EP1392953B1

EP1392953B1 - Line hanger, running tool and method

Info

Publication number: EP1392953B1
Application number: EP02736875A
Authority: EP
Inventors: John M. Yokley; Larry E. Reimert
Original assignee: Dril Quip Inc
Current assignee: Dril Quip Inc
Priority date: 2001-05-18
Filing date: 2002-05-15
Publication date: 2007-03-14
Anticipated expiration: 2022-05-15
Also published as: BR0209857A; EP1392953A4; BR122013000176B1; NO20140708A1; BR122013000179B1; DK1712731T3; NO20035101D0; NO335372B1; WO2002097234A1; BR0209857B1; DK1712732T3; EP1392953A1; BR122013000178B1; NO20172023A1; DK1392953T3

Description

When drilling a well, 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.
Rather than suspending a concentric casing from the bottom of the borehole to the surface, 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 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.
When the liner reaches the desired location relative to the bottom of the open borehole and the previously set casing or liner, 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. When mechanically setting the liner hanger, it is usually necessary to achieve relative downhole rotation of parts between the setting tool and liner hanger to release the hanger slips. 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.
To release the running tool from the set liner hanger, 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.
Generally, the deeper a well is drilled, the higher the temperature and pressure which is encountered. Thus, it is desirable to have liner packers which will ensure quality cementing of the liner so as to provide a high safety factor in preventing gas from the formation from migrating up the annulus between the liner and outer casing.
During the cementing operation, 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. First, 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.

Running Tool Release Mechanism

As a practical matter, 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. For various reasons, hydraulically operated running tool release mechanisms may fail to operate, or may prematurely release the running tool from the liner hanger.
Accordingly, improvements in release mechanisms are desired 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.

Packoff Bushing

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. During cementing operations, 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. Also, 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. Depending on the manufacturer, retrievable packoff bushings are also referred to as retrievable seal mandrels or retrievable cementing bushings. Regardless of the terminology, 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.
Cooperating surfaces on the liner running adapter, the slick joint on the running tool, and the seal body of the packoff bushing axially interconnect the bushing to the liner hanger while running the liner hanger into the well. These cooperating surfaces may be unlocked to release the running tool from the liner hanger and allow axial manipulation of the running tool and slick joint relative to the packoff bushing. The slick joint thus seals with the packoff bushing during axial movement of the running tool. Once the cooperating surfaces are unlocked from each other, shoulders on the packoff bushing and the running tool engage after a predetermined amount of axial movement between the running tool and the seal body, so that the packoff bushing may be retrieved to the surface with the running tool after the cementing operations is complete. A conventional packoff bushing is disclosed in U.S. Patent 4,281,711.
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. When the packoff bushing is pulled out of the liner hanger, the dogs or lugs conventionally carried by the packoff bushing are allowed to move radially inward, thereby preventing the retrievable packoff bushing from being stabbed back into and locked into the liner hanger. Conventional liner hanger running tools do not allow the packoff bushing to be "re-stabbed" into the liner hanger and thereby re-establish pressure integrity between the liner hanger and the running tool. In many applications, it is difficult for the operator to determine the exact amount the running tool has been picked up, particularly when operating in deep or highly deviated wells. If the operator picks up the running tool an axial distance not permitted by the length of a slick joint, the packoff bushing will be pulled up with the running tool and will disengage from the liner hanger, which may cause a cementing failure costing the operator millions of dollars in lost time and money. The consequences of unintentionally unseating the packoff bushing from the liner hanger and not being able to re-stab and lock into the liner hanger may thus be severe.
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. Since 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.
Another problem with prior art packoff bushing concerns the limited load capacity of the lugs that lock the packoff bushing to the liner hanger. Conventional packoff bushings utilize multiple lugs protruding from the packoff seal body, which increases the complexity and the cost of the packoff bushing. The limited size of these lugs nevertheless restricts or limits the cementing pressure capacity of the packoff bushing.

