EP3173574A1 - Assembly and method for an expandable packer - Google Patents
Assembly and method for an expandable packer Download PDFInfo
- Publication number
- EP3173574A1 EP3173574A1 EP15290293.8A EP15290293A EP3173574A1 EP 3173574 A1 EP3173574 A1 EP 3173574A1 EP 15290293 A EP15290293 A EP 15290293A EP 3173574 A1 EP3173574 A1 EP 3173574A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- seal
- packer assembly
- inlet
- fluid
- hydrostatic pressure
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Withdrawn
Links
- 238000000034 method Methods 0.000 title claims description 11
- 230000002706 hydrostatic effect Effects 0.000 claims abstract description 42
- 239000012530 fluid Substances 0.000 claims description 83
- 230000015572 biosynthetic process Effects 0.000 claims description 53
- 238000007789 sealing Methods 0.000 claims description 31
- 238000001125 extrusion Methods 0.000 claims description 7
- 230000007423 decrease Effects 0.000 claims description 2
- 238000005755 formation reaction Methods 0.000 description 50
- 238000005070 sampling Methods 0.000 description 30
- 239000000523 sample Substances 0.000 description 17
- 239000000463 material Substances 0.000 description 7
- 239000013536 elastomeric material Substances 0.000 description 6
- 230000006835 compression Effects 0.000 description 5
- 238000007906 compression Methods 0.000 description 5
- 229920001971 elastomer Polymers 0.000 description 5
- 239000005060 rubber Substances 0.000 description 5
- -1 but not limited to Substances 0.000 description 4
- 238000012544 monitoring process Methods 0.000 description 4
- 229920000459 Nitrile rubber Polymers 0.000 description 3
- 238000012360 testing method Methods 0.000 description 3
- 238000010276 construction Methods 0.000 description 2
- 238000005553 drilling Methods 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 230000015654 memory Effects 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 239000000853 adhesive Substances 0.000 description 1
- 230000001070 adhesive effect Effects 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 239000000835 fiber Substances 0.000 description 1
- 239000000706 filtrate Substances 0.000 description 1
- NBVXSUQYWXRMNV-UHFFFAOYSA-N fluoromethane Chemical compound FC NBVXSUQYWXRMNV-UHFFFAOYSA-N 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
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Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
- E21B49/10—Obtaining fluid samples or testing fluids, in boreholes or wells using side-wall fluid samplers or testers
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
- E21B33/1216—Anti-extrusion means, e.g. means to prevent cold flow of rubber packing
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/127—Packers; Plugs with inflatable sleeve
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
Definitions
- Wellbores or boreholes may be drilled to, for example, locate and produce hydrocarbons.
- it may be desirable to evaluate and/or measure properties of encountered formations and formation fluids.
- 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).
- 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.
- 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.
- 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.
- 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.
- 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.
- first and second features are formed in direct contact
- additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
- 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.
- formation fluid samples are collected through an outer layer of the packer assembly and conveyed to a desired collection location.
- 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.
- 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.
- 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.
- 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.
- 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).
- 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).
- the seal may block mixing of the first and second formation fluids in the space.
- embodiments of the seal help the packer assembly to collect relatively uncontaminated formation fluid that is representative of the fluid in the formation.
- 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.
- the well system 20 includes a conveyance 24 employed to deliver at least one packer assembly 26 downhole.
- 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.
- 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.
- the packer assembly 26 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.
- packer assembly 26 may have an axial axis or direction 37, a radial axis or direction 38, and a circumferential axis or direction 39.
- 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.
- the inner bladder 42 e.g., inner packer
- 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.
- 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.
- 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.
- 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.
- 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.
- the drain 50 may have an elongated shape.
- 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.
- the seal 72 is configured with a shape substantially matching that of the drain.
- the seal 72 may be configured as an oval or circular ring.
- 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 .
- the seal 72 is disposed within the outer layer 40 (e.g., outer skin).
- the seal 72 is configured as an inflatable seal.
- the inflatable seal 72 includes an interior 90 surrounded by one or more layers 92.
- 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.
