EP1712732B1 - Suspension de colonne perdue, outil de pose et procédé associé - Google Patents

Suspension de colonne perdue, outil de pose et procédé associé Download PDF

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Publication number
EP1712732B1
EP1712732B1 EP06012130A EP06012130A EP1712732B1 EP 1712732 B1 EP1712732 B1 EP 1712732B1 EP 06012130 A EP06012130 A EP 06012130A EP 06012130 A EP06012130 A EP 06012130A EP 1712732 B1 EP1712732 B1 EP 1712732B1
Authority
EP
European Patent Office
Prior art keywords
packer
liner
ring
setting
seal
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.)
Expired - Lifetime
Application number
EP06012130A
Other languages
German (de)
English (en)
Other versions
EP1712732A1 (fr
Inventor
John M. Yokley
Larry E. Reimert
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.)
Dril Quip Inc
Original Assignee
Dril Quip 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
Priority claimed from US09/943,701 external-priority patent/US6575238B1/en
Priority claimed from US09/981,487 external-priority patent/US6712152B1/en
Priority claimed from US10/083,320 external-priority patent/US6666276B1/en
Application filed by Dril Quip Inc filed Critical Dril Quip Inc
Priority claimed from EP02736875A external-priority patent/EP1392953B1/fr
Publication of EP1712732A1 publication Critical patent/EP1712732A1/fr
Application granted granted Critical
Publication of EP1712732B1 publication Critical patent/EP1712732B1/fr
Anticipated expiration legal-status Critical
Expired - Lifetime legal-status Critical Current

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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
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/01—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
    • 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
    • E21B23/04—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
    • E21B23/042—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion using a single piston or multiple mechanically interconnected pistons
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/04—Casing heads; Suspending casings or tubings in well heads
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
    • E21B33/1212—Packers; Plugs characterised by the construction of the sealing or packing means including a metal-to-metal seal element
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
    • E21B33/1216—Anti-extrusion means, e.g. means to prevent cold flow of rubber packing
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/02—Subsoil filtering
    • E21B43/10—Setting of casings, screens, liners or the like in wells
    • 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
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/01—Sealings characterised by their shape

