WO2011090491A1 - Downhole device actuator and method - Google Patents
Downhole device actuator and method Download PDFInfo
- Publication number
- WO2011090491A1 WO2011090491A1 PCT/US2010/023690 US2010023690W WO2011090491A1 WO 2011090491 A1 WO2011090491 A1 WO 2011090491A1 US 2010023690 W US2010023690 W US 2010023690W WO 2011090491 A1 WO2011090491 A1 WO 2011090491A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- outer sleeve
- tubular segment
- collar
- energy storage
- string
- Prior art date
Links
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- 238000004146 energy storage Methods 0.000 claims abstract description 45
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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
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
-
- 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
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/02—Couplings; joints
- E21B17/021—Devices for subsurface connecting or disconnecting by rotation
-
- 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
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
- E21B17/1014—Flexible or expansible centering means, e.g. with pistons pressing against the wall of the well
-
- 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
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
- E21B17/1042—Elastomer protector or centering means
-
- 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
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
- E21B17/1078—Stabilisers or centralisers for casing, tubing or drill pipes
-
- 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
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
- E21B17/206—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables with conductors, e.g. electrical, optical
-
- 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
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/06—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting packers
-
- 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
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
-
- H—ELECTRICITY
- H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
- H02K—DYNAMO-ELECTRIC MACHINES
- H02K49/00—Dynamo-electric clutches; Dynamo-electric brakes
- H02K49/10—Dynamo-electric clutches; Dynamo-electric brakes of the permanent-magnet type
-
- 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
- E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
Definitions
- This application relates to methods and devices for downhole operations in earthen boreholes. More specifically, this application relates to actuating a device coupled to a tubular string and run into an earthen borehole.
- a tubular string typically called a drill string
- a tubular string typically called a casing string
- Some boreholes may be extended in a step-wise manner, and additional strings of casing are cemented in the borehole as part of each step.
- a tubular string may be installed within the bore of the cemented casing string to facilitate, for example, the recovery of oil and/or gas from penetrated geologic formations.
- Various devices may be coupled to a tubular string and actuated downhole to facilitate their installation. These devices are typically actuated after being run into and positioned within a borehole, e.g., in a desired location therein.
- bow spring centralizers may be used to position a casing string within a borehole for a subsequent cementing step.
- Bow spring centralizers may be disposed on a casing string at spaced intervals to provide an annulus between the casing string and the borehole.
- Cement slurry may be displaced through the bore of the casing string and into the annulus to form a protective cement liner therein.
- more robust bow springs may be needed to provide sufficient stand-off, but more robust bow springs will increase frictional resistance to movement of the casing string through the borehole.
- One solution is to run centralizers, e.g., bow spring centralizers, on the casing string in a retracted (e.g., collapsed) mode to reduce the frictional resistance to movement of the casing string through the borehole.
- the retracted centralizers may then be deployed at a targeted interval, e.g., to provide the desired stand-off between the casing string and the borehole.
- a challenge is presented in actuating the stand-off portion (e.g., bow spring) of the centralizers from the retracted or collapsed mode to a deployed (expanded) mode without compromising the integrity of the casing string.
- the centralizers are substantially inaccessible because they are disposed within a narrow annulus between the casing string and the borehole.
- One attempted solution provides a method of restraining a centralizer installed on a casing string in a collapsed mode using one or more dissolvable restraining bands, and then dissolving the bands downhole using a strong acid, such as fluoric acid, circulated into the annulus. This solution is disfavored because the acid is dangerous to handle at the surface and can damage critical components in the borehole.
- a strong acid such as fluoric acid
- a packer may be used to seal off an annulus between two tubular strings such as, for example, an annulus between an installed casing string and a production string disposed within the bore of the casing string.
- the pressure in the annulus may be monitored so that a leak in the casing string and/or production string can be readily detected, e.g., for diagnoses and/or repair.
- a packer may be coupled to a tubular string and run into a borehole in a retracted (run-in) mode and then expanded, e.g., to an isolating mode downhole. As above, a challenge is presented in actuating the packer from the retracted mode to the isolating mode without compromising the integrity of the pipe string.
