EP1712731B1 - 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
EP1712731B1
EP1712731B1 EP06012129A EP06012129A EP1712731B1 EP 1712731 B1 EP1712731 B1 EP 1712731B1 EP 06012129 A EP06012129 A EP 06012129A EP 06012129 A EP06012129 A EP 06012129A EP 1712731 B1 EP1712731 B1 EP 1712731B1
Authority
EP
European Patent Office
Prior art keywords
port
tool
liner
liner hanger
plug
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
EP06012129A
Other languages
German (de)
English (en)
Other versions
EP1712731A1 (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 EP1712731A1 publication Critical patent/EP1712731A1/fr
Application granted granted Critical
Publication of EP1712731B1 publication Critical patent/EP1712731B1/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 surfaces 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 Typically, 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 and 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 wich 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 topically 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 seat the between the liner and the previously set casing or liner.
  • a packer setting toot is disclosed in EP-A-0985797 .
  • fluid such as drilling mud in the 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 allows time for the gas in the formation to migrate up the 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 too! 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.
  • release mechanisms which will reliably release the running tool from the set liner only when intended, particularly when retrieving is easily accomplished and premature disengagement of the running tool from the liner is highly unlikely.
  • 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 respectto 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 z slick joint determines the maximum length that the running tool should be picked up after release from the liner hanger.
  • the stick 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 seat 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 packoff of the liner top 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
  • Some prior art packer setting assemblers 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 concerting 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 retrievable hydraulically operated tool for running in a wellbore to perform a downhole tool activation
  • the tool comprising a running tool tubular body for suspending in the wellbore from a conveyance tubular, such that fluid may be circulated through a bore in the conveyance tubular and in the tubular body, the tubular body including a fluid inlet port from the bore in the tubular body, a fluid pressure responsive member In fluids communication with the fluid inlet port and moveable relative to the tubular body from an initial position to an activated position in response to fluid pressure within the tubular body, a port closure member moveable with respect to the tubular body from a port isolation position to an open port position, the port closure member in the port isolation position blocking fluid communication from the bore in the tubular body, and permitting fluid communication from the bore in the tubular body through the fluid inlet port when in the open port position, a seat supported on the port closure member, such that an increases in fluid pressure in the tabular bore when a plug lands
  • the port closure member may comprise a sleeve axially moveable within the bore of the tubular body.
  • the plug may be a ball.
  • the ball may land on the seat to substantially seal off the bore through the tubular body.
  • the port closure member may be retained in the port isolation position by a shear member.
  • the seat may permanently deform in response to increased fluid pressure to pass the plug through the seat.
  • the fluid pressure responsive member may include a piston moveable from the initial position to the activated position in response to fluid pressure.
  • the piston may move axially upward from the initial position to the actuated position in response to fluids pressure.
  • the retrievable tool axial movement of the piston to the activated position may cause one of (a) axial movement of a slip to set the liner hanger, (b) movement of a release mechanism to released the liner hanger from the running tool, and (c) relative movement between a cone and a seal to seal between the liner hanger and surrounding casing.
  • a method of hydraulically operating a tool for running in a well bore to perform a downhole-tool activation comprising suspending a running tool tubular body in the Well bore from a conveyance tubular, providing a fluid inlet port from a bore in the tubular body, providing a fluid pressure responsive member in fluid communication with the fluid inlet port and moveable relative to the tubular body from an initial position to an activated position in response to fluid pressure, providing a port closure, member moveable with respect to the tubular body from a port isolation position to an open port position, the port closure member in the port isolation position blocking fluid communication from the bore in the tubular body, and permitting fluid communication from the bore in the tubular through the fluid inlet port when in the open port position, supporting a seat on the port closure member, landing a plug on the seat to shift the port closure member from the port isolation position to the open port position in response to fluid pressure above the landed plug and, performing the downhole tool activation in response to movement of the fluid pressure
  • the fluid pressure responsive member may include a piston moveable from the initial position to the activated position in response to fluid pressure.
  • the piston may move axially upward from the initial position in response to fluids pressure.
  • the plug may be a ball which lands on the seat to substantially seal off the bore through the tubular body.
  • the method may further comprise retaining the port closure, member in the port isolation position by a shear member.
  • the seat may permanently deform in response to increased fluid pressure to pass the plug through the seat.
  • Movement of the fluid pressure responsive member may cause one of (a) axial movement of a slip to set the liner hanger, (b) movement of a release mechanism to release the liner hanger from the running tool, and (c) relative movement between a cone and a seal to seal between the liner hanger and surrounding casing.
  • the plug may be released after the downhole tool has been activated in response to movement of the fluids pressure responsive member to the activated piston.
  • 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 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 tabular ball seat 232 is supported at the lower end of sleeve 212.
  • the lower end of the ball seat has a neck portion 234 wich 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.
  • 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 1B 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 barextending 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 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 transmit this downward force through to the pusher sleeve 148 and the packer element 150.
  • a body lock ring 270 (see Figure 1F ) 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 convector. 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 lower ball seat 246 (see 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.
  • This in tum permits split ring 264 having outer teeth gripping the liner hanger 110 to move into position opposite a reduced diameter lower end 268 of the sleeve 252 and thus out of gripping engagement with the liner hanger, whereby the running tool is released from the liner hanger.
  • 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 invention 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.
  • Figure 2-8 illustrate movement of components of the tool 120 in the process of setting the liner.
  • 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 280 in the liner hanger releasing assembly.
  • Higher fluid 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 pump-down plug 182 (see Figure 5A ) thus follows the cement into the liner wiper plug 180. As the pump-down plug gets close to the running tool, 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, was 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.
  • a pump down plug 182 as shown in Figure 5A 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 cup 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 receptacle 130. 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 top 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 Upon checking for fluid flow and/or fluid loss, the operator putts 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 1 D 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 11 C .
  • 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 ore 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 shoulders 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 11 B 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 pack off 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 include threads 16 and seal 18 for seated 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 maybe 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 look 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.
  • Figure 12B illustrates the splined members 27 of the piston 26 and the splined members 33 off 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 fluids 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 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 hall 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 own 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 finer hanger running adapter or tie back receptacle.
  • the packoff bushing is designed to be restabbable 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 then running tool is slacked back off into the liner hanger. When there is pressure below the packoff bushing, the bushing is securely lacked 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 predetermine size orifice will take a predetermined period of time to release the linger 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 annuity between then 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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Claims (17)

