US20040244966A1 - Slip system for retrievable packer - Google Patents

Slip system for retrievable packer Download PDF

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Publication number
US20040244966A1
US20040244966A1 US10/457,065 US45706503A US2004244966A1 US 20040244966 A1 US20040244966 A1 US 20040244966A1 US 45706503 A US45706503 A US 45706503A US 2004244966 A1 US2004244966 A1 US 2004244966A1
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US
United States
Prior art keywords
slip
slips
packer
tail
slip system
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.)
Abandoned
Application number
US10/457,065
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English (en)
Inventor
Patrick Zimmerman
David Ward
Michael Ritter
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Weatherford Lamb Inc
Original Assignee
Weatherford Lamb Inc
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 Weatherford Lamb Inc filed Critical Weatherford Lamb Inc
Priority to US10/457,065 priority Critical patent/US20040244966A1/en
Assigned to WEATHERFORD/LAMB, INC. reassignment WEATHERFORD/LAMB, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: RITTER, MICHAEL G., WARD, DAVID G., ZIMMERMAN, PATRICK J.
Priority to GB0412258A priority patent/GB2402412B/en
Priority to CA002469971A priority patent/CA2469971C/fr
Publication of US20040244966A1 publication Critical patent/US20040244966A1/en
Abandoned legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • E21B33/1295—Packers; Plugs with mechanical slips for hooking into the casing actuated by fluid pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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 the boreholes or wells
    • E21B23/06—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for setting packers
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing

Definitions

  • the present invention generally relates to downhole tools for use in a hydrocarbon wellbore. More particularly, the present invention pertains to packers used for sealing fluid flow within a wellbore. More particularly still, the present invention relates to a slip system for use in a downhole tool, such as a retrievable packer.
  • An annular packer may also be used in connection with a formation treatment operation.
  • hydraulically actuated packers are oftentimes employed in order to isolate certain formations during a fracturing operation.
  • hydraulically actuated annular packers are typically used in connection with acid treatments for cleaning downhole tools, such as pipe and sand screens. In these instances, the packer is run into the wellbore on a working string rather than production tubing.
  • Slip systems assist in mechanically holding the packer in place along the surrounding casing, thereby protecting the integrity of the fluid seal provided by the sealing element.
  • Slip systems include a slip, and a cone having a beveled surface for receiving the slip.
  • a plurality of slips are disposed radially around the outer diameter of a tubular mandrel.
  • the slips have a tail that is connected to a slip ring.
  • the slip ring is slideably placed around the outer diameter of a central mandrel in the packer. Movement of the slip ring through hydraulic or hydro-mechanical actuation drives the slip ring axially towards the cones. Movement of the slip ring causes the respective slips to be driven along the beveled surfaces of the cones, and thereby moved radially outward into engagement with the surrounding tubular.
  • FIG. 1 presents a known arrangement for a portion of slip system 50 as commonly employed with a wellbore packer.
  • a slip ring 30 is first seen in the drawing.
  • the slip ring 30 defines a relatively short tubular member having a plurality of pockets 32 .
  • the pockets 32 are equidistantly spaced around the slip ring 30 in radial array.
  • Each pocket 32 is configured to receive an end portion 14 of a slip 10 .
  • five pockets 32 are shown, meaning that five slips 10 will be employed in the slip system 50 .
  • various numbers of pockets 32 and corresponding slips 10 are known.
  • FIG. 1 An exemplary slip 10 is also seen in FIG. 1.
  • the slip 10 has a first end that defines a tail 14 .
  • the slip 10 has a second opposite end that defines a slip body 12 .
  • the slip body 12 has an outer surface for engaging a surrounding tubular string, such as a string of casing, or liner (not shown).
  • a plurality of teeth 18 , or “wickers,” is placed along the slip body 12 to assist in creating a frictional engagement with the surrounding tubular string.
  • the tail 14 and the slip body 12 of the slip 10 are connected by an intermediate shank 16 .
  • the shank 16 in known slips 10 has a width that is narrower than the width of the tail portion 14 .
  • the shank 16 and tail portion 14 are configured in a perpendicular geometry in order to form a “T.”
  • the shank 16 and the tail portion 14 of the slip 10 are configured to be received in a pocket of the slip ring 30 , such as pockets 32 of FIG. 1.
  • each pocket 32 has a base opening 34 for receiving the tail portion 14 of the slip 10 .
  • each pocket 32 has a neck opening 36 extending up from the base portion 34 for receiving the shank 16 of the slip 10 .
  • the slip 10 will include a guide rail 20 .
  • a pair of guide rails 20 is disposed on either side of the slip body 12 .
  • the guide rails 20 are slideable along slots (not shown) in a cage body (also not shown) associated with the cones.
  • the guide rails 20 assist in directing the slips 10 into engagement with the surrounding tubular body when the slip system is set.
  • the slip system for the packer In order to retrieve the packer, the slip system for the packer must be released from the surrounding casing. This, in turn, means that the slip ring 30 must be moved away from the cones, and the slips 10 moved downward off of the respective beveled surfaces of the cones. In some instances, release of the slip system requires extreme mechanical force, such as the application of many thousands of pounds of tensile force imparted by pulling up on the packer mandrel (not shown in FIG. 1). In order to release the slip system, this mechanical tensile force is directed through the shank portion 16 of the slips 10 and associated neck portion 36 of the pockets 32 .
  • the shank 16 has a limited width. Where extreme and sudden tensile force is generated during release of the packer, a great deal of tensile force must be borne by the trim amount of material in the shank 16 . Further, because of the perpendicular geometry of the tail portion 14 of the slip 10 , a great deal of shear stress must be borne by the tail 14 at the points of contact with the base portion 34 of the pockets 32 . If the shank 16 or tail 14 of the slip 10 are unable to withstand the generated tensile and shear forces, the slip 10 will break, leaving the packer frictionally set within the wellbore. This, in turn, requires expensive milling and circulation operations to remove the packer.
  • both the slip 10 and the slip ring 30 have a defined thickness “t.”
  • t it is desirable by the operator of the well to have a thin slip system, so as to retain a larger bore within the packer.
  • a larger bore means more area through which production fluids may flow in a production tubing, and a greater diameter for running tools down the wellbore.
  • the manufacturer might also consider increasing the width of the shank 16 .
  • increasing the width of the shank 16 produces a reciprocal reduction of material in the slip ring, i.e., 30 , at the neck opening 36 .