Packer Setting Assembly

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. When the packer setting assembly is raised out of the packer setting sleeve, 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. When the dogs engage the top of the setting sleeve, 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 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. In some well environments, 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, and/or have provided heavier springs to bias the dogs radially outward. These changes have had little if any affect on achieving higher reliability.
US-A-4757860 discloses a downhole tool in which casing hangers are connected to the upper ends of successively smaller diameter casing strings and adapted to be lowered into and landed within the bore of a casing head. The casing hangers incorporate openings to permit cement to circulate as the string is cemented within a well bore. The openings are adapted to be closed off by means of a seal assembly when the casing has been cemented.
The present invention seeks to provide an improved downhole tool and method of forming a downhole seal.
According to one aspect of the present invention, there is provided a downhole tool for use in a subterranean well to seal with a generally cylindrical interior surface of a tubular or another downhole tool, the tool comprising a wedge ring having a substantially conical outer surface configured to radially expand an annular seal assembly upon axial movement of the annular seal assembly relative to the wedge ring such that the seal assembly is expanded from a run-in position to an expanded sealing position wherein the seal assembly is in sealing engagement with the generally cylindrical interior surface, wherein the annular seal assembly has a reduced diameter run-in position and an expanded sealing position, the seal assembly including a metal framework having a radially inward annular base and a plurality of metal ribs each extending radially outward from the base, the metal framework including an upper downwardly angled primary seal metal rib for sealing pressure below the seal assembly, a lower upwardly angled primary seal metal rib for sealing pressure above the seal assembly, a primary elastomeric seal in a cavity radially outward from the base and axially between the upper primary seal metal rib and the lower primary seal metal rib, an upper downwardly angled secondary seal metal rib spaced axially above the upper primary seal metal rib, and a lower upwardly angled secondary seal metal rib spaced axially below the lower primary seal metal rib.
Preferably there is an upper biasing member between the upper primary seal metal rib and the upper secondary seal metal rib for exerting a downward biasing force on the upper primary seal metal rib in response to high fluid pressure below the seal assembly, and a lower biasing member spaced between the lower primary seal metal rib and the lower secondary seal metal rib for exerting an upward force on the lower primary seal metal rib in response to high fluid pressure above the seal assembly.
Conveniently the upper biasing member is an upper secondary elastomeric seal between the upper primary seal metal rib and the upper secondary seal metal rib, and the lower biasing member is a lower secondary elastomeric seal spaced between the lower primary seal metal rib and the lower secondary seal metal rib.
Conveniently an outer surface of each of the upper primary seal metal rib, the lower primary seal metal rib, the upper secondary seal metal rib and the lower secondary metal rib is configured for forming an annular metal-to-metal seal with a generally cylindrical interior surface.
Advantageously each of the downwardly angled primary seal metal rib, the upwardly angled primary seal metal rib, the downwardly angled secondary seal metal rib and the upwardly angled secondary seal metal rib is inclined while in the run-in position at an angle of at least 15° with respect to a plane perpendicular to a central axis of the cylindrical interior surface.
Preferably there is a conveyance tubular for positioning the tool at a selected location below the surface of the well, and wherein the seal assembly seals between the tubular and a liner in the well.
In one embodiment said conveyance tubular supports the wedge ring generally stationary while the seal assembly moves axially with respect to the stationary wedge ring.
In another embodiment the conveyance tubular supports the seal assembly generally stationary while the wedge ring moves axially with respect to the stationary seal assembly.
Conveniently the primary elastomeric seal includes a void area when the primary elastomeric seal is moved into sealing engagement with the cylindrical surface, such that the primary elastomeric seal may thermally expand to fill at least part of the void area in response to elevated downhole temperatures.
Advantageously there is one or more axially spaced protrusions on a radially inner surface of the annular base of the metal framework each for metal-to-metal sealing engagement with the conical outer surface of the wedge ring.
Preferably there is one or more annular elastomeric sealing members for sealing between the base of the metal framework and the conical outer surface of the wedge ring.
Conveniently there is one or more annular metal protrusions on one of an outer surface of a conveyance tubular and an inner surface of the wedge ring to form a metal-to-metal seal between the wedge ring and a conveyance tubular.
Advantageously there is one or more annular elastomeric sealing members carried by one of the conical wedge ring and a conveyance tubular for forming an elastomeric seal between the conveyance tubular and the wedge ring.
Preferably there is an elongate member having an outwardly facing frusto conical surface and adapted to be lowered into and suspended within a wellbore, and a slip comprising a circumferentially expandable and contractible c-ring having slip teeth about its outer side and a frusto conical surface on its inner side disposed about the frusto conical surface of the elongate member so that the c-ring maybe moved vertically between a contracted position in which the teeth are spaced from the wellbore and an expanded portion in which the teeth engage the wellbore.