Definitions

  • a borehole is typically drilled from the earth's surface to a selected depth and a string of casing is suspended and then cemented in place within the borehole.
  • a drill bit is then passed through the initial cased borehole and is used to drill a smaller diameter borehole to an even greater depth.
  • a smaller diameter casing is then suspended and cemented in place within the new borehole. This is conventionally repeated until a plurality of concentric casings are suspended and cemented within the well to a depth which causes the well to extend through one or more hydrocarbon producing formations.
  • a liner is often suspended adjacent to the lower end of the previously suspended casing, or from a previously suspended and cemented liner, so as to extend the liner from the previously set casing or liner to the bottom of the new borehole.
  • a liner is defined as casing that is not run to the surface.
  • a liner hanger is used to suspend the liner within the lower end of the previously set casing or liner.
  • the liner hanger has the ability to receive a tie back tool for connecting the liner with a string of casing that extends from the liner hanger to the surface.
  • a running and setting tool disposed on the lower end of a work string may be releasably connected to the liner hanger, which is attached to the top of the liner.
  • the work string lowers the liner hanger and liner into the open borehole so that the liner extends below the lower end of the previously set casing or liner.
  • the borehole is filled with fluid, such as a selected drilling mud, which flows around the liner and liner hanger as the liner is run into the borehole.
  • the assembly is run into the well until the liner hanger is adjacent the lower end of the previously set casing or liner, with the lower end of the liner typically slightly above the bottom of the open borehole.
  • a setting mechanism is conventionally actuated to move slips on the liner hanger from a retracted position to an expanded position and into engagement with the previously set casing or liner. Thereafter, when set down weight is applied to the hanger slips, the slips are set to support the liner.
  • the typical liner hanger may be actuated either hydraulically or mechanically.
  • the liner hanger may have a hydraulically operated setting mechanism for setting the hanger slips or a mechanically operated setting mechanism for setting the slips.
  • a hydraulically operated setting mechanism typically employs a hydraulic cylinder which is actuated by fluid pressure in the bore of the liner, which communicates with the bore of the work string.
  • the hanger slips are typically one-way acting in that the hanger and liner can be raised or lifted upwardly, but a downward motion of the liner sets the slips to support the hanger and liner within the well.
  • the setting tool may be lowered with respect to the liner hanger and rotated to release a running nut on the setting tool from the liner hanger. Cement is then pumped down the bore of the work string and liner and up the annulus formed by the liner and open borehole. Before the cement sets, the setting tool and work string are removed from the borehole. In the event of a bad cement job, a liner packer and a liner packer setting tool may need to be attached to the work string and lowered back into the borehole.
  • the packer is set utilizing a packer setting tool.
  • Packers for liners are often called "liner isolation" packers.
  • a typical liner isolation packer system includes a packer element mounted on a mandrel and a seal nipple disposed below the packer. The seal nipple stings into the tie back receptacle on top of or below the previously set and cemented liner hanger.
  • a liner isolation packer may be used, as explained above, to seal the liner in the event of a bad cement job.
  • the liner isolation packer is typically set down on top of the hanger after the hanger is secured to the outer tubular, and the packer is set by the setting tool to seal the annulus between the liner and the previously set casing or liner.
  • fluid such as drilling mud in the annulus between the liner and outer casing is displaced by cement as the cement is pumped down the flow bore of the work string.
  • the drilling mud and then the cement flows around the lower end of the liner and up the annulus. If there is a significant restriction to flow in the annulus, the flow of the cement slows and a good cementing job is not achieved. Any slowing of the cementing in the annulus allows time for the gas in the formation to migrate up the annulus and through the cement to prevent a good cementing job.
  • the liner hanging running tool must include a release mechanism so that, once the liner is reliably set to the lower end of the casing, the running tool can be released from the liner hanger and retrieved to the surface.
  • Conventional liner hanger running tool releasing mechanisms include hydraulically actuated mechanisms, and release mechanisms that are manipulated by left-hand rotation of the running string. The left-hand rotation of the running string is, however, generally considered undesirable since it may result in an unintended disconnection of one of the joints of the running string, thereby causing separation of the running string and a fishing operation to retrieve the running tool, which may have been damaged by the unintended disconnection.
  • hydraulically operated running tool release mechanisms may fail to operate, or may prematurely release the running tool from the liner hanger.
  • a liner hanger packoff bushing conventionally seals between the liner hanger and the running tool, and thus between the liner and the running string or work string, which conventionally may be drill pipe.
  • a packoff bushing is particularly required during cementing operations so that fluid pumped through the drill pipe continues to the bottom of the well and then back up into the annulus between the well bore and the liner to cement the liner in place.
  • the seal body of the packoff bushing is fitted in the annulus between the liner hanger and the running tool, and includes OD seals for sealingly engaging the liner hanger and ID seals for sealingly engaging the running tool.
  • Packoff bushings are preferably retrievable with the running tool to prevent having to drill out the bushings after the cementing operation is complete.
  • a packoff bushing is preferably lockable to the liner hanger by locking within a profile to prevent the bushing from moving axially with respect to the liner hanger. If the packoff bushing is not lockable to the profile of the liner hanger, the bushing may get "pumped out” through the top of the receptacle, thereby losing a cementing job.
  • a conventional retrievable and lockable packoff bushing includes metal dogs or lugs which are locked into engagement with the liner hanger to prevent the packoff bushing from moving axially during the cementing operation.
  • the packoff bushing is retrievable with the running tool, and thus eliminates the need to drill out the bushing after cementing operations are complete.
  • retrievable packoff bushings are also referred to as retrievable seal mandrels or retrievable cementing bushings.
  • the retrievable and lockable packoff bushing seals the annulus between the running string and the top of the liner, and may be locked in a profile of the liner hanger by the slick joint to prevent the bushing from being pumped out of the liner hanger.
  • a significant limitation on prior art packoff bushings concerns their desired retrievability with the running tool, when coupled with the desire to pick up the running tool relative to the packoff bushing before the cementing operation.
  • An operator will typically want to pick up the running tool after release from the liner hanger to ensure that these tools are disconnected.
  • the length of the running tool slick joint determines the maximum length that the running tool should be picked up after release from the liner hanger.
  • the slick joint used with the liner hanger running tool has a polished OD surface which seals against the ID seals on the seal body of the packoff bushing.
  • the slick joint OD surface can become scratched or damaged during handling, thereby causing a cementing leak during the cementing operation.
  • the running tool is designed to move axially substantial distances relative to the packoff bushing, the inner seals on the seal body may wear out during the cementing process due to the reciprocation of the running tool slick joint. This problem is exacerbated when the quality of the polished surface on the slick joint has deteriorated. Axially long slick joints are expensive to manufacture and maintain.
  • a conventional liner hanger running tool includes a packer setting assembly, which allows the activation and the packer.
  • Conventional packer setting assemblies incorporate multiple spring-loaded dogs or lugs which may be compressed to a reduced diameter position by insertion into the packer setting sleeve when running the liner hanger in the well and when cementing the liner within the casing.
  • the dogs or lugs expand to a diameter greater than the ID at the upper end of the setting sleeve, which is also the tie back receptacle of the liner hanger.
  • a setting force may be transferred from the running string through the dogs and to the packer setting sleeve as running string weight is slacked off to set the packer element.
  • An assembly using dogs for transmitting setting forces is shown in CA-A-2289374 .
  • Some prior art packer setting assemblies include an axial bearing to facilitate rotation of the work string while setting the packer element.
  • Other packer setting assemblies include both a bearing and a shear indicator to provide a visual confirmation that the proper setting load was applied to the packer, and/or an unlocking feature that allows the packer setting assembly to be pulled out of the packer setting sleeve one time without exposing the setting dogs. This latter tool allows re-stabbing the packer setting assembly into the packer setting sleeve one time, thereby arming the setting dogs so they are ready to expand the second time the dogs are pulled out of the setting sleeve.
  • a primary problem concerning prior art packer setting assemblies is poor reliability.
  • the packer setting dogs of conventional packer setting assemblies collapse and re-enter the setting sleeve without setting the packer element.
  • Manufacturers have provided more dogs or lugs to alleviate this problem, have provided heavier springs to bias the dogs radially outward. These changes have had little if any affect on achieving higher reliability.
  • an improved liner hanger running tool which includes improvements to a running tool release mechanism, a retrievable packoff bushing, and a packer setting assembly.
  • the improved packer setting assembly may be used in operations not involving a liner hanger running tool.
  • a packer setting assembly for setting a radial set packer element, the packer setting assembly applying a force on one of the packer element and a cone to move the packer element relative to the cone, characterised in that the packer setting assembly comprises a radially expandable force transmitting C-ring, the force transmitting C-ring when expanded acting to engage a setting sleeve for applying a set-down weight through the setting sleeve to set the radial set packer element.
  • the assembly may comprise a lockout mechanism for preventing the force transmitting C-ring from moving to the expanded position.
  • the lockout mechanism may include a lockout C-ring for radially expanding to engage the top of the liner and thereby disengage the lockout mechanism.
  • the lockout mechanism may move from an expanded position to a retracted position due to a camming surface on a housing of the packer setting assembly, thereby releasing the force transmitting C-ring.
  • the packer setting assembly may further comprise a lock-out mechanism for allowing the force transmitting C-ring to be raised out of the top of a liner hanger one time without moving the force transmitting C-ring to the expanded position, such that the next time the force transmitting C-ring is moved out of the liner hanger, the force transmitting C-ring expands to its expanded position for engagement with the liner hanger.
  • the packer setting assembly may further comprise a packer setting housing, an I. D. seal for sealing between a packer mandrel and the packer setting housing; and an O. D. seal for sealing with between the setting sleeve and the packer setting housing, such that fluid pressure may be used to assist in applying a setting force through to the setting sleeve to the packer element.
  • the packer setting assembly may further comprise a packer setting housing about a mandrel and a bearing for facilitating rotation of the mandrel relative to the housing,
  • the radiale set packer element may include a metal radially inward base and one or more radially outer seal bodies.
  • the setting sleeve may act on the packer element of a liner hanger to seal between the liner hanger and a casing.
  • a method of setting a radial set packer element by applying a force on one of the packer element and a cone to move the packer element relative to the cone characterised in that the method comprises providing a radially expandable force transmitting C-ring, expanding the force transmitting C-ring to engage a setting sleeve, and applying a set-down weight through the setting sleeve to set the radial set packer element.
  • the method may comprise providing a lockout mechanism for preventing the force transmitting C-ring from moving to the expanded position, and engaging the lock out mechanism with the top of the liner hanger to release the force transmitting C-ring.
  • the method may comprise providing a C-ring lockout mechanism, moving the C-ring lockout mechanism from an expanded position to a retracted position by applying set down weight to the C-ring lockout mechanism due to a camming surface on a housing of the packer setting assembly, thereby releasing the force transmitting C ring.
  • the lockout mechanism may move axially to release the force-transmitting C-ring.
  • the method may comprise allowing the force transmitting C-ring to be raised out of the top of a liner hanger one time without moving the force transmitting C-ring to the expanded position, such that the next time the force transmitting C-ring is moved out of the liner hanger, the force transmitting C-ring expands to its expanded position for engagement with the liner hanger.
  • the method may further comprise providing a packer setting housing, providing an I.D. seal for sealing between a packer mandrel and the packer setting housing, and providing an O.D. seal for sealing with between the setting sleeve and the packer setting housing, such that fluid pressure assists in applying a setting force to the setting sleeve.
  • the radial set packer element may include a metal radially inward base and one or more radically outer seal bodies.
  • the running tool 120 may initially be attached to the lower end of a work string WS and releasably connected to the liner hanger, from which the liner is suspended for lowering into the bore hole beneath the previously set casing or liner C.
  • the assembly may easily be run in at a rate that does not adversely affect the well formations or the running tool.
  • a tie back receptacle 130 as shown in Figure 1B is supported about the running tool 120, with its upper end having the liner hanger slip setting assembly 140.
  • the upper end of the tie back receptacle 130 upon removal of the running tool, provides a means by which a casing tie back (not shown) may subsequently extend from its upper end to the surface.
  • the tool 120 includes a central mandrel 132, which may comprise multiple connected sections.
  • the lower end of the tie back receptacle 130 is connected to the packer element pusher sleeve 148 as shown in Figure 1F , whose function will be described in connection with the setting of the packer element 150 about an upper cone 152, as well as setting of one alternative embodiment of slip 142A about a lower cone 144A (see Figure 1G ) below the packer element 150.
  • the running tool 120 includes a cementing bushing 160 (see Figure 1E ) from which a tubular body 162 is suspended for supporting the ball diverter 280 (see Figure 1I ) and liner wiper plug 180 (see Figure 1J ) at the lower end of the running tool.
  • the retrievable cementing bushing 160 provides a retrievable seal between the running tool 120 and the liner hanger assembly for fluid circulation purposes. By incorporating an axially movable slick joint, the running tool can be moved without breaking the seal provided by the packoff bushing.
  • the liner hanger slip setting assembly 140 as shown in Figure 1B includes a sleeve 212 disposed within and axially moveable relative to a portion 210 of the running tool mandrel 132.
  • the piston sleeve 212 is held in its upper position by shear pins 222 in mandrel portion 210.
  • a tubular ball seat 232 is supported at the lower end of sleeve 212.
  • the lower end of the ball seat has a neck portion 234 which is reduced in diameter and is thinner, for the purpose described below.
  • a ball 240 is dropped from the surface into the running tool bore 126 and onto the seat 232.
  • An increase in fluid pressure within the mandrel 132 will shear the pins 222 and lower the ball seat to a landed position in the bore of the running tool, e.g., against the stop shoulder 236.
  • This description also relates to improved apparatus for dropping a ball as above mentioned which includes a head suspended from a top drive for use in sequentially dropping balls and plugs into a liner suspended from the head. More particularly, it relates to the use of such equipment in cementing the liner within the outer casing, wherein the one or more balls are to be dropped onto a seat within the liner to actuate certain parts for the purpose of hanging the liner in the outer casing, followed by the dropping of pump down plugs through the liner for pumping cement beneath them into the annulus between the liner and outer casing.
  • U.S. Patent Nos. 6,182,752 and 6,206,095 allege to solve the problem of excess height by means of heads of such construction as to permit the balls and plugs to be mounted and dropped from essentially the same vertical location beneath the top drive. Nevertheless, their construction is complicated and requires large internal rotating parts which increased the possibility of leakage and other need for repair.
  • a housing having an inlet adapted to be fluidly connected in line with the lower end of a top drive, an outlet generally aligned with the inlet, and passages extending downwardly within the housing at circumferentially spaced locations.
  • Each passage has an upper end opening to the side of the inlet and a lower end connecting with the outlet, and lateral passages in the housing each connect the inlet with a passage.
  • a closure member is removably mounted in the upper end of each passage to permit a ball or plug to be installed therein, and plug valves are mounted in the housing each for opening and closing a passage beneath the lateral passage connecting thereto so as to support the ball or plug, when closed, and permit it to pass therethrough, when open. Circulating fluid may pass downwardly through an open passage when a ball or plug is not in the passage.
  • the head A10 comprises a housing A11 having a vertical opening A12 in its upper end and a vertical opening A13 in its opposite lower end, the openings being generally vertically aligned.
  • the upper opening is threadedly connected to a tubular member A14 whose upper end is threaded for connection with a top drive.
  • a Kelly valve A16 installed for opening or closing its bore A15.
  • the valve allows cement to be supplied to the bore A15 through one or more side openings A16 in member A14 beneath the Kelley valve.
  • the member A14 is installed on a swivel A20 which has openings therethrough aligned with openings A16 in fittings A17 leading to the bore A15 of the member. As well known in the art, this permits relative rotation between the swivel and tubular member so that the tubular member and cementing truck are fluidly connected during relative rotation.
  • the lower end opening A13 in the head is threadably connected to the upper end of a sub A21 having a bore A22 therethrough adapted to be connected with the liner or other tubular member suspended therefrom.
  • a "flag" A23 is mounted on a stem A24 rotatable in the sub for indicating the passage of a ball or plug therethrough.
  • the housing is of a generally frustoconical shape and has four passages P 1 , P 2 , P 3 and P 4 extending downwardly and inwardly therethrough to connect at their lower ends with the opening A13. More particularly, these passageways are-equally spaced apart about the center line of the housing, and thus to opening A12, to connect at their lower ends with a common opening A21A in the upper end of the sub A21.
