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CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application claims benefit of PCT International application number PCT/GB01/05614 filed on Dec. 21, 2001, entitled “Method and Apparatus,” which claims benefit of British application serial number 0031409.6, filed on Dec. 22, 2000, and British application serial number 0109996.9 filed on Apr. 24, 2001. 
   Aspects of the present invention relate to a method and apparatus for various remedial or repair operations in oil and gas wells. Certain other aspects of the present invention have applications in the context of lateral boreholes. 
   Aspects of the present invention relate to a method and apparatus for various remedial or repair operations in oil and gas wells. Certain other aspects of the present invention have applications in the context of lateral boreholes. 
   DESCRIPTION OF RELATED ART 
   It is known to use expandable tubular members to line or case boreholes that have been drilled into a formation to facilitate the recovery of hydrocarbons. The expandable tubular members are typically of a ductile material so that they can withstand plastic and/or elastic deformation to radially expand their inner diameter (ID) and/or outer diameter (OD). The tubular members can typically sustain a plastic deformation to expand their OD and/or ID by around 10% at least, although radial plastic deformation in the order of 20% or more is possible. 
   The radial expansion of the tubular members can typically be achieved in one of two ways. 
   A radial expansion force can typically be applied by an inflatable element (e.g. a packer or other such apparatus that is capable of inflating or otherwise expanding) to a particular portion of the member, so that the inflatable element is inflated within the member to radially expand the member at the particular portion thereof. This can be repeated at one or more locations either adjacent to the particular portion, or spaced therefrom. 
   Alternatively, an expander device can be pushed or pulled through the member to impart a radial expansion force to the casing so that the ID and/or the OD of the member increases. This is generally called radial plastic deformation in the art, but “radial expansion force” will be used herein to refer to both of these options. 
   BRIEF SUMMARY OF THE INVENTION 
   According to a first aspect of the present invention, there is provided a tubular remedial apparatus for performing downhole remedial or repair operations on downhole tubulars such as casing, liner or the like in a wellbore, the apparatus comprising an expandable tubular member and at least one expander element. 
   According to a second aspect of the present invention, there is provided a method of performing downhole repair or remedial operations, the method comprising the steps of providing an expandable member; locating the member in a tubular in the borehole; providing at least one expander element and locating this within the expandable member; and actuating the expander element to radially expand at least a portion of the expandable member against the wellbore tubular. 
   The expander element can be integral with the expandable member, or can be separate therefrom. 
   The expandable member is typically a lightweight member such as a thin-walled tubular member. The wall thickness of the lightweight member is typically up to around 5 millimeters. The lightweight member is typically of stainless steel or an alloy of steel (e.g. a nickel alloy). Alternatively, the expandable member can be a heavyweight tubular having a wall thickness of greater than 5 mm. For lightweight members, the diameter-to-thickness ratio is in the order of 40 to 60, whereas the diameter-to-thickness ratio of a heavyweight expandable tubular member is typically around 20 to 30. 
   In preferred embodiments, the expandable member comprises a tubular with a central heavyweight portion disposed between two lightweight portions. Optionally, the central heavyweight portion is provided with at least one orifice. This particular expandable member can be used to repair a faulty gas lift valve, for example. 
   The expandable member is typically a one-piece member. The expandable member can be in the form of a coil or a roll for example. Alternatively, the tubular member can comprise two or more portions that are coupled together (e.g. by welding or screw threads). 
   Optionally, two axially spaced-apart expander elements can be used. In this embodiment, the elements can be coupled together by a shaft or the like. 
   The or each expander element typically comprises an inflatable element, such as a packer or the like. However, a mechanical expander device may also be used. 
   In its broadest context, the method of the second aspect of the present invention facilitates the repair of a damaged or faulty casing, liner or the like. In this embodiment, the expandable member is located in the casing, liner or the like at the damaged or faulty area, and radially expanded so that at least a portion of the member contacts an inner surface of the casing, liner or the like. Thus, the expandable member overlays the damaged or faulty casing, liner etc. 
   In a particular embodiment of the invention, the method can be used to repair a faulty or damaged valve located in a tubular. In this case, the method comprises the steps of locating the expandable member in a bore of the tubular so that it straddles the valve; locating the expander element in the expandable member at a first portion of the expandable member; actuating the expander element to expand the first portion of the expandable member; de-actuating the expander element; moving the expander element to a second portion of the expandable member; and actuating the expander element to expand the second portion of the expandable member. 
   The first and second portions of the expandable member typically comprise first and second ends of the expandable member. However, the member need only be expanded on each side of the valve. 
   Optionally, the method may be used to expand the entire length of the expandable member by de-actuating the expander element and moving it to another location between the first and second portions of the member, and then re-actuating it to expand the expandable member at the other location. The expander element may be moved more than once and expanded at more than one other location. 
   The valve may comprise a safety valve, chemical injection valve, gas lift valve, sliding sleeve valve or the like. 
   According to a third aspect of the present invention, there is provided a lateral tubular adapter apparatus, the apparatus having a longitudinal bore and at least one expander element. 
   According to a fourth aspect of the present invention, there is provided a method of hanging a lateral tubular from a cased wellbore, the method comprising the steps of providing a conduit having a longitudinal bore and at least one expander element, the conduit having an aperture therein; locating the conduit at or near a lateral opening in the casing of the borehole; and expanding the or each expander element to radially expand portions of the conduit on opposite sides of the aperture. 
   The apparatus preferably has first and second axially spaced-apart expander elements, preferably located on opposite sides of the aperture. 
   The opening in the borehole typically comprises a lateral borehole. 
   The conduit is typically a lightweight or heavyweight member as discussed above. 
   The aperture in the conduit is typically teardrop shaped, but other shapes may also be used, such as ovals, circles, ellipses etc. 
   The expander element typically comprises an inflatable element as described above. An annular chamber is typically located under a plurality of overlapping metal plates. The annular chamber is typically in fluid communication with the bore of the apparatus, e.g. via one or more ports. An elastomeric covering is typically located over the metal plates. The metal plates typically overlap in the longitudinal direction (i.e. in a direction that is parallel to the longitudinal axis of the apparatus). 
