zone 70 and a guard inlet 98
configured to collect fluid from the guard zone 74. The sampling
and guard inlets 96 and 98 may be coupled to separate flowlines 54
(not shown) to convey fluids through the packer assembly 26. As
described in detail below, when the inflatable seal 72 is inflated,
the inflatable seal 72 moves into a space 100 between the sampling
and guard inlets 96 and 98 based on the hydrostatic pressure of the
fluid in the interior 90.
[0027] FIG. 7 is a cross-sectional view of an embodiment of the
drain 50 of the packer assembly 26 taken along line 6-6 of FIG. 5.
The inflatable seal 72 shown in FIG. 7 is in an inflated state.
Specifically, the introduction of fluid at hydrostatic pressure
into the interior 90 of the inflatable seal 72 has caused the
inflatable seal 72 to inflate as indicated by arrows 110 until the
one or more layers 92 of the inflatable seal 72 have contacted the
formation 28 or wellbore wall 32 (e.g., casing or open wellbore
wall). In other words, the inflatable seal 72 shown in FIG. 7 has
moved into the space 100 between the sampling and guard inlets 96
and 98 based on the hydrostatic pressure of the fluid in the
interior 90. More specifically, the inflatable seal 72 inflates
because the hydrostatic pressure within the interior 90 of the
inflatable seal 72 is greater than a pressure in a drawdown zone
112 (e.g., sampling and guard zones 70 and 74). Drawdown may refer
to the use of a pump or piston in the packer assembly 26 to
decrease the pressure in the drawdown zone 112 adjacent the drain
50 to cause fluid from the formation 28 to enter the packer
assembly 26. When the pressure in the drawdown zone 112 is less
than a formation pressure, the differential pressure may cause
fluid to flow out from the formation 28 and into the drawdown zone
112. The greater the difference between the hydrostatic pressure
within the interior 90 and the drawdown pressure, the greater the
inflation the inflatable seal 72 undergoes. As shown in FIG. 7, the
inflatable seal 72 blocks fluids in the sampling and guard zones 70
and 74 from mixing with one another. Accordingly, the inflatable
seal 72 enables the sampling inlet 96 to collect fluid from the
sampling zone 70 that is separate from the fluid the guard inlet 98
collects from the guard zone 74. Thus, the inflatable seal 72 helps
improve the focused sampling performance of the drain 50.
[0028] FIG. 8 is a cross-sectional view of a portion of an
embodiment of the drain 50 with the inflatable seal 72. In the
illustrated embodiment, the inflatable seal 72 includes an opening
130 through which the fluid at the hydrostatic pressure may enter
or leave. The opening 130 may be fluidly coupled to a source 132 of
the fluid at the hydrostatic pressure. As shown, the source 132 may
be contained within a hydrostatic fluid flowline 134 formed within
the drain 50 or packer assembly 26. The hydrostatic fluid flowline
134 may be supplied with borehole fluid or other fluid within the
packer assembly 26 that is at the hydrostatic pressure. In certain
embodiments, the hydrostatic fluid flowline 134 may include a valve
136 used to control or adjust the flowrate of the fluid at the
hydrostatic pressure. For example, the valve 136 may be opened when
sealing of the sampling and guard zones 70 and 74 is desired and
closed when sealing is no longer desired. In addition, the valve
136 may be partially closed to reduce the amount or flowrate of
fluid at the hydrostatic pressure that enters the interior 90,
thereby reducing the inflation of the inflatable seal 72.
Similarly, the valve 136 may be opened to increase the amount or
flowrate of fluid at the hydrostatic pressure that enters the
interior 90, thereby increasing the inflation of the inflatable
seal 72.
[0029] In certain embodiments, the valve 136 shown in FIG. 8 may be
coupled to an actuator 138. For example, the conveyance 24 may
include a processor 140 of a control/monitoring system 142. In the
context of the present disclosure, the term "processor" refers to
any number of processor components. The processor 140 may include a
single processor disposed onboard the conveyance 24. In other
implementations, at least a portion of the processor 140 (e.g.,
where multiple processors collectively operate as the processor
140) may be located within the well system 20 of FIG. 1 and/or
other surface equipment components. The processor 140 may also or
instead be or include one or more processors located within the
conveyance 24 and connected to one or more processors located in
drilling and/or other equipment disposed at the wellsite surface.
Moreover, various combinations of processors may be considered part
of the processor 140. Similar terminology is applied with respect
to the control/monitoring system 142, as well as a memory 144 of
the control/monitoring system 142, meaning that the
control/monitoring system 142 may include various processors
communicatively coupled to each other and/or various memories at
various locations.