  • each passage is adapted to receive a closure member 25, the threaded connection between each closure member and its passage enabling the closure member to be selectively removed or installed.
  • the housing also has a lateral opening A26 connecting the lower end of its upper opening A12 with one of the passages P 1 , P 2 , P 3 and P 4 beneath the closure member therefor.
  • Each passage P 1 , P 2 , P 3 and P 4 is in turn open and closed by means of through bore plug valves PV 1 , PV 2 , PV 3 , and PV 4 installed in the housing beneath the lateral openings A26, and vertically staggered to accommodate the valves.
  • These valves of course control the passage of a plug or a ball as well as circulating fluid through the top drive, the head and into the liner below it.
  • circulation of the fluid may be continuous through at least one passage, even though the individual passages are closed to contain balls or wiper plugs.
  • each plug valve comprises a body having an opening A30 therethrough adapted, upon rotation of the body between its alternate positions, for alignment with or across a passage.
  • These valve bodies may of course be rotated in any suitable manner and are held in place by a mounting plate MP bolted to the outside of the housing.
  • one of the passages may receive a ball B between the top closure member and valve, while another passage may receive a pump down plug PDP.
  • One of the other passages may be used to receive a ball or a plug, depending on the use of the balls and plugs in the system in which the head is installed.
  • the fourth passage may be left open for enabling fluid to be freely circulated downwardly therethrough on a continuous basis.
  • a plug or a ball may be installed in a passage by removal of the closure member A25, which provides easy visual access to the passage to determine if the ball or plug in place or has been dropped downwardly. Each ball drops freely by virtue of its own weight when the plug valve in its passage is opened.
  • the pump down plug however, has wiper blades on it which are flexibly engaged with the passage, so that the downward movement of the wiper blade into the liner may be assisted by the passage of fluid through the ports connecting with the passage.
  • the fourth passage may receive either a plug or a ball, depending on the needs of the system in which the head is installed or left open for free downward flow of the circulating fluid.
  • the plug valves PV for the individual passages. Closure of the plug valve in the three passages may facilitate downward pressure through the fourth passage when its plug valve is open, thus forcing the ball or plug downwardly into the liner.
  • each plug valve is mounted for rotation within its passage by means of a mounting plate MP bolted to a recessed portion of the outer side of the head and engaging an annular shoulder about the plug valve member.
  • piston sleeve 220 is disposed about and is axially moveable relative to portion 210.
  • An upper sealing ring 214 is disposed about a smaller O.D. of the running tool mandrel than is the lower sealing ring 216 to form an annular pressure chamber 218 between them for lifting the tie back receptacle 130 from the position shown in Figure B to an upper position, as will be described in connection with setting the slips 142A.
  • Ports 242 formed in the running tool mandrel 132 connect the running tool bore with the surrounding pressure chamber 218 once the sleeve 212 is lowered. An increase in pressure through the ports 242 will raise the piston sleeve 220.
  • the slip assembly include slip segments 141 which are raised by a tie bar over the outer conical surface of a cone 143 to cause teeth 142 about the slips to grip the casing C.
  • the frusto conical surfaces of the member and slip extend downwardly and inwardly, the lower end of the slip is received in an upwardly facing recess in the member, and the teeth of the c-ring face downwardly in position to engage the wellbore, as the c-ring is raised over the surface of the member whereby the member may be suspended within the wellbore.
  • the means for raising the lower end of the c-ring from the recess to a position for sliding along the conical surface of the member comprises at least one tie bar extending vertically through the member for guided reciprocation with respect thereto. More particularly, the inner side of the c-ring and lower end of the tie bar have interfitting parts which enable the lower end of the c-ring to be raised out of the recess, but which are disengageable when the bar is raised to permit the ring to expand into engagement with the wellbore.
  • the inner frusto conical surface of the c-ring has relatively blunt teeth about its frusto conical surface for engagement with the frusto conical surface of the member so as to control the friction between them, and thus control the force applied to the casing.
  • the elongate member is a liner and the recess to receive the end of the slip is of annular shape.
  • the liner B20 has a downwardly and inwardly extending frusto conical surface B22 thereabout above an upwardly facing annular recess B23.
  • the liner has been lowered on a suitable running tool (not shown) to a position in the outer well casing in which the liner is to be hung off.
  • c-ring C is initially expanded to permit it to be disposed about the conical wedge surface of the liner. It may then be contracted and forced downwardly to cause its lower end B26 to move into the recess B23. When so installed, the c-ring slip is held in retracted position in a shape somewhat larger than its fully contracted shape of Figs. B1A and B1B.
  • the inner frusto conical surface of the c-ring slip has blunt teeth CF thereon which, as well known in the slip art, control the frictional engagement with the liner and thus the outward force applied to the casing.
  • blunt teeth CF thereon which, as well known in the slip art, control the frictional engagement with the liner and thus the outward force applied to the casing.
  • the blunt teeth on the inner side of the slip will begin to gall the wedge surface of the liner so as to control the extent to which the teeth bite into the casing.
  • the force thus applied to the casing and liner may be controlled by the relationship of the inner and outer teeth to one another.
  • the teeth CF are preferred, the inner surface of the c-ring may be smooth.
  • tie bars B30 extend downwardly through a slot B40 in the liner for guided reciprocation with respect thereto.
  • the lower end of each tie bar is connected to the upper end of the slip for raising its lower end out of the recess.
  • the lower end of each tie bar B30 has a flange 50 which is received in a groove B36 about the inner diameter of the c-ring, as the c-ring is initially mounted in the recess.
  • the flange B50 on its lower end moves out of the groove B36 to release the c-ring therefrom, as shown in Fig. B5.
  • the weight of the liner may be slacked off on to the outer frusto conical surface of the c-ring to force the teeth of the c-ring outwardly into gripping engagement with the outer casing as shown in Fig. B6.
  • a liner hanger system comprising a joint of casing adapted to be connected as part of an outer casing installed within a wellborn, and a liner adapted to be lowered and landed within the outer casing.
  • the bore of the casing joint has a polished bore and vertically spaced, upwardly facing landing surfaces formed therein, and the liner includes a tubular body having a recess formed about its body, and a hanger element comprising a circumferentially expandible and contractible C-ring disposed within the recess.
  • the ring has teeth on its outer diameter for landing on the landing surfaces of the casing joint when in its expanded portion, and upon relative vertical movement with respect to the liner, is expanded outwardly against the polished bore. Upon continued relative movement of the liner and ring, the teeth will move into a position in which they expand further outwardly into landed positions on the landing surfaces to permit the liner to be suspended therefrom.
  • the joint C10 of the outer casing section is threaded at its upper and lower ends to permit it to be connected as part of the outer casing installed in the well bore, as in the liner hanger systems referred to above.
  • the polished bore of the casing section has an annular recess C11 in its lower portion, and a series of vertically spaced, upwardly facing landing shoulders C12 above the recess C11 and separated therefrom by annular restriction C14.
  • annular recess C15 formed in the bore above and separated from the landing surfaces C12 by means of an upper restriction C16 above an annular recess C13.
  • the restrictions and landing shoulder are of essentially the same diameter of the polished bore above them.
  • Hanger C17 is shown in Figure C2 to be carried within a recessed portion 18 about the liner L.
  • the hanger C17 is a C ring split about its circumference in position to be urged circumferentially outwardly to engage the inner diameter of the casing when expanded, but held in its contracted position, as shown, as the liner is run into the outer casing. In this position, its lower end C20 is adapted to be received within a groove C19 in the upper end of an enlarged outer diameter portion C21 of the liner.
  • the upper end of the hanger has teeth C22 formed thereabout in vertically spaced relation corresponding to the landing surfaces C12 of the casing and fitting within recess C18 about the liner.
  • the toothed section and lower end of the ring are connected by an outwardly enlarged cylindrical portion C35 whose inner surface engages the outer surface of enlargement C25 about the liner.
  • liner hanger system includes a suitable mechanism to raise the hanger out of its retained position, to free its lower end from groove C19. This may be accomplished by raising the hanger by means of tie bars C30 connected at their upper ends to a cone C cover which a packing element is adapted to be lowered to set it against the outer casing.
  • the tie bars extend through vertical slots in the recessed portion of the liner, and have an outer flange C31 releasably connected in a groove C32 about a lower extension of the cone C.
  • the lower radially enlarged section C35 of the hanger which extends over the outer enlargement 25 of the liner, is free to move outwardly into the recess C11 in the outer casing.
  • the teeth C22 about the upper end of the hanger move outwardly onto the landing surfaces, thus forming multiple shoulders on which to support the load of the liner within the outer casing.
  • This outward expansion of the hanger element has occurred after it has been lowered beneath the enlargement in the bore of the outer casing as the liner is lowered from its Fig. C3 to its Fig. C4 position.
  • enlargement C35 thereabout beneath its teeth fits closely within the recess C16 in the outer casing bore so as to limit outward expansion of the hanger element once it is moved into hanging position.
  • An inwardly enlarged portion C60 on the lower end of the hanger, beneath its outwardly enlarged portion C35 moves over the outer diameter of the lower end of the liner, thereby cooperating with the enlargement C50 to maintain the hanger element in its outer hanging position.
  • the annular packer element 150 (see Figure 1F ) is disposed about a downwardly-enlarged upper cone 152 beneath the pusher sleeve 148.
  • the packer element 150 is originally of a circumference in which its O.D. is reduced and thus spaced from the casing C. However, the packer element 150 is expandable so that it may be moved downwardly over the cone 152 to seal against the casing.
  • the packer element 150 is adapted to be set by means which includes spring-pressed lugs 328 which, when moved upwardly out of the tie back receptacle 130, will be forced to an expanded position, as shown in Figure 6A , to engage the top of the tie back receptacle.
  • the expanded lugs 328 transmit this downward force through to the pusher sleeve 148 and the packer element 150.
  • a body lock ring 270 (see Figure 1 F) is disposed between the tie back connector 130 and the pusher sleeve 148 and permits the packer element 150 to be forced downwardly over the upper cone 154 by lowering of the tie back connector. Upward movement of the set packer element is prevented.
  • the packer element 150 may be of a construction as described in U.S. Patent No. 4,757,860 , comprising an inner metal body for sliding over the cone and annular flanges or ribs which extend outwardly from the body to engage the casing. Rings of resilient sealing material may be mounted between such ribs.
  • the seal bodies may be formed of a material having substantial elasticity to span the annulus between the liner hanger and the casing C.
  • the present invention also relates to an improved radial set packer for sealing with a casing or other downhole cylindrical surface which is configured with a primary seal and a backup seal, and may be part of a downhole tool including a conveyance tubular and a conical wedge ring, and thus may be used for reliable sealing engagement between a liner hanger and a casing string.
  • Packer elements or packers which are radially set by axial movement of the packer element relative to a conical wedge ring have been used for sealing in subterranean well bores.
  • a conveyance tubular is conventionally provided for positioning the packer element at the desired position within the well bore, and an actuator causes the packer element to move axially with respect to a conical wedge ring and thereby expand into sealing engagement with the cylindrical surface to be sealed.
  • U.S. Patents 4,757,860 (previously mentioned) and 5,076,356 disclose radial set packer elements which may be used in various applications, including a subsea wellhead. In a typical wellhead application, the packer element may need to expand in diameter approximately 0.030 inches in orderto obtain a reliable seal with the polished bore.
  • U.S. Patents 5,511,620 and 5,333,692 disclose packerelements intended for sealing between a liner hanger and a casing. More specifically, a conical member is moved axially with respect to the packer element to expand the packer element into engagement with a casing.
  • That expansion may be significantly greater than the expansion of a packer element in a wellhead application due to the difference in diameter of the casing from the drift (smallest allowable ID for a particular size casing) to the maximum allowed by API for that size casing.
  • the difference between this drift and the maximum for a particular size casing may thus be 7.620 mm (0.300 inches) or greater.
  • the seal element is stationary with respect to a movable conical element, the radially extending flanges or ribs of the seal element may not expand as desired into portions of the non-uniform diameter casing string to obtain reliable metal-to- metal sealing engagement.
  • the packer element does not always form a reliable metal-to-metal seal with the conical wedge ring, and the conical wedge ring similarly does not form a reliable metal-to-metal sea with the too mandrel.
  • the elastomeric sealing portions of the seal element are not allowed to thermally expand in response to high temperature conditions, and thus exert uncontrollable forces on the spaced apart metal radial flanges or ribs.
  • the radial set annular packer element according to the present invention is positioned downhole by a conveyance tubular.
  • the packer element may be moved by a setting tool from a reduced diameter run-in position to a set and expanded diameter position, such that the packer element engages a casing, a polished bore receptacle, or other downhole cylindrical surface in a well. If the cylindrical surface is a casing or other member which may be irregularly shaped, the packer element is preferably moved axially relative to a conical wedge ring or cone during the setting operation.
  • the packer element is particularly well suited for reliably sealing against high pressure either from above or below the element, and includes a primary elastomeric seal and a secondary elastomeric seal, and a primary metallic seal and a secondary metallic seal.
  • the metal ribs of the packer element are angled so that the primary elastomeric seal is pressed against a rib angled toward the high pressure, and the secondary elastomeric seal is similarly pressed against a rib angled toward the high pressure.
  • the secondary elastomeric seal body acts on the primary rib to prevent the primary rib from becoming perpendicular with respect to the sealing surface, and thereby enhances the reliability of the seal.
  • each of the primary and the backup metallic ribs of the sealing element are angled at least 15° with respect to a plane perpendicular to a central axis of the sealing element.
  • Another feature of the invention is that axially spaced metal protrusions provide a reliable metal-to-metal seal between the packer element and the cone, and also preferably between the cone and the mandrel or body interior of the cone.
  • the elastomeric seal bodies of the packer element include specifically designed volumetric voids so that, after the seal bodies engage the surface, the elastomeric seal bodies will be compressed until the ends of the ribs engage the sealing surface. At this stage, the now smaller voids in the seal bodies allow for thermal expansion of each seal body between the metal ribs to minimize undesirable stress force on the ribs.
  • Figure D1 depicts an annular packer element D10 positioned at the lower end of a pusher sleeve D12 at the lower end of a tie back receptacle prior to sealing engagement with a casing C.
  • Conventional grooves or threads D28 or similar connectors may be used to interconnect the packer element to the tie back receptacle.
  • Axial movement of the packer sleeve D12 and thus the packer element D10 in response to the packer setting operation pushes the packer element downward relative to the tapered cone D14 to expand the seal element into sealing engagement with the casing.
  • the cone D14 is in turn supported on a liner hanger body D16.
  • the packer element D10 may be supported on the end of a seal actuator which replaces the pusher sleeve D12, and the liner hanger body D16 may be a packer mandrel or other conveyance tubular for positioning the packer element in the well.
  • the body D16 is thus part of the conveyance tubular which positions the packer element at a selected position within the well bore.
  • the pusher sleeve of the tie back receptacle shown in Figure D1 represents a lower portion of an actuator sleeve which urges the packer element from a reduced diameter run-in position to an expanded diameter activated or sealed position.
  • the actuator sleeve may thus apply a selected axial force to the packer element to set the packer.
  • the actuator may be selectively activated by various mechanisms, including set down weight or other manipulation of the conveyance tubular, and may include axial movement of a piston in response to fluid pressure, either with or without dropping plugs or balls to increase fluid pressure. Further details with respect to the use of the packer element in a liner hanger application are disclosed in U.S. Provisional Application Serial No. 60/292,049 filed 18 May 2001 .
  • the packer element as shown in Figure D1 is in its original configuration in which the OD is reduced prior to being sealed with the casing.
  • Packer element D10 is expandable so that it is moved downwardly over the stationary cone D14 to seal against the casing, as discussed below and as shown in Figure D3.
  • the packer element D10 be moved into reliable sealing engagement with the casing by a setting operation which includes moving the packer element D10 axially with respect to the packer cone D14, rather than moving the cone with respect to the stationary packer element.
  • This setting operation forms a more reliable seal with the casing by allowing the ribs D20, during the setting operation, to flex or deform into the shape of the casing.
  • the packer element D10 comprises an inner metal body or base D18 for sliding over the conical wedge ring or cone D14 and annular flanges or ribs D20 which extend radially outwardly from the base D18 to engage the casing.
  • the base D18 is relatively thin to facilitate radial expansion.
  • the base D18 and the ribs D20 form a metal framework to support the rubber or other resilient and preferably elastomeric seal bodies. Rings of resilient seal bodies D22, D24 and D26 are provided between the ribs D20, and preferably the upper and lower sides of each seal body are in engagement with a respective rib.
  • the body D18 and the ribs D20 are formed from material having sufficient ductility to expand into the annulus between the casing and the liner hanger.
  • the metal portion of the packer element namely the base D18 and the radially projecting ribs D20, is thus formed from material which is relatively soft compared to metals commonly associated with downhole tools. This allows the packer element to reliably expand into sealing engagement with the casing at a reduced setting load.