   The step of actuating the inflatable element typically includes the additional step of providing pressurised fluid in the annular chamber. The pressurised fluid typically expands the metal plates and/or the elastomeric covering. 
   The inflatable elements typically include one or more ports that are in fluid communication with the annular chamber. The ports typically include a rupture or burst disc therein. The rupture or burst disc is typically rated to burst at around 4000 psi. 
   The apparatus typically includes a first centraliser located at or near each inflatable element. The first centraliser comprises two or more radially extending blades or the like that engage an inner surface of the conduit. A portion of the first centraliser typically engages at least a portion of the inflatable element. The first centraliser typically engages at least the elastomeric covering of the inflatable element. The first centraliser includes one or more shear screws that retain the first centraliser in a certain axial location with respect to the inflatable element. The first centraliser thus prevents premature inflation of the inflatable element by preventing the elastomeric covering from radially expanding. The shear screws are typically rated to shear at around 500 psi. 
   The step of inflating the inflatable elements typically includes the additional step of applying a pressure in the annular chamber of the inflatable elements, the pressure being greater than the rating of the shear screws to shear the shear screws of the first centraliser. The shearing of the shear screws typically allows the first centraliser to move axially towards the inflatable element, thus allowing the elastomeric covering to expand. Thus, the first centraliser prevents the inflatable element from prematurely inflating until the shear screws shear. 
   The apparatus typically includes at least one second centraliser for centralising the conduit on the inflatable elements as the apparatus is run into a borehole. The or each second centraliser typically includes a groove for receiving an O-ring. The O-ring is typically compressed when the inflatable element is expanded. Compression of the O-ring causes the or each centraliser to be retained on the apparatus. Alternatively, the second centraliser comprises a ring of resilient material (e.g. rubber) that engages the conduit, and a retaining clamp. A second centraliser is typically located at a first end of the conduit. 
   At least a portion of the conduit is typically swaged. The swaged portion is typically at a second end of the conduit. The swaged portion typically engages a least a portion of the apparatus (e.g. one of the inflatable elements). The swaged portion substantially prevents the ingress of dirt, fluids etc into an annulus between the apparatus and the conduit as the apparatus is being run into the borehole. Alternatively, or additionally, a further centraliser may be located at the second end. The or each second centraliser also prevents the ingress of wellbore debris and the like into an annulus between the or each inflatable element and the conduit. 
   The apparatus typically includes a retainer sub that is located between the first and second inflatable elements. The retainer sub includes a piston that is capable of moving along an axis that is substantially parallel to a longitudinal axis of the apparatus. A surface of the piston is adapted to engage at least one radial piston. Preferably, four radial pistons are provided, each radial piston being circumferentially spaced-apart from the others (e.g. by 90°). The or each radial piston is typically set on an axis that is substantially perpendicular to the longitudinal axis of the apparatus. Movement of the piston in a first direction typically moves the piston to a first configuration in which the surface engages the or each radial piston. The engagement of the piston with the or each radial piston typically causes the or each radial piston to be moved radially outward so that an end thereof engages an inner surface of the conduit. Thus, the conduit is retained in place by the engagement of the or each radial piston therewith. Movement of the piston in a second direction, typically opposite to the first direction, typically moves the piston to a second configuration where the surface disengages the or each radial piston. In this configuration, the or each radial piston can disengage the conduit. The piston is typically held in the first configuration by one or more shear screws. The shear screws are typically rated to shear at around 500 psi. 
   The method typically includes the additional steps of applying pressure to a first end of the piston to move the piston to the first configuration, and locating the shear screws to retain the piston in the first configuration. The method typically includes the additional steps of applying a pressure to a second end of the piston, the pressure typically being higher than the rating of the shear screws, to move the piston to the second configuration. 
   The apparatus typically includes a locator. The locator typically facilitates alignment of the aperture in the conduit with the opening to the lateral borehole. In one embodiment, the locator comprises a spring-loaded arm. 
   The method typically includes the additional step of locating the locating arm in an extended portion of the aperture in the conduit. The extended portion typically comprises an elongate slot. The method typically includes the additional step of running the apparatus into the borehole until the locating arm locates the opening to the lateral borehole. 
   The apparatus typically includes a ball catcher located at a distal end of the apparatus. The ball catcher typically includes a ball seat that is typically capable of receiving a ball. The ball seat is typically coupled to the ball catcher using one or more shear screws. The shear screws are typically rated to shear at around 3000 psi. The ball seat is movable from a first position where it blocks one or more ports in the apparatus, to a second position where it opens the ports in the apparatus. The ports in the apparatus are typically in fluid communication with the bore of the apparatus. 
   The method typically includes the additional step of dropping a ball into the borehole before pressure is applied in the bore of the apparatus. 
   The method typically includes the additional step of applying a pressure to the ball that exceeds the rating of the shear screws to move the ball seat to the second position. This allows the pressure in the bore to be vented into the borehole via the ports. The venting of the pressure allows the inflatable elements to deflate and thus the apparatus can be retrieved from the borehole. 
   The method optionally includes the additional steps of applying a pressure of around 4000 psi to the bore of the apparatus to rupture the burst discs in the or each inflatable element. This allows the pressure in the bore of the apparatus to be vented outwith the apparatus. 