  • significant shear load is still borne at the perpendicular point where the slip shank 16 meets the tail 14 .
  • an overall increase in tensile strength within the slip system is not necessarily gained.
  • the present invention provides an improved slip system that is able to withstand greater tensile forces during packer release without an increase in thickness of material.
  • the slip system comprises (1) a plurality of slips; (2) a tubular slip ring for holding the individual slips at an end; and (3) a tubular cone body having beveled surfaces for receiving the individual slips when the slip system is actuated.
  • Each slip has a first end that defines a tail.
  • the slip has a second opposite end that defines a slip body.
  • the slip body has an outer surface for engaging a surrounding tubular string, such as a string of casing, or liner. Pluralities of teeth are placed along the slip body to assist in creating a frictional engagement with the surrounding tubular string.
  • the tail and the slip body are integral, meaning that the intermediate shank portion of prior art slips is essentially removed. Instead, a dovetail geometry is provided within the tail, creating an increased tail width at the end of the tail opposite the slip body.
  • the bodies of the slips and the pockets have mating beveled side edges.
  • the sides of the bodies of the slips are beveled to face upwardly, while the sides of the pockets are beveled to face downwardly.
  • the slip ring comprises a tubular body having a plurality of pockets. Each pocket is substantially equidistantly spaced in radial array around the slip ring. Further, each pocket is dimensioned to receive the dovetailed configuration of the tail on the respective slips.
  • the tails of the slips and the pockets have mating beveled side edges.
  • the sides of the tails of the slips are beveled to face upwardly, while the sides of the pockets are beveled to face downwardly.
  • the lower edge of the tails of the slips are beveled to face downwardly, while the lower edge of the pockets are beveled to face upwardly.
  • FIG. 1 provides a perspective view of a slip system of the prior art.
  • a slip ring and an exemplary slip are provided. (The tubular body providing the cones is not shown.)
  • An exemplary slip is shown exploded away from the slip ring for clarification.
  • FIG. 2 presents a perspective view of a slip system of the present invention, in one embodiment.
  • a tubular slip ring is seen for holding individual slips.
  • a single exemplary slip is shown within one of the pockets of the slip ring.
  • a tubular cone body having beveled surfaces for receiving the respective slips is shown.
  • FIG. 3A presents a cross-sectional view of the slip system of FIG. 2. The system has been cut longitudinally along line 3 A- 3 A.
  • FIG. 3B presents a second cross-sectional view of the slip system of FIG. 2.
  • the slip system is shown through line 3 B- 3 B.
  • FIG. 4 is a perspective view of an individual slip of the slip system in the present, invention, in one embodiment. The outer surface of the slip is seen.
  • FIG. 5 shows another perspective view of the individual slip of FIG. 3. In this view, the inner surface of the slip is seen.
  • FIG. 6 provides a cross-sectional view of a packer as might employ the slip system of FIG. 2. This is a hydraulically actuated packer. The packer is seen in its run-in position.
  • FIG. 7 provides another cross-sectional view of the packer of FIG. 6.
  • the packer is being actuated. Fluid injected under pressure causes a setting piston to act against upper and lower slip systems, and an intermediate sealing element. The packer is seen set against a surrounding string of casing.
  • FIG. 8 presents yet another cross-sectional view of the packer of FIG. 6.
  • the packer is being released from frictional and sealed engagement with a surrounding tubular body.
  • FIG. 9 presents an alternate embodiment of a slip system.
  • the alternate slip system employs a modified slip design.
  • the alternate slip system is shown in perspective view.
  • FIG. 10 presents the modified slip of FIG. 9, in perspective view.
  • the present invention provides a slip system 100 for frictionally engaging a temporarily set body, such as a packer or a whipstock, within a wellbore.
  • An improved slip system 100 of the present invention in one embodiment, is shown in FIG. 2.
  • the slip system 100 comprises (1) a plurality of slips 110 ; (2) a tubular slip ring 130 for holding the individual slips 110 at an end; and (3) a tubular cone body 140 having beveled surfaces 142 for receiving the individual slips 110 when the slip system 100 is actuated.
  • FIGS. 3A and 3B present cross-sectional views of the slip system 100 of FIG. 2.
  • the slip system 100 has been cut longitudinally along line 3 A- 3 A.
  • the slip system 100 is shown through line 3 B- 3 B. From these cross-sectional views, the tubular nature of the slip ring 130 and the cone body 140 are seen.
  • FIG. 4 provides a perspective view of an individual slip 110 of the slip system 100 in the present invention, in one embodiment.
  • the outer surface of the slip 110 is seen.
  • FIG. 5 shows another perspective view of the individual slip 110 of FIG. 3. In this view, the inner surface of the slip 110 is shown.
  • each slip 110 has a first end that defines a tail 114 .
  • the slip 110 has a second opposite end that defines a slip body 112 .
  • the slip body 112 has an outer surface for engaging a surrounding tubular string, such as a string of casing, or liner (not shown).
  • Pluralities of teeth, such as wickers 118 are preferably placed along the slip body 112 to assist in creating a frictional engagement with a surrounding tubular string (not shown).