Conveniently the elongate member has a recess to receive an end of the c-ring to retain the c-ring contracted about the member, as it is lowered, whereby, upon removal of the one end from the recess, the c-ring is free to expand toward its fully expanded position to cause its slip teeth to grip the wellbore, so that the weight of the member may be hung from the casing upon relative vertical movement of the conical surfaces of the c-ring and member.
Advantageously the frusto conical surface of the member extends downwardly and inwardly and the frusto conical surface of the c-ring is slideable upwardly over the surface of the member as the member is lowered to cause its teeth to move outwardly to engage the wellbore.
Preferably there is a part carried by the member for guided reciprocation with respect thereto and engageable with the end of the c-ring or in order to remove the end of the c-ring from the recess and thus release it for expansion.
Conveniently the part for releasing the c-slip comprises a tie bar extending guidably within the end of the c-ring is in the recess, so as to permit the c-slip to be removed from the recess by the tie bar and then released therefrom to permit the c-ring to expand into engagement with the bore of the casing.
According to another aspect of the present invention, there is provided a method of forming a downhole seal with a generally cylindrical interior surface of a tubular or another downhole tool, the method comprising providing an annular seal assembly disposed about a conveyance tubular, the seal assembly having a reduce diameter run-in position and an expanded position, the seal assembly including a metal framework having a radially inward annular base and a plurality of metal ribs each extending radially outward from the base, the metal framework including an upper downwardly angled primary seal metal rib for sealing pressure below the seal assembly, a lower upwardly angled primary seal metal rib for sealing pressure above the seal assembly, a primary elastomeric seal in a cavity radially outward from the base and axially between the upper primary seal metal rib and the lower primary seal metal rib, an upper downwardly angled secondary seal metal rib spaced axially above the upper primary seal metal rib, and a lower upwardly angled secondary seal metal rib spaced axially below the lower primary seal metal rib, providing a wedge ring having a substantially conical outer surface, and axially moving the annular seal assembly relative to the wedge ring such that the seal assembly is expanded from its run-in position to its expanded position wherein the seal assembly is in sealing engagement with the generally cylindrical interior surface.
Preferably an upper biasing member is provided between the upper primary seal metal rib and the upper secondary seal metal rib for exerting a downward biasing force on the upper primary seal metal rib in response to high fluid pressure below the seal assembly, and providing a lower biasing member spaced between the lower primary seal metal rib and the lower secondary seal metal rib for exerting an upward force on the lower primary seal metal rib in response to high fluid pressure above the seal assembly.
Conveniently an outer surface of each of the upper primary seal metal rib, the lower primary seal metal rib, the upper secondary seal metal rib and the lower secondary metal rib is configured for forming an annular metal-to-metal seal with a generally cylindrical interior surface.
Advantageously the wedge ring is generally stationary while the seal assembly moves axially with respect to the stationary wedge ring.
Preferably a set down weight transmitted to the seal assembly through the conveyance tubular moves the seal assembly axially with respect to the stationary wedge ring.
Conveniently one or more axially spaced protrusions are provided on a radially inner surface of the annular base of the metal framework each for metal-to-metal sealing engagement with the conical outer surface of the wedge ring.
Advantageously one or more annular elastomeric sealing members are provided for sealing between the base of the metal framework and the conical outer surface of the wedge ring.
Preferably one or more annular metal protrusions are provided on one of an outer surface of the conveyance tubular and an inner surface of the wedge ring to form a metal-to-metal seal between the wedge ring and the conveyance tubular.
Conveniently a setting member is provided for lowering the liner within the wellbore and an outwardly facing frusto conical surface tapered downwardly and radially inward and a circumferentially expandable and contractible c-ring is provided having slip teeth about its outer side and a frusto conical surface on its inner side for co-operation with the frusto conical surface of the setting member, the c-ring being moveable between a radially contracted retained position in which the slip teeth are spaced from the well casing and an expanded position in which the slip teeth engage an interior surface of the well casing the method comprising the step of compressing the c-ring on the setting member to its contracted position and retaining an end of the compressed c-ring within a recess in the setting member with a stop to prevent the c-ring from moving radially outward to the expanded relaxed position when the liner is desirably positioned in the wellbore, moving the c-ring axially with respect to the stop to release the c-ring to expand such that the slip teeth engage the well casing, and moving the frusto conical surface of the setting member downward to force the slip teeth to bite the well casing, such that the liner is hung from the interior surface of the well casing.
Advantageously the stop is fixed to the setting member and the c-ring moves axially upward to disengage the stop.
Preferably the method further comprises the step of providing a tie bar axially that is moveable within the setting member, interconnecting the tie bar and the c-ring until the c-ring disengages the stop and thereafter releasing the tie bar from the c-ring for expansion of the c-ring upon lowering of the setting member.
Conveniently a plurality of blunt inner teeth are provided along the inner frusto conical surface of the c-ring for frictional engagement with the frusto conical surface on the setting member.
Advantageously the setting member is moved downward by its weight.