   
     BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING 
     Embodiments of the present invention shall now be described, by way of example only, with reference to the accompanying drawings, in which: 
       FIG. 1  is a part cross-sectional view of a safety valve that has been repaired using one embodiment of a method according to an aspect of the present invention; 
     FIGS  2   a  to  2   c  one embodiment of apparatus according to an aspect of the present invention in various stages of expanding a tubular member; 
       FIG. 3  is a part cross-sectional view of a sliding sleeve that has been repaired using one embodiment of a method according to an aspect of the present invention; 
       FIG. 4  is a part cross-sectional elevation of a mandrel valve that houses a gas lift valve that has been repaired using one embodiment of a method according to an aspect of the present invention; 
     FIGS  5   a  to  5   d  are four cross-sectional elevations of a gas lift orifice showing the stages of repair; 
       FIG. 6   a  shows a part cross-sectional elevation of a casing and a lateral borehole that has been provided with a portion of one embodiment of apparatus according to an aspect of the present invention; 
       FIG. 6   b  shows a perspective view of a conduit for use with one embodiment of apparatus according to an aspect of the present invention; 
     FIGS  7   a  to  7   i  are cross-sectional elevations that together show an embodiment of apparatus according to an aspect of the present invention; 
       FIG. 8  shows an enlarged view of a centraliser forming part of the apparatus of  FIG. 7   a ; and 
       FIG. 9  shows a similar view of the apparatus of  FIG. 7   a  with an alternative centraliser. 
   

   DETAILED DESCRIPTION OF THE INVENTION 
   Referring to the drawings,  FIG. 1  shows in part cross-section a conventional safety valve, generally designated  10 . Safety valve  10  includes a flapper  12  that can be moved from an open position (shown in  FIG. 1 ) to a closed position (not shown). The safety valve  10  is typically located as part of a production string  11  through which fluids (e.g. hydrocarbons) are recovered from a payzone or reservoir (not shown) to the surface. 
   Safety valve  10  includes a mandrel  13  in which the flapper  12  is located. Mandrel  13  is typically coupled to the production string  11  using any conventional means (e.g. conventional pin and box connections). 
   In the open position, flapper  12  lies generally parallel to a longitudinal axis of the safety valve  10  and thus does not obstruct the flow of fluids through a bore  10   b  of the safety valve  10 . Thus, fluids can flow through the safety valve  10  and the production string  11  to the surface. In the closed position, the flapper  12  is pivoted upwards (with respect to the orientation of the valve  10  in  FIG. 1 ) through 90° around a pivot pin  14  or the like so that the flapper  12  lies substantially perpendicular to the longitudinal axis of the safety valve  10  and thus closes bore  10   b  thereby preventing the flow of hydrocarbons and the like through the valve  10  and the production string  11 . 
   Operation of the safety valve  10  is typically achieved via a control line  16  that extends from the valve  10  back to the surface (not shown). The control line  16  is used to actuate a piston and spring mechanism, generally designated  18 , that controls the actuation of the flapper  12  as is known in the art. 
   It is often the case that the flapper  12  becomes stuck in the closed position and thus prevents fluids from flowing through the production string  11  by blocking the bore  10   b  of the safety valve  10 . When this occurs, it is necessary to perform a remedial operation to open the flapper  12  to facilitate the recovery of hydrocarbons. 
   When the flapper  12  becomes stuck in the closed position, an insert valve (not shown) can be landed on an upper profile  20  (nipple) and the flapper  12  can be controlled using a punch (not shown). The punch provides a jarring action that can be used to punch through into the control line and operate the flapper  12 . However, the insert valve can generally only be used when there is mechanical failure of the safety valve  10 . 
     FIG. 2  shows a portion of apparatus, generally designated  30 , which can be used to isolate the flapper  12  and lock the flapper  12  in the open position. Apparatus  30  includes a portion of lightweight expandable tubular member  32  (e.g. casing, liner, drill pipe or the like). The lightweight expandable member  32  is generally a thin-walled tubular of up to around 5 mm wall thickness that is typically of stainless steel or an alloy of steel (e.g. a nickel alloy). The force required to radially expand a thin-walled (or lightweight) tubular is typically less than that required to expand a conventional expandable tubular member that typically has a wall thickness of greater than 5 mm. For lightweight pipe, the diameter-to-thickness ratio is in the order of 40 to 60, whereas the diameter-to-thickness ratio of conventional expandable tubular members is around 20 to 30. 
   It will be appreciated that conventional expandable members could also be used in the present invention, but lightweight pipe will be referred to as it is preferred for certain embodiments, because less rig equipment need be used for the use of lightweight pipe, and the lightweight pipe itself is easier to handle and requires less force to radially expand it. Also, lightweight pipe facilitates bigger expansion ratios so that the pipe can be inserted into the borehole through other conduits that have relatively small IDs and then radially expanded to increase the ID and/or OD of the lightweight pipe. 
   Referring in particular to  FIG. 2   a , an inflatable element  34  can be used to radially expand the lightweight expandable tubular member  32 . The inflatable element  34  may be a packer or the like, but can be of any design that is capable of inflating and deflating. The inflatable element  34  is attached to, for example, a coiled tubing string, drill pipe (e.g. a drill string) or a wireline (with downhole pump) or the like so that it can be lowered into the borehole. 
   The inflatable element  34  is lowered into the borehole through the bore of the lightweight expandable member  32  and then inflated at the required position to radially expand the ID and/or OD of the member  32 , as shown in  FIG. 2   b . The inflatable element  34  can then be deflated and moved upwards again to a further portion of the member  32  that is to be expanded, where it can be re-inflated to increase the ID and/or the OD of the member  32  (see the sequence of  FIGS. 2   a ,  2   b  and  2   c ). This process can then be repeated until either the entire length of the member  32  is radially expanded, or until certain portion(s) thereof have been expanded, as will be described. 
   It will be appreciated that the member  32  and the inflatable element  34  can be used to repair a faulty or damaged portion of casing, liner or the like in a borehole. The member  32  can be run into the borehole so that it is located within the damaged or faulty portion of the pre-installed casing, liner or the like. Thereafter, the inflatable element  34  is located within the member  32  at a first location (typically one end of the member) and then inflated to expand the member at this first location. The inflatable element  34  is then deflated and moved to a second location, spaced-apart from the first location, and then re-inflated to expand the member  32  at the second location. The second location may be at the opposite end of the member  32 . This process can be repeated until the entire length of the member  32  is radially expanded into contact with the damaged or faulty casing, liner or the like if required. Thus, the member  32  overlays the damaged or faulty portion of the pre-installed casing, liner or the like. 