  1. Outil récupérable à mise en oeuvre hydraulique (120) pour passage dans un trou de forage pour assurer une activation d'outil en fond de puits, l'outil comprenant :
    un corps tubulaire (132) d'outil de passage prévu pour suspension dans le trou de forage à partir d'un tube de transport (WS), de sorte qu'un fluide peut être mis en circulation à travers un alésage (126) dans le tube de transport (WS) et dans le corps tubulaire (132), le corps tubulaire incluant un orifice d'admission de fluide (242) à partir de l'alésage (126) dans le corps tubulaire (132) ;
    un élément sensible à une pression de fluide (220) en communication fluidique avec l'orifice d'admission de fluide (242) et mobile par rapport au corps tubulaire (132) d'une position initiale à une position activée en réponse à une pression de fluide à l'intérieur du corps tubulaire (132) ;
    un élément de fermeture d'orifice (212) mobile par rapport au corps tubulaire (132) d'une position d'isolement d'orifice à une position d'ouverture d'orifice, l'élément de fermeture d'orifice (212), dans la position d'isolement d'orifice, coupant une communication fluidique à partir de l'alésage (126) dans le corps tubulaire (132), et autorisant, lorsqu'il se trouve dans la position d'ouverture d'orifice, une communication fluidique à partir de l'alésage (126) dans le corps tubulaire (132) à travers l'orifice d'admission de fluide (242) ;
    un siège (232) supporté sur l'élément de fermeture d'orifice (212), de sorte qu'une augmentation de pression de fluide dans l'alésage tubulaire (126), au moment où un obturateur (240) se pose sur le siège (232), décale élément de fermeture d'orifice (212) d'une position d'isolement d'orifice à la position d'ouverture d'orifice en réponse à une pression de fluide au-dessus de l'obturateur posé ;
    caractérisé en ce que l'outil comprend un mécanisme de libération d'obturateur permettant une libération de l'obturateur lorsque l'élément de fermeture d'orifice a été amené dans la position d'ouverture d'orifice.
  2. Outil récupérable tel que défini dans la revendication 1, dans lequel l'élément de fermeture d'orifice comprend un manchon (212) qui peut se déplacer axialement à l'intérieur de l'alésage (126) du corps tubulaire (132).
  3. Outil récupérable tel que défini dans la revendication 1 ou la revendication 2, dans lequel l'obturateur (240) est une boule.
  4. Outil récupérable tel que défini dans la revendication 3, dans lequel la boule (240) se pose sur le siège (232) pour fermer sensiblement hermétiquement l'alésage (126) traversant le corps tubulaire (132).
  5. Outil récupérable tel que défini dans l'une quelconque des revendications 1 à 4, dans lequel l'élément de fermeture d'orifice (212) est maintenu dans la position d'isolement d'orifice par un élément de cisaillement (222).
  6. Outil récupérable tel que défini dans l'une quelconque des revendications 1 à 5, dans lequel le siège (232) se déforce de façon permanente en réponse à une pression de fluide augmentée pour faire passer l'obturateur (240) à travers le siège (232).
  7. Outil récupérable tel que défini dans l'une quelconque des revendications 1 à 6, dans lequel l'élément sensible a une pression de fluide inclut un piston (220) mobile de la position initiale à à position activée sen réponse à une pression de fluide.
  8. Outil récupérable tel que défini dans la revendication 7, dans lequel le piston (220) se déplace axialement vers le haut de la position initiale à la position activée en réponse à une pression de fluide.
  9. Outil récupérable tel que défini dans l'une quelconque des revendications 1 à 8, dans lequel un déplacement axial du piston (220) dans la position activée provoque l'un (a) d'un déplacement axial d'un coin grippeur (142) pour mettre en place à bride de support de colonne perdue, (b) d'un déplacement d'un mécanisme de libération (250) pour libérer la bride de support de colonne perdue de l'outil de passage, et (c) d'un déplacement relatif entre un cône (152) est un joint d'étanchéité (150) pour assurer une étanchéité entre la bride de support de colonne perdue et le boîtier d'entourage.
