WO2024130087A1 - Garniture d'étanchéité pour utilisation dans un puits de forage - Google Patents

Garniture d'étanchéité pour utilisation dans un puits de forage Download PDF

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Publication number
WO2024130087A1
WO2024130087A1 PCT/US2023/084237 US2023084237W WO2024130087A1 WO 2024130087 A1 WO2024130087 A1 WO 2024130087A1 US 2023084237 W US2023084237 W US 2023084237W WO 2024130087 A1 WO2024130087 A1 WO 2024130087A1
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WO
WIPO (PCT)
Prior art keywords
packer
sealing element
slips
packer device
wellbore
Prior art date
Application number
PCT/US2023/084237
Other languages
English (en)
Inventor
Farhan Ahmed OMER
Yiming FAN
Carlos Daniel Vadillo Benavides
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2024130087A1 publication Critical patent/WO2024130087A1/fr

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  • the present disclosure generally relates to one or more packer devices (hereinafter “the packer” or “the packers” that are usable in or within one or more wellbores (hereinafter “the wellbore” or “the wellbores”).
  • the packers are disposable and/or settable at one or more locations and/or position in or within the wellbores. Further, the packers are configured, adapted, sized, and/or shaped to form one or more seals (hereinafter “the seal” or “the seals”) in or within the wellbores.
  • the packers are configured, adapted, sized, and/or shaped to form the seals against one or more surrounding tubular members and/or casings (collectedly referred to hereinafter as “the casing” or “the casings”).
  • one or more methods disclosed herein comprise using the packers in or within the wellbores and/or disposing or setting the packers within the wellbores and/or within the casings disposed within the wellbores.
  • wellbores are formed within or drilled into subterranean formations to recover hydrocarbons trapped within the subterranean formations.
  • wellbore fluids are typically circulated through the drill string, out the drill bit and upward in an annular passage provided between the drill string and the wall of the wellbore.
  • Wellbore fluids are often used for, but not limited to: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation); transportation of “cuttings” (pieces of subterranean formation dislodged by the cutting action of the teeth on a drill bit) to the surface; controlling formation fluid pressure to prevent blowouts; maintaining well stability; suspending solids in the well; minimizing fluid loss into and stabilizing the subterranean formation through which the wellbore is being drilled; fracturing the subterranean formation in the vicinity of the wellbore; displacing the fluid within the wellbore with another fluid; cleaning the wellbore; testing the wellbore; transmitting hydraulic horsepower to the drill bit; fluid used for emplacing one or more packers in or within the wellbore; and/or disposing and/or setting the one or more packers in or within the wellbore.
  • a packer In many well applications, one or more packers are used along a well string to seal off zones or sections of a wellbore.
  • a packer comprises a sealing element which may be expanded in a radially outward direction to form a seal between a central packer mandrel and a surrounding wellbore surface, such as, for example, an interior casing surface.
  • the packer also may comprise or work in cooperation with slips of one or more slip arrangements which have gripping members oriented to engage the surrounding wellbore surface.
  • the slips also may be expanded in a radially outward direction until forced into gripping engagement with the surrounding wellbore surface so as to securely position or set the packer at a desired location along the wellbore.
  • a packer device for forming one or more seals against a surrounding casing in a wellbore, comprises a mandrel comprising a cone, an expandable base disposable along an outer surface of the mandrel adjacent to the cone, one or more slips movable along the expandable base, and a sealing element coupled to the expandable base, having a first end and an opposite second end adjacent to the one or more slips.
  • the sealing element further comprises a latch mechanism disposed at or adjacent to the second end, shaped and/or configured to engage the one or more slips such that the sealing element is couplable to the one or more slips via the latch mechanism.
  • the sealing element comprises a flexible packer sealing element and a packer element structure that is adjacent to the expandable base.
  • the flexible packer sealing element comprises the vee-packing style bottom end and the packer element structure comprises the latch mechanism.
  • the packer element structure comprises a plurality of deflectable ribs adjacent to the flexible packer sealing element.
  • the plurality of deflectable ribs comprises first ribs and second ribs disposed between or adjacent to the first ribs.
  • the flexible packer sealing element comprises at least one flexible elastomeric material.