  • the radially projecting ribs D20 of the packer element are each substantially angled with respect to a plane perpendicular to a central axis of the packer element. More specifically, the centerline of each rib is angled in excess of 15°, and preferably about 30°, relative to the plane D38 perpendicular to the central axis of the packer element. Although the ribs may be slightly tapered to become thinner moving radially outward, the ribs preferably have a substantially uniform axial thickness. Rib. D32 is shown in Figure D2 at an angle D33 between the rib centerline and the plane D38.
  • each of the ribs D20 to expand substantially as the diameter of the casing varies or "grows", whether in response to internal pressure and/or thermal expansion. Because of the ability of the angled ribs D20 to flex, reliable metal-to-metal contact is maintained between the ends of the ribs and the casing, as shown in Figure D3.
  • the packer element D10 inherently forms both a primary seal with the casing and a secondary seal with the casing, with the secondary seal depending upon the direction of pressure.
  • the packer element may include both a primary and a backup elastomeric seal, and a primary and a backup metallic seal.
  • the downward inclination of the ribs D30 and D32 is such that relatively high fluid pressure above the packer element may pass by these ribs and the annular elastomeric upper seal body D22, so that the interior seal body D24, which constitutes a majority of the elastomeric seal area, forms the primary elastomeric seal against fluid flow.
  • Seal body D24 preferably engages the ribs D32, D34 and the base D18, and substantially fills the annular void between these surfaces.
  • Seal body D26 When fluid pressure is above the seal element D10, the lower seal body D26 positioned between ribs D34 and D36 forms a backup secondary elastomeric seal in the event the primary elastomeric seal were to leak.
  • high fluid pressure is below the packer element, high pressure fluid would likely flow past the ribs D36 and D34, so that seal body D24 is the primary seal element. Seal body D22 between the ribs D30 and D32 thus becomes the secondary elastomeric seal element.
  • the primary elastomeric seal element is thus pressed in an axial direction (generally along the central axis of either the conveyance tubular body or the casing) in response to pressurized fluid, against an inclined rib which is angled toward the high pressure, and the secondary elastomeric seal element is captured between two ribs each angled toward the high pressure side, so that the secondary seal element is also pressed in an axial direction against a rib angled in the direction of the high pressure.
  • the backup seal is captured between two ribs and thus minimizes the likelihood that the axially innermost rib D32 or D34 will flex outward to come in line with the plane D38, i.e., perpendicular to the wall of the casing.
  • the material of the seal body D22 or D26 thus acts as a biasing force which tends to retain the rib D32 or D34 at a desired angle, which then supports the primary seal body D24 and prevents the rib D32 or D34 from becoming perpendicular to the wall of the casing C. Should the ribs flex past the point of being perpendicular to the casing wall, the packing element likely will lose its sealing integrity with the casing.
  • the radial ribs D20 are thus vertically spaced from one another and act independently with respect to upward and downward directed pressure forces.
  • Packer element D10 also includes multiple metal sealing surfaces, namely the ends of each of the ribs D20, to form annular metal-to-metal seals with the casing. More particularly, these angled ribs are configured to keep a constant metal-to-metal seal with the casing -even though the packing element may be subjected to variable fluid pressure and temperature cycles. Under high pressure, the two ribs adjacent the high pressure may flex toward the base D18 and thus not maintain sealing integrity.
  • a primary metal seal is nevertheless formed by one of the axially innermost ribs D32 or D34 on the downstream side of elastomeric packer body D24, and a backup metal-to-metal seal is formed by the axially outermost rib D30 or D36 spaced axially farthest from the high pressure.
  • High fluid pressure forces both the primary and secondary backup ribs to reduce the angle D33, thereby forming a tighter sealed engagement with the casing.
  • the redundant or backup elastomeric seal D22 or D26 exerts a biasing force which tends to prevent the primary metal seal D32 or D34 from moving past the position where it is perpendicular to the wall of the casing.
  • each of the elastomeric seal bodies D22 or D24 and D26 is provided with a substantial void area D23, D25 and/or D27 to allow for compression of the elastomeric body and for thermal expansion so that, during both the final setting operation and during use downhole, the rubber-like material is not squeezed outwardly past the ends of the ribs, or squeezed to exert substantial forces on the ribs which will alter the flexing of the ribs.
  • the void area between the ends of the ribs and the base of the sealing element is such that at least about 5% to 10% thermal expansion of elastomeric material may occur.
  • each of the elastomeric seal bodies thus preferably includes voids that allow each resilient seal body to compress between the metal ribs without over-stressing or buckling the ribs. These voids will thus be substantially filled due to compression of the resilient sealing material, and will become substantially filled, as shown in Figure 3 , due to compression of the seal bodies and thermal expansion of the resilient seal bodies. The stress level on each of the elastomeric seals may therefore remain substantially constant with varying thermal cycles in the well bore.
  • the elastomeric seal bodies have been compressed to reduce the void area, leaving only a small void volume for additional thermal expansion.
  • the void area is preferably designed to be from 5 to 10% of the volume of the resilient seal bodies once each seal body is in its compressed position with the ends of the ribs engaging the casing, but prior to thermal expansion.
  • Figure D3 depicts the packer element D10 in sealed engagement with the casing C, and at a temperature wherein the elastomeric material has already expanded to fill most of the void area discussed above.
  • Figure D3 also shows the flexing or bending of these ribs from the run in position as shown in dashed lines to the sealing position as shown in the solid lines.
  • the inclination of the ribs i.e., angle D33 as shown in Figure D2 is thus increased during the packer setting operation.
  • the ribs D30 and D32 at the upper end of the packer element D10 are angled downwardly, and the ribs D34 and D36 at the lower end of the packer element are angled upwardly.
  • the centerline of each rib is angled at least 15° with respect to the plane D38 perpendicular to the central axis of element 10 priorto setting, i.e. when of a reduced diameter as shown in Figure D1.
  • the base D18 of the packer seal includes a plurality of inwardly projecting protrusions D40. These annular protrusions or beads on the packer element provide a reliable metal-to-metal sealing engagement with the packer cone D14. These protrusions provide high stress points to form a reliable metal-to-metal seal. Similar protrusions D42 on the packer mandrel D16 provide metal-to-metal sealing engagement between the packer mandrel D16 and the packer cone D14. Accordingly, the seal operates in conjunction with the packer cone to obtain a complete metal-to-metal seal between the packer mandrel and the packer cone, between the packer cone and the seal element, and between the seal element and the casing.
  • the multiple seal protrusions or beads D40 form axially spaced metal-to-metal seals between the base D18 of the sealing element D10 and the tapered cone D14, while protrusions D42 seal between the cone D14 and the packer body or other conveyance tubular D16.
  • These metal-to-metal seals are energized as the packer seal is set, and preferably include multiple redundant annular metal-to-metal seals.
  • one or both of the radially inner and intermediate metal-to-metal seals could be formed by annular protrusions on the packer cone for sealing with either or both the packer element base D18 and the packer mandrel D16.
  • the resilient elastomeric seals D48 on the ID of the seal bore D18 may be backup seals, since the spaced apart metal protrusions D40 form the metal-to-metal seal between the packing element and the cone once the packer element is fully set.
  • Another elastomeric seal such as a V packing D15, provides an elastomeric backup seal between the cone D14 and the body D16,
  • These metal protrusions D40 on the ID of the element D10 are axially in line with (laterally substantially opposite) the area where the ribs D20 seal against the casing. The interface between the casing and the metal ribs D20 of the packing element D10 thus force the metal seal protrusions D40 into tight metal-to-metal sealing contact with the cone D14.
  • the protrusions D42 on the body D16 are similarly axially in line with the element D10.
  • the metal-to-metal seals between the packer element and the cone are preferably provided on the packer element, since its axial position relative to the cone when in the set position may vary with the well conditions.
  • the packer element D10 With the desired setting force applied to the packer element D10, the packer element will be pushed down the ramp of a cone D14 so that the ribs D20 come into metal-to-metal engagement with the casing.
  • Metal seal protrusions D40 and D42 between the packing element D10 and the cone D14 and between the body D16 and the cone D14 are in contact, but have not been energized.
  • the ribs on the packing element may be flexed inward to a position in solid lines in Figure D3. This high setting force will compress the seal bodies between the ribs and cause the outer diameter of each seal body into tight sealing engagement with the casing.
  • This high setting force will also cause the metal protrusions D40 along the ID of the seal element D10 and the metal protrusions D42 along the OD of the mandrel D16 to form a reliable metal-to-metal seal with the cone D14. Under this load, these metal protrusions form high localized stress at the point the protrusions engage the cone to achieve a reliable metal-to-metal seal.
  • the metal protrusions which provide the desired metal-to-metal seals between the body or mandrel D16 and the cone D14 could be provided on either the outer generally cylindrical surface of body D16 or the inner generally cylindrical surface of cone D14.
  • a reliable fluid pressure tight barrier which may be both a liquid barrier and a gas barrier, is thus formed with high reliability under various temperatures, pressures and sealing longevity conditions, due to the combination of the elastomeric and metal seals.
  • the BOP preventer rams may be closed around the drill pipe (or other conveyance tubular) and fluid pressure may be applied to the annulus to pressure assist the setting of the packer element.
  • the sealing element is well suited for use in a liner hanger for sealing between the packer mandrel of the liner hanger and the casing.
  • the initial set down weight on the seal element D10 will thus force the seal element down the cone D14 and into contact with the casing C.
  • the seal material which is radially outward of the ends of the ribs D20 will be compressed to occupy much of the void area in the seal bodies.
  • the remaining void area may be from 5% to 10% of the volume of each seal body, assuming there has been no significant expansion of the seal bodies due to thermal expansion. If the seal bodies experience high thermal expansion prior to a setting operation, the void area will be reduced by compression of the seal bodies.
  • the pressure may cause the casing to expand in diameter and, this expansion will cause the ribs to expand with the casing, so that the position of the ribs with respect to the expanded casing may return to the configuration as shown in dashed lines in Figure D3.
  • the ability of the ribs to "grow" in diameter with the expanding casing keeps the ends of the ribs in reliable metal-to-metal contact with the casing as the well goes through pressure and temperature cycles.
  • the ribs may return to the solid line configuration as shown in Figure 3 .
  • the seal element D10 is thus ideally suited for applications in which high pressure may be applied from either direction to the seal element, since the seal element inherently provides both a primary seal and a secondary seal, with each elastomeric seal being supported in a direction to resist axial movement in response to the high pressure by a rib which is angled in the direction of the high pressure, and which allows flexing to conform to the casing.
  • the rib on each side of the primary seal body is supported by the secondary seal body, which biases the rib toward the high pressure.
  • the liner hanger running tool conventionally includes the actuator which provides the compressive force to the packer element D10 to set the packer.
  • an actuator may be used for applying the compressive force to move the seal from a run in or radially reduced position to a sealing or radially expanded position.
  • the actuator may be hydraulically powered or may use mechanical setting operations. Thereafter, a retainer keeps the seal element in sealing contact with the casing, after the running tool is returned to the surface, by preventing or limiting axial movement of the packer element when fluid pressure is applied.
  • the sealing element may be used in various applications in a well bore having a tubular disposed therein, wherein a packer mandrel or other conveyance tubular is positioned within the well bore to position the packer element at a selected location.
  • the packer element is disposed about the conveyance tubular and includes a plurality of elastomeric seal bodies for sealing engagement with the well bore tubular, and a plurality of metal ribs which separate the elastomeric seal bodies, with the rib ends intended for metal-to-metal sealing engagement with the tubular.
  • the packer element may be run into the well in a configuration similar to that shown in Figure D1 in which the sealing element has a reduced diameter, and the packer element deformed radially outward into sealing engagement with the well bore tubular as it moves relative to a conical wedge ring, until the packer element reaches the final set position, as shown in Figure D3.
  • the radial set sealing element of the present invention may thus be used for various types of downhole tools. Additional back-up secondary metal ribs could be provided, as well as additional back-up elastomeric bodies engaging these additional ribs.
  • the substantially conical wedge ring or cone may have various constructions with a generally outer conical surface configured to radially expand the annular seal assembly or packer upon axial movement of the packer element relative to the wedge ring, due either to axial movement of the packer element relative to the stationary wedge ring or axial movement of the wedge ring relative to the stationary packer element.
  • the seal assembly includes an upper elastomeric seal body, a primary elastomeric seal body, and a lower elastomeric seal body.
  • each of the upper and lower seal bodies ideally provide the backup elastomeric seal in the event the primary elastomeric seal were to leak, it is an important function of the upper seal body D22 and the lower seal body D26 to provide a desired biasing force against the respective rib D32 or D34.
  • These elastomeric seal bodies thus function as biasing members between the axially outermost rib and the adjacent inner rib to exert a force which prevents the inner rib from flexing beyond a predetermined stage.
  • the lower seal body D26 engages both the inner rib D34 and the outer rib D36, and exerts an upward biasing force to prevent rib D34 from moving downward past a position where it is perpendicular to the wall of the casing.
  • the lower seal body D26 exerts a downward biasing force which tends to increase the downward flexing to the outer rib D36 when the inner rib D34 flexes downward in response to high pressure above the packer element.
  • Elastomeric bodies which are configured other than shown herein may thus be used for this purpose.
  • plastic materials in various configurations may provide the desired biasing force, and ideally also a secondary resilient seal.
  • a wave spring or other metallic material biasing member may be used instead of or in cooperation with the elastomeric bodies D22 and D26.
  • each of the metal ribs of the packer element as disclosed herein are annular members with the outermost surface of each rib, when in the run-in position, being substantially the same radial spacing from a central axis of the tool for reliable sealing engagement with the surface to be sealed.
  • one or more of the ribs could include radial notches so that the rib would not form a complete annular metal-to-metal seal, which then could be provided by the elastomeric seal, although then the complete annular metal seal would not be obtained.
  • a plurality of axially spaced protrusions are provided for metal-to-metal sealing engagement between the packer element and the cone, and between the cone and the conveyance tubular. In other applications, a single annular protrusion may be sufficient to form the desired metal-to-metal sealing function.
  • the lower ball seat 246 (see Figure 1D ) is mounted within the running tool bore by shear pins 248 opposite the pressure chamber 256.
  • Sleeve 245 thus supports seat 246.
  • the lower end of the ball seat has reduced thinner section or neck 258.
  • one or more ports 260 formed in the running tool are positioned to be uncovered to permit fluid pressure in the running tool to be admitted to the pressure chamber 256 upon lowering of the seat 246.
  • the ball 240 when released from the upper seat 232 will land onto the second seat 246, whereby pressure within the running tool above the ball will move the seat 246 downward upon shearing the pins 248 to open the ports 260 leading to the pressure chamber 256.
  • the ball 240 may thus pass through the first seat 232 for seating on the reduced diameter 258 of the second seat 246 so that additional pressure may be supplied through the ports 260 for raising the outer piston sleeve 252.
  • the lower end of the running tool mandrel 132 extends downwardly below the slip assembly and has an enlarged body 145 (see Figure 11 ) adapted to reciprocate within the liner 146.
  • This enlarged body 145 has an upwardly facing shoulder 147 which may be raised into engagement with a downwardly facing shoulder to permit the running tool to be raised out of the set liner hanger, as will be described.
  • the inner pipe is a liner having an upper end installed within an outer casing by a column of cement pumped out the lower end of the liner into the annulus between it and the outer casing.
  • a ball is dropped onto a seat in the bore of the liner to permit circulating fluid to be directed into a portion thereof for hydraulically actuating a part in the system external to the liner bore, and an opening on which the ball is seated may be circumferentially yieldable, upon application of higher circulating pressure, to cause the ball to pass therethrough and out the lower end of the liner.
  • the ball may then be followed by a pump down plug to force the cement downwardly through the lower end of the liner and into the annulus between it and the outer casing.
  • the ball is relatively large, and, in any case larger than the bore of the liner wiper plugs (LWP) into which the pump down plugs (PDP) are to be installed.
  • LWP liner wiper plugs
  • PDP pump down plugs
  • the bore through the wiper plug is as small as possible, the inner diameter of the liner to be cemented in the outer hanger is necessarily enlarged to accommodate the wiper plugs which are carried about it. Consequently, it is the object of this description to provide apparatus for such a system in which the balls may be substantially larger than the pump down plugs, and thus larger than the bore through the wiper plugs in which the pump down plugs are to be landed.
  • apparatus which includes the previously described diverter 280 comprising a tubular member such as a sub having an upper end connected to a well pipe for lowering into a casing in the well to permit it to be cemented therein, and having a bore with a relatively large diameter upper portion and a relatively smaller diameter lower portion.
  • the larger portion enables one or more balls to be lowered therethrough, but the LWP in the smaller diameter portion prevents passage of the balls while permitting passage of the pump down plugs into the liner wiper plug.