  • the tail 114 and the slip body 112 are integral, meaning that the intermediate shank portion of prior art slips is essentially removed. Instead, a dovetail geometry is provided within the tail 114 , creating an increasing tail width at the end of the tail 114 opposite the slip body 112 . In this manner, the overall width of the slip 110 is increased, thereby increasing its ability to withstand tensile forces without a reciprocal increase in thickness. Further, tensile forces in the tail portion 114 are borne along an angle, thereby increasing the tensile strength of the slip 110 .
  • the slip system 100 of the present invention also includes a slip ring 130 .
  • the slip ring 130 comprises a tubular body having a plurality of pockets 132 .
  • Each pocket 132 is substantially equidistantly spaced in radial array around the slip ring 130 .
  • each pocket 132 is dimensioned to receive the dovetailed configuration of the tail 114 on the respective slips 110 .
  • the pockets 132 each employ a mating dovetail configuration.
  • the tails 114 of the slips 110 and the pockets 132 preferably have mating beveled sides.
  • the sides 111 of the tails 114 of the slips 110 are beveled to face outwardly (shown in FIGS. 4 and 5), while the sides 131 of the pockets 132 are beveled to face inwardly.
  • the end 117 of each tail 114 of the slips 110 is beveled to face inwardly (shown in FIGS. 4 and 5), while each edge 137 of the pockets 132 that receives the ends 117 is beveled to face outwardly. Enough play is afforded in the mating configuration of the pockets 132 to allow the slips 110 to slide and move radially outward to engage a surrounding casing.
  • FIG. 6 presents a cross-sectional view of a packer 200 as might receive the slip system 100 of FIG. 2.
  • the exemplary packer 200 is a hydraulically actuated packer 200 .
  • the packer 200 is seen in FIG. 6 in its run-in position.
  • the packer 200 generally defines an elongated tubular tool have an upper end 200 U and a lower end 200 L.
  • the packer 200 includes a sealing element 230 disposed intermediate the upper 200 U and lower 200 L ends.
  • the sealing element 230 is seen in cross section in FIG. 6.
  • the sealing element 230 is fabricated from a pliable and compressible material that is capable of being extruded into sealing engagement with surrounding casing (shown at 250 in FIG. 6) when the packer 200 is actuated.
  • the packer 200 also comprises an elongated packer mandrel 210 .
  • the packer mandrel 210 extends from the upper end 200 U to the lower end 200 L of the packer 200 .
  • the packer mandrel 210 defines an elongated tubular body.
  • the packer mandrel 210 has an inner diameter defining a bore 205 , and an outer diameter. In the arrangement for the packer 200 of FIG. 6, all operational parts, including the sealing element 230 , are disposed along the outer diameter of the packer mandrel 210 .
  • the upper end of the packer mandrel 210 includes a threaded connection 212 U.
  • the threads connect to a lower joint of production tubing, an injection tubing, or some other working string (not shown).
  • the lower end of the packer mandrel 210 also preferably includes a threaded connection 212 L.
  • the lower connection 212 L may be left open, or may be attached to a tailpipe, a bottom sub, or even another packer for isolating an area of interest.
  • a sealing element 230 is circumferentially disposed around the packer mandrel 210 .
  • a pair of gauge rings 232 U, 232 L is placed above and below the sealing element 230 , respectively.
  • the upper gauge ring 232 U provides a shoulder above the sealing element 230
  • the lower gauge ring 232 L provides a shoulder below the sealing element 230 .
  • compression of the sealing element 230 is accomplished by moving the upper 232 U and lower 232 L gauge rings relatively towards one another.
  • An elongated housing 240 is disposed below the lower gauge ring 232 L.
  • the housing 240 defines an elongated tubular body concentrically placed around the packer mandrel 210 .
  • the upper end of the housing 240 is threadedly connected to the lower end of the lower gauge ring 232 L.
  • An annular region 242 is retained between the concentrically arranged packer mandrel 210 and the surrounding housing 240 .
  • One or more ports 215 U, 215 L are placed within the packer mandrel 210 .
  • the ports 215 serve as setting ports, and provide fluid communication between the bore 205 of the packer mandrel 210 and the annular region 242 within the housing body 240 .
  • the channel of fluid communication created by the setting ports 215 U, 215 L allows hydraulic pressure to be applied to the sealing element 230 and slip systems 220 U, 220 L around the packer mandrel 210 .
  • upper setting ports 215 U serve to actuate the sealing element 230 and upper slip system 220 U
  • lower setting ports 215 L serve in actuating the lower slip system 220 L.
  • a pair of subs 214 U, 214 L is also provided around the packer mandrel 210 .
  • a top sub 214 U is provided proximate to the upper end 212 U of the packer mandrel 210 .
  • a bottom sub 214 L is provided above the lower end 212 L of the packer 210 .
  • the top sub 214 U is threadedly connected to the packer mandrel 210 , such that it has no relative movement with the packer mandrel 210 .
  • the bottom sub 214 L is connected to the packer mandrel 210 .
  • the connection between the bottom sub 214 L and the packer mandrel 212 L is temporary.
  • a shear ring 213 is provided between the bottom sub 214 L and the packer mandrel 212 L. As will be described more fully below, the shear ring 213 retains the connection between the bottom sub 214 L and the packer mandrel 210 until it is desired to release the packer 200 from the surrounding wellbore.