- tubular tubular string
- tubular segment include, but are not limited to, a casing segment and/or a casing string.
- an actuator comprises an outer sleeve threadedly received on a threaded portion of a tubular segment between an energy storage member, such as, but not limited to, a spring, e.g., a compression spring, which may be in a charged (or compressed) mode to store energy therein, and a bow spring centralizer actuatable from a retracted mode to an expanded mode.
- a spring e.g., a compression spring
- a transfer device may be run into the bore of the tubular segment and rotated to activate, or "trigger," the actuator.
- the outer sleeve of the actuator engages and expands the adjacent bow spring centralizer using the energy provided from the energy storage member, e.g., an expanding compression spring.
- an actuator comprises an outer sleeve threadedly received on a threaded portion of a tubular segment between an energy storage member, such as, but not limited to, a spring, e.g., a compression spring, which may be in a charged (or compressed) mode to store energy therein, and a packer actuatable from a retracted mode to an expanded mode.
- a spring e.g., a compression spring
- a transfer device may be run into the bore of the tubular segment and rotated to activate, or "trigger," the actuator.
- the outer sleeve of the actuator engages and expands the adjacent packer using the energy provided from the energy storage member, e.g., an expanding compression spring.
- an actuator comprises an outer sleeve threadedly received on a threaded portion of a tubular segment between an energy storage member, such as, but not limited to, a spring, e.g., a compression spring, which may be in a charged (or compressed) mode to store energy therein, and a fluid valve actuatable from a closed position to an open position or, alternately, from an open position to a closed position.
- an energy storage member such as, but not limited to, a spring, e.g., a compression spring, which may be in a charged (or compressed) mode to store energy therein, and a fluid valve actuatable from a closed position to an open position or, alternately, from an open position to a closed position.
- a transfer device may be run into the bore of the tubular segment and rotated to activate, or "trigger," the actuator.
- a transfer device may be used to enable a magnetic clutch to activate the actuator of the first aspect.
- an actuator may be received on a tubular segment adjacent to an actuatable bow spring centralizer.
- the actuator may comprise an energy storage member, such as a compression spring, having a bore received onto the tubular segment and restrained in a charged (or compressed) mode by an outer sleeve threadedly received on an adjacent threaded and non-magnetic portion of the tubular segment.
- a magnet is coupled to the outer sleeve, and a second magnet is coupled to an inner pipe string and run into the bore of the tubular segment and into the bore of the outer sleeve to form a magnetic clutch.
- Rotation of the inner pipe string transfers torque to the outer sleeve through the magnetic clutch.
- the outer sleeve may be rotated from threaded engagement with the tubular segment to release the energy storage member (e.g., the compression spring) to a discharged (e.g., an expanded) mode.
- the energy storage member displaces the outer sleeve to engage and actuate the adjacent bow spring centralizer.
- Energy storage members that can be used in this application may include, without limitation, a spring (e.g., compression spring or a coil spring) and/or a fluidic cylinder or other chamber and/or other members to convert potential energy to kinetic energy, e.g., including the use of gravitational force.
- a spring e.g., compression spring or a coil spring
- a fluidic cylinder or other chamber e.g., including the use of gravitational force.
- a transfer device may be used to enable a magnetic clutch to activate the actuator of the second aspect.
- an actuator may be received on a tubular segment adjacent to an actuatable packer.
- the actuator may comprise an energy storage member, such as a compression spring, having a bore received onto the tubular segment and restrained in a charged (or compressed) mode by an outer sleeve threadedly received on an adjacent threaded and non-magnetic portion of the tubular segment.
- a magnet is coupled to the outer sleeve, and a second magnet is coupled to an inner pipe string and run into the bore of the tubular segment and into the bore of the outer sleeve to form a magnetic clutch.
- the energy storage members that can be used in this application may include, without limitation, a spring (e.g., compression spring or a coil spring) and/or a fluidic cylinder or other chamber and/or other members to convert potential energy to kinetic energy, e.g., including the use of gravitational force.
- a transfer device may be used to enable a magnetic clutch to activate the actuator of the third aspect.
- an actuator may be received on a tubular segment adjacent to an actuatable fluid valve.