Brief Description of the Drawings

Figure D1 is a half-sectional view of the seal element according to a preferred embodiment of the present invention positioned at the lower end of a tie back receptacle for moving down along a cone and sealing with a casing,
Figure D2 is an enlarged view of a seal element shown in Figure 1 positioned when the seal element initially engages the casing,
Figure D3 is a cross-sectional view of the seal element in its final set position for sealing engagement between the cone and the casing,
Figures B1A and B1B are respectively an elevational view, broken away in part, and an end view of a c-ring along in a fully contracted position wherein its side edges are engaged with one another; the outer side of the c-ring having vertical slots to facilitate the passage of fluid between the liner and outer well casing when the slip is expanded,
Figures B2A and B2B are similar views of the c-ring in a fully expanded position,
Figures B3A and B3B are vertical sectional views of the slip assembly wherein the collapsed c-ring is shown in Figure B3A disposed about the liner with its lower end received within the recess of the liner, and in Figure B3B, raised in from the recess and expanded to a position in which the liner may be raised to move its outer side upwardly over the frusto conical surface of the liner so as to cause its teeth to engage the well casing,
Figure B3C is an enlarged detailed view of a portion of Figure 3B to illustrate controlled friction teeth on the inner slide of the c-ring,
Figures B4, B5 and B6 are enlarged vertical sectional views of the assembly showing the c-ring as it is moved by the liner from the retracted to the expanded position, and
Figures B3AA and B3BB are detailed sectional views as indicated on Figures B3A and B3B.