  • a sub installed beneath the larger portion has a pocket to one side of its bore into which the ball, or at least a portion of it, diverted to thereby permit the pump down plug to pass between the ball and the side of the sub opposite the pocket, whereby the pump down plug may continue downwardly to enter the liner wiper plug.
  • the sub also includes a ramp extending across the bore of the sub and slanting downwardly toward the pocket so that, when the ball is dropped, it will land on the ramp and thus be guided into the slot. More particularly, the ramp has a U-shaped slot which is too narrow to pass a ball but is wide enough to pass a plug down between its closed end and the inner side of the diverted ball.
  • each of Figs. E1, E2 and E4 shows, in vertical cross section, a tubular member E10 suspended within a liner L installed within an outer casing C within a wellbore, its purpose being to circulate cement downwardly through the lower portion of the tubular member and into the annulus between the liner and the casing to cement the liner within the casing.
  • a liner wiper plug LWP is suspended from the tubular member with a pump down plug is installed therein.
  • the ball diverter BD comprises a sub which is installed between the upper and lower portions of the tubular member, and has a pocket P formed in side of the sub to receive a portion of a ball B adapted to pass downwardly through the tubular member.
  • a ramp R mounted on the sub has an upper face which is slanted downwardly from its upper end to its lower end to terminate opposite the pocket P.
  • a slot S in the ramp is narrower than the ball, so that when the ball is dropped through the running tool and into the upper end of the tubular member of the cementing tool, it will be guided into the pocket.
  • the opening between the inner end of the slot permits the lips of the pump down plug to flex inwardly so that the pump down plug is free to continue downwardly to a seated position in the liner wiper plug LWP, as shown in Fig. E4. That is, following dropping of the ball into the pocket, the pump down plug will, under the influence of downwardly directed circulating fluid, pass between the ball and closed end of the slot in the ramp. The pump down plug continues to be lowered until it lands in the liner wiper plug, as shown in Fig. E4, thus closing the lower end of the bore through the tubular member, all in a matter well known in the art.
  • Figure 2-8 illustrate movement of components of the tool 120 in the process of setting the liner.
  • fluids are circulated through the well bore "bottoms up".
  • the ball 240 is dropped from handling equipment at the surface and allowed either to free fall or be pumped at a desired rate onto the upper seat 232.
  • pins 222 between the seat and the liner hanger setting assembly are sheared to permit the ball and seat to move downwardly to a position uncovering ports 242 in the body of the slip setting assembly 140.
  • the further application of fluid pressure will cause the surrounding piston sleeve 220 to travel upwardly.
  • the tie back receptacle 130, the actuator slip slat 149 and slips 142 are pulled upward until the circumferentially spaced slips engage with the casing C.
  • the piston sleeve 220 of the slip setting assembly 140 surrounding the running tool mandrel 132 has been moved upwardly by the increase in pressure above the ball 240.
  • the piston sleeve 220 is moved upwardly until the upper end 312 of the piston sleeve 220 engages and releases the split lock ring 244. This enables the tie back receptacle 130 to continue to be moved upwardly.
  • the fluid pressure can be reapplied to the seated ball 240 to a higher predetermined level, so that the ball may be pumped to the lower seat 246 in the liner hanger releasing assembly 250.
  • a predetermined pressure may be applied to move the ball seat 246 and sleeve 245 downward to uncover the ports 260 in the liner hanger releasing assembly.
  • Higherfluid pressure may then be applied to cause the piston sleeve 252 to move upwardly, thereby allowing the liner hanger releasing ring 264 to collapse within the reduced diameter lower end 268 of the sleeve 252, thereby disengaging the running tool from the liner hanger.
  • the hydraulic release is not operable to move the ring 264 to disengage the running tool, the operator may resort to a mechanical release mode. The function of the ball in releasing the running tool from the set liner hanger is discussed below.
  • the further increase in pressure on the ball 240 and the lower seat 246 will release the ball from the lower seat so that circulation through the running string may continue while the ball 240 is pumped downwardly into the ball diverter 280. Fluids may then be circulated through the tool awaiting cement displacement. The cement and the displacement fluid are then injected into the running tool and pumped downwardly. When the cement has been pumped, the pump down plug which seals with the drill pipe is released from the surface handling equipment to land on a seat in the liner wiper plug, thereby forming a barrier between the previously displaced cement and the displacement fluid. A calculated amount of displacement fluid is required to pump the drill pipe plug down to the lower liner wiper plug.
  • the pump-down plug 182 (see Figure 5A ) thus follows the cement into the liner wiper plug 180.
  • the pump rate may be lowered so as to reduce the risk of malfunction between the latching and sealing of the lower wiper plug and the pump-down plug. This allows observation of the pump pressure increase when the pump-down plug 182 has landed in the lower wiper plug 180, as shown in Figure 5A .
  • the drill string may be pressured to the predetermined level to shear the pins 186 (see Figure 5A ) connecting the plug set to the running tool.
  • displacement fluids move the plug set down the liner 146 to the landing collar 370.
  • the plug set thus forms a barrier between the cement and the displacement fluid, and keeps the displacement fluid from contaminating the cement fluids.
  • a calculated amount of displacement fluid may be used to force the cement to desired height in the annulus between the liner and the casing.
  • conventional liner hanger running tools include a plug holder sub adapted to support a liner wiper plug on the running tool during a cementing operation.
  • the plug holder sub is conventionally latched to the running string, and the liner wiper plug is attached to the plug holder sub by a shear connection.
  • shear connections frequently are prematurely weakened or are sheared either by running tool manipulation or by the momentum of the pump down plug landing and seating on the liner wiper plug.
  • Some manufacturers have included a plug holder sub that has a latching lug and a shifting sleeve. The plug cannot be released until the pump down plug shifts the sleeve to allow the latching lugs to relax and thereby allows the plug set to separate from the running tool.
  • U.S. Patents 4,624,312 and 4,934,452 disclose plug holder subs which use a collet instead of a latching lug
  • U.S. Patent 5,036,922 discloses a running tool which employs a piston that is shifted in order for the plug set to be released.
  • the plug holder sub may be used for positioning a wiper plug which may be released from a liner hanger running tool or the end of a tubular string during a cementing operation.
  • the plug holder sub may be releasably positioned on the lower end of the liner hanger running tool, and is sized to pass a pump down plug, which lands in the liner wiper plug supported on the running tool by the plug holder sub.
  • the liner wiper plug is connected to the plug holder sub in a manner which prevents premature release of the plug set from the running tool, either upon manipulation of the running tool or due to the hammering effect of the pump down plug entering and latching into the liner wiper plug.
  • the piston that unlocks the plug set from the running tool acts on a fluid filled chamber which is vented to the annulus through an orifice.
  • a fluid filled chamber which is vented to the annulus through an orifice.
  • increased fluid pressure acts on the piston.
  • the type and volume of fluid vented, as well as the size of the orifice, determine the time it takes to move the piston to a plug release position. This time is important to allow the operator to determine the correct displacement of cement volumes for cementing the liner in the well.
  • the plug holder sub allows the running tool to be manipulated without any detrimental effects on the liner wiper plug.
  • the pump down plug may be pumped at any desired speed to the liner wiper plug and sealed and latched. The hammering effect of landing the pump down plug on the liner wiper plug will not prematurely release the plug set.
  • the operator may increase pressure to the running tool, thereby confirming to the operator that the plug has been seated in the liner wiper plug.
  • the operator may calculate the exact amount of displacement fluids it will take to cement the liner in the well.
  • the fluid pressure may then be increased, causing the piston to start to move to the plug release position.
  • the pump down plug and the liner wiper plug as a set will thus be released after a predetermined amount of time, which again is important to the operator being able to determine the correct displacement volumes for cementing the liner in the well.
  • the time it takes for high pressure to expel fluid through a metering jet is monitored to increase the reliability of properly releasing the liner wiper plug during the cementing operation.
  • a C-shaped retainer member may be used for attaching the liner wiper plug to a tubular body, wherein movement of a piston to a release position releases the C-shaped retainer to release the liner wiper plug.
  • the C-shaped ring may have threads or other internal gripping members for gripping engagement with the liner wiper plug.
  • a metering jet may also have external threads for threaded engagement with the tubular body.
  • Figure 1 depicts a plug holder sub F110 for supporting a conventional liner wiper plug.
  • the sub f110 includes the body f112 secured to the lower end of the running tool mandrel. Before the running tool and liner is lowered in the well, the liner wiper plug engages locking ring F114, which is supported between body F112 and the lower body F116 by piston F134.
  • Locking ring F114 includes grooves or threads F115 or other suitable members for grippingly engaging the liner wiper plug.
  • Seal F120 on the lower body F116 seals the plug holder sub to the liner wiper plug. Threads F128 connect the body F112 to lower body F116, and seal F122 seals between these connected bodies.
  • the body F112 includes a passageway F128 which is open to the annulus about the running tool.
  • An orifice jet F130 with a relatively sized orifice is positioned along this port, and preferably includes threads for engagement with threaded port F126.
  • Fluid containing chamber F132 is pressurized by the piston F134, which includes an OD seal F136 and an ID seal F138.
  • the left side view of Figure F1 shows a pin F131 sealing off a weep port to the chamber F132.
  • the pin F131 has a small port therein for slowly releasing pressurized fluid to the annulus.
  • the pin F131 may be secured within the weep port by a swaging operation, and is another form of a metering jet.
  • the right side illustrates a jet F130 for threading to the body F112.
  • a significant advantage of the plug holder sub is that the increase in fluid pressure is not the primary factor that determines the release of the plug set.
  • the rate at which the piston moves up to expel fluid from the chamber is primarily a function of a particular jet size and the type of fluid in the chamber. Accordingly, the operator will see an increase in pressure when the pump down plug is landed on the liner wiper plug, and will then know, within selected limits, that a predetermined amount of time should elapse from that increase in pressure until the plug set is released.
  • Plugs are conventionally run in a well in pairs, and the plug holder sub as shown in Figure F1 is suited for supporting one pair of liner wiper plugs.
  • one pair of plugs are preferably used before the cement fluid, and another set of wiper plugs are used after the cement fluid and before the displacing fluid.
  • each of the plug sets may be separately released in response to an increase in fluid pressure, which moves a respective piston to expel fluid from the chamber and thereby release the plug set.
  • One piston responsive to a low pressure fluid could thus be provided on the support sub, with that piston releasing the first plug set.
  • a second piston may move in response to fluid pressure to release the second plug set.
  • Each piston may force fluid through a selective orifice in a jet.
  • the second piston and/or both first and second piston may be shear pinned so that no movement occurs until a selected pressure level is obtained.
  • the first plug set alternatively could isolate the port for the second plug set so pressure could not act on the second plug set till the first plug set was released.
  • Figure F2 depicts the piston F134 in its retaining position, with the C-shaped retaining member F114 held radially inward so that its threads engage the mating threads F152 on the liner wiper plug F154.
  • the through passageway in liner wiper plug F154 is provided with a seat F156 for sealing with a conventional pump down plug, as discussed above.
  • the liner wiper plug F154 conventionally includes at least one and preferably two cup shaped elastomeric sealing members F158 on an exterior thereof so that high fluid pressure behind the liner wiper plug forces the liner wipers outward into sealing engagement with the liner.
  • An annular body F159 with o-rings F160 and latch ring F161 may be provided for sealing and latching the plug set with the landing collar.
  • the spacer and cement fluids may be mixed while circulating fluids for cement displacement.
  • the pump down plug When the cement has been pumped, the pump down plug may be released from the surface, forming a barrier between the previously displaced cement and the displacement fluid. A calculated amount of displacement fluid may thus be used to pump the pump down plug to the liner wiper plug.
  • fluid pressure may be reduced, e. g. to about 3.447 MPA (500 psi), and this pressure will increase when the pump down plug lands in the liner wiper plug, as discussed above.
  • the work string can be pressured up and after a selected period of time, the liner wiper plug and the pump down plug will be released from the plug holder sub. Increased fluid pressure thus moves a piston to release a lock ring, which releases the liner wiper plug from the plug holder sub.
  • the piston within the plug holder sub preferably acts on a fluid with a known viscosity at the temperature of the plug holder sub. Fluid flow through a predetermined size orifice will take a predetermined period of time to release the liner wiper plug. This time may be used by the operator to positively calculate displacement fluid volumes. A calculated amount of displacement fluid will thus force the cement to the desired height in the between the liner and the casing. Fluid will thus be pumped until the liner wiper plug and the pump down plug set latches into the landing collar, at which time pressure may be increased to, e. g. 6.895 MPa (1000 psi), over circulating pressure to complete latching of plugs and check that the seals between the plugs and the landing collar are holding. Pressure may then be bleed off and checked for bleed back to ensure that the float equipment is holding pressure.
  • metering jets may be used for selectively metering fluid from the chamber
  • Significant restrictions can be formed within the passageway F128 to effectively constitute a metering jet.
  • Fluid in the chamber F132 will be at a known viscosity for the downhole conditions, and with a selectively size metering jet the operator will know with reasonable accuracy the time it will take for the piston F134 to move from the retaining position to the release position.
  • retainer members may be used for interconnecting the tubular body F116 with the liner wiper plug.
  • a preferred retainer member has a C-shaped configuration with internal grooves or teeth for attaching to the liner wiper plug. The internal surface of the piston F134 thus prevents the retainer member from moving to the released position until the piston moves axially to its release position, as shown on the right side of Figure F1.
  • the liner wiper plug may be used at the lower end of the liner hanger running tool.
  • the plug holder sub may be used more generally at the lower end of any conveyance tubular, such as conveyance tubular F140 as generally shown in Figure F1.
  • the conveyance tubular F140 may thus be used to both transmit fluid pressure to the interior of the plug holder sub, and also to position the plug holder sub at a selected location within the well.
  • the plug holder sub may thus be used at the lower end of various types of tools, including a liner hanger running tool, or at the lower end of the tubular string used in a cementing operation, in order to reliably release the wiper plug from the plug holder sub during the cementing operation.
  • the wiper plug once released may seal with the liner or with another downhole tubular.
  • a pump down plug F182 as shown in Figure F5A may include upwardly facing cups 183 for cleaning the drill string, so that increased pressure in the running string when the plug 182 seals with the liner wiper plug 120 releases both plugs (the set) from the lower end of the liner hanger.
  • the liner wiper plug 180 has similar cups 181, and lands on the collar 186 to be sealingly locked in place and close off the lower end of the casing.
  • the released running tool 120 may be picked up until the packer setting assembly 380 (see Figure 1C ) is removed from the top of the tie back receptacle130, whereby the spring pressed lugs 328 are raised to a position above the top of the tie back receptacle, at which time they expand outwardly.
  • weight can be slacked off by engaging the lugs 328 with the top of the tie back receptacle to cause the packer element 150 to begin its downward sealing sequence.
  • This weight also activates a sealing ring 384 between the packer setting assembly 380 and the tie back receptacle to aid in further setting the packer element with annulus pressure assist.
  • rams on a BOP at the surface may be closed onto the drill pipe to form a pressure vessel between the rams and the expanded packer.
  • the cross sectional area between the casing and the drill pipe is known and the load required to fully set the packer element 150 is known, so that the operator may apply pre-determined fluid pressure to the annulus to cause the tie back receptacle to move down applying a predetermined additional axial load to the packer element.
  • the mandrel 132 of the released running tool 120 may then be raised to raise the cementing bushing 160 to cause the lugs 392 on the bushing to move in and unlock from the liner hanger 110.
  • the operator may circulate fluid through the running tool to pump any excess cement to the surface. Circulation effectively reduces the amount of cement that will need to be drilled out before reentering the top of the liner, and enables the operator to check for fluid flow and/or fluid loss.
  • FIG 8A shows the released running tool 120 raised from the liner.
  • the operator pulls the running tool out of the hole. Once the tool reaches the surface, the operator may check for damage to the running tool, wash fluids off the tool, and flush the tool I.D, before returning the tool to the shop.
  • Figure 9C also shows what remains in the casing C, namely the set packer 150 and set slips 142.
  • the liner hanger releasing assembly 250 as shown in Figure 1D and 1E may be replaced with the releasing assembly shown in Figures 10 and 11 .
  • the liner hanger releasing assembly as shown in Figures 10 and 11 may still be disposed beneath the packer setting assembly 380 as described above or the packer setting assembly 52 described below, and includes an inner piston sleeve 340 sealably disposed about the running tool mandrel 132, and another piston sleeve 342 disposed about the inner piston sleeve.
  • the piston sleeve 340 forms a pressure chamber similar to the sleeve 252 shown in Figure 1D for releasing the liner hanger.
  • the liner hanger releasing assembly as shown in Figures 10 and 11 releases the lock ring 326 which is externally grooved for engaging the grooved inner diameter of the liner hanger 110 of the upper end of the liner 146.
  • the lock ring 326 is held in locking position by the enlarged upper outer diameter of the piston sleeve 340 which, as shown in the Figure 10A , is in its lower position.
  • the clutch 316 as shown in Figure 1D is pressed downwardly by springs 318 to engage the liner hanger 110, which is threaded for engagement with right-handed threads 324 on the running tool mandrel 132.
  • the nut 322 carries lugs 326 which are pressed outwardly by springs 327 into vertical slots formed in the liner hanger 110 to prevent relative rotation between the mandrel 132 and the liner hanger.