  10. Procédé de mise en oeuvre hydraulique d'un outil (120) pour passage dans un puits de formage pour obtenir une activation d'outil en fond de puits, le procédé comprenant :
    la suspension d'un corps tubulaire (132) d'outil de passage dans le puits de forage à partir d'un tube de transport (WS) ;
    la réalisation d'un orifice d'admission de fluide (242) à partir d'un alésage (126) dans le corps tubulaire (132);
    la disposition d'un élément sensible à une pression de fluide (220) en communication fluidique avec l'orifice d'admission de fluide (242) et mobile par rapport au corps tubulaire (132) d'une position initiale à une position activée en réponse à une pression de fluide
    le fait d'amener un élément de fermeture d'orifice (212), mobile par rapport au corps tubulaire (132), d'une position d'isolement d'orifice à une position d'ouverture d'orifice, l'élément de fermeture d'orifice (212), dans la position d'isolement d'orifice, coupant une communication fluidique à partir de l'alésage (126) dans le corps tubulaire (132), et autorisant, lorsqu'il se trouve dans la position d'ouverture d'orifice, une communication fluidique à partir de l'alésage (126) dans le tube à travers l'orifice d'admission de fluide (242) ;
    le support d'un siège (232) sur l'élément de fermeture d'orifice (212) ;
    la pose d'un obturateur (240) sur le siège (232) pour décaler l'élément de fermeture d'orifice (212) de la position d'isolement d'orifice à la position d'ouverture d'orifice en réponse à une pression de fluide au-dessus de l'obturateur posé (240) ; et
    l'obtention de l'activation d'outil en fond de puits en réponse à un déplacement de l'élément sensible à une pression de fluide (220) dans la position activée ;
    caractérisé en ce que le procédé comprend la libération de l'obturateur après le déplacement de l'outil de fermeture d'orifice dans la position d'ouverture d'orifice.
  11. Procédé tel que défini dans la revendication 10, dans lequel l'élément sensible à une pression de fluide (220) inclut un piston mobile de la position initiale à la position activée en réponse à une pression de fluide.
  12. Procédé tel que défini dans la revendication 11, dans lequel le piston se déplace axialement vers le haut à partir de la position initiale en réponse à une pression de fluide.
  13. Procédé tel que défini dans l'une quelconque des revendications 10 à 12, dans lequel l'obturateur (240) est une boule qui se pose sur le siège (232) pour fermer sensiblement hermétiquement l'alésage traversant le corps tabulaire (132).
  14. Procédé tel que défini dans l'une quelconque des revendications 10 à 13, comprenant en outre le maintien de l'élément de fermeture d'orifice dans la position d'isolement d'orifice pair un élément de cisaillement (222).
  15. Procédé tel que défini dans l'une quelconque des revendications 10 à 14, dans lequel le siège (232) se déforme de façon permanente en réponse à une pression de fluide augmentée pour faire passer l'obturateur (240) à travers le siège.
  16. Procédé tel que défini dans l'une quelconque des revendications 10 à 15, dans lequel le déplacement de l'élément sensible à une pression de fluide (220) provoque l'un (a) d'un déplacement axial d'un coin grippeur (142) pour mettre en place la bride de support de colonne perdue, (b) d'un déplacement d'un mécanisme de libération (250) port libérer à bride de support de colonne perdue de l'outil de passage, et (c) d'un déplacement relatif entre un cône et un joint d'étanchéité pour assurer une étanchéité entre la bride de support de colonne perdue et le boîtier d'entourage.
  17. Procédé selon l'une quelconque des revendications 11 à 16, dans lequel l'obturateur (240) est libéré après l'activation de l'outil en fond de puits en réponse à un déplacement de l'élément sensible à une pression de fluide (220) dans la position activée.
EP06012129A 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé Expired - Lifetime EP1712731B1 (fr)