[0030] FIG. 9 is a cross-sectional view of an embodiment of the
inflatable seal 72 with four layers. As shown in FIG. 9, the
inflatable seal 72 includes a first innermost sealing layer 160
that surrounds the interior 90. In certain embodiments, the first
innermost sealing layer 160 may be made from an elastomeric
material, such as, but not limited to, rubber, which may help block
the fluid in the interior 90 from reaching or contacting other
layers of the inflatable seal 72. Next, a second anti-extrusion
layer 162 surrounds the first innermost sealing layer 160. In
certain embodiments, the second anti-extrusion layer 162 may be
made from one or more fibers, which may help block extrusion of the
elastomeric material of the first innermost sealing layer 160
during inflation of the inflatable seal 72. Next, a third
mechanical layer 164 surrounds the second anti-extrusion layer 162.
In certain embodiments, the third mechanical layer 164 may be made
from one or more cables, which may also help reduce stress on the
second anti-extrusion layer 162 during inflation of the inflatable
seal 72. Finally, a fourth external skin layer 166 surrounds the
third mechanical layer 164. In certain embodiments, the fourth
external skin layer 166 may be made from an elastomeric material,
such as, but not limited to, rubber, which may provide an effective
sealing surface with the formation 28. The four-layer structure of
the illustrated embodiment of the inflatable seal 72 may provide
increased durability compared to other configurations of the
inflatable seal 72. Specifically, the four-layer structure may
provide increased resistance to failure or leakage at high
pressures and/or high temperatures, such as those encountered in
the wellbore 22.
[0031] FIG. 10 is a cross-sectional view of an embodiment of the
inflatable seal 72 with three layers. As shown in FIG. 10, the
inflatable seal 72 includes an inner mechanical layer 180 that
surrounds the interior 90. In certain embodiments, the inner
mechanical layer 180 may be made from a flexible material, which
may help block the fluid from escaping the interior 90. In certain
embodiments, the inner mechanical layer 180 includes an inner
opening 182 that enables the inner mechanical layer 180 to expand
radially 37. Next, an outer mechanical layer 184 surrounds the
inner mechanical layer 180. In certain embodiments, the outer
mechanical layer 184 may be made from a flexible material, which
may help block the transfer of fluid to or from the interior 90. In
certain embodiments, the outer mechanical layer 184 includes an
outer opening 186 that enables the outer mechanical layer 184 to
expand radially 37. As shown in FIG. 10, the outer opening 186 may
be disposed opposite from the inner opening 182 to help block fluid
from escaping the interior 90. In certain embodiments, the inner
and outer mechanical layers 180 and 184 may be coupled to one
another via an adhesive or other mechanical bonding technique,
which may help block fluid from flowing from the interior 90,
through the inner opening 182, and along the interface between the
inner and outer mechanical layers 180 and 184. Alternatively or
additionally, two or more O-rings 188 may be disposed between the
inner and outer mechanical layers 180 and 184 to form a seal
blocking fluid from escaping the interior 90. Next, an external
skin layer 190 surrounds the outer mechanical layer 184. In certain
embodiments, the external skin layer 190 may be made from an
elastomeric material, such as, but not limited to, rubber, which
may provide an effective sealing surface with the formation 28 or
wellbore wall 32 (e.g., casing or open wellbore wall). The external
skin layer 190 may include one or more openings 192 to help improve
the sealing provided by the inflatable seal 72. For example, with
two openings 192, the external skin layer 190 includes an upper
portion 194 that contacts the formation 28 or wellbore wall 32
(e.g., casing or open wellbore wall) and a lower portion 196 that
contacts the seal groove 94. Such a split or divided design for the
external skin layer 190 may provide additional operational
flexibility. For example, the upper portion 194 may be made from a
more durable material selected for repeated contact against the
formation 28 or wellbore wall 32 (e.g., casing or open wellbore
wall) compared to the material selected for the lower portion 196.
Further, the material selected for the external skin layer 190 may
be chosen based on the external skin layer 190 undergoing
compression work and not a combination of compression and tension.
Such materials selected for compression work may be less costly,
more readily available, and/or more durable than other
materials.
[0032] FIG. 11 is a cross-sectional view of an embodiment of the
external skin layer 190 of the inflatable seal 72 of FIG. 10. As
shown in FIG. 11, the external skin layer 190 may have a shape that
improves sealing of the inflatable seal 72 against the formation 28
or wellbore wall 32 (e.g., casing or open wellbore wall). For
example, the external skin layer 190 may have a relatively flat
surface 200 that contacts the formation 28 or wellbore wall 32
(e.g., casing or open wellbore wall). Other suitable shapes may be
used for the external skin layer 190 depending on the particular
conditions, composition, or irregularities of the wellbore 22. Such
shapes may be possible because the external skin layer 190 works in
compression and not in both compression and tension in certain
embodiments. As shown in FIG. 11, the external skin layer 190 may
be separated into the upper and lower portions 194 and 196 by the
opening 192.