  • the lock ring 326 Upon raising of the inner piston 340, the lock ring 326 is free to contract inwardly about the lower reduced outer diameter 268 of the piston sleeve 340 and thereby free the running tool to be raised after setting of the slips but prior to setting of the packer, thus permitting circulation of cement downwardly through the tool and upwardly within the annulus between the tool and casing.
  • the operator may rotate the tool to the right so that with the right-hand threads between the threaded nut 322 and the running tool mandrel 132 lower the nut on the mandrel 132, as shown in Figure 11C .
  • the running tool may be picked up the distance the nut 322 moved down, thereby releasing the lock ring 326 and thus disengaging the running tool from the liner hanger.
  • the locking ring 326 has collapsed on the reduced O.D. 341 of the inner piston 340.
  • the running tool 120 may thus be lowered to engage its clutch with that of the liner hanger.
  • the clutch 316 is pressed downwardly by the spring 318, so that the lower teeth 317 (see Figure 8C ) at the upper end of liner hanger 110 are engaged with similar teeth at the lower end of clutch 316 to maintain rotary engagement between the running tool and the liner hanger.
  • the upper end 332 of the clutch 316 may be splined to the O.D. of the running tool mandrel 132 so as to permit relative axial movement with respect thereto under the urging of the spring 318.
  • Figures 11A-C accordingly illustrates a liner hanger release assembly which enables the operator to release mechanically by right-hand rotation, in the event he is unable to release hydraulically.
  • the running tool mandrel 132 is surrounded by the pair of inner and outer sleeve pistons 340 and 342.
  • the inner piston 340 has a shoulder 272 for engaging shoulder 274 of the running tool mandrel 132.
  • Intermediate seal rings above and below ports 260 are uncovered upon lowering of the ball 240 on the ball seat 246 to the lower position, as shown in Figure 11C .
  • Outer sleeve piston 342 surrounds the inner piston 340 and, while in the position as shown in Figure 11A , is supported on the inner piston 340 by engaging an outer shoulder 348 on the inner piston with the generally opposite shoulder on the outer piston 342. More particularly, this shoulder 348 is generally aligned with the port 262 in the inner sleeve 340 and intermediate the upper and lower seal rings 346 between the inner and outer sleeves.
  • a ring 350 forms a stop shoulder at the upper end of the inner piston 340 to limit upward movement of the outer piston 342 with respect to the inner piston.
  • the inner piston 340 is stopped in a upward direction by a downwardly facing shoulder 344 on the running tool.
  • the lock ring 326 is held in a locked position between an enlarged diameter portion of the inner piston 340 and the inner diameter of the liner hanger 110.
  • the nut 322 as shown in Figure 11B is positioned below reduced diameter portion 341 of the inner piston 340, with the internal threads 352 engaged with the threads 324 about the running tool mandrel 132.
  • the threaded nut 322 is prevented from rotation relative to the liner hanger assembly by spring pressed lugs 326 in vertical slots in the liner hanger 110. If the running tool is not hydraulically released by opening of the ports 260 to raise the inner piston 340 and release the lock ring 326, the running tool may be mechanically released by a second hydraulic release operation, as discussed above.
  • a preferred embodiment of a packoff bushing 10 is depicted for sealing between a radially outward liner running adapter of the liner hanger and a radially inward running tool mandrel.
  • the packoff bushing 10 is axially captured on the running tool mandrel or tubular body 12.
  • the compact design of the packoff bushing and its limited axial movement on the running tool body 12 facilitates re-stabbing the packoff bushing into the liner hanger, as explained below.
  • the upper end 14 of body 12 includes threads 16 and seal 18 for sealed engagement with the lower end of the liner hanger releasing assembly of the running tool.
  • the lower end 20 of the body 12 includes similar threads 22 for interconnection with a sleeve which extends downward to a ball diverter.
  • the body or sub 12 is thus part of the mandrel of the running tool, and a slick joint is not required.
  • an internal seal 24 and an external seal 28 are provided on the locking piston 26.
  • Seal 24 which may be a V-packing seal, thus seals between the locking piston 26 and the body 12 and seal 28, which may also be a V-packing seal, seals between the piston 26 and the running adapter of the liner hanger 48.
  • Retainer 30 is threadably connected to the piston 26 for holding the seals 24 and 28 in place.
  • Retaining member 32 is threadably connected to top cap 34 so that the one-piece C-ring 36 is positioned between the top cap 34 and the piston 26.
  • Retaining member 32 includes a shoulder 38 for engaging shoulder 40 on the body 12.
  • the lower flange portion 33 of the retaining member 32 and the upper end 27 of the piston 26 are each splined, so that the spline fingers are circumferentially interlaced about the packoff bushing. Flange portions 33 thus capture the lock ring 36 axially when the piston 26 is forced upward.
  • the lock ring 36 is a unitary C-shaped ring having a circumference in excess of 200°, and normally less than about 350°, and is intended for engaging and axially locking to the liner hanger.
  • a preferred lock ring 36 may have a circumference of from 300° to 340 °, thereby providing substantially full circumferential contact with the liner hanger while allowing for radial expansion and contraction of the lock ring.
  • the relaxed diameter of the lock ring 36 is substantially as shown in Figure 12A .
  • the packing retainer 30 is normally spaced axially a slight distance above the stop surface 44 on the body 12 for locking and unlocking the bushing.
  • the load shoulder 44 on the top cap 34 provides a means for transmitting forces downward to the liner hanger during the running-in and cementing operation. Shoulder 44 would thus engage shoulder 45 on the running adapter 48 of the liner hanger when a set down weight is applied to the liner hanger so that the liner hanger is "hung off”.
  • a bearing 46 may be provided to allow the running tool body 12 to rotate relative to a set packoff bushing during an emergency releasing operation. The packoff bushing may thus be reliably maintained in the locked position, with the piston 26 up and the C-ring 36 expanded, as shown in Figure 12A , when fluid pressure is applied to the packoff bushing.
  • an annular groove 47 in the running adapter 48 of the liner hanger receives the lock ring 36 to securely lock the packoff bushing to the liner hanger when fluid pressure is applied to the piston 26. Without fluid pressure, the C-ring 36 thus retracts radially inward toward the retaining member 32 when the lock ring 36 engages the top surface of the groove 47 as the bushing is pulled out of the liner hanger.
  • the C-ring 36 When the bushing is re-stabbed into the liner hanger, the C-ring 36 is retracted radially inward, e.g., when the lock ring 36 engages load shoulder 45 on the liner hanger. During upward movement of the running tool relative to the liner hanger, the C-ring 36 thus may move radially inward when engaged, and may also move radially inward when the packoff bushing is re-stabbed back into the liner hanger.
  • the C-ring design significantly increases reliability of the tool and reduces both the complexity and the costs of prior art tools which use multiple lugs or dogs.
  • Figure 12B illustrates the splined members 27 of the piston 26 and the splined members 33 of the retaining member 32, and the C shape of the lock ring 36.
  • External slots 37 circumferentially spaced about the C-ring 36 facilitate expansion and contraction of the C-ring.
  • the liner hanger running tool with the packoff bushing disclosed herein may be used on various types of liner hanger operations.
  • the packoff bushing may be used with or without a packer setting assembly and a packer element for sealing between the liner hanger and the casing.
  • the packoff bushing as disclosed herein is positioned axially between the liner hanger releasing assembly and the slip setting assembly, the packoff bushing could be provided at other locations in the liner hanger running tool.
  • Figure 13 illustrates a preferred embodiment of a packer setting assembly 52, which will allow activation and packoff of the liner top packer.
  • the packer setting assembly is provided on the sleeve shaped body or sub 54 which is part of the mandrel of the running tool, and includes lower threads 55 for engagement with a lower sub of the mandrel.
  • the packer setting assembly 52 includes a housing 56 carrying a V packing seal 58. Other conventional elastomeric seals may replace the V packing 58.
  • a flow slot 53 in the body 54 ensures fluid communication with the splines or ribs 57 on the body 54, so that the housing 56 moves axially along these splines without trapping fluid pressure.
  • Packing retainer 60 and snap ring 62 hold the V packing in place.
  • a packer setting or force transmitting C-ring 64 is positioned on the housing 56, and includes an internal sleeve portion 66.
  • a C-shaped trip ring or lockout ring 70 is positioned between the lock sleeve 68 and retainer cap 72.
  • Lock sleeve 68 engages the sleeve portion 66 to retain the C-ring 64 in the compressed position as shown in Figure 13 , so that when released the C-ring 64 will snap out.
  • a housing extension 74 is threadably secured to housing 56, and bearing 80 allows the body 54 to rotate relative to housing 56.
  • Bearing sleeve 78 is connected to the sub 54 by shear member 82.
  • Sleeve portion 84 of the bearing sleeve 78 engages the body 54 as shown in Figure 13 , although sealing between the body 54 and the bearing sleeve 78 is not required. Packing members 86 on the body 54 are discussed below.
  • trip ring 70 which was positioned within the polished bore receptacle, will snap to a radially outward position, as shown in Figure 13 , due to the natural biasing of the C-shaped trip ring.
  • the trip ring 70 will engage the top of the polished bore receptacle 90 as shown in Figure 13 , and the packer setting C-ring 64 is positioned within the polished bore receptacle.
  • housing 56 When set down force is applied, housing 56 will move downward relative to lock sleeve 68, and the trip ring 70 will move radially inward due to camming action.
  • the entire packer setting assembly may thus be lowered to bottom out on a lower portion of the running adapter prior to initiating the cementing operation.
  • the radially outward biasing force of the C-ring 64 will cause the C-ring to engage the top of the polished bore receptacle of the liner hanger. More particularly, the shoulder 65 will engage the top of the polished bore receptacle 90, since the natural or released diameter of the C-ring 64 approximates the outer diameter of the receptacle 90.
  • the flat surface 65 on the C-ring 64 thus engages the top surface of the tie back receptacle 90.
  • the tapered surface 73 at the lower end of retainer cap 72 engages the mating tapered surface 63 of the upper end of C-ring 64, and the setting weight thus results in a radially outward force applied to the C-ring 64 to effectively lock the C-ring in the weight-transfer position, so that the C-ring will not prematurely snap radially inward before the packer is set.
  • the packer setting assembly 52 has high reliability since a substantial downward set weight may be transmitted through the C-ring 64 to the tie back receptacle, and since the mechanical setting pressure is assisted by fluid pressure between the ID of the casing and the OD of the running tool or drill pipe.
  • the radially inward surface of projection 88 on the housing 56 is then supported on the larger diameter surface 90 of the sub 54, with packing members 86 sealing with the housing 56.
  • a collar or similar stop on the body 54 engages the top of bearing sleeve 78 to limit downward travel of the mandrel. Seal 58 remains sealed to the tie back receptacle.
  • the increase in pressure in the annulus between the casing and the running tool allows the housing 56 to act as a piston which is forced downward in response to the annulus pressure, thereby providing increased downward force to reliably set the liner hanger packer when the packer is forced radially outward as it is pushed down the packer setting cone.
  • the setting tool is conventionally attached to the lower end of a work string, typically a drill pipe, and is connected to a liner hanger, which is attached to the top of the liner.
  • the work string lowers the liner into the borehole into a position above the lower end of the previously set casing or liner. With the liner at a desired depth, well bore fluids are circulated "bottoms up" to clean the hole.
  • a setting ball may initially be dropped from a cementing manifold at the surface. The ball may either free fall or may be pumped to the liner hanger slip setting assembly, where the ball will rest on the expandable ball seat.
  • Fluid pressure may then be increased to a selected value, e. g. 3.447 MPa (500 psi), which exerts a force on the shear screws acting between the ball seat and the mandrel of the slip setting assembly.
  • a selected value e. g. 3.447 MPa (500 psi)
  • the screws will shear to release the ball and seat to a position that uncovers hydraulic ports in the mandrel.
  • Continued pumping of fluid will then force the ball through the seat, and allow the ball to be pumped to the second ball seat within the releasing tool.
  • Fluid pressure is then increased to shear screws between the piston and the mandrel of the liner hanger setting assembly.
  • the piston which was exposed to pressure within the running string when the ball was first released, is responsive to fluid pressure and travels upward, thereby forcing the slips to release and come into contact with the casing.
  • the liner load may then be slacked off onto the set slips. Once the slips are supporting the weight of the liner, the liner off.
  • set down weight With the liner load slacked off onto the hanger slips, additional slack off or "set down weight” may be applied to the hanger to check for any hanger movement.
  • the set down weight will be transmitted through the running tool to the liner hanger, which is supported by the liner hanger slips.
  • This set down weight may, for example, be transmitted through the running tool mandrel to the packoff bushing and then from the load shoulder on the packoff bushing to the liner hanger.
  • a ball may then be landed, and the ball seat moved to expose fluid ports. Pressure may then be increased to a selected value, e. g. 8.274 MPa (1200 psi), which is transmitted through ports in the mandrel of the liner hanger releasing assembly.
  • the operator may continue to pressure the drill sting to the maximum allowable pressure checking for release in small pressure increments up to the shear pressure of the secondary piston. If the primary piston does not release the running tool from the liner hanger, continued pressure will shear the secondary piston from the primary piston and the secondary piston will move axially up to disengage the clutch of the running tool from the clutch on the liner hanger. With the clutch disengaged, the running tool may be rotated 5-6 turns to the right to disengage the running tool from the liner hanger.
  • the operator at this stage may pick up the running string and note the loss of liner weight on a rig weight indicator, thereby indicating that the running tool is released from the liner hanger. This pick up operation will also disengage the packoff bushing from the liner hanger running adapter or tie back receptacle.
  • the packoff bushing is designed to be re-stabbable so that the operator may pull the running tool and the packoff bushing upward as desired to check that the running tool is released from the liner hanger. After it is confirmed that the running tool is released, the packoff bushing will be re- stabbed when the running tool is slacked back off into the liner hanger. When there is pressure below the packoff bushing, the bushing is securely locked to the liner hanger.
  • a selected fluid pressure e. g. 17.24 MPa (2500 psi) may then be used to shear the secondary piston from the clutch to allow the clutch to re-engage the liner hanger.
  • pressure may then be applied to the ball and seat.
  • a predetermined pressure e. g. 20.68 MPa (3000 psi)
  • the ball will pass through the port isolation ball seat; expanding the diameter of the seat.
  • the ball is forced through the seat to permanently deforming the ball seat.
  • the drop in pressure and re-gaining fluid circulation will then indicate that the ball has successfully passed through the ball seat.
  • the ball is then allowed to free fall or be pumped to the ball diverter.
  • the spacer and cement fluids may be mixed while circulating fluids for cement displacement.
  • the pump down plug When the cement has been pumped, the pump down plug may be released from the surface, forming a barrier between the previously displaced cement and the displacement fluid. A calculated amount of displacement fluid may thus be used to pump the pump down plug to the liner wiper plug.
  • fluid pressure may be reduced, e. g. to about 3.447 MPa (500 psi), and this pressure will increase when the pump down plug latches in the liner wiper plug.
  • the work string can be pressured up and after a selected period of time, the liner wiper plug and the pump down plug will be released from the plug holder sub.
  • Increased fluid pressure thus moves a piston to release a ring, which releases the liner wiper plug from the plug holder sub.
  • the piston within the plug holder sub acts on a fluid with a known viscosity, and fluid flow through a predetermined size orifice will take a predetermined period of time to release the liner wiper plug. This time may be used by the operator to positively calculate displacement fluid volumes. A calculated amount of displacement fluid will thus force the cement to the desired height in the between the liner and the casing. Fluid will thus be pumped until the liner wiper plug and the pump down plug set latches into the landing collar, at which time pressure may be increased to, e. g.
  • the packer setting assembly incorporates an unlocking feature that allows the packer setting assembly to be pulled out of the liner hanger tie back receptacle one time without unlocking the packer setting ring.
  • the packer setting ring Upon re-stabbing the assembly into the tie back receptacle, the packer setting ring becomes armed and is ready to expand the second time the packer setting assembly is pulled out of the tie back receptacle. Accordingly, the running tool may be picked up until the packer setting assembly is removed from the tie back receptacle, which allows the trip ring to expand and engage the top of the tie back receptacle.
  • drill pipe weight may be slacked off on top of the tie back receptacle. This downward force through the packer setting assembly and to the tie back receptacle initiates the packer setting sequence. This action will shear screws and allow the setting load to be transmitted to the packing element. As a load increases, the packer element will expand in OD as it moves down the cone, thereby pushing the expanding packer element out into engagement with the casing.
  • the rig rams may be closed around the drill pipe, so that a pressure vessel is formed between the casing and the running tool and between the packer element and the seals of the ram at the surface. Knowing how much load is required to properly set the packer element, a known fluid pressure can be applied to the annulus to cause the tie back receptacle to move down, thereby applying a greater and known load to the packer element. A desired setting load to the packer element may thus be applied through a combination of set down weight and fluid pressure.
  • fluid may be circulated through the drill string to circulate any excess cement to the surface, thereby reducing the need for drill out.
  • the operator may pull the setting tool from the well. Once at the surface, the tool may be checked for damage and serviced.
  • the tools as discussed above function as an assembly for a specific application, i.e., for the running and releasing of the liner hanger, the cementing of the liner into the wellbore and the setting of the packer element.
  • a packer element could be run into a wellbore without a liner hanger slip mechanism and therefore the slip releasing assembly would not be required in the running tool.
  • Various combinations of the disclosed tools could be put together to run a variety of downhole tools.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Pipe Accessories (AREA)
  • Packaging Of Annular Or Rod-Shaped Articles, Wearing Apparel, Cassettes, Or The Like (AREA)