   Referring again to  FIG. 1 , there is shown a portion of lightweight expandable tubular member  22  that has been inserted through the bore  10   b  of the safety valve  10 . Note that the member  22  has been shown in  FIG. 1  as having portions thereof that have been radially expanded. It will be appreciated that the OD of the member  22  is less than the diameter of the bore  10   b  and the diameter of the throughbore (not shown) of the production string  11  so that it can be passed from the surface through the string  11  and into the bore  10   b  of the valve  10 . 
   As the unexpanded expandable member  22  is passed through the bore  10   b , it engages the flapper  12  and pushes it back to the open position as shown in  FIG. 1 . Once the unexpanded expandable member  22  has been located in the correct position, the inflatable element  34  ( FIG. 2 ) is lowered on a wireline or the like into the member  22  so that the inflatable element  34  is located within the bore of the member  22 . The inflatable element  34  is typically positioned at or near an upper end of the member  22  and then inflated to radially expand the member  22  at the upper end. It will be noted that “upper” and “lower” are being used with respect to the orientation of the safety valve  10  in  FIG. 1 , but this is arbitrary. 
   The radial expansion of the member  22  causes an outer surface thereof to engage an inner surface of the production string  11  to provide a first expanded portion  24 . The inflatable element  34  is then deflated and can be moved downwardly to a second location that is below but adjacent to the first expanded portion  24 . The inflatable element  34  is then re-inflated to provide a second expanded portion  26  in the same manner as the first expanded portion  24 . It will be appreciated that the first and second expanded portions  24 ,  26  may be expanded at the same time, depending upon the length of the inflatable element  34  in a direction that is parallel to the longitudinal axis of the safety valve  10 . Indeed, the length of the member  22  that is radially expanded by the inflatable element  34  is generally dependent upon the length of the element  34 . 
   It will also be appreciated that only the first expanded portion  34  may be required to keep the member  22  in position. Thus, the inflatable element  34  may need to be inflated only once at the upper end. 
   Once the upper portions  24 ,  26  have been expanded, the inflatable element  34  is then lowered through the member  22  to a third location, typically at a lower end of the member  22 . At the third location, the inflatable element  34  is then re-inflated to expand the member  22  to provide a third expanded portion  28 . Again, the inflatable element  34  can be deflated, moved to a different location, and re-inflated to produce various expanded portions where the member  22  has been radially expanded. Indeed, the inflatable element  34  can be used to radially expand the entire length of the member  22  so that an outer surface thereof engages either an inner surface of the production string  11  or the bore  10   b  of the safety valve  12 , but this is not necessary. 
   It will be appreciated that the member  22  need not be expanded at the upper and lower ends thereof, as the member  22  need only be expanded on each side of the flapper  12 . 
   Thus, the flapper  12  is held in the open position by the overlay of the lightweight expandable tubular member  22  that pushes the flapper  12  back and keeps it in the open position. Heavyweight pipe may also be used where the inflatable element  34  is capable of exerting sufficient force to expand heavyweight pipe. 
   It will also be appreciated that the member  22  can be radially expanded at each end simultaneously by using two axially spaced-apart inflatable elements  34  that are coupled, for example, by a shaft (not shown in  FIG. 1 ). The length of the shaft will be dependent upon the length of the expandable member  22  that is to be located in the bore  10   b  of the safety valve  10 . 
   It will further be appreciated that locking the flapper  12  of the safety valve  10  in the open position allows hydrocarbons to be recovered, but it will generally be necessary to install another safety valve elsewhere in the production string  11 . 
   Referring now to  FIG. 3 , there is shown a sliding sleeve valve  50  that is typically used to establish communication between a tubing string  52  and an annulus (not shown) between the tubing string  52  and a casing or liner (not shown). Sliding sleeve valve  50  includes a mandrel  54  that is provided with attachment means (e.g. conventional pin and box screw thread connectors) so that the valve  50  can be incorporated as part of the tubing string  52 . 
   Mandrel  54  includes a perforated portion  56  that includes a plurality of circumferentially spaced-apart ports  58 . A sleeve  60  is located within mandrel  54  that can slide substantially parallel to a longitudinal axis of the sliding sleeve valve  50 . Sleeve  60  is provided with one or more ports  62  that are similar to the ports  58  in the mandrel  60 . 
   The operation of the sliding sleeve valve  50  is well known in the art, and typically uses a wireline shifting tool that has dogs that engage an upper profile  64  so that the sleeve  60  can be pulled upwards to align the ports  62  with the ports  58 . The wireline shifting tool is typically turned upside down so that the dogs engage a lower profile  66  to move the sleeve  60  downwards so that the ports  62  are no longer aligned with ports  58 . 
   The sleeve  60  can sometimes become stuck in the open position (i.e. where the ports  58 ,  62  are aligned). Also, when the ports  62  are mis-aligned with the ports  58  (i.e. when the sleeve  60  is moved downwards) there can sometimes be leakage of production fluids that can be lost into the annulus. 
   A lightweight expandable member  68  can be used to isolate the sliding sleeve valve  50  by blocking the ports  58  in the mandrel  54 . The expandable member  68  is inserted through a bore  54   b  in mandrel  54  and through bore  52   b  of the tubing string  52 , as shown in  FIG. 3 . Thereafter, the inflatable element  34  is used to radially expand at least upper and lower portions  68   u ,  68   l  of the member  68  as described above. It will be noted that the member  68  has been radially expanded over much of its length in  FIG. 3 , although this is not necessary. The radial expansion of the upper and lower portions  68   u ,  68   l  provides a metal-to-metal seal with the mandrel  54  and/or the tubing string  52  and thus fluid flows through the member  68  to the surface. 
   Thus, the member  68  prevents any fluid being lost through ports  58 ,  62  to the annulus, and blocks the ports  58 . 
   It will again be appreciated that a heavyweight expandable tubular member could be used in place of the lightweight one, providing the inflatable element  34  is capable of exerting sufficient force to expand the heavyweight member. 