  • the at least one flexible elastomeric material comprises at least one of aflas, chloroprene, ethylene propylene diene monomer, fluoroelastomers, nitrile, hydrogentated nitrile, polytetrafluoroethylene, and polyurethane.
  • the expandable base comprises a metal substrate.
  • the metal substrate comprises at least one ductile steel.
  • the mandrel comprises an undercut adjacent to the cone and/or the sealing element.
  • the one or more slips are movable along or over a sloped surface of the expandable base.
  • the one or more slips comprises at least one recess formed therein and the at least one recess faces the sloped surface of the expandable base.
  • At least one shear member of the expandable base is disposed within the at least one recess of the one or more slips such that the one or more slips are coupled to the expandable base.
  • the sealing element comprises a vee-packing style bottom end disposed at or adjacent to the first end.
  • a method comprises disposing the packer device of claim 1 in a wellbore.
  • the method further comprises setting the packer device and the one or more slips in the wellbore by moving the one or more slips along a sloped surface of the expandable base.
  • a method comprises disposing a packer device in a wellbore, wherein the packer device is coupled to at least one slip via a latch mechanism and comprises a sealing element coupled to an expandable base, and the sealing element comprises a vee-packing style bottom end. Additionally, the method comprises shifting an actuator member associated with the packer device and/or the at least one slip to cause setting of the packer device and the at least one slip in the wellbore.
  • the method further comprises applying force and/or pressure onto the sealing element such that a plurality of ribs associated with the sealing element are deflected within the wellbore.
  • the method further comprises applying force and/or pressure onto the vee-packing style bottom end such that a plurality of ribs associated with the sealing element are deflected within the wellbore.
  • the method further comprises sealing the wellbore with the packer device.
  • FIG. 1 illustrates a well system comprising the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 2 illustrates the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 3A illustrates a cross-sectional view of a portion of the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 3B illustrates a cross-sectional view of a portion of the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 3C illustrates a cross-sectional view of a portion of the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 4 illustrates a cross-sectional view of a portion of the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 5 illustrates a cross-sectional view of a portion of the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 6 illustrates a cross-sectional view of a liner top packer system comprising the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIGS. 7 and 8 illustrate packer elements of the packer disclosed herein and comparative results of forces experienced by the liner top packer system shown in FIG. 6 during setting of the liner top packer system, according to one or more embodiments of the present disclosure.
  • FIG. 9 illustrates a cross-sectional view of structural features and/or relationships of the packer disclosed herein, according to one or more embodiments of the present disclosure.
  • FIG. 10 illustrates a cross-sectional view of the packer disclosed herein at least one slip, according to one or more embodiments of the present disclosure.
  • the article “a” is intended to have its ordinary meaning in the patent arts, namely “one or more.”
  • the term “about” when applied to a value generally means within the tolerance range of the equipment used to produce the value, or in some examples, means plus or minus 10%, or plus or minus 5%, or plus or minus 1 %, unless otherwise expressly specified.
  • the term “substantially” as used herein means a majority, or almost all, or all, or an amount with a range of about 51 % to about 100%, for example.
  • examples herein are intended to be illustrative only and are presented for discussion purposes and not by way of limitation.
  • packers 34, 900 for enabling the packers (i.e., the packer 34 and/or the packer 900 (collectively referred to hereinafter as “packers 34, 900”)) to be actuated from original or initial positions to sealing and/or gripping positions along the wellbores.
  • the packers 34, 900 disclosed herein may isolate and/or seal off one or more sections or zones of the wellbores.
  • the packers 34, 900 may be, comprise, include, or consist of at least one production packer, at least one casing packer, at least one retrievable packer, at least one test packer, at least one permanent packer, or a combination thereof.
  • the packers 34, 900 may be run into the wellbores on at least one tubing, at least one string, at least one wireline, at least one pipe, at least one coiled tubing, or a combination thereof.
  • the methods disclosed herein may utilize the packers 34, 900 in one or more well operations, such as, for example, well completion, production, injection, and/or workover activities.
  • the packers 34, 900 may be constructed, configured, adapted, sized, and/or shaped to enable sequential actuation of one or more sealing elements and/or slips via actuation inputs along the annulus and/or interior surfaces of one or more well strings.