- the actuator may comprise an energy storage member, such as a compression spring, having a bore received onto the tubular segment and restrained in a charged (or compressed) mode by an outer sleeve threadedly received on an adjacent threaded and non-magnetic portion of the tubular segment.
- a magnet is coupled to the outer sleeve, and a second magnet is coupled to an inner pipe string and run into the bore of the tubular segment and into the bore of the outer sleeve to form a magnetic clutch.
- the energy storage members that can be used in this application may include, without limitation, a spring (e.g., compression spring or a coil spring) and/or a fluidic cylinder or other chamber and/or other members to convert potential energy to kinetic energy, e.g., including the use of gravitational force.
- the inner pipe string described above in connection with the fourth, fifth and sixth aspects, respectively, of the invention may serve dual purposes, activating the actuator and pumping fluid to the borehole, such as, an acid to stimulate a formation face, a pressurized fluid to a portion of the borehole to test the seal of a packer or cement slurry. More information relating to an inner pipe string of the kind that can facilitate certain embodiments of the system, method and actuator disclosed herein is available from Davis-Lynch, Inc. of Pearland, Texas, USA.
- an actuator and/or the actuatable device described above in connection with the first aspect of the invention may be protected from unwanted engagement with the borehole by a centralizer (or centralizers) coupled to the tubular segment adjacent to the actuator and/or the device.
- a centralizer or centralizers
- an actuator and an adjacent actuatable device are protected from unwanted contact with the borehole by straddling both with a pair of centralizers to provide standoff between the tubular string and the borehole. It should be understood that the actuator may be more exposed to engagement with the borehole in curved or irregular sections of the borehole.
- An eleventh aspect of the invention comprises a method of using an actuator to actuate a bow spring centralizer disposed on a tubular string and run into a borehole and includes the steps of: receiving a bow spring centralizer on a tubular with a non-magnetic tubular segment having an adjacent externally threaded portion; threadedly receiving an outer sleeve comprising a magnet on the threaded portion of the tubular segment; receiving an energy storage device, for example, a spring, e.g., a compression spring, restrained in a charged or compressed mode on the tubular segment by engagement with the outer sleeve; making-up the tubular segment into a tubular string; running the tubular string into a borehole to form an annulus between the outer sleeve and the borehole; rotating the outer sleeve from threaded engagement with the tubular string using a magnetic clutch; releasing the energy storage device, for example, the spring, e.g., the compression spring, from the compressed position to
- a twelfth aspect of the invention comprises a method of using an actuator to actuate a packer disposed on a tubular string and run into a borehole and includes the steps of: receiving a packer on a tubular with a non-magnetic tubular segment having an adjacent externally threaded portion; threadedly receiving an outer sleeve comprising a magnet on the threaded portion of the tubular segment; receiving an energy storage device, for example, a spring, e.g., a compression spring, restrained in a charged or compressed mode on the tubular segment by engagement with the outer sleeve; making- up the tubular segment into a tubular string; running the tubular string into a borehole to form an annulus between the outer sleeve and the borehole; rotating the outer sleeve from threaded engagement with the tubular string using a magnetic clutch; releasing the energy storage device, for example, the spring, e.g., the compression spring, from the compressed position to expand
- a thirteenth aspect of the invention comprises a method of using an actuator to actuate a fluid valve disposed on a tubular string and run into a borehole and includes the steps of: receiving a fluid valve on a tubular with a non-magnetic tubular segment having an adjacent externally threaded portion; threadedly receiving an outer sleeve comprising a magnet on the threaded portion of the tubular segment; receiving an energy storage device, for example, a spring, e.g., a compression spring, restrained in a charged or compressed mode on the tubular segment by engagement with the outer sleeve; making- up the tubular segment into a tubular string; running the tubular string into a borehole to form an annulus between the outer sleeve and the borehole; rotating the outer sleeve from threaded engagement with the tubular string using a magnetic clutch; releasing the energy storage device, for example, the spring, e.g., the compression spring, from the compressed position to expand and displace
- a fourteenth aspect of the invention comprises a method to actuate a device on a tubular string run into a borehole and comprises the steps of: receiving an actuatable device, such as a bow spring centralizer, a packer or a fluid valve, on a tubular segment; threadedly receiving an outer sleeve having a magnet on adjacent threads of a nonmagnetic portion of the tubular segment; receiving a compression spring in a compressed mode onto the tubular segment adjacent the outer sleeve; making-up the tubular segment into a tubular string with a tag -in receptacle aligned with the bore of the tubular string; running the tubular string into a borehole; coupling a portion of a torque transfer device having a second magnet to an inner pipe string; running the inner pipe string into the bores of the tubular segment and the outer sleeve; sealably engaging the inner pipe string with the tag-in receptacle to position the torque transfer device within the outer slee
- a magnetic clutch is formed by positioning the second magnet on the inner pipe string proximal the magnet on the outer sleeve to form a magnetic clutch.