Referring initially to Figure D1 an annular packer element D10 according to a preferred embodiment of the present invention is 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. In an environment where the packer element is not the top liner hanger seal, 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. In the Figure D1 embodiment, 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 is 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.
Referring to Figures D1 and D2, 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. This feature allows 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. Also, the packer element may include both a primary and a backup elastomeric seal, and a primary and a backup metallic seal. Referring to Figure D3, it should be understood that 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. The term "fluid" as used herein includes gas, liquids and combinations of gas and liquid. Seal body D24 preferably engages the ribs D32, D34 and the base D18, and substantially fills the annular void between these surfaces. 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. Similarly, when 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. Most importantly, the backup seal, whether that be seal body D22 or D26, 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.
Referring again to Figure D2, 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. Preferably 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. This 5% to 10% void area thus allows for thermal expansion of each elastomeric resilient seal, thereby avoiding the creation of additional forces to act on the ribs D20. 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 D3, 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.
As shown in Figure D3, 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. As explained above, the centerline of each rib is angled at least 15° with respect to the plane D38 perpendicular to the central axis of element 10 prior to 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 D14 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. Alternately, 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.
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. When the setting pressure is increased, 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. After the sealing element comes into contact with the casing, 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. Initially, 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. Once the elastomeric bodies have been deformed so that the ends of the ribs engage the casing, 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.
During well operations, 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. When pressure is released and the casing shrinks, the ribs may return to the solid line configuration as shown in Figure D3.
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.
In the case of a liner hanger, the liner hanger running tool conventionally includes the actuator which provides the compressive force to the packer element D10 to set the packer. In other applications where the seal element is used, 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.
Various types of conveyance tubulars may be used for positioning the packer element at a selected location below the surface of the well. 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. In a preferred embodiment, the seal assembly includes an upper elastomeric seal body, a primary elastomeric seal body, and a lower elastomeric seal body. While 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. For example, 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. At the same time, 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.
In addition to the primary metal-to-metal seal, the secondary metal-to-metal seal, the primary elastomeric seal and the secondary elastomeric seal, additional sets of metal-to-metal and elastomeric seals could be provided in the packer element. Elastomeric bodies which are configured other than shown herein may thus be used for this purpose. Various types of plastic materials in various configurations may provide the desired biasing force, and ideally also a secondary resilient seal. Alternatively, a wave spring or other metallic material biasing member may be used instead of or in cooperation with the elastomeric bodies D22 and D26.
Preferably 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. In other embodiments, 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. Preferably 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.
Referring now to Figures B3A and B3B, a liner B20 has a downwardly and inwardly extending frusto conical surface B22 thereabout above and 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.
As will be described in more detail below, 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.
When the c-ring has been pulled upwardly to remove its lower end from the recess B23, it expands towards its fully expanded position of Figs B2A and B2B, whereby downwardly facing teeth B22 about its outer side engage the outer well casing, as shown in Fig. B3B, in a somewhat less than fully expanded position. Then, when the c-slip is raised, the inner surface of the c-ring will slide over wedge surface B22 to urge it outwardly to cause its teeth to bite into the outer well casing, and thus permit the weight of the liner and its associated parts to be hung off on the casing.
As shown in Figs. B3A and B3B and in detail in Figs. B3AA and B3BB, 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. Thus, as the teeth take on initial bite into 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. Although the teeth CF are preferred, the inner surface of the c-ring may be smooth.
With reference to Figs. B4 to B6, one or more 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. Thus, as shown in Figs. B4 - B6, 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.
As the tie bar is raised to lift the c-ring out of the recess B23, the flange B50 on its lower end moves out of the groove B36 to release the c-ring therefrom, as shown in Fig. B5. At this time, of course, 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.
As an alternative to slip assemblies, as previously described, other apparatus for this purpose - i.e. hanging an inner casing within an outer casing, have locking elements adapted to be expanded into matching locking grooves formed in the outer casing. In some cases, the locking elements are adapted to be spring biased into matching grooves formed in the outer casing. However, these springs are susceptible to breaking or other malfunctions. This is especially true since the hanger often comprises a large number of intricate parts which are expensive to replace, and which require a delay in the overall well operations. In still other cases, the hangers having only a single latching part for fitting within a single groove, thus limiting its load carrying capacity.
In one embodiment a liner hanger system comprising a joint of casing is adapted to be connected as part of an outer casing installed within a wellbore, and a line is 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.