  • the actuation inputs comprise one or more mechanical actuations and/or pressure inputs along the annulus and/or the interior surface of the well string.
  • the packer 34, 900 may be disposed, located, and/or positioned along at least one well string and/or may be disposed, located, and/or positioned in at least one wellbore, wherein the at least one wellbore may be, comprise, or consist of a vertical wellbore or a deviated wellbore including cased wellbores.
  • the packers 34, 900 may comprise center structures (i.e., mandrel structures) having passages therethrough.
  • Packer element structures of the packers 34, 900 may be positioned about the center structures and include sealing elements mounted along expandable bases such that the sealing elements may be radially expanded.
  • the sealing elements of the packers 34, 900 may be formed of at least one suitable elastomeric material, and the expandable bases of the packers 34, 900 may comprise a plurality of metal base elements, which are shiftable in radially outward directions.
  • the packer 34, 900 may comprise actuator members connected to portions of the packer element structures via release mechanisms.
  • the center structures of the packers 34, 900 may be mandrel structures and/or the release mechanisms of the packers 34, 900 may be shear members.
  • the shear members may comprise tabs or a plurality of tabs extending between the expandable bases and the actuator members.
  • the shear members effectively provide shearing mechanisms on radially expanding packer element structures formed of the seal elements and metal substrates to sequentially set the packers 34, 900.
  • the sequential setting comprises setting the seal elements followed by shearing of the shear members, which then allows setting of the slips. This sequential method or process may create a jarring effect, which ensures that engagement features of the slips bite into the surrounding wellbore surfaces, casing surfaces, or harder casing metallurgies.
  • the engagement features of the slips may be, comprise, or consist of anchors, teeth, wedges, or a combination thereof.
  • a well system 30 is illustrated and comprises a well string 32 including the packer 34 having a packer element structure 36 with a sealing element 38.
  • the packer 34 also comprises a slip section 40 which may have a plurality of slips 42.
  • the well string 32 is positioned in a wellbore 44 having a wellbore surface 46 against which the packer 34 may be set.
  • the wellbore 44 may be lined with a casing 48 and the wellbore surface 46 may be an internal casing surface surrounding the packer 34.
  • the packer 34 may comprise a center structure 50 having an outer surface 54 that comprises a conical/sloped section 56 sloping in a radially outward direction with respect to a longitudinal axis 58 of the packer 34.
  • the conical/sloped surface 56 of the center structure 50 may be created and/or provided by a cone 88 mounted along a mandrel 90.
  • the cone 88 may be secured to the mandrel 90 via at least one attachment mechanism.
  • the at least one attachment mechanism may be, comprise, or consist of one or more hooks, dogs, pins, screws, springs, and/or fasteners 92 (collectively referred to herein after as “fasteners 92”).
  • the packer 34 may also include a packer element structure 36 having a packer sealing element 38, which is expandable and mounted or mountable on an expandable base 60 (as shown in FIGS. 3A-3C and 4) positioned along the outer surface 54 of the center structure 50.
  • the packer sealing element 38 may be formed of at least one flexible elastomeric material.
  • the at least one flexible elastomeric material may be, comprise, or consist of one or more chloroprenes, one or more ethylene propylene diene monomers, one or more fluoroelastomers, one or more nitriles, one or more hydrogentated nitriles (hereinafter “HNBR”), one or more polytetrafluoroethylenes, one or more polyurethanes, or a combination thereof.
  • HNBR hydrogentated nitriles
  • the packer 34 may further comprise an actuator member 62 connected to the packer element structure 36.
  • the actuator member 62 may be in the form of a push collet 64 and/or may be coupled to an expandable base 60 via at least one release mechanism 66.
  • the at least one release mechanism 66 may be in the form of a shear member 68.
  • the shear member 68 may be at least one shear tab.
  • the shear member 68 may extend from the expandable base 60 into a corresponding recess 70 of the actuator member 62.
  • At least one method of affecting, causing, initiating, producing, providing, and/or triggering a linear actuation motion of the actuator member 62 may involve, comprise, or consist of applying and/or providing at least one annulus pressure to a sealed pressure chamber via ports 94.
  • the at least one annulus pressure is usable or may be used to drive, force, and/or move the actuator member 62 linearly along the mandrel 90.
