(19)
(11) EP 3 173 574 A1

(12) EUROPEAN PATENT APPLICATION

(43) Date of publication:
31.05.2017 Bulletin 2017/22

(21) Application number: 15290293.8

(22) Date of filing: 26.11.2015
(51) International Patent Classification (IPC): 
E21B 33/127(2006.01)
E21B 49/10(2006.01)
(84) Designated Contracting States:
AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR
Designated Extension States:
BA ME
Designated Validation States:
MA MD

(71) Applicants:
  • Services P├ętroliers Schlumberger
    75007 Paris (FR)

    FR 
  • Schlumberger Holdings Limited
    Road Town, Tortola (VG)

    GB NL 
  • Schlumberger Technology B.V.
    2514 JG The Hague (NL)

    AL AT BE BG CH CY CZ DE DK EE ES FI GR HR HU IE IS IT LI LT LU LV MC MK MT NO PL PT RO RS SE SI SK SM TR 

(72) Inventors:
  • Milh, Patrice
    92140 Clamart (FR)
  • Corre, Pierre-Yves
    92140 Clamart (FR)

(74) Representative: Rzaniak, Martin 
Etudes & Productions Schlumberger 1, rue Henri Becquerel, BP 202
92142 Clamart Cedex
92142 Clamart Cedex (FR)

   


(54) ASSEMBLY AND METHOD FOR AN EXPANDABLE PACKER


(57) A downhole packer assembly that includes an inner packer and a drain (50) coupled to the inner packer. The drain includes a sample inlet (96), a guard inlet (98), and a seal (40) 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.




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.

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;

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;

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;

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;

FIG. 5 is a front view of a drain of a packer assembly according to an embodiment of the present disclosure;

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;

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;

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;

FIG. 9 is a cross-sectional view of an inflatable four-layer seal according to an embodiment of the present disclosure;

FIG. 10 is a cross-sectional view of an inflatable two-layer seal according to an embodiment of the present disclosure;

FIG. 11 is a cross-sectional view of an external layer of an inflatable seal according to an embodiment of the present disclosure;

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

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



[0006] 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.

[0007] 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.

[0008] 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.

[0009] 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.

[0010] 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.

[0011] 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.

[0012] 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.

[0013] 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.

[0014] 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.

[0015] 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.

[0016] 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.

[0017] 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.

[0018] 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.

[0019] 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.

[0020] 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).

[0021] 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.

[0022] 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.

[0023] 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.


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.
 




Drawing






















Search report












Search report