- the inflatable seal 72 is at least partially disposed in a seal groove 94 that at least partially contains or holds the seal 72.
- 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.
- the inflatable seal 72 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.
- 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.
- wellbore wall 32 e.g., casing or open wellbore wall
- 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.
- 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.
- 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.
- FIG. 8 is a cross-sectional view of a portion of an embodiment of the drain 50 with the inflatable seal 72.
- 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.
- 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.
- the hydrostatic fluid flowline 134 may include a valve 136 used to control or adjust the flowrate of the fluid at the hydrostatic pressure.
- 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.
- 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.
- 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.
- the valve 136 shown in FIG. 8 may be coupled to an actuator 138.
- the conveyance 24 may include a processor 140 of a control/monitoring system 142.
- 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.
- 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.
- FIG. 9 is a cross-sectional view of an embodiment of the inflatable seal 72 with four layers.
- the inflatable seal 72 includes a first innermost sealing layer 160 that surrounds the interior 90.
- 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.
- a second anti-extrusion layer 162 surrounds the first innermost sealing layer 160.
- 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.
- a third mechanical layer 164 surrounds the second anti-extrusion layer 162.
- 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.
- a fourth external skin layer 166 surrounds the third mechanical layer 164.
- 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.
- FIG. 10 is a cross-sectional view of an embodiment of the inflatable seal 72 with three layers.
- the inflatable seal 72 includes an inner mechanical layer 180 that surrounds the interior 90.
- the inner mechanical layer 180 may be made from a flexible material, which may help block the fluid from escaping the interior 90.
- the inner mechanical layer 180 includes an inner opening 182 that enables the inner mechanical layer 180 to expand radially 37.
- an outer mechanical layer 184 surrounds the inner mechanical layer 180.
- 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.
- 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.
- 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.
- 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.
- an external skin layer 190 surrounds the outer mechanical layer 184.
- 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.
- 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.
- 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.
- 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.
- FIG. 11 is a cross-sectional view of an embodiment of the external skin layer 190 of the inflatable seal 72 of FIG. 10 .
- 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).
- 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.
- the external skin layer 190 may be separated into the upper and lower portions 194 and 196 by the opening 192.
- 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 .
- the seal 72 is configured as a piston seal.
- 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 .
- 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).
- 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).
- 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.
- 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.
- 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.
- 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.
- 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 .
- the piston seal 72 may include a stop configured to block the piston 210 from moving completely out of the piston chamber 212.
- the piston chamber 212 may include a shoulder to block movement of the piston 210 out of the piston chamber 212.
- 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.
- the drain includes a second inflatable seal 230 surrounding the guard zone 74.
- 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.
- 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.
- 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.
- the second inflatable seal 230 may be used together with the outer layer 40.
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- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Investigation Of Foundation Soil And Reinforcement Of Foundation Soil By Compacting Or Drainage (AREA)
- Sampling And Sample Adjustment (AREA)
Abstract
Description
- 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.
- 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.
- 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.
- 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.
- 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 inFIG. 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 ofFIG. 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. - 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.
- 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.
- 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.