  • a pair of slips 220 U, 220 L is provided with the packer 200 of FIG. 6.
  • an upper slip system 220 U is provided above the sealing element 230 . More specifically, the upper sealing element 220 U is disposed between the top sub 214 U and the upper gauge ring 232 U.
  • the lower slip system 232 L is placed below the sealing element 230 . More specifically, the lower slip system 220 U is disposed between the elongated outer housing 240 and the bottom sub 214 L.
  • the lower slip system 220 L may be a known slip system, such as slip system 50 shown in FIG. 1. It can be seen that the slip system 220 L includes slips 224 L disposed within a slip ring 222 L. The slips include teeth 226 L on an outer surface thereof. The slips 224 L also have an inner surface configured to ride along a beveled surface 228 L of a lower cone body 229 L.
  • the upper slip system 220 U must be a slip system such as slip system 100 shown in FIG. 2. Visible in FIG. 6, in cross section, are components of a slip system 220 U in accordance with the slip system 100 of FIG. 2. Thus, there is a slip 224 U (analogous to slip 110 of FIG. 2); there is a slip ring 222 U (analogous to slip ring 130 in FIG. 2); there is an upper cone 228 U (analogous to tubular cone body 140 in FIG. 2); and there are beveled surfaces 229 U (analogous to the outwardly beveled surfaces 142 seen in FIG. 2).
  • FIG. 6 presents the packer 200 in its run-in position.
  • the sealing element 230 and the slips 220 U, 220 L have not been set.
  • FIG. 7 provides a cross-sectional view of the packer of FIG. 6, but with the packer 200 having been actuated.
  • the sealing element 230 has now been compressed between the upper 232 U and lower 232 L gauge rings.
  • the sealing element 230 is seen extruded into sealed engagement with a surrounding casing 250 .
  • Actuation of the sealing element 230 has been accomplished by injection of hydraulic fluid, under pressure, through upper setting ports 215 U. Details concerning actuation of the packer 200 in order to effectuate sealing are not important for purposes of the present invention. It is noted, however, that a setting piston 260 is provided around the packer mandrel 210 . More specifically, the setting piston 260 is nested concentrically between the packer mandrel 210 and the surrounding housing 240 . The setting piston 260 acts in response to hydraulic pressure provided through the lower setting ports 215 L. The setting piston 260 moves downwardly against the lower cone system 220 L. At the same time, hydrostatic and formation pressures act together against the housing 240 .
  • Relative movement between the housing 240 and the setting piston 260 is permitted. Relative upward movement of the housing 240 relative to the packer mandrel 210 and setting piston 260 serves to compress the sealing element 230 and to also set the upper slip system 220 U.
  • the packer 200 is designed to be retrievable from within the casing 250 .
  • the packer 200 is released by a straight pull of the production tubing (or other working string) above the packer 200 and from the surface. Because the packer 200 withstands extremely high forces during operation, extraordinary tensile force is required to release the packer 200 . For this reason, the improved slip system 100 of the present invention is necessary to serve as the upper slip system 220 U in the packer 200 .
  • FIG. 8 presents yet another cross-sectional view of the packer 200 of FIG. 6.
  • the packer 200 is being released from frictional and sealed engagement with the surrounding tubular body 250 .
  • the lower shear ring 213 has broken, releasing the packer mandrel 210 from the bottom sub 214 L. This allows the packer mandrel 210 to move upward relative to the sealing element 230 and the upper 220 U and lower 220 L slip systems.
  • the details as to how the various components of the packer 200 are released are not important; it is sufficient to note that split rings 217 engage shoulders along the components of the packer 200 , allowing the packer 200 and its radially disposed components to be removed from the wellbore.
  • FIG. 9 presents an alternate embodiment of a slip system 100 ′.
  • the slip system 100 ′ employs a modified slip design, shown at 110 ′ in FIG. 10.
  • the modified slip design utilizes slips 110 ′ which have teeth 118 ′ with a finer pitch, and which cover the majority of the slip surface. This more evenly distributes the loads placed into the slip system 100 ′ during operation of the retrievably set tool, such as packer 200 of FIGS. 6A-6B.
  • a small section 119 ′ at the front of each slip 110 ′ does not contain teeth. In one arrangement, the surface of this flat section 119 ′ is 0.010′′ below that of the teeth 118 ′. This serves to limit the depth that the teeth bite into the casing.
  • the tail of the slip 110 ′ has a similar dovetail geometry as the previous embodiment shown in FIGS. 4 and 5; however, the sides 111 ′ of the slip tail 114 ′ are not beveled, nor are the sides 131 ′ of the mating pockets 132 ′ on the slip ring 130 ′. During retrieval, this serves to eliminate any radial force in the slip ring 130 ′ which can cause deflection or deformation of the slip ring 130 ′. These changes allow the slip system 100 ′ to withstand significantly higher working loads while maintaining retrievability.
US10/457,065 2003-06-06 2003-06-06 Slip system for retrievable packer Abandoned US20040244966A1 (en)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US10/457,065 US20040244966A1 (en) 2003-06-06 2003-06-06 Slip system for retrievable packer
GB0412258A GB2402412B (en) 2003-06-06 2004-06-02 Slip system for retrievable packer
CA002469971A CA2469971C (fr) 2003-06-06 2004-06-04 Systeme de glissement pour packer recuperable