  • the packers 34, 900 may comprise a slip structure 40 having a plurality of slips 42.
  • the slips 42 include engagement members 76 constructed to securely engage a surrounding wellbore surface 46, when the slips 42 are radially expanded during setting of the packer 34.
  • the engagement features 76 may be, comprise, or consist of anchors, teeth, wedges, or a combination thereof and the surrounding wellbore surface 46 may be, comprise, or consist of an internal casing surface. As shown in FIG.
  • the slips 42 and/or corresponding teeth 76 may be disposed or located on the actuator member 62, e.g., on push collet 64, in one or more embodiments of the present disclosure. Additionally, at least one portion of the expandable base 60 is provided with an outwardly sloped surface 80, e.g., a conical surface.
  • the actuator member 62 may move, slide, and/or shift linearly to set the packer sealing element 38 and/or to shear the shear member 68. Once the shear member 68 is sheared, continued linear movement of the actuator member 62 may force radial expansion of the slips 42 as the slips 42 may move, progress, and/or slide along the outwardly sloped surface 80 of the expandable base 60.
  • the actuator member 62 may move and/or shift or be moved and/or shifted linearly, e.g., in a direction toward the packer sealing element 38 along the axis 58.
  • the moving and/or shifting of the actuator member 62 may be achieved via at least one application of at least one pressure along the interior passage 52 (as shown in FIG. 2) and/or along the annulus between the well string 32 and the wellbore surface 46 (as shown in FIG. 1 ).
  • One or more pressure piston actuation and/or pressure actuation techniques may be utilized and/or executed to move the actuator member 62 and/or the actuator member 62 may be configured, adapted, sized, and/or shaped to be shifted mechanically via the one or more pressure piston actuation and/or pressure actuation techniques.
  • At least one linear movement of the actuator member 62 may cause at least one linear/axial movement of the packer element structure 36 along the sloped section 56 of the outer surface 54 due to the actuator member 62 being coupled to the expandable base 60 via the shear member 68.
  • the expandable base 60 and the packer sealing element 38 are forceable or may be forced in a radially outward direction until the packer sealing element 38 may be moved into a sealing engagement with the wellbore surface 46.
  • As the packer sealing element 38 may be forced into a sealing engagement with the wellbore surface 46, further linear movement may be prevented, substantially prevented, resisted and/or terminated.
  • the actuator member 62 may shear the shear member 68 so as to release or decouple the actuator member 62 from the packer element structure 36.
  • the actuator member 62 is slidable or may slide along the sloped surface 80 of the expandable base 60, which forces or may force the slips 42 in a radially outward direction until engagement members 76 are secured against and/or into the surrounding wall surface 46.
  • the release or decoupling due to the shearing of the shear member 68 may create or creates at least one jarring effect during setting of the slips 42, which may result in an improved engagement of engagement members 76 with the surrounding wall surface 46.
  • the packer 34 is able or may be able to independently set the packer sealing element 38 followed by subsequent setting of the slips 42.
  • the packer element structure 36 may be in the form of a deflecting rib seal having first ribs 82 that extend from a radially inward portion of the expandable base 60.
  • the first ribs 82 may be disposed in packer sealing element 38.
  • the first ribs 82 are deflectable or may deflect during the setting and/or when experiencing at least one wellbore pressure from either side (i.e. , from above or below) of the packer sealing element 38.
  • the expandable base 60 and packer sealing element 38 are combinable or may combine to provide an expandable bonded seal, which energizes when the at least one wellbore pressure is applied.
  • the packer 34 may be, comprise, or consist of a liner top packer.
  • the packer element structure 36 may comprise second ribs 84 extending outwardly into packer sealing element 38.
  • the first ribs 82 may be, comprise, or consist of one or more deflecting ribs and/or the second ribs 84 may be, comprise, or consist of one or more vertical ribs.
  • the first ribs 82 may be on upper and lower sides of the second ribs 84 and/or adjacent to the second ribs 84.
  • the second ribs 84 may be disposed, located, and/or positioned between the first ribs 82 as shown in FIGS. 3A-3C, 4-6, and 9.
  • the first ribs 82 may be oriented in a generally outward and downward and upward directions.