- Referring generally to
FIG. 1 , one embodiment of awell system 20 is illustrated as deployed in awellbore 22. Thewell system 20 includes aconveyance 24 employed to deliver at least onepacker assembly 26 downhole. In many applications, thepacker assembly 26 is deployed byconveyance 24 in the form of a wireline, butconveyance 24 may have other forms, including tubing strings, for other applications. In the illustrated embodiment, thepacker assembly 26 is used to collect formation fluids from a surroundingformation 28. Thepacker assembly 26 is selectively expanded in a radially outward direction to seal across anexpansion zone 30 with a surroundingwellbore wall 32, such as a surrounding casing or open wellbore wall. When thepacker assembly 26 is expanded to seal againstwellbore wall 32, formation fluids can be flowed into thepacker assembly 26, as indicated byarrows 34. The formation fluids are then directed to a flowline, as represented byarrows 35, and produced to a collection location, such as a location at awell site surface 36. As described in detail below, thepacker assembly 26 may include a seal configured to move into a space between a sample inlet and a guard inlet based on hydrostatic pressure. - Referring generally to
FIG. 2 , one embodiment of thepacker assembly 26 is illustrated, which may have an axial axis ordirection 37, a radial axis ordirection 38, and a circumferential axis ordirection 39. In this embodiment,packer assembly 26 includes an outer layer 40 (e.g., outer skin) that is expandable in thewellbore 22 to form a seal with surroundingwellbore wall 32 acrossexpansion zone 30. Thepacker assembly 26 further includes an inner,inflatable bladder 42 disposed within an interior ofouter layer 40. In one example, the inner bladder 42 (e.g., inner packer) is selectively expanded by fluid delivered via aninner mandrel 44. Furthermore,packer assembly 26 includes a pair ofmechanical fittings 46 that are mounted aroundinner mandrel 44 and engaged withaxial ends 48 ofouter layer 40. - With additional reference to
FIG. 3 ,outer layer 40 may include one or more windows or drains 50 through which formation fluid is collected whenouter layer 40 is expanded against surroundingwellbore wall 32.Drains 50 may be embedded radially into a sealingelement 52 ofouter layer 40. By way of example, sealingelement 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, orflowlines 54 may be operatively coupled withdrains 50 for directing the collected formation fluid in an axial 37 direction to one or both of themechanical fittings 46. As further illustrated inFIG. 4 ,flowlines 54 may be aligned generally parallel with apacker axis 56 that extends through the axial ends ofouter layer 40. -
FIG. 5 is a front view of an embodiment of thedrain 50 of thepacker assembly 26. The illustrated embodiment includes asampling zone 70, aseal 72 surrounding the sampling zone, and aguard zone 74 surrounding theseal 72. As shown inFIG. 5 , theseal 72 divides thedrain 50 into the sampling andguard zones drain 50 may be used for guarded or focused sampling. Fluid collected in thesampling zone 70 is relatively less contaminated by filtrate than fluid collected in theguard 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 inFIG. 5 , thedrain 50 may have an elongated shape. In other embodiments, thedrain 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, theseal 72 is configured with a shape substantially matching that of the drain. For example, theseal 72 may be configured as an oval or circular ring. -
FIG. 6 is a cross-sectional view of an embodiment of thedrain 50 of thepacker assembly 26 taken along line 6-6 ofFIG. 5 . As shown inFIG. 6 , theseal 72 is disposed within the outer layer 40 (e.g., outer skin). In the illustrated embodiment, theseal 72 is configured as an inflatable seal. Specifically, theinflatable 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 theinflatable seal 72. Theinflatable seal 72 shown inFIG. 6 is in an un-inflated or deflated state. In addition, theinflatable seal 72 is at least partially disposed in aseal groove 94 that at least partially contains or holds theseal 72. In the illustrated embodiment, thedrain 50 includes asampling inlet 96 configured to collect fluid from thesampling zone 70 and aguard inlet 98 configured to collect fluid from theguard zone 74. The sampling andguard inlets packer assembly 26. As described in detail below, when theinflatable seal 72 is inflated, theinflatable seal 72 moves into aspace 100 between the sampling andguard inlets -