- the interaction of the magnets enables transfer of torque from the inner pipe string to the outer sleeve to rotate the outer sleeve and thereby threadedly disengage the outer sleeve from the externally threaded portion of the tubular string.
- a plurality of second magnets may be coupled to the inner pipe string in a first pattern to interact with a plurality of magnets coupled to the outer sleeve in a coincident pattern.
- an outer sleeve having a magnet and an inner pipe string having a second magnet may be used to form a magnetic clutch and to actuate, operate or otherwise magnetically engage mechanisms other than the threadedly engaged outer sleeve described herein.
- the inner string may be manipulated along an axis (e.g., longitudinally manipulated) of the tubular string to move a tab (e.g., within the inner sleeve) into or from a slot (e.g., on the exterior of the tubular string) to couple or decouple one component to or from the other.
- the tab and the slot may be juxtaposed so that the tab is on the tubular string and the slot is within the outer sleeve.
- Such axial manipulation may be used independently of or in conjunction with other uses of the magnetic clutch disclosed herein.
- Fig. 1 is an elevation view of an embodiment of the actuator in a run-in mode and disposed on a tubular segment adjacent to a centralizer having flexible ribs.
- Fig. 2 is an elevation view of the actuator of Fig. 1 in an activated mode to actuate the centralizer.
- FIG. 3 is an elevation view of the apparatus of Fig. 1 with an inner pipe string and torque transfer device superimposed thereon to illustrate a magnetic clutch.
- Fig. 3A is an elevation view of an embodiment of a transfer device on an inner pipe string and a plurality of magnets coupled to the torque transfer device to interact with the plurality of magnets coupled to the outer sleeve of Fig. 3.
- Fig. 4A is an elevation section view of an actuatable packer having a packing member received between a first collar and a second collar adjacent the outer sleeve of the actuator.
- Fig. 4B is the packer of Fig. 4A after the outer sleeve of the actuator displaces the second collar towards the first collar to radially expand the packing member.
- FIG. 5A is an elevation section view of a valve having a closure sleeve movably received between the outer sleeve of the actuator and a back-up spring and in a closed position to cover fluid ports in the tubular string.
- Fig. 5B is the view of Fig. 5A after the outer sleeve of the actuator displaces the closure sleeve from the closed position to an open position to permit fluid flow through the fluid ports.
- Fig. 1 is an elevation view of an embodiment of an actuator 5 in a run-in mode and disposed on a non-magnetic tubular segment 8 adjacent to an actuatable centralizer 9 having flexible ribs 16, e.g., ribs in a collapsed position.
- the illustrated actuator 5 comprises a compression spring 7 and an adjacent outer sleeve 10 comprising a plurality of magnets 48B and an internally threaded portion 10A (shown in Fig. 1 in dotted lines) threadedly received on an externally threaded portion 8A (also shown in dotted lines) of the tubular segment 8.
- Energy storage member is depicted as a compression spring 7 which is also illustrated in a charged or compressed (run-in) mode to store energy therein, and the compression spring 7 is restrained in the compressed mode between a collar 22, e.g., a stop collar as known to one of ordinary skill in the art, and the outer sleeve 10.
- a thrust bearing 30 may be disposed intermediate the compressed spring 7 and the outer sleeve 10 to limit friction resistance to rotation of the outer sleeve 10 relative to the compressed spring 7.