Claims (16)

  1. Un assemblage de garniture d'étanchéité (52) destiné à régler un élément de garniture d'étanchéité radiale, l'assemblage de garniture d'étanchéité appliquant une force sur l'élément d'étanchéité ou un cône de façon à déplacer l'élément d'étanchéité par rapport au cône, caractérisé en ce que l'assemblage de garniture d'étanchéité comprend :
    un anneau en C de transmission de force extensible radialement (64), l'anneau en C de transmission de force lorsqu'il est étendu agissant de façon à s'engager dans un manchon de réglage (90) de façon à appliquer un poids d'abaissement par le manchon de réglage de façon à régler l'élément de garniture d'étanchéité radiale.
  2. L'assemblage de garniture d'étanchéité (52) selon la Revendication 1, comprenant en outre :
    un mécanisme de verrouillage destiné à empêcher l'anneau en C de transmission de force (64) de se déplacer vers la position étendue.
  3. L'assemblage de garniture d'étanchéité (52) selon la Revendication 2, où le mécanisme de verrouillage comporte un anneau en C de verrouillage (70) destiné à s'étendre radialement de façon à s'engager dans une partie supérieure de la garniture (90) et ainsi libérer le mécanisme de verrouillage.
  4. L'assemblage de garniture d'étanchéité (52) selon la Revendication 2 ou 3, où le mécanisme de verrouillage passe d'une position étendue à une position rétractée du fait d'une surface de came sur un boîtier (68) de l'assemblage de garniture d'étanchéité, libérant ainsi l'anneau en C de transmission de force (64).
  5. L'assemblage de garniture d'étanchéité (52) selon la Revendication 1, comprenant en outre :
    un mécanisme de verrouillage destiné à permettre à l'anneau en C de transmission de force (64) d'être extrait de la partie supérieure d'une suspension de colonne perdue (90) une fois sans déplacer l'anneau en C de transmission de force (64) vers la position étendue, de sorte que la fois suivante, l'anneau en C de transmission de force (64) est déplacé à l'extérieur de la suspension de colonne perdue (90), l'anneau en C de transmission de force (64) s'étend vers sa position étendue pour s'engager dans la suspension de colonne perdue (90).
  6. L'assemblage de garniture d'étanchéité (52) selon l'une quelconque des Revendications précédentes, comprenant en outre :
    un boîtier de garniture d'étanchéité (56),
    un joint intérieur (86) destiné à obturer hermétiquement entre un mandrin d'étanchéité et le boîtier de garniture d'étanchéité, et
    un joint extérieur (58) destiné à obturer hermétiquement entre le manchon de réglage et le boîtier de garniture d'étanchéité, de sorte qu'une pression par fluide puisse être utilisés pour participer à l'application d'une force de réglage par le manchon de réglage jusqu'à l'élément d'étanchéité.
  7. L'assemblage de garniture d'étanchéité (52) selon l'une quelconque des Revendications précédentes, comprenant en outre :
    un boîtier de garniture d'étanchéité autour d'un mandrin, et
    un roulement (80) destiné à faciliter la rotation du mandrin par rapport au boîtier.
  8. L'assemblage de garniture d'étanchéité (52) selon l'une quelconque des Revendications précédentes, où l'élément de garniture d'étanchéité radiale comporte une base métallique radialement intérieure et un ou plusieurs corps d'étanchéité radialement extérieurs.
  9. L'assemblage de garniture d'étanchéité selon l'une quelconque des Revendications précédentes, où le manchon de réglage agit sur l'élément d'étanchéité d'une suspension de colonne perdue de façon à obturer hermétiquement entre la suspension de colonne perdue et une enveloppe.
  10. un procédé de réglage d'un élément de garniture d'étanchéité radiale (52) par l'application d'une force sur l'élément d'étanchéité ou un cône de façon à déplacer l'élément d'étanchéité par rapport au cône, caractérisé en ce que le procédé comprend :
    la fourniture d'un anneau en C de transmission de force extensible radialement (64),
    l'extension de l'anneau en C de transmission de force (64) de façon à s'engager dans un manchon de réglage (90), et
    l'application d'un poids d'abaissement par le manchon de réglage (90) de façon à régler l'élément de garniture d'étanchéité radiale.
  11. Le procédé selon la Revendication 10, comprenant en outre :
    la fourniture d'un mécanisme de verrouillage destiné à empêcher l'anneau en C de transmission de force (64) de se déplacer vers la position étendue, et
    l'engagement du mécanisme de verrouillage dans une partie supérieure de la suspension de colonne perdue afin de libérer l'anneau en C de transmission de force.
  12. Le procédé selon la Revendication 11, comprenant en outre :
    la fourniture d'un mécanisme de verrouillage d'anneau en C,
    le déplacement du mécanisme de verrouillage d'anneau en C d'une position étendue à une position rétractée par l'application d'un poids d'abaissement au mécanisme de verrouillage d'anneau en C du fait d'une surface de came sur un boîtier de l'assemblage de garniture d'étanchéité, libérant ainsi l'anneau en C de transmission de force (64).
  13. Le procédé selon l'une quelconque des Revendications 11 ou 12, où le mécanisme de verrouillage se déplace axialement de façon à libérer l'anneau en C de transmission de force.
  14. Le procédé selon l'une quelconque des Revendications 10 à 13, comprenant en outre l'opération consistant à :
    permettre à l'anneau en C de transmission de force (64) d'être extrait de la partie supérieure d'une suspension de colonne perdue une fois sans déplacer l'anneau en C de transmission de force (64) vers la position étendue, de sorte que la fois suivante l'anneau en C de transmission de force est déplacé à l'extérieur de la suspension de colonne perdue, l'anneau en C de transmission de force (64) s'étend vers sa position étendue pour s'engager dans la suspension de colonne perdue.
  15. Le procédé selon l'une quelconque des Revendications 10 à 14, comprenant en outre :
    la fourniture d'un boîtier de garniture d'étanchéité,
    la fourniture d'un joint intérieur destiné à obturer hermétiquement entre un mandrin d'étanchéité et le boîtier de garniture d'étanchéité, et
    la fourniture d'un joint extérieur destiné à obturer hermétiquement entre le manchon de réglage et le boîtier de garniture d'étanchéité, de sorte qu'une pression par fluide participe à l'application d'une force de réglage au manchon de réglage.
  16. Le procédé selon l'une quelconque des Revendications 10 à 15, où l'élément de garniture d'étanchéité radiale comporte une base métallique radialement intérieure et un ou plusieurs corps d'étanchéité radialement extérieurs.
EP06012130A 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé Expired - Lifetime EP1712732B1 (fr)