  • the second ribs 84 may be oriented to project in a radially outward direction and serve to prevent the packer sealing element 38 from undue swaging and also serve as or provide a hard stop which may limit an amount of deflection of the first ribs 82.
  • the first ribs 82 may deflect when the packer sealing element 38 is set in a sealing position against surrounding wellbore surface 46 via application of force and/or pressure. Deflection of the first ribs 82 may effectively store setting energy when the sealing element 38 is in the sealing position. Additionally, the deflecting rib seal design of the packers 34, 900 may require about 50,000 pound of force (hereinafter “Ibf”) or less of a setting load. In some embodiments, the setting load may be less than about 45,000 Ibf, less than about 40,000 Ibf, or less than about 35,000 Ibf.
  • the setting load associated with packers 34, 900 and/or the sealing element 38 disclosed herein may be at least half of the setting load required in prior art seal assemblies of known packers.
  • the at least one elastomeric material of the packer sealing element 38 may be shaped with a profile so that when force and/or pressure may be applied to the packers 34, 900 and/or the packer sealing element 38, then the at least one elastomeric material is pushable or may push the first ribs 82 against the surrounding wellbore surface 46.
  • the sealing action of the packer sealing element 38 with the surrounding wellbore surface 46 is or may be robust.
  • first ribs 82 and/or the second ribs 84 may cooperate together to provide an improved self-energizing seal.
  • first ribs 82 may energize or may help to energize the packer sealing element 38 with applied pressure that may force the packer sealing element 38 into an improved sealing with the surrounding wellbore surface 46.
  • first ribs 82 may energize or may help to energize the sealing action with applied annular pressure. In an embodiment and when force and/or pressure 100 is applied from either/both directions (see FIG.
  • the first ribs 82 may energize or may help to energize the sealing on both of the outside diameter and the inside diameter of the packer element structure 36.
  • the sealing element 38 may hold or may be held against increased annular pressures acting on the packer 34, 900.
  • the increased annular pressures may be at least about 15,000 pounds per square inch (hereinafter “psi”), at least about 17,500 psi, or at least about 20,000 psi.
  • the first ribs 82 may be angled upwardly and downwardly to deflect upon setting and/or to become further energized when force and/or pressure 100 may be applied from above or below.
  • the expandable base 60 may comprise one or more internal metal bumps 86 (hereinafter “bumps 86”) oriented to form an improved metal-to-metal seal with the corresponding outer surface 54 of the center structure 50.
  • the bumps 86 may create or provide at least one high contact pressure when the packer sealing element 38 may be set against the surrounding wellbore wall surface 46.
  • a metal-to- metal seal may be provided, and the metal-to-metal seal may provide an improved and/or higher resistance to backlash.
  • force or pressure may be applied from either side of the packers 34, 900, the first ribs 82 and the bumps 86 may maintain or may help to maintain the seal along the exterior and interior of the packer element structure 36.
  • an inner seal 78 may be disposed, located, and/or positioned between the outer surface 54 and the expandable base 60 to form an improved and/or suitable seal along the interior of the packer element structure 36.
  • the inner seal 78 may be an O-ring style seal and/or the inner seal may be disposed, located, and/or positioned between internal metal bumps 86 to form the improved and/or suitable seal along the interior of packer element structure 36.
  • the packer element structure 36 may be a swage type seal having the expandable base 60 in the form of a metal substrate comprising a ductile metal material 102, as shown in FIG. 3A.
  • the ribs 82, 84 are sized, shaped, configured, and/or adapted to be deflect and/or are deflectable during setting of the packers 34, 900.
  • force and/or pressure 100 may be applied to the packers 34, 900 at the end near or adjacent to the packer sealing element 38.
  • the ribs 82, 84 are energized and/or deflected or may be energized and/or deflected and a contact press increases or may increase.
  • force and/or pressure 100 may be applied to the packers 34, 900 at the end near or adjacent to the expandable base 60.
  • the ribs 82, 84 are energized and/or deflected or may be energized and/or deflected and a contact press increases or may increase.
  • the packers 34, 900 sets or may set within the wellbore 44 when higher forces and/or pressures are applied to the end near or adjacent to the expandable base 60.
  • the packer sealing element 38 may be in the form of at least one elastomer that may be bonded to the metal expandable base 60 at one or more bond sites, positions, and/or locations 104.