- the actuator 5 is shown received on a tubular segment 8 adjacent to a centralizer 9 for purposes of illustration only. It should be understood that the actuator 5 may be used in conjunction with a variety of actuatable devices.
- the centralizer 9 disposed adjacent to the outer sleeve 10 in Fig. 1 comprises a plurality of ribs 16 coupled between a first collar 12 and a second, e.g., moving, collar 14 that is adjacent to, but spaced from, the outer sleeve 10 of the actuator 5.
- the ribs 16 of the centralizer 9 are shown in Fig. 1 in a substantially flattened (retracted) mode.
- a gap 11 may separate the second collar 14 of the centralizer 9 from engagement with the outer sleeve 10 of the actuator 5.
- Fig. 1 illustrates the first collar 12 of the centralizer 9 disposed adjacent to a stop collar 20, it should be understood that the stop collar 20 may be integrally formed with or coupled to the first collar 12 to, for example, maintain a gap 11 between the outer sleeve 10 of the actuator 5 and the centralizer 9.
- a stop collar 13 may be positioned between the first collar 12 and the second collar 14 to limit expansion of the centralizer 9 as described below in connection with Fig. 2.
- Fig. 2 is an elevation view of the actuator 5' of Fig. 1 in an activated or released mode to actuate the adjacent centralizer 9' to a deployed (expanded) mode.
- the outer sleeve 10' is shown axially displaced after being rotated from threaded engagement with the non-magnetic tubular segment 8. Upon threaded disengagement, the outer sleeve 10 of Fig. 1 is released to move along the tubular segment 8 in response to force applied by the compression spring 7 to the position shown in Fig. 2.
- the outer sleeve 10' is shown in Fig.
- FIG. 2 after engaging the second collar 14' at sleeve end 10B and displacing the second collar 14 toward the first collar 12 to a position corresponding to a deployed mode of the centralizer 9'.
- the first collar 12 of the centralizer 9' is restrained against movement by stop collar 20.
- the ribs 16' are shown in Fig. 2 in a deployed mode, e.g., extended, to provide stand-off between the tubular segment 8 and the wall 4A of the borehole 4.
- the displacement of the outer sleeve 10' from its position in Fig. 1 corresponds to the separation between the interior threads 10A of the outer sleeve 10' from the externally threaded portion 8A of the non-magnetic tubular portion 8 illustrated in Fig. 2.
- FIG. 3 is an elevation view of the actuator of Fig. 1 with the position of an inner pipe string superimposed thereon to illustrate a magnetic clutch.
- the magnetic clutch illustrated in Figs. 3 and 3A comprises a plurality of magnets 48B coupled to the outer sleeve 10 (see Fig. 3) and a transfer device 34 comprising a plurality of magnets 48A coupled to the inner pipe string 36 (e.g., a magnet retainer 46 in Fig. 3A).
- the transfer device 34 illustrated in Fig. 3A (and shown in dotted lines in an engaged position within the outer sleeve 10 in Fig. 3) magnetically couples the outer sleeve 10 to the inner pipe string 36 to provide a magnetic clutch.
- Rotation of the inner pipe string 36 transfers torque to the outer sleeve 10 through the magnetic clutch, and the magnetic interaction is enabled by a non-magnetic tubular segment 8 through which the magnetic interaction occurs.
- the threaded interface between the externally threaded portion 8A of the tubular segment 8 and the internally threaded portion 10A of the outer sleeve 10 is exaggerated in the illustration of Figs. 1-3. These threads may be fine threads having a small pitch and a large thread count (threads per inch or cm) to minimize the torque required to threadedly disengage the outer sleeve 10 from the tubular segment 8.
- the magnets 48B of the outer sleeve 10 in the embodiment illustrated in Fig. 3 are arranged in a generally columnar pattern.
- a variety of arrangements of the magnets 48B may be used, and the arrangement illustrated in Fig. 3 is but an example of how the magnet(s) 48B might be arranged on the outer sleeve 10.
- three separate columnar arrangements of magnets may be angularly distributed, e.g., at 120 degree intervals.