Claims

A downhole tool for use in a subterranean well to seal with a generally cylindrical interior surface of a tubular or another downhole tool, the tool comprising a wedge ring (D14) having a substantially conical outer surface configured to radially expand an annular seal assembly upon axial movement of the annular seal assembly relative to the wedge ring (D14) such that the seal assembly is expanded from a run-in position to an expanded sealing position wherein the seal assembly is in sealing engagement with the generally cylindrical interior surface, characterised in that the annular seal assembly has a reduced diameter run-in position and an expanded sealing position, the seal assembly including a metal framework having a radially inward annular base (D18) and a plurality of metal ribs (D20) each extending radially outward from the base (D18), the metal framework including an upper downwardly angled primary seal metal rib (D32) for sealing pressure below the seal assembly, a lower upwardly angled primary seal metal rib (D34) for sealing pressure above the seal assembly, a primary elastomeric seal (D24) in a cavity radially outward from the base (D18) and axially between the upper primary seal metal rib (D32) and the lower primary seal metal rib (D34), an upper downwardly angled secondary seal metal rib (D30) spaced axially above the upper primary seal metal rib (D32), and a lower upwardly angled secondary seal metal rib (D36) spaced axially below the lower primary seal metal rib (D34).
A downhole tool according to Claim 1 wherein there is an upper biasing member (D22) between the upper primary seal metal rib (D32) and the upper secondary seal metal rib (D30) for exerting a downward biasing force on the upper primary seal metal rib (D32) in response to high fluid pressure below the seal assembly, and a lower biasing member (26) spaced between the lower primary seal metal rib (D36) and the lower secondary seal metal rib (D34) for exerting an upward force on the lower primary seal metal rib (D34) in response to high fluid pressure above the seal assembly.
A downhole tool according to Claim 2 wherein the upper biasing member is an upper secondary elastomeric seal (D22) between the upper primary seal metal rib (D32) and the upper secondary seal metal rib (D30), and the lower biasing member is a lower secondary elastomeric seal (D26) spaced between the lower primary seal metal rib (D34) and the lower secondary seal metal rib (D36).
A downhole tool according to any one the preceding Claims wherein an outer surface of each of the upper primary seal metal rib (D32), the lower primary seal metal rib (D34), the upper secondary seal metal rib (D30) and the lower secondary metal rib (D36) is configured for forming an annular metal-to-metal seal with a generally cylindrical interior surface.
A downhole tool according to any one of the preceding Claims wherein each of the downwardly angled primary seal metal rib (D32), the upwardly angled primary seal metal rib (D34), the downwardly angled secondary seal (D30) metal rib and the upwardly angled secondary seal metal rib (D36) is inclined while in the run-in position at an angle of at least 15° with respect to a plane perpendicular to a central axis of the cylindrical interior surface.
A downhole tool according to any one of the preceding Claims wherein there is a conveyance tubular (D16) for positioning the tool at a selected location below the surface of the well, and wherein the seal assembly seals between the tubular and a liner in the well.
A downhole tool according to Claim 6 wherein said conveyance tubular (D16) supports the wedge ring (D14) generally stationary while the seal assembly moves axially with respect to the stationary wedge ring (D14).
A downhole tool according to Claim 6 wherein the conveyance tubular (D16) supports the seal assembly generally stationary while the wedge ring (D14) moves axially with respect to the stationary seal assembly.
A downhole tool according to any one of the preceding Claims wherein the primary elastomeric seal (D24) includes a void area (D25) when the primary elastomeric seal (D24) is moved into sealing engagement with the cylindrical surface, such that the primary elastomeric seal (D24) may thermally expand to fill at least part of the void area (D25) in response to elevated downhole temperatures.
A downhole tool according to any one of the preceding Claims wherein there is one or more axially spaced protrusions (D40) on a radially inner surface of the annular base (D18) of the metal framework each for metal-to-metal sealing engagement with the conical outer surface of the wedge ring (D14).