   It will also be appreciated that the upper and lower ends  68   u ,  68   l  of the member  68  could be expanded simultaneously using two axially spaced-apart inflatable elements  34  that are coupled together. The member  68  need not be expanded along its entire length and can merely be expanded at or near the upper and lower ends  68   u ,  68   l  (or any other convenient location) to close off and seal the sliding sleeve valve  50 . 
   Referring now to  FIG. 4 , there is shown a side pocket mandrel  70  that is a tubing-mounted accessory having a side pocket  72  that can receive a number of different valve assemblies. The side pocket  72  is typically located on the outer diameter of the mandrel  70 . The mandrel  70  is provided with attachment means  74 ,  76  at the ends thereof so that the mandrel  70  can be included as part of e.g. a production string (not shown). The attachment means  74 ,  76  typically comprise conventional pin and box connectors. 
   The valve assembly that can be installed in the side pocket  72  may be of any conventional type, such as a chemical injection valve (not shown) or a gas lift valve (not shown) for example. The valve assembly is typically installed in and removed from the side pocket  72  using a wireline (not shown). 
   In the event that the valve assembly in side pocket  72  fails to operate correctly, a portion of lightweight (or heavyweight) expandable member  78  can be used to straddle an opening  80  that allows the valve assembly to communicate with a bore  70   b  of the mandrel  70 . The valve assembly is typically removed first before the expandable member  78  is located in place, although this is not always necessary. 
   The inflatable element  34  can then be used to radially expand an upper portion  78   u  and a lower portion  78   l  of the member  78  as described above, optionally simultaneously. The member  78  thus straddles the opening  80  and prevents any fluids flowing through the mandrel  70  from being lost. The inflatable element  34  can be used to expand any selected portions of the member  78 , or indeed expand it over its entire length. 
   Where a gas lift valve assembly is used, the member  78  may contain a fixed diameter orifice that will allow gas to be injected from the annulus. Gas lift is a form of enhanced recovery where gas is injected at pressure down the annulus. The side pocket  72  of the mandrel  70  would contain a gas lift valve that is set to open at a certain pressure (typically in the range of between 2000 and 3000 psi). When the pressure in the annulus reaches the pressure that the gas lift valve is set to open at, the valve opens (typically against a spring bias) and allows gas to enter the mandrel  70  and thus the tubing or production string. The gas mixes with the recovered hydrocarbons in the string, thus reducing its density and causing the hydrocarbons to rise to the surface. The injected gas is separated from the hydrocarbons at the surface and re-injected to continue the process. Alternatively, or additionally, the injected gas forms bubbles in the fluids that rise to the surface, sweeping the fluids with them. 
   It may not be desirable to completely seal off the gas lift valve using a portion of lightweight or heavyweight expandable member as shown in  FIG. 4 . Referring to  FIG. 5 , there is shown a schematic representation of the gas lift valve. The valve is represented by a portion of tubing  82  that is provided with a perforation  84 . The perforation  84  represents the gas lift valve that allows gas from the annulus to be injected into the tubing  82 . 
   An expandable tubular member  86  that includes a central heavyweight portion  88  and two lightweight end portions  90 ,  92  is used to isolate the perforation  84  (i.e. the faulty gas lift valve), but can still provide a path for injected gas. The path is provided by a hardened orifice  94  in the heavyweight portion  88 . 
   The two end portions  90 ,  92  may be provided with a coating of a friction and/or sealing material  96  to provide a good anchor and/or seal between the expandable tubular member  86  and the tubing  82 . It will be appreciated that members  22 ,  32 ,  68  and  78  of the previous embodiments may similarly be provided with a friction and/or sealing material  96 . 
   The friction and/or sealing material  96  is typically a rubber material and may comprise first and second bands that are axially spaced-apart along a longitudinal axis of the member  86 . The first and second bands are typically axially spaced by some distance, for example 3 inches (approximately 76 mm). 
   The first and second bands are typically annular bands that extend circumferentially around an outer surface  86   s  of the member  86 , although this configuration is not essential. The first and second bands typically comprise 1-inch wide (approximately 26 mm) bands of a first resilient material (e.g. a first type of rubber). The material  96  need not extend around the full circumference of the surface  86   s.    
   Located between the first and second bands is a third band (not shown) of a second resilient material (e.g. a second type of rubber). The third band preferably extends between the first and second bands and is thus typically 3 inches (approximately 76 mm) wide. 
   The first and second bands are typically of the same depth as the third band, although the first and second bands may be of a slightly larger depth. 
   The first type of rubber (i.e. first and second bands) is preferably of a harder consistency than the second type of rubber (i.e. third band). The first type of rubber is typically 90 durometer rubber, whereas the second type of rubber is typically 60 durometer rubber. Durometer is a conventional hardness scale for rubber. 
   The particular properties of the rubber or other resilient material may be of any suitable type and the hardnesses quoted are exemplary only. It should also be noted that the relative dimensions and spacing of the first, second and third bands are exemplary only and may be of any suitable dimensions and spacing. 
   An outer face of the bands can be profiled (e.g. ribbed) to enhance the grip of the bands on the tubing  82 . The ribs also provide a space into which the rubber of the bands can extend or deform into when the member  86  is expanded, as rubber is generally incompressible. 
   The two outer bands being of a harder rubber provide a relatively high temperature seal and a back-up seal to the relatively softer rubber of the third band. The third band typically provides a lower temperature seal. 
   The two outer bands of rubber can be provided with a number of circumferentially spaced-apart notches (not shown) e.g. four equidistantly spaced notches can be provided. The notches generally do not extend through the entire depth of the rubber bands and are typically used because the first and second bands are of a relatively hard rubber material and this may stress, crack or break when the member  86  is radially expanded. The notches provide a portion of the bands that is of lesser thickness than the rest of the bands and this portion can stretch when the member  86  is expanded. The stretching of this portion substantially prevents the bands from cracking or breaking when the member  86  is expanded. The notches can also provide a space for the rubber to deform or extend into as it is compressed. 