- the magnets 48A on the inner pipe string 36 may be coupled to the magnet carrier 46 of Fig. 3A in an arrangement generally coinciding with the arrangement of the magnets 48B on the outer sleeve 10 of Fig. 3.
- the inner pipe string 36 may comprise a bore (not shown in Fig. 3A) through which a fluid, for example, a cement slurry, an acid or a pressurized fluid, may be provided to an end (not shown in Fig. 3A) of a tubular string into which the tubular segment 8 is included.
- a fluid for example, a cement slurry, an acid or a pressurized fluid
- the transfer device 34 of Fig. 3A may include a first spacer 43A and/or a second spacer 43B straddling the magnet carrier 46 to radially position the magnets 48A within the bore of the non-magnetic tubular segment 8 (see Fig. 3) when the inner pipe string 36 is run into the tubular segment 8.
- the first and/or second spacers 43A, 43B are shown in Fig. 3A as generally triangular in shape, but may comprise a variety of shapes without loss of function.
- the actuator 5 described above in connection with Figs. 1 through 3A may be used to actuate a variety of devices used in downhole operations.
- the energy stored in the compression spring 7 of the actuator 5 and released upon activation to displace the outer sleeve 10 as disclosed above may be used to actuate, for example, a centralizer 9, as shown in Figs. 1 and 2, a packer 6 (as discussed in more detail in relation to Figs. 4A and 4B below), a cement basket, a casing hanger, an openable fluid port (as discussed in more detail in relation to Figs. 5A and 5B below), and many other actuatable devices.
- the device to be actuated may be positioned to minimize or prevent frictional resistance to rotation of the outer sleeve.
- Figs. 1 and 3 illustrate a gap 11 that may be disposed between the moving collar 14 of the centralizer 9 and the outer sleeve 10 of the actuator 5.
- the centralizer 9 may be restrained from sliding on the non-magnetic tubular segment 8 to maintain a gap 11 and prevent the device which is, in the illustrations in Fig. 1 and 3, a centralizer 9, from frictionally engaging the outer sleeve 10 as it rotates toward threaded disengagement from the tubular segment 8.
- Figs. 1 and 3 illustrate a gap 11 that may be disposed between the moving collar 14 of the centralizer 9 and the outer sleeve 10 of the actuator 5.
- the centralizer 9 may be restrained from sliding on the non-magnetic tubular segment 8 to maintain a gap 11 and prevent the device which is, in the illustrations in Fig. 1 and 3, a centralizer 9, from frictionally engaging the outer sleeve
- FIG. 1 and 3 illustrate a slightly bowed configuration of the ribs 16 of the centralizer 9 in the collapsed or retracted mode to ensure that the ribs 16, upon actuation by the actuator (see element 5 in Figs. 1 and 3), deploy to the bowed configuration illustrated in Fig. 2.
- straight ribs could load upon engagement by the outer sleeve 10 in a compressive mode, like a column, and thereby prevent full expansion of the compression spring 7 (see Fig. 2).
- Fig. 4A is a sectional elevation view of a packer 6 having a generally sleeve- shaped packing member 60 received onto the tubular segment 8 between a first collar 40 and a moving collar 42 adjacent the outer sleeve 10.
- the packing member 60 may be, for example, but without limitation, an elastic polymer, rubber, or some other resilient, solid material.
- the tubular segment 8 of Fig. 4A is illustrated as threadedly included within a tubular string disposed within a larger tubular string 2 having an interior bore 2A.
- the packing member 60 of the packer 6 is illustrated in Fig.
- a gap 11 may be disposed between the moving collar 42 of the packer 6 and the outer sleeve 10 of the actuator 5 to prevent the moving collar 42 from frictional engagement with the outer sleeve 10 when the outer sleeve 10 is rotated to threadedly disengage the interior threads 10A from the threaded portion 8A of the non-magnetic tubular segment 8 to release the compression spring 7 to move the outer sleeve 10.
- Fig. 4B is the packer of Fig. 4A after the outer sleeve 10' threadedly disengages the tubular segment 8 and displaces the second collar 42' against the packing member 60' to close the gap 11' and axially compress the packing member 60' between the first collar 40 and the second, e.g., moving collar 42' to actuate the packer 6' to an expanded mode.