A downhole tool according to Claim 10 wherein there is one or more annular elastomeric sealing members (D48) for sealing between the base (D18) of the metal framework and the conical outer surface of the wedge ring (D14).
A downhole tool according to Claim 10 or Claim 11 wherein there is one or more annular metal protrusions (D42) on one of an outer surface of a conveyance tubular (D16) and an inner surface of the wedge ring (D14) to form a metal-to-metal seal between the wedge ring (D14) and a conveyance tubular (D16).
A downhole tool according to Claim 12 wherein there is one or more annular elastomeric sealing members (D48) carried by one of the conical wedge ring (D14) and a conveyance tubular (D16) for forming an elastomeric seal between the conveyance tubular (D16) and the wedge ring (D14).
A downhole tool according to any one of the preceding Claims wherein there is an elongate member (B20) having an outwardly facing frusto conical surface (B22) and adapted to be lowered into and suspended within a wellbore, and a slip comprising a circumferentially expandable and contractible c-ring (C) having slip teeth about its outer side and a frusto conical surface (B22) on its inner side disposed about the frusto conical surface of the elongate member (B20) so that the c-ring (C) maybe moved vertically between a contracted position in which the teeth are spaced from the wellbore and an expanded portion in which the teeth engage the wellbore.
A downhole tool according to Claim 14 wherein the elongate member (B20) has a recess (B23) to receive an end of the c-ring (C) to retain the c-ring (C) contracted about the member (B20), as it is lowered, whereby, upon removal of the one end from the recess (B23), the c-ring (C) is free to expand toward its fully expanded position to cause its slip teeth to grip the wellbore, so that the weight of the member (B20) may be hung from the casing upon relative vertical movement of the conical surfaces of the c-ring (C) and member (B20).
A downhole tool according to Claim 14 or Claim 15 wherein the frusto conical surface (B22) of the member (B20) extends downwardly and inwardly and the frusto conical surface of the c-ring (C) is slideable upwardly over the surface of the member (B20) as the member (B20) is lowered to cause its teeth to move outwardly to engage the wellbore.
A downhole tool according to any one of Claims 14 to 16 wherein there is a part (B30) carried by the member (B20) for guided reciprocation with respect thereto and engageable with the end of the c-ring (C) or in order to remove the end of the c-ring (C) from the recess (B23) and thus release it for expansion.
A downhole tool according to Claim 17 wherein the part (B30) for releasing the c-slip (C) comprises a tie bar (B30) extending guidably within the end of the c-ring (C) is in the recess (B23), so as to permit the c-slip (C) to be removed from the recess (B23) by the tie bar (B30) and then released therefrom to permit the c-ring (C) to expand into engagement with the bore of the casing.
A method of forming a downhole seal with a generally cylindrical interior surface of a tubular or another downhole tool, the method comprising providing an annular seal assembly disposed about a conveyance tubular (D16), the seal assembly having a reduce diameter run-in position and an expanded position, the seal assembly including a metal framework having a radially inward annular base (D18) and a plurality of metal ribs (D20) each extending radially outward from the base (D18), the metal framework including an upper downwardly angled primary seal metal rib (D32) for sealing pressure below the seal assembly, a lower upwardly angled primary seal metal rib (D34) for sealing pressure above the seal assembly, a primary elastomeric seal (D24) in a cavity radially outward from the base (D18) and axially between the upper primary seal metal rib (D32) and the lower primary seat metal rib (D34), an upper downwardly angled secondary seal metal rib (D30) spaced axially above the upper primary seal metal rib (D32), and a lower upwardly angled secondary seal metal rib (D36) spaced axially below the lower primary seal metal rib (D34), providing a wedge ring (D14) having a substantially conical outer surface, and axially moving the annular seal assembly relative to the wedge ring (D14) such that the seal assembly is expanded from its run-in position to its expanded position wherein the seal assembly is in sealing engagement with the generally cylindrical interior surface.