  • the ductile metal material may be, comprise, or consist of 8620 steel or another suitable ductile steel and/or the at least one elastomer may be HNBR.
  • the materials and configurations selected for the expandable base 60 and/or the packer sealing element 38 may be adjusted accordingly.
  • the slips 42 may be mounted to or integrally formed with the actuator member 62 and/or the collet 64 and the slips 42 may be disposed, located, and/or positioned for sliding engagement with a secondary ramp created by the sloped surface 80 of the expandable base 60 (see FIGS. 4 and 5).
  • the secondary ramp and/or the sloped surface 80 may energize or may help to energize the slips 42 for improved slip bite when force and/or pressure is applied thereon and/or applied on the packer sealing element 38.
  • the packers 34, 900 may provide or may effectively provide a high hold down load capacity with a relatively compact slip length by enabling energization of the slips 42 when force and/or pressure may be applied.
  • the packer element structure 36 shown in FIG. 4 may be similar or substantially similar to packer element structure 36 as described and/or illustrated in FIGS. 3A-3C. More specifically, the packer element structure 36 shown in FIG. 4 may having, comprise, or consist of the first ribs 82, centrally located with respect to the second ribs 84, the packer sealing element 38, and/or the bumps 86. As a result of this configuration and/or construction, the packer element structure 36 shown in FIG. 4 may reduce or substantially reduce backlash to improve sealing pressure of the packers 34, 900. In at least one embodiment, this configuration and/or construction of the packer element structure 36 as shown in FIG. 4 may prevent or substantially prevent backlash on the packer sealing element 38 when at least one lower annulus pressure 106 may be applied and/or may energize the engagement members 76 of the slips 42 as application of force and/or pressure may increase as shown in FIG. 5.
  • a higher ramp angle and/or a compound ramp angle 108 of the secondary ramp and/or the sloped surface 80 may be used and/or provided to reduce or substantially reduce radial loading that may be experienced by the casing 48 and/or the mandrel 90.
  • the packer element structure 36 as shown in FIGS. 4 and 5 may achieve and/or provide an improved and/or higher hold down capacity.
  • the engagement members 76 of the slips 42 may be fully or at least partially supported by the secondary ramp and/or the sloped surface 80 to aid and/or help each engagement member 76 of the slips 42 bite into and/or engage the surrounding casing 48.
  • the slips 42 are or may be sequentially actuated using a shear sequence, as described above, such that the slips 42 are set or may become set after the packer sealing element 38 may be fully or at least partially set.
  • the shearing sequence be used or utilized to achieve at least one desired jarring effect that ensures or may ensure the slips 42 bite into harder metallurgies associated with the surrounding casing 48.
  • the packers 34, 900 may be constructed in various sizes, shapes, and/or configurations.
  • the center structure 50, the packer element structure 36, the actuator member 62, and the slips 42 may have a variety of sizes, shapes, and/or configurations.
  • the slips 42 may be formed as a unitary and/or integral part, piece or component of the actuator member 60 while, in other embodiments, the slips 42 may be formed as a slip ring or other structure separate or substantially separate from or with respect to the actuator member 60.
  • the packer element structure 36 may comprise various types of materials and/or sizes, shapes, and/or configurations for forming the packer sealing element 38 and/or the expandable base 60. Additionally, various integral or separate components may be used, incorporated, and/or utilized in forming the sloped surface 56 and/or the sloped surface 80.
  • a liner top packer system may include, comprise, or consist of the packer element 36, the cone 88, and/or the mandrel 90 as shown in FIG. 6.
  • the entire packer element is disposed on the cone in the unset position which reduces the cross section of the packer element as the inner diameter (hereinafter “ID”) of the packer element is restricted by the outer diameter (hereinafter “OD”) of the cone, and the OD of the packer element is restricted by the packer OD.
  • an undercut 96 may be added to the mandrel 90 under a cone nose of the cone 88 which may allow the ID of the packer element 36 to be smaller or substantially smaller than the cone nose and/or to be only restricted by the OD of the mandrel 90.
  • the packer element 36 may be off or partially off the cone 88 in the unset condition, which may increase or substantially increase the cross-section of the packer element 36.
  • the undercut 96 to the mandrel 90, the packer element 36 is able or may be able to set over the cone 88 without any hang-up.