- the packing member 60' may thus be radially expanded to seal against the interior bore 2A of the larger tubular string 2 to isolate the uphole annular portion 12A from the downhole annular portion 12B.
- the magnet retainer 46 generally remains in its position relative to the larger tubular string and the non-magnetic tubular portion 8 as the outer sleeve 10' moves along the tubular segment 8 under the force of the compression spring 7' a distance corresponding to the separation between the interior threads 10A of the outer sleeve 10' from the threaded portion 8A of the non-magnetic tubular segment 8.
- FIG. 5A is an elevation view of a valve 15 having a closure sleeve 21 movably received between the outer sleeve 10 and a back-up spring 27 and in a closed position to cover fluid ports 8B in the tubular segment 8.
- a pusher sleeve 19 having flow passages 19A is disposed intermediate the closure sleeve 21 and the outer sleeve 10.
- a gap 11 may be disposed between the pusher sleeve 19 and the outer sleeve 10.
- Fig. 5B is the elevation view of Fig. 5A after the outer sleeve 10' is released to displace the closure sleeve 21' along the tubular segment 8 from the closed position to an open position to permit fluid flow through the fluid ports 8B.
- the back-up spring 27' is shown in a compressed configuration as acted upon by the larger compression spring 7' through the outer sleeve 10', pusher sleeve 19', and closure sleeve 21'.
- the flow passages 19A of the pusher sleeve 19' are aligned with the fluid ports 8B in the tubular segment 8 to establish fluid communication between the bore 8C of the tubular segment 8 and the annulus 2B between the tubular segment 8 and the wall 2A of the larger tubular 2.
- embodiments of the system, actuator and the method of using the actuator may be used in an open borehole, as illustrated in Figs. 1 and 2, or in a cased hole, as illustrated in Figs. 4A through 5B, to simultaneously or separately actuate a plurality of actuatable devices of the same or different kinds that may be coupled to a tubular string and run into a borehole.
- the thread pitch or thread count of one actuator as compared to another, the number of rotations of the inner pipe string, after the magnetic clutch is formed by positioning of the inner pipe string, can be used to vary the sequence or timing of actuation of a plurality of devices coupled to the tubular string.
- an inner pipe string could be rotated to actuate a first actuatable device, then operations could commence, followed by further rotation to actuate a second actuatable device.
- the magnets used in embodiments of the invention may or may not comprise rare earth magnets or electromagnets.
- a non-magnetic tubular segment 8 is provided to enable the magnetic interaction between the magnets 48A on the inner pipe string 36 and the magnets 48B on the outer sleeve 10, and the non-magnetic tubular segment 8 may be, for example, stainless steel.
- embodiments of the invention using multiple outer sleeves driven, using magnetic couplings between the inner pipe string and the outer sleeves may continue to effectively function notwithstanding disablement of one or more outer sleeves due to, for example, contact with the borehole.
- an outer sleeve engage the borehole for example, at a borehole irregularity or deviation
- the inner string is not disabled from continued rotation within the bore of the tubular string, and other outer sleeves may continue to rotate to threaded disengagement in response to rotation of the inner pipe string without damage to or substantial impairment of the intended benefit provided by the invention.
- Non-magnetic refers to a substance that is substantially unaffected by, or does not substantially interfere with, a magnetic field.
- Non-limiting examples of non-magnetic substances include polymers, stainless steel, copper (e.g., nickel-copper alloy), aluminum and combinations thereof.
- the use of the term “non-magnetic” does not necessarily require the absolute absence of any substance that may be affected by or interfere with a magnetic field.
- a non-magnetic tubular segment it is within the scope of the invention for a non-magnetic tubular segment to have articles disposed thereon or included therein that are sufficiently small so as not to substantially affect or interfere with a magnetic field.