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
US10/457,065 US20040244966A1 (en) 2003-06-06 2003-06-06 Slip system for retrievable packer

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US20040244966A1 true US20040244966A1 (en) 2004-12-09

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US10/457,065 Abandoned US20040244966A1 (en) 2003-06-06 2003-06-06 Slip system for retrievable packer

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US (1) US20040244966A1 (fr)
CA (1) CA2469971C (fr)
GB (1) GB2402412B (fr)

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US20080169105A1 (en) * 2007-01-15 2008-07-17 Williamson Scott E Convertible seal
US20090038808A1 (en) * 2007-08-08 2009-02-12 Baker Hughes Incorporated Tangentially-loaded high-load retrievable slip system
US20100084140A1 (en) * 2008-10-06 2010-04-08 Baker Hughes Incorporated Downhole seal and anchor releasing system and method
WO2012140201A2 (fr) 2011-04-15 2012-10-18 Extreme Invent As Outil de bouchon provisoire
CN104018793A (zh) * 2014-06-26 2014-09-03 西南石油大学 一种镶齿及螺纹卡瓦牙板
US8893779B2 (en) 2010-07-19 2014-11-25 Weatherford/Lamb, Inc. Retrievable slip mechanism for downhole tool
WO2016089417A1 (fr) * 2014-12-05 2016-06-09 Halliburton Energy Services, Inc. Fonctionnalité anti-pré-actionnement et anti-re-actionnement pour garnitures d'étanchéité extractibles avec coins au-dessus d'éléments.
US9416608B2 (en) 2013-07-17 2016-08-16 Baker Hughes Incorporated Slip, tangential slip system having slip, and method thereof
US9534462B2 (en) 2014-08-22 2017-01-03 Baker Hughes Incorporated Support cone for retrievable packer
US20180045017A1 (en) * 2016-08-11 2018-02-15 Blackhawk Specialty Tools, Llc Slip Assembly for Anchoring Downhole Plugs and Retainers
US20190063178A1 (en) * 2013-05-13 2019-02-28 Magnum Oil Tools International, Ltd. Split ring slips , slotted unibody slips, multi-segment interlocking slips and methods of making the same
US11230903B2 (en) 2020-02-05 2022-01-25 Weatherford Technology Holdings, Llc Downhole tool having low density slip inserts
CN114086907A (zh) * 2021-10-11 2022-02-25 中国海洋石油集团有限公司 一种穿越式生产封隔器
WO2022187789A1 (fr) * 2021-03-01 2022-09-09 Baker Hughes Oilfield Operations Llc Ensemble garniture d'étanchéité avec système de coins de retenue
US20230175330A1 (en) * 2021-11-23 2023-06-08 Vertice Oil Tools Inc. Anchor mechanism

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CA2676758A1 (fr) * 2005-05-03 2006-11-09 Noetic Engineering Inc. Outil de prehension
US7775572B2 (en) 2007-12-10 2010-08-17 Noetic Technologies Inc. Gripping tool with fluid grip activation
DK2313601T3 (en) 2008-07-18 2018-01-02 Noetic Tech Inc Grip Extension Coupling for Providing Gripper Tools with Improved Scope, and Procedure for Using Them
US9291029B2 (en) 2012-04-27 2016-03-22 Altus Intervention As Anchor mechanism for use in a well

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WO2009020951A3 (fr) * 2007-08-08 2009-04-16 Baker Hughes Inc Système de coins de retenue récupérable a charge tangentielle et capacité de charge élevée
WO2009020951A2 (fr) * 2007-08-08 2009-02-12 Baker Hughes Incorporated Système de coins de retenue récupérable a charge tangentielle et capacité de charge élevée
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US20180045017A1 (en) * 2016-08-11 2018-02-15 Blackhawk Specialty Tools, Llc Slip Assembly for Anchoring Downhole Plugs and Retainers
US11230903B2 (en) 2020-02-05 2022-01-25 Weatherford Technology Holdings, Llc Downhole tool having low density slip inserts
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GB2619481A (en) * 2021-03-01 2023-12-06 Baker Hughes Oilfield Operations Llc Packer assembly with slip system
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GB2402412A (en) 2004-12-08
GB2402412B (en) 2006-07-05

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