FIG. 7 is a cross-sectional view of an embodiment of thedrain 50 of thepacker assembly 26 taken along line 6-6 ofFIG. 5 . Theinflatable seal 72 shown inFIG. 7 is in an inflated state. Specifically, the introduction of fluid at hydrostatic pressure into the interior 90 of theinflatable seal 72 has caused theinflatable seal 72 to inflate as indicated byarrows 110 until the one ormore layers 92 of theinflatable seal 72 have contacted theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall). In other words, theinflatable seal 72 shown inFIG. 7 has moved into thespace 100 between the sampling andguard inlets inflatable seal 72 inflates because the hydrostatic pressure within theinterior 90 of theinflatable seal 72 is greater than a pressure in a drawdown zone 112 (e.g., sampling andguard zones 70 and 74). Drawdown may refer to the use of a pump or piston in thepacker assembly 26 to decrease the pressure in thedrawdown zone 112 adjacent thedrain 50 to cause fluid from theformation 28 to enter thepacker assembly 26. When the pressure in thedrawdown zone 112 is less than a formation pressure, the differential pressure may cause fluid to flow out from theformation 28 and into thedrawdown zone 112. The greater the difference between the hydrostatic pressure within the interior 90 and the drawdown pressure, the greater the inflation theinflatable seal 72 undergoes. As shown inFIG. 7 , theinflatable seal 72 blocks fluids in the sampling andguard zones inflatable seal 72 enables thesampling inlet 96 to collect fluid from thesampling zone 70 that is separate from the fluid theguard inlet 98 collects from theguard zone 74. Thus, theinflatable seal 72 helps improve the focused sampling performance of thedrain 50. -
FIG. 8 is a cross-sectional view of a portion of an embodiment of thedrain 50 with theinflatable seal 72. In the illustrated embodiment, theinflatable seal 72 includes anopening 130 through which the fluid at the hydrostatic pressure may enter or leave. Theopening 130 may be fluidly coupled to asource 132 of the fluid at the hydrostatic pressure. As shown, thesource 132 may be contained within a hydrostaticfluid flowline 134 formed within thedrain 50 orpacker assembly 26. The hydrostaticfluid flowline 134 may be supplied with borehole fluid or other fluid within thepacker assembly 26 that is at the hydrostatic pressure. In certain embodiments, the hydrostaticfluid flowline 134 may include avalve 136 used to control or adjust the flowrate of the fluid at the hydrostatic pressure. For example, thevalve 136 may be opened when sealing of the sampling andguard zones 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 theinflatable seal 72. Similarly, thevalve 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 theinflatable seal 72. - In certain embodiments, the
valve 136 shown inFIG. 8 may be coupled to anactuator 138. For example, theconveyance 24 may include aprocessor 140 of a control/monitoring system 142. In the context of the present disclosure, the term "processor" refers to any number of processor components. Theprocessor 140 may include a single processor disposed onboard theconveyance 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 thewell system 20 ofFIG. 1 and/or other surface equipment components. Theprocessor 140 may also or instead be or include one or more processors located within theconveyance 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 theprocessor 140. Similar terminology is applied with respect to the control/monitoring system 142, as well as amemory 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. -
FIG. 9 is a cross-sectional view of an embodiment of theinflatable seal 72 with four layers. As shown inFIG. 9 , theinflatable seal 72 includes a firstinnermost sealing layer 160 that surrounds the interior 90. In certain embodiments, the firstinnermost 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 theinflatable seal 72. Next, asecond anti-extrusion layer 162 surrounds the firstinnermost sealing layer 160. In certain embodiments, thesecond anti-extrusion layer 162 may be made from one or more fibers, which may help block extrusion of the elastomeric material of the firstinnermost sealing layer 160 during inflation of theinflatable seal 72. Next, a thirdmechanical layer 164 surrounds thesecond anti-extrusion layer 162. In certain embodiments, the thirdmechanical layer 164 may be made from one or more cables, which may also help reduce stress on thesecond anti-extrusion layer 162 during inflation of theinflatable seal 72. Finally, a fourthexternal skin layer 166 surrounds the thirdmechanical layer 164. In certain embodiments, the fourthexternal 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 theformation 28. The four-layer structure of the illustrated embodiment of theinflatable seal 72 may provide increased durability compared to other configurations of theinflatable 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 thewellbore 22. -