   Alternatively, the material  96  may be in the form of a zigzag. In this embodiment, the material  96  comprises a single (preferably annular) band of resilient material (e.g. rubber) that is, for example, of 90 durometers hardness and is about 2.5 inches (approximately 28 mm) wide by around 0.12 inches (approximately 3 mm) deep. 
   To provide a zigzag pattern and hence increase the strength of the grip and/or seal that the material  96  provides in use, a number of slots (e.g. 20 in number) are milled into the band of rubber. The slots are typically in the order of 0.2 inches (approximately 5 mm) wide by around 2 inches (approximately 50 mm) long. 
   The slots are milled at around 20 circumferentially spaced-apart locations, with around 18° between each along one edge of the material  96 . The process is then repeated by milling another 20 slots on the other side of the material  96 , the slots on the other side being circumferentially offset by 9° from the slots on the first side. The slots also provide a space for the rubber to deform or extend into when the member  86  is expanded. 
     FIGS. 5   a  and  5   b  show the expandable tubular member  86  located in the tubing  82  before it has been expanded. The inflatable element  34  is used to apply a radial expansion force to the lightweight portions  90 ,  92  only to expand them into contact with an inner surface of the tubing  82 , as shown in  FIGS. 5   c  and  5   d . The inflatable element  34  is located on a coiled tubing string, drill string, wireline (with downhole pump) or the like and passed through a bore  82   b  of the tubing  82  and a bore  86   b  of the member  86  to the required position. Thereafter, the inflatable element  34  is inflated to radially expand the portions  90 ,  92 . It will be appreciated that the inflatable element  34  may have to be deflated, moved and then re-inflated to expand the length of the lightweight portions  90 ,  92 . This is of course dependent upon the length of the portions  90 ,  92  and the length of the inflatable element  34 . 
   The portions  90 ,  92  can also be expanded simultaneously by providing two inflatable elements  34  that are axially spaced-apart as described above. 
   As can be seen from  FIGS. 5   c  and  5   d , the friction and/or sealing material  96  comes into contact with the tubing  82  when the portions  90 ,  92  have been radially expanded. The material  96  generally enhances the grip that the member  86  has on the tubing  82  and can also be used as a seal. 
   The heavyweight portion  88  of member  86  is not expanded so that there is an annulus  98  between the heavyweight portion  88  and the tubing  82 . Gas from the orifice  84  (i.e. the gas that has been injected through the gas lift valve) flows into the annulus  98  and through the hardened orifice  94  in the heavyweight portion  88 . The orifice  94  thus allows gas to be injected to enhance the recovery of hydrocarbons. 
   It will be appreciated that the gas injection cannot be controlled as well as with a gas lift valve, but the orifice  94  allows gas to be mixed with the hydrocarbons to facilitate their recovery. 
   It will also be appreciated that a similar member  86  can be used to isolate a faulty or inoperative chemical injection valve or the like. 
   Referring to  FIG. 6   a , there is shown a portion of pre-installed casing  100  that has a lateral borehole  102  drilled through a side thereof in a known manner. Casing  100  is typically a 9 and five eighths inch casing (approximately 245 mm), and the lateral borehole  102  is typically 8½ inches (approximately 216 mm) in diameter. 
   When drilling the lateral borehole  102 , a milled casing exit or opening  104  is formed at or near the casing  100 . The opening  104  is typically drilled or milled at an angle to the longitudinal axis of the casing  100 , and the opening  104  that is formed is typically a rough hole in the surrounding formation and the casing  100 . 
   Conventionally, a hook hanger (not shown) is landed at or near the opening  104  that has a flange (not shown) that mates with the opening  104 . However, the flange is generally not a good fit with the opening  104  as the opening  104  is generally not a precise opening in the casing  100  and formation, and is not usually of precise and constant dimensions and shape. When the flange is presented to the opening  104 , sand etc can get around the side of the flange that falls into the main bore  100   b  through casing  100  and can block the main bore  100   b  thus restricting or preventing the flow of hydrocarbons to the surface. The sand can also cause the blockage of lower lateral boreholes. 
   The sand also causes other difficulties, such as blocking the inlets to downhole pumps and the like, and if the sand enters downhole apparatus such as pumps, it can cause components within the apparatus to wear out or otherwise fail. Furthermore, the contamination of the recovered hydrocarbons with sand and the like necessitates sand management at the surface to sift out or otherwise remove the sand from the recovered hydrocarbons, and can also necessitate sand clean-out trips. 
   In order to prevent the sand etc from sifting into the bore  100   b , a conduit  106  (best shown in  FIG. 6   b ) is located between the flange on the hook hanger and the rough opening  104 . Conduit  106  comprises a portion of, for example, lightweight expandable member that has an elongate or tear-shaped aperture  108 . In use, and as shown in  FIG. 6   a , aperture  108  in conduit  106  is aligned (approximately) with opening  104 . Thereafter, end portions  106   a ,  106   b  of conduit  106  are radially expanded to provide a coupling between the conduit  106  and the casing  100 . An outer surface  106   s  of the conduit  106  can be provided with a friction and/or sealing material  110 , similar to material  96  described above, to enhance the grip of the conduit  106  on the casing  100  and to provide a seal that prevents the ingress of sand etc into the main bore  100   b.    
   It will be appreciated that the material  110  may not be required as the radial expansion of the ends  106   a ,  106   b  of the conduit  106  will provide a metal-to-metal seal by contact of the outer surface  106   s  with the bore  100   b.    
   Referring now to  FIGS. 7   a  to  7   i , there is shown in part cross-section an apparatus  150  that is particularly suitable for expanding end portions  106   a ,  106   b  of the conduit  106 . For clarity, the left-hand side of  FIG. 6   b  is a continuation of the right hand side of  FIG. 6   a  and so on. Conduit  106  can be either a heavyweight or a lightweight member, but is preferably a lightweight member. The aperture  108  in conduit  106  can be seen in  FIGS. 7   c  to  7   g . Aperture  108  is shaped and sized to conform generally to the opening  104  in the casing  100 . 