Landscapes
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Mechanical Engineering (AREA)
- Power Engineering (AREA)
- Earth Drilling (AREA)
- Actuator (AREA)
Abstract
Description
Claims
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
BRPI1004214A BRPI1004214A2 (en) | 2010-01-19 | 2010-02-10 | WELL BORE ACTUATOR AND METHOD |
EP10705226A EP2526257A1 (en) | 2010-01-19 | 2010-02-10 | Downhole device actuator and method |
CA2733290A CA2733290A1 (en) | 2010-01-19 | 2010-02-10 | Downhole device actuator and method |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/689,787 | 2010-01-19 | ||
US12/689,787 US20100175888A1 (en) | 2008-08-15 | 2010-01-19 | Downhole Device Actuator and Method |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2011090491A1 true WO2011090491A1 (en) | 2011-07-28 |
Family
ID=42045289
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2010/023690 WO2011090491A1 (en) | 2010-01-19 | 2010-02-10 | Downhole device actuator and method |
Country Status (5)
Country | Link |
---|---|
US (1) | US20100175888A1 (en) |
EP (1) | EP2526257A1 (en) |
BR (1) | BRPI1004214A2 (en) |
CA (1) | CA2733290A1 (en) |
WO (1) | WO2011090491A1 (en) |
Cited By (3)
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CN103628824A (en) * | 2013-11-05 | 2014-03-12 | 成都晟鑫机电设备有限公司 | Drilling and cutting integrated drill pipe |
CN103835663A (en) * | 2014-03-05 | 2014-06-04 | 中国石油大学(华东) | Anti-collision drilling assembly for vertical sections in dense cluster well groups and anti-collision method thereof |
US9777557B2 (en) | 2014-05-14 | 2017-10-03 | Baker Hughes Incorporated | Apparatus and method for operating a device in a wellbore using signals generated in response to strain on a downhole member |
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EP2668362B1 (en) * | 2011-01-28 | 2020-01-01 | Baker Hughes, a GE company, LLC | Non-magnetic drill string member with non-magnetic hardfacing and method of making the same |
US8893807B2 (en) * | 2011-03-15 | 2014-11-25 | Baker Hughes Incorporated | Remote subterranean tool activation system |
CN103748307B (en) * | 2011-07-14 | 2016-07-13 | 哈里伯顿能源服务公司 | Control the method and system transmitted from the moment of torsion of slewing |
US9121240B2 (en) * | 2012-02-27 | 2015-09-01 | Donald R. Greenlee | Hydrostatic setting tool |
US9580976B1 (en) | 2013-03-14 | 2017-02-28 | Sandia Corporation | Deployable centralizers |
US9725967B2 (en) | 2013-07-24 | 2017-08-08 | Bp Corporation North America Inc. | Centralizers for centralizing well casings |
CN103806863B (en) * | 2014-01-29 | 2016-06-22 | 中国石油集团西部钻探工程有限公司 | Fluid power concussion centralizer |
NO342655B1 (en) * | 2014-08-20 | 2018-06-25 | E Holstad Holding As | Apparatus for sealing a bore, a system comprising the apparatus and a method of using the apparatus |
CN106194062B (en) * | 2016-09-18 | 2018-05-04 | 重庆科技学院 | Clamp are picked up in a kind of steel oilfield tubulars transhipment |
US11933114B2 (en) * | 2019-10-09 | 2024-03-19 | Schlumberger Technology Corporation | Systems for securing a downhole tool to a housing |
US11512540B2 (en) * | 2019-10-31 | 2022-11-29 | Schlumberger Technology Corporation | Methods for mitigating whirl |
CN114293928B (en) * | 2021-12-28 | 2023-06-27 | 辽宁石油化工大学 | Underground stable joint for plugging operation |
CN115112291B (en) * | 2022-05-20 | 2023-07-21 | 四川中能西控低碳动力装备有限公司 | Double-layer pipeline dynamic air pressure measuring device and method of engine gas supply system |
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- 2010-02-10 WO PCT/US2010/023690 patent/WO2011090491A1/en active Application Filing
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Also Published As
Publication number | Publication date |
---|---|
CA2733290A1 (en) | 2011-08-10 |
BRPI1004214A2 (en) | 2017-08-08 |
US20100175888A1 (en) | 2010-07-15 |
EP2526257A1 (en) | 2012-11-28 |
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