FIG. 10 is a cross-sectional view of an embodiment of theinflatable seal 72 with three layers. As shown inFIG. 10 , theinflatable seal 72 includes an innermechanical layer 180 that surrounds the interior 90. In certain embodiments, the innermechanical layer 180 may be made from a flexible material, which may help block the fluid from escaping the interior 90. In certain embodiments, the innermechanical layer 180 includes aninner opening 182 that enables the innermechanical layer 180 to expand radially 37. Next, an outermechanical layer 184 surrounds the innermechanical layer 180. In certain embodiments, the outermechanical 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 outermechanical layer 184 includes anouter opening 186 that enables the outermechanical layer 184 to expand radially 37. As shown inFIG. 10 , theouter opening 186 may be disposed opposite from theinner opening 182 to help block fluid from escaping the interior 90. In certain embodiments, the inner and outermechanical layers inner opening 182, and along the interface between the inner and outermechanical layers rings 188 may be disposed between the inner and outermechanical layers external skin layer 190 surrounds the outermechanical layer 184. In certain embodiments, theexternal 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 theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall). Theexternal skin layer 190 may include one ormore openings 192 to help improve the sealing provided by theinflatable seal 72. For example, with twoopenings 192, theexternal skin layer 190 includes anupper portion 194 that contacts theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall) and alower portion 196 that contacts theseal groove 94. Such a split or divided design for theexternal skin layer 190 may provide additional operational flexibility. For example, theupper portion 194 may be made from a more durable material selected for repeated contact against theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall) compared to the material selected for thelower portion 196. Further, the material selected for theexternal skin layer 190 may be chosen based on theexternal 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. -
FIG. 11 is a cross-sectional view of an embodiment of theexternal skin layer 190 of theinflatable seal 72 ofFIG. 10 . As shown inFIG. 11 , theexternal skin layer 190 may have a shape that improves sealing of theinflatable seal 72 against theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall). For example, theexternal skin layer 190 may have a relativelyflat surface 200 that contacts theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall). Other suitable shapes may be used for theexternal skin layer 190 depending on the particular conditions, composition, or irregularities of thewellbore 22. Such shapes may be possible because theexternal skin layer 190 works in compression and not in both compression and tension in certain embodiments. As shown inFIG. 11 , theexternal skin layer 190 may be separated into the upper andlower portions opening 192. -
FIG. 12 is a cross-sectional view of an embodiment of thedrain 50 of thepacker assembly 26 taken along line 6-6 ofFIG. 5 . As shown inFIG. 12 , theseal 72 is configured as a piston seal. Specifically, thepiston seal 72 includes apiston 210 disposed in apiston chamber 212, which is fluidly coupled to the hydrostaticfluid flowline 134. Asealing layer 214 may be coupled to anexternal surface 216 of thepiston 210 and thesealing layer 214 may be configured to seal against theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall) as shown inFIG. 12 . In certain embodiments, thesealing layer 214 may be made from an elastomeric material, such as, but not limited to, rubber, which may provide an effective sealing surface with theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall). In addition, a thickness of thepiston 210 may be reduced to help thepiston 210 and sealinglayer 214 to better comply with or adapt to irregularities in theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall). - When the embodiment of the
piston seal 72 shown inFIG. 12 is in operation, the fluid at hydrostatic pressure may push thepiston 210 as indicated byarrows 218, causing thesealing layer 214 to move into thespace 100 between the sampling andguard inlets piston chamber 212. More specifically, thepiston seal 72 operates because the hydrostatic pressure within thepiston chamber 212 is greater than the pressure in the drawdown zone 112 (e.g., sampling andguard zones 70 and 74). The greater the difference between the hydrostatic pressure within thepiston chamber 212 and the drawdown pressure, the greater the force thesealing layer 214 exerts upon thewellbore 28 or wellbore wall 32 (e.g., casing or open wellbore wall). As shown inFIG. 12 , thesealing layer 214 blocks fluids in the sampling andguard zones piston seal 72 enables thesampling inlet 96 to collect fluid from thesampling zone 70 that is separate from the fluid theguard inlet 98 collects from theguard zone 74. Thus, thepiston seal 72 helps improve the focused sampling performance of thedrain 50. In certain embodiments, a piston O-ring 220 may be used to help block the fluid at hydrostatic pressure in thepiston chamber 212 from entering thedrawdown zone 112 during operation of thepiston seal 72. In further embodiments, thevalve 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 theinflatable seal 72 shown inFIG. 8 . In still further embodiments, thepiston seal 72 may include a stop configured to block thepiston 210 from moving completely out of thepiston chamber 212. For example, thepiston chamber 212 may include a shoulder to block movement of thepiston 210 out of thepiston chamber 212. -