Applications Claiming Priority (12)

Application Number Priority Date Filing Date Title
US29204901P 2001-05-18 2001-05-18
US31645901P 2001-08-31 2001-08-31
US31657201P 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
US10/004,945 US6681860B1 (en) 2001-05-18 2001-12-04 Downhole tool with port isolation
US10/004,588 US6739398B1 (en) 2001-05-18 2001-12-04 Liner hanger running tool and method
US10/136,969 US6761221B1 (en) 2001-05-18 2002-05-02 Slip assembly for hanging an elongate member within a wellbore
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
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
EP1712731A1 EP1712731A1 (fr) 2006-10-18
EP1712731B1 true EP1712731B1 (fr) 2009-09-02

Family

ID=49582879

Family Applications (5)

Application Number Title Priority Date Filing Date
EP06012127A Expired - Lifetime EP1712729B1 (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
EP06012129A Expired - Lifetime EP1712731B1 (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
EP08105836A Expired - Lifetime EP2020482B1 (fr) 2001-05-18 2002-05-15 Suspension de colonne perdue, outil de pose et procédé associé

Family Applications Before (2)

Application Number Title Priority Date Filing Date
EP06012127A Expired - Lifetime EP1712729B1 (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

Family Applications After (2)

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
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) EP1712729B1 (fr)
BR (1) BR122013000180B1 (fr)
DK (3) DK2020482T3 (fr)

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Also Published As

Publication number Publication date
EP1712730A2 (fr) 2006-10-18
DK1712729T3 (da) 2011-10-24
BR122013000180B1 (pt) 2016-07-19
EP1712729A3 (fr) 2006-12-27
EP1712731A1 (fr) 2006-10-18
EP2020482B1 (fr) 2012-09-26
EP1712730B1 (fr) 2010-12-15
EP1712729A2 (fr) 2006-10-18
EP2020482A2 (fr) 2009-02-04
DK2020482T3 (da) 2012-10-22
EP1712730A3 (fr) 2006-12-27
EP1712729B1 (fr) 2011-07-20
EP2020482A3 (fr) 2011-04-27
EP1712732A1 (fr) 2006-10-18
DK1712730T3 (da) 2011-01-24
EP1712732B1 (fr) 2009-07-15

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