  • the increased cross-section of the packer element 36 allows or may allow the OD of the packers 34, 900 to be reduced and/or the bypass area of the packers 34, 900 may be increased.
  • the undercut 96 of the mandrel 90 may adopt, comprise, or consist of various sizes, shapes, and/or configurations without departing from the scope of the present disclosure.
  • FIGS. 7 and 8 comparative results of forces experienced by the liner top packer system during setting of the liner top packer are shown. Specifically, FIG. 7 shows the resulting forces experienced by a liner top packer system disclosed herein without the undercut 96 of the mandrel 90, and FIG. 8 shows the resulting forces experienced by a liner top packer system disclosed herein having the undercut 96 of the mandrel 90, according to one or more embodiments of the present disclosure.
  • the peak load may be at least about 10 kilopounds (hereinafter “klbf”), at least about 15 klbf, at least about 20 klbf, at least about 25 klbf, or at least about 30 klbf.
  • klbf kilopounds
  • the peak load shown in FIG. 7 is eliminated as shown in FIG. 8.
  • the undercut 96 is able to eliminate that peak load during the initial portion of the swaging of the packer element 36 over the cone 88.
  • elimination of excessive load forces during setting of the liner top packer disclosed herein is useful or may be useful when there is at least one shear event to initiate the setting of the liner top packer disclosed herein.
  • a cross-sectional view of the packer 900 may show one or more structural features and/or relationships of the packer 900 as shown in FIGS. 9 and 10.
  • the packer 900 may be similar or substantially similar to the packer 34 as discussed above and/or may have one or more similar parts of the packers 34, 900 which are not further discussed hereinafter.
  • the packer 900 may include, comprise, or consist of the packer sealing element 38, a vee-packing style bottom end 902 (hereinafter “bottom end 902”), and/or a latch mechanism 904 opposite with respect to the bottom end 902.
  • a length of the packer 900 may be defined by or between the bottom end 902 and the latch mechanism 904.
  • the bottom end 902 may be integrally formed with the packing sealing element 38 and/or made of the at least one elastomer of the packer sealing element 38.
  • the bottom end 902 may be connected, attached, secured, fastened, and/or bonded to the packer element structure 36, the packer sealing element 38, and/or the ribs 82, 84.
  • the packer 900 may have a thickness defined by or between an outer side 906 and an inner side 908 opposite with respect to the outer side 906 as shown in FIG. 9.
  • the ribs 82, 84 may face or point towards outer side 906 and/or the ribs 82, 84 and/or the latch mechanism 904 may extend away from the inner side 908 and towards the outer side 906.
  • the bottom end 902 may have, comprise, or consist of at least one curved or flat surface 910 (hereinafter “surface 910”) disposed, located, and/or positioned between the outer side 906 and the inner side 908 (collectively referred to hereinafter as “sides 906, 908”).
  • the surface 910 may be, comprise, or consist of at least one valley, at least one trough, at least one channel, and/or at least one depression that may be disposed, located, and/or positioned between the sides 906, 908.
  • the surface 910 may be a concaved surface extending between and/or disposed, located, or positioned between the sides 906, 908 as shown in FIG. 9.
  • the surface 910 may be noncurved, linear or flat as shown in FIG. 10.
  • the packer element structure 36 may have, comprise, or consist of at least one curved or rounded surface 911 (hereinafter “curved surface 911”).
  • the curved surface 911 may be, comprise, or consist of at least one valley, at least one trough, at least one channel, and/or at least one depression that may be disposed, located, and/or positioned between the sides 906, 908.
  • the curved surface 911 may be a concaved surface extending between and/or disposed, located, or positioned between the sides 906, 908.
  • the latch mechanism 904 may have, comprise, or consist of at least one curved or rounded portion 912 (hereinafter “rounded portion 912”) that may be extending away from the outer side 906 and/or towards the inner side 908.
  • the rounded portion 912 may be integrally formed with the ribs 82, 84.
  • the rounded portion 912 may be connected, attached, fastened, affixed, and/or secured to the packer element structure 36, the expandable base 60, and/or the ribs 82, 84.