FIG. 13 is a cross-sectional view of an embodiment of thedrain 50 with theinflatable seal 72 separating the sampling andguard zones inflatable seal 230 surrounding theguard zone 74. Thus, the secondinflatable seal 230 blocks fluid present in the wellbore 22 from entering theguard zone 74, thereby helping thedrain 50 to collect representative samples of fluid from theformation 28 and improving the focused sampling performance of thedrain 50. The secondinflatable seal 230 may operate in a similar manner to theinflatable seal 72. Specifically, the introduction of fluid at hydrostatic pressure into the interior 90 of the secondinflatable seal 230 causes the secondinflatable seal 230 to inflate as indicated byarrows 110 until one ormore layers 92 of the secondinflatable seal 230 contact theformation 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 secondinflatable seal 230 undergoes. In certain embodiments, use of the secondinflatable seal 230 may enable theouter layer 40 of thepacker assembly 26 to be omitted, thereby simplifying the construction and reducing the cost of thepacker assembly 26. In further embodiments, the secondinflatable seal 230 may be used together with theouter layer 40. - 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 (20)
- A downhole packer assembly, comprising:an inner packer; anda drain coupled to the inner packer, wherein the drain comprises:a sample inlet;a guard inlet; anda 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.
- 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.
- 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.
- The downhole packer assembly of claim 1, wherein the seal is configured to improve sealing performance as the hydrostatic pressure increases.
- The downhole packer assembly of claim 1, wherein the seal is coupled to a source of fluid at the hydrostatic pressure.
- The downhole packer assembly of claim 5, comprising a valve configured to control a flow of the fluid at the hydrostatic pressure.
- The downhole packer assembly of claim 5, wherein the seal comprises an inflatable seal configured to inflate with the fluid.
- 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.
- 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.
- 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.
- 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; anda sealing layer coupled to an external surface of the piston and configured to seal against a wall of a wellbore.
- The downhole packer assembly of claim 11, comprising a stop configured to block the piston from moving completely out of a piston chamber.
- 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.
- 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.
- 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.
- 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; anda 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; andcollecting a second formation fluid through the guard inlet, wherein the seal blocks mixing of the first and second formation fluids in the space.
- 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.
- The method of claim 16, comprising improving sealing performance of the seal as the hydrostatic pressure increases.
- The method of claim 16, comprising inflating the seal with fluid at the hydrostatic pressure.
- The method of claim 16, comprising moving a piston of the seal with fluid at the hydrostatic pressure.
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
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EP15290293.8A EP3173574A1 (en) | 2015-11-26 | 2015-11-26 | Assembly and method for an expandable packer |
US15/778,640 US20180340420A1 (en) | 2015-11-26 | 2016-10-18 | Systems and Methods for an Expandable Packer |
PCT/US2016/057453 WO2017091302A1 (en) | 2015-11-26 | 2016-10-18 | Systems and Methods for an Expandable Packer |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
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EP15290293.8A EP3173574A1 (en) | 2015-11-26 | 2015-11-26 | Assembly and method for an expandable packer |
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EP3173574A1 true EP3173574A1 (en) | 2017-05-31 |
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EP15290293.8A Withdrawn EP3173574A1 (en) | 2015-11-26 | 2015-11-26 | Assembly and method for an expandable packer |
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US (1) | US20180340420A1 (en) |
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WO2015095646A1 (en) * | 2013-12-19 | 2015-06-25 | Schlumberger Canada Limited | Guard filtering system for focused sampling probe |
EP2927421B1 (en) * | 2014-04-03 | 2019-02-20 | Services Pétroliers Schlumberger | Differential pressure mover |
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- 2015-11-26 EP EP15290293.8A patent/EP3173574A1/en not_active Withdrawn
-
2016
- 2016-10-18 US US15/778,640 patent/US20180340420A1/en not_active Abandoned
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Also Published As
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WO2017091302A1 (en) | 2017-06-01 |
US20180340420A1 (en) | 2018-11-29 |
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