   Referring to  FIG. 7   a , apparatus  150  includes a connector sub  152  that is provided with a conventional box connection  154  to allow the apparatus  150  to be coupled to a drill string, coiled tubing string, wireline or the like. 
   An inflatable element that typically comprises a packer  156  is threadedly coupled to the connector sub  152  at threads  158 . Packer  156  includes an annular chamber  160  that is located below a plurality of overlapping metal plates  162 . The metal plates  162  typically overlap in the longitudinal direction (i.e. in a direction that is parallel to a longitudinal axis x of the apparatus  150 ). The annular chamber  160  is in fluid communication with a longitudinal bore  164  of the apparatus  150  via a port  166 . An elastomeric covering  168  is located over the metal plates  162 . 
   A centraliser  170 , best shown in  FIG. 8 , is located over the elastomeric covering and engages an end portion  106   e  of the conduit  106 . The centraliser  170  is typically of TEFLON™, although it may also be of rubber or any other suitable material. An O-ring  172  is located in a groove  174  on the centraliser  170  and thus retains the conduit  106  in contact with the apparatus  150 , and also retains the centraliser  170  in position on the apparatus  150  and the conduit  106 . In particular, the centraliser  170  keeps the conduit  106  centralised as the apparatus  150  and conduit  106  are run into the hole, and also provides a coupling between the apparatus  150  and conduit  106 . The centraliser  170  also serves to prevent the ingress of contaminants (e.g. dirt etc) from entering an annulus  176  between the elastomeric covering  168  and the conduit  106 . This is particularly the case when the apparatus  150  is being withdrawn from the casing  100  before the apparatus  150  is operated to expand the end portions  106   a ,  106   b  of the conduit  106 . 
     FIG. 9  shows a view of the apparatus  150  of  FIG. 7   a , but the apparatus  150  is provided with an alternative centraliser  180 . The centraliser  180  comprises a rubber ring  182  that is typically of 90 durometers hardness, although other hardnessess may be used. A first end  184  of the rubber ring  182  is located in the annulus  176  between the elastomeric covering  168  and the conduit  106 . A metal or other clamp  188  is used to hold the rubber ring  182  in place. 
   Referring again to  FIG. 7   b , a second centraliser  190  is threadedly engaged with the packer  156  using threads  192 . The second centraliser  190  is used to ensure that the conduit  106  remains central on the apparatus  150  as it is run into the casing  100 . The second centraliser  190  is provided with shear screws  194  (two shown in  FIG. 7   b ) that are set to shear at a particular pressure (e.g. 500 psi). A port  196  that communicates with the bore  164  of the apparatus  150  is provided in the second centraliser  190 , and a burst disc  198  is located in the port  196 . The burst disc  198  is set to rupture at a pressure of around 4000 psi, and is used for the release of pressure in an emergency as will be described. 
   The shear screws  194  that are set to shear at around 500 psi, also ensure that the packer  156  does not prematurely inflate. This is because the second centraliser  190  cannot move as it is retained in position by the shear screws  194 , and thus the elastomeric covering  168  cannot be axially displaced, thereby preventing the packer  156  from inflating. 
   Referring now to  FIGS. 7   b  and  7   c , there is shown a retainer sub  200  that is threadedly engaged with the packer  156  at threads  202 . The retainer sub  200  includes an annular piston  204  that can slide along an axis that is substantially parallel to the longitudinal axis x of the apparatus  150 . The retainer sub  200  is provided with a port  206  that communicates fluid from outwith the apparatus  150  to a chamber  208 . The fluid enters the chamber  208  forcing the piston  202  to the position shown in  FIG. 7   c . As the piston moves to the left in  FIG. 7   c  under fluid pressure, an outer surface  202   s  of the piston  202  engages a number of radial pistons  210 .  FIG. 7   c  shows only two radial pistons  210 , but it will be appreciated that four such pistons  210  are typically provided, each being circumferentially spaced-apart by 90°. 
   The radial pistons  210  are pushed outwardly by the outer surface  202   s  as the piston  202  moves to the left. An outer end  210   e  of the radial pistons  210  dimple an inner surface  106   i  of the conduit  106  and thus provide a means of locking or retaining the conduit  106  in place on the apparatus  150 . Indeed, the retainer sub  200  also serves to centralise the conduit  106 . It will be appreciated that the radial pistons  210  have been shown as protruding through the conduit  106 , but the pistons  210  only require to dimple the inner surface  106   i  to retain the conduit  106  in place. The retainer sub  200  is typically actuated at the surface before the apparatus  150  is run in. 
     FIGS. 7   c  to  7   f  show an intermediate sub  220  that is threadedly engaged at a first end with the retainer sub  200  at threads  224 , and threadedly engaged at a second end with a locator sub  230 , best shown in  FIG. 7   g , at threads  226 . 
     FIG. 7   g  shows a locator sub  230  that includes a spring-loaded locator arm  232 . Arm  232  is normally biased to a radially extended position (as shown in  FIG. 7   g ), but can be retracted into a slot  233  in the sub  230 . The arm  232  is located in an elongate slot  109  of the aperture  108  in conduit  106  ( FIG. 6   b ). 
   As the apparatus  150  is being run into the casing  100 , the arm  232  is pushed back against the spring bias that tends to extend the arm  232 . When the apparatus  150  approaches the opening  104  in casing  100 , the spring loaded arm  232  springs outward through the opening  104  and locates the apparatus  150  at a lower end of the opening  104 . The locator sub  230  thus ensures that the conduit  106  is located correctly before the ends  106   a ,  106   b  are radially expanded, as will be described. 
   The locator sub  230  is threadedly engaged at a second end thereof with a second intermediate sub  240  at threads  242 . Referring to  FIG. 7   h , the other end of the intermediate sub  240  is threadedly engaged with a second packer  256 , which is substantially the same as the first packer  156 , at threads  244 . Like features of the packer  256  have been designated with the same reference numerals prefixed “2” instead of “1”. 
   The second packer  256  is threadedly engaged at its second end with a third centraliser  290 , which is substantially the same as the second centraliser  190 , at threads  292 . Like parts of the third centraliser  290  have been referenced with the same numeral prefixed “2” instead of “1”. 