  • the rounded portion 912 may be, comprise, or consist of at least one hooked or hook-shaped portion and/or at least one curved device sized, shaped, configured, and/or adapted for catching, engaging, securing, and/or holding at least one slip 1000 as shown in FIG. 10. Additionally, the latch mechanism 904 may be removed and the packer 900 can be connected to a sloped surface 80 or slips 1000.
  • the bottom end 902 may form at least one seal and/or the formed at least one seal is energized or may become energized when force and/or pressure may be applied to the bottom end 902.
  • the packer 900 may achieve or exhibit an improved and/or additional sealing force when compared to known packer devices.
  • the latch mechanism 912 of the packer 900 may catch, engage, secure, and/or hold the at least one slip 1000, as shown in FIG. 10, to ensure that the at least one slip 1000 may remain connected, coupled, attached, secured and/or affixed to the packer 900 as the packer 900 is set in the wellbore 44.
  • the at least one slip 1000 may be connected, coupled, attached, secured, and/or affixed to the packer 900 via the latch mechanism 912.
  • the packers 34, 900 are on or may be on the cone 88 and/or the packers 34, 900 may seal with or form at least one seal between the casing 48 and the cone 88.
  • the seal is formed or may be formed with the packer sealing element 38 and/or the ribs 82, 84 of the packer element structure 36.
  • the seal and/or the packer sealing element 38 is squeezed or may be squeezed between the cone 88 and the casing 48.
  • the packers 34, 900 are free of any seal, such as, for example, any O-ring seal between the casing 48 and the cone 88, the packer element structure 36, and/or the packers 34, 900.
  • O-ring seals are excluded from sealing mechanisms of the packers 34, 900 in their entireties.

Landscapes

  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)

Abstract

Dispositifs de garniture d'étanchéité et procédés d'utilisation des dispositifs de garniture d'étanchéité formant des joints d'étanchéité contre un tubage environnant dans des puits de forage. Le dispositif de garniture d'étanchéité comprend un mandrin comprenant un cône, une base extensible pouvant être disposée le long d'une surface externe du mandrin adjacente au cône, un coin de retenue mobile le long de la base extensible, et un élément d'étanchéité couplé à la base extensible et comprenant une extrémité inférieure de style garniture en V adjacente à une première extrémité et/ou un mécanisme de verrouillage facultatif adjacent à une seconde extrémité et conçu pour venir en prise avec le coin de retenue de telle sorte que l'élément d'étanchéité peut être couplé au coin de retenue par l'intermédiaire du mécanisme de verrouillage.
PCT/US2023/084237 2022-12-15 2023-12-15 Garniture d'étanchéité pour utilisation dans un puits de forage WO2024130087A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US202263387602P 2022-12-15 2022-12-15
US63/387,602 2022-12-15

Publications (1)

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WO2024130087A1 true WO2024130087A1 (fr) 2024-06-20

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Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20030159832A1 (en) * 2002-02-25 2003-08-28 Williamson Jimmie Robert Infinitely variable control valve apparatus and method
US20070056725A1 (en) * 2005-09-09 2007-03-15 Chad Lucas Seal assembly
US20100139911A1 (en) * 2008-12-10 2010-06-10 Stout Gregg W Subterranean well ultra-short slip and packing element system
US20190292864A1 (en) * 2018-03-23 2019-09-26 Dril-Quip, Inc. Self-locking packer carrier
WO2021080934A1 (fr) * 2019-10-20 2021-04-29 Schlumberger Technology Corporation Actionnement combiné de coins de retenue et d'un élément d'étanchéité de garniture d'étanchéité

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20030159832A1 (en) * 2002-02-25 2003-08-28 Williamson Jimmie Robert Infinitely variable control valve apparatus and method
US20070056725A1 (en) * 2005-09-09 2007-03-15 Chad Lucas Seal assembly
US20100139911A1 (en) * 2008-12-10 2010-06-10 Stout Gregg W Subterranean well ultra-short slip and packing element system
US20190292864A1 (en) * 2018-03-23 2019-09-26 Dril-Quip, Inc. Self-locking packer carrier
WO2021080934A1 (fr) * 2019-10-20 2021-04-29 Schlumberger Technology Corporation Actionnement combiné de coins de retenue et d'un élément d'étanchéité de garniture d'étanchéité

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