Applications Claiming Priority (12)

Application Number Priority Date Filing Date Title
US29204901P 2001-05-18 2001-05-18
US31657201P 2001-08-31 2001-08-31
US31645901P 2001-08-31 2001-08-31
US09/943,701 US6575238B1 (en) 2001-05-18 2001-08-31 Ball and plug dropping head
US09/943,854 US6655456B1 (en) 2001-05-18 2001-08-31 Liner hanger system
US09/981,487 US6712152B1 (en) 2000-08-31 2001-10-17 Downhole plug holder and method
US10/083,320 US6666276B1 (en) 2001-10-19 2001-10-19 Downhole radial set packer element
US10/004,588 US6739398B1 (en) 2001-05-18 2001-12-04 Liner hanger running tool and method
US10/004,945 US6681860B1 (en) 2001-05-18 2001-12-04 Downhole tool with port isolation
US10/136,992 US6698513B1 (en) 2001-05-18 2002-05-02 Apparatus for use in cementing an inner pipe within an outer pipe within a wellbore
US10/136,969 US6761221B1 (en) 2001-05-18 2002-05-02 Slip assembly for hanging an elongate member within a wellbore
EP02736875A EP1392953B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procede associe

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
EP02736875A Division EP1392953B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procede associe

Publications (2)

Publication Number Publication Date
EP1712732A1 EP1712732A1 (fr) 2006-10-18
EP1712732B1 true EP1712732B1 (fr) 2009-07-15

Family

ID=49582879

Family Applications (5)

Application Number Title Priority Date Filing Date
EP06012129A Expired - Lifetime EP1712731B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé
EP06012130A Expired - Lifetime EP1712732B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé
EP06012128A Expired - Lifetime EP1712730B1 (fr) 2001-05-18 2002-05-15 Dispositif pour déposer un bouchon ou une bille
EP06012127A Expired - Lifetime EP1712729B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé
EP08105836A Expired - Lifetime EP2020482B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé

Family Applications Before (1)

Application Number Title Priority Date Filing Date
EP06012129A Expired - Lifetime EP1712731B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé

Family Applications After (3)

Application Number Title Priority Date Filing Date
EP06012128A Expired - Lifetime EP1712730B1 (fr) 2001-05-18 2002-05-15 Dispositif pour déposer un bouchon ou une bille
EP06012127A Expired - Lifetime EP1712729B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé
EP08105836A Expired - Lifetime EP2020482B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé

Country Status (3)

Country Link
EP (5) EP1712731B1 (fr)
BR (1) BR122013000180B1 (fr)
DK (3) DK1712730T3 (fr)

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Also Published As

Publication number Publication date
EP1712729B1 (fr) 2011-07-20
EP1712731A1 (fr) 2006-10-18
EP1712729A2 (fr) 2006-10-18
EP1712730A2 (fr) 2006-10-18
EP2020482B1 (fr) 2012-09-26
EP2020482A3 (fr) 2011-04-27
DK2020482T3 (da) 2012-10-22
EP2020482A2 (fr) 2009-02-04
BR122013000180B1 (pt) 2016-07-19
EP1712730B1 (fr) 2010-12-15
EP1712729A3 (fr) 2006-12-27
EP1712730A3 (fr) 2006-12-27
EP1712731B1 (fr) 2009-09-02
EP1712732A1 (fr) 2006-10-18
DK1712729T3 (da) 2011-10-24
DK1712730T3 (da) 2011-01-24

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