   The end  106   b  of the conduit  106  is swaged ( FIG. 7   i ) to reduce the diameter thereof so that it engages an outer surface  268   s  of the elastomeric coating  268 . This substantially prevents the ingress of fluid, dirt etc into the annulus  276  between the elastomeric covering  268  and the conduit  106  as the apparatus  150  is run into the casing  100 . The first centraliser  170  ( FIG. 7   a ) or the alternative centraliser  180  ( FIG. 9 ) may used in place of, or in addition to, the swaged end  106   b . Thus, a centraliser  170 ,  180  could be used at both ends  106   a ,  106   b  of the conduit  106 . 
   The second packer  256  is threadedly engaged at threads  302  with a ball catcher  300  ( FIG. 7   i ). Ball catcher  300  is provided with a ball seat  304  that receives a ball  306  in use. The ball seat  304  is provided with shear screws  308  that retain the seat  304  in contact with the ball catcher  300  until a pressure of around 3000 psi is applied to the ball seat  304 . The catcher  300  has an annular shoulder  310  that retains the ball seat  304  when the shear screws  308  shear, as shown in phantom in  FIG. 7   i . The ball catcher  300  is also provided with circumferentially spaced-apart ports  312  that are used to bleed off pressure within the apparatus  150  as will be described. Four such ports  312  are typically provided, each port  312  being circumferentially spaced-apart from one another by around 90°. 
   Operation and use of the apparatus  150  shall now be described, with reference in particular to  FIGS. 6   a  and  7   a  to  7   i.    
   The apparatus  150  is assembled as described above and the conduit  106  is located over the apparatus  150  as shown in  FIGS. 7   a  to  7   i . In particular, the spring-loaded arm  232  is located in the elongated slot  109  of the aperture  108  in the conduit  106 . The conduit  106  is held in place on apparatus  150  initially by the centraliser  170  ( FIGS. 7   a  and  8 ) or the centraliser  180  ( FIG. 9 ). Also, the swaged end  106   b  of the conduit  106  ( FIG. 7   i ) engages the outer surface  268   s  of the elastomeric covering  268  of the second packer  256  that aids to keep the conduit  106  in place. 
   The conduit  106  is also held in place on the apparatus  150  by actuation of the retainer sub  200 . A pressure source (e.g. a hydraulic hand pump or the like) is coupled to the port  206  and pressure is applied to the piston  202  to move it to the position shown in  FIG. 7   c . As the piston moves from right to left as shown in  FIG. 7   c , the piston  202  contacts the lower surface of the radial pistons  210  and pushes them radially outward so that the end  210   e  contacts and dimples the inner surface  106   i  of the conduit  106 . The piston  202  is held in this position by locating a number of shear screws  209  (two shown in  FIG. 7   c ) that lock the piston  202  in place. The shear screws  209  are typically rated to shear at a pressure of around 500 psi. Thus, the conduit  106  is rigidly attached to the apparatus  150  and also centralised with respect to the apparatus  150 . 
   The apparatus  150  is then attached to a drill string, coiled tubing string or the like using the box connection  154 . The apparatus  150  can then be run into the casing  100  on the drill string or coiled tubing string. As the apparatus  150  is being run in, the spring loaded arm  232  is compressed into slot  233  by engagement with the casing  100 . However, when the apparatus reaches the opening  104  in casing  100 , the arm  232  springs radially outward and engages a lower surface of the opening  104 , thus correctly locating the conduit  106  and the apparatus  150 . 
   The ball  306  is then dropped down the bore of the drill string or the coiled tubing string so that it passes through the bore  164  of the apparatus  150  and engages the ball seat  304 , as shown in  FIG. 7   i . Pressure is then applied by pressuring up the bore of the drill string or coiled tubing string and the bore  164  against the ball  306 . The pressure is typically in the order of 500 psi or more and is generally increased up to around 1400 psi or more to fully inflate the packers  156 ,  256 . 
   As the pressure is increased over around 500 psi, fluid from the bore  164  enters the annular chambers  176 ,  276  of the packers  156 ,  256  through the ports  166 ,  266 . The increase in pressure in chambers  176 ,  276  serves to push the metal plates  162 ,  262  outwardly against the elastomeric coverings  168 ,  268  that are also pushed outwardly. The outward movement of the elastomeric coverings  168 ,  268  continues until they engage the inner surface  106   i  of the conduit  106  at or near the ends  106   a ,  106   b . Continued application of pressure into the annular chambers  176 ,  276  causes the elastomeric coverings  168 ,  268  to radially expand the ends  106   a ,  106   b  as shown in  FIG. 6   a , so that the ends  106   a ,  106   b  contact the inner surface of the casing  100 . It will be appreciated that the conduit  106  shown in  FIGS. 7   a  to  7   i  is not provided with a friction and/or sealing material  96 ,  110 , although this can be provided. 
   The radial expansion of the ends  106   a ,  106   b  secures the conduit  106  in place around the opening  104  and the contact between the conduit  106  and the casing  100  provides a seal (optionally with a friction and/or sealing material  96 ,  110 ) that prevents the ingress of sand, silt, shale or the like into the main bore  100   b  of the casing  100 . The flange for the hook hanger can then be landed on the aperture  108  in the conduit  106 . This is advantageous as the size and shape of the aperture  108  will generally be constant and the flange of the hook hanger can be made to fit the aperture  108  easily. Also, as the ends  106   a ,  106   b  only of the conduit  106  are radially expanded, the radial expansion of these ends  106   a ,  106   b  should not interfere with the size and shape of the aperture  108 . 
   As the packers  156 ,  256  inflate, the centraliser  170  ( FIG. 7   a ) disengages from the O-ring  172  located in the groove  174 . This is because an end  170   a  of the centraliser  170  is contacted first by the expansion of the elastomeric covering  168 ,  268 , that serves to pivot or tilt the centraliser  170  around the end  170   a . This pivoting or tilting pushes the opposite end