A method according to Claim 19 wherein an upper biasing member (D22) is provided between the upper primary seal metal rib (D32) and the upper secondary seal metal rib (D30) for exerting a downward biasing force on the upper primary seal metal rib (D32) in response to high fluid pressure below the seal assembly, and providing a lower biasing member (D26) spaced between the lower primary seal metal rib (D34) and the lower secondary seal metal rib (D36) for exerting an upward force on the lower primary seal metal rib (D34) in response to high fluid pressure above the seal assembly.
A method according to Claim 19 or Claim 20 wherein an outer surface of each of the upper primary seal metal rib (D32), the lower primary seal metal rib (D34), the upper secondary seal metal rib (D30) and the lower secondary metal rib (D36) is configured for forming an annular metal-to-metal seal with a generally cylindrical interior surface.
A method according to any one of Claims 19 to 21 wherein the wedge ring (D14) is generally stationary while the seal assembly moves axially with respect to the stationary wedge ring (D14).
A method according to Claim 22 wherein a set down weight transmitted to the seal assembly through the conveyance tubular (D16) moves the seal assembly axially with respect to the stationary wedge ring (D14).
A method according to any one of Claims 19 to 23 wherein one or more axially spaced protrusions (D40) are provided on a radially inner surface of the annular base (D18) of the metal framework each for metal-to-metal sealing engagement with the conical outer surface of the wedge ring (D14).
A method according to Claim 24 wherein one or more annular elastomeric sealing members (D48) are provided for sealing between the base (D18) of the metal framework and the conical outer surface of the wedge ring (D14).
A method according to any one of Claims 19 to 25 wherein one or more annular metal protrusions (D42) are provided on one of an outer surface of the conveyance tubular (D16) and an inner surface of the wedge ring (D14) to form a metal-to-metal seal between the wedge ring (D14) and the conveyance tubular (D16).
A method according to any one of Claims 19 to 26 wherein a setting member (B20) is provided for lowering the liner within the wellbore and an outwardly facing frusto conical surface (B22) tapered downwardly and radially inward and a circumferentially expandable and contractible c-ring (C) is provided having slip teeth about its outer side and a frusto conical surface (B22) on its inner side for co-operation with the frusto conical surface of the setting member (B20), the c-ring (C) being moveable between a radially contracted retained position in which the slip teeth are spaced from the well casing and an expanded position in which the slip teeth engage an interior surface of the well casing the method comprising the step of compressing the c-ring (C) on the setting member (B20) to its contracted position and retaining an end of the compressed c-ring (C) within a recess (B23) in the setting member (B20) with a stop to prevent the c-ring (C) from moving radially outward to the expanded relaxed position when the liner is desirably positioned in the wellbore, moving the c-ring (C) axially with respect to the stop to release the c-ring (C) to expand such that the slip teeth engage the well casing, and moving the frusto conical surface of the setting member (B20) downward to force the slip teeth to bite the well casing, such that the liner is hung from the interior surface of the well casing.
A method according to Claim 27 wherein the stop is fixed to the setting member (B20) and the c-ring (C) moves axially upward to disengage the stop.
A method according to Claim 27 or Claim 28 wherein the method further comprises the step of providing a tie bar (B30) axially that is moveable within the setting member (B20), interconnecting the tie bar (B30) and the c-ring (C) until the c-ring (C) disengages the stop and thereafter releasing the tie bar (B30) from the c-ring (C) for expansion of the c-ring (C) upon lowering of the setting member (B20).
A method according to any one of Claims 27 to 28 wherein a plurality of blunt inner teeth are provided along the inner frusto conical surface of the c-ring (C) for frictional engagement with the frusto conical surface on the setting member (B20).
A method according to any one of Claims 27 to 31 wherein the setting member (B20) is moved downward by its weight.