[0033] FIG. 12 is a cross-sectional view of an embodiment of the
drain 50 of the packer assembly 26 taken along line 6-6 of FIG. 5.
As shown in FIG. 12, the seal 72 is configured as a piston seal.
Specifically, the piston seal 72 includes a piston 210 disposed in
a piston chamber 212, which is fluidly coupled to the hydrostatic
fluid flowline 134. A sealing layer 214 may be coupled to an
external surface 216 of the piston 210 and the sealing layer 214
may be configured to seal against the formation 28 or wellbore wall
32 (e.g., casing or open wellbore wall) as shown in FIG. 12. In
certain embodiments, the sealing layer 214 may be made from an
elastomeric material, such as, but not limited to, rubber, which
may provide an effective sealing surface with the formation 28 or
wellbore wall 32 (e.g., casing or open wellbore wall). In addition,
a thickness of the piston 210 may be reduced to help the piston 210
and sealing layer 214 to better comply with or adapt to
irregularities in the formation 28 or wellbore wall 32 (e.g.,
casing or open wellbore wall).
[0034] When the embodiment of the piston seal 72 shown in FIG. 12
is in operation, the fluid at hydrostatic pressure may push the
piston 210 as indicated by arrows 218, causing the sealing layer
214 to move into the space 100 between the sampling and guard
inlets 96 and 98 based on the hydrostatic pressure of the fluid in
the piston chamber 212. More specifically, the piston seal 72
operates because the hydrostatic pressure within the piston chamber
212 is greater than the pressure in the drawdown zone 112 (e.g.,
sampling and guard zones 70 and 74). The greater the difference
between the hydrostatic pressure within the piston chamber 212 and
the drawdown pressure, the greater the force the sealing layer 214
exerts upon the wellbore 28 or wellbore wall 32 (e.g., casing or
open wellbore wall). As shown in FIG. 12, the sealing layer 214
blocks fluids in the sampling and guard zones 70 and 74 from mixing
with one another. Accordingly, the piston seal 72 enables the
sampling inlet 96 to collect fluid from the sampling zone 70 that
is separate from the fluid the guard inlet 98 collects from the
guard zone 74. Thus, the piston seal 72 helps improve the focused
sampling performance of the drain 50. In certain embodiments, a
piston O-ring 220 may be used to help block the fluid at
hydrostatic pressure in the piston chamber 212 from entering the
drawdown zone 112 during operation of the piston seal 72. In
further embodiments, the valve 136 may be used to control or adjust
the flowrate of the fluid at the hydrostatic pressure in a similar
manner as discussed above with respect to the embodiment of the
inflatable seal 72 shown in FIG. 8. In still further embodiments,
the piston seal 72 may include a stop configured to block the
piston 210 from moving completely out of the piston chamber 212.
For example, the piston chamber 212 may include a shoulder to block
movement of the piston 210 out of the piston chamber 212.
[0035] FIG. 13 is a cross-sectional view of an embodiment of the
drain 50 with the inflatable seal 72 separating the sampling and
guard zones 70 and 74. In addition, the drain includes a second
inflatable seal 230 surrounding the guard zone 74. Thus, the second
inflatable seal 230 blocks fluid present in the wellbore 22 from
entering the guard zone 74, thereby helping the drain 50 to collect
representative samples of fluid from the formation 28 and improving
the focused sampling performance of the drain 50. The second
inflatable seal 230 may operate in a similar manner to the
inflatable seal 72. Specifically, the introduction of fluid at
hydrostatic pressure into the interior 90 of the second inflatable
seal 230 causes the second inflatable seal 230 to inflate as
indicated by arrows 110 until one or more layers 92 of the second
inflatable seal 230 contact the formation 28 or wellbore wall 32
(e.g., casing or open wellbore wall). The greater the difference
between the hydrostatic pressure within the interior 90 and the
drawdown pressure, the greater the inflation the second inflatable
seal 230 undergoes. In certain embodiments, use of the second
inflatable seal 230 may enable the outer layer 40 of the packer
assembly 26 to be omitted, thereby simplifying the construction and
reducing the cost of the packer assembly 26. In further
embodiments, the second inflatable seal 230 may be used together
with the outer layer 40.
[0036] The foregoing outlines features of several embodiments so
that those skilled in the art may better understand the aspects of
the present disclosure. Those skilled 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 purposes and/or achieving the same advantages of the
embodiments introduced herein. Those skilled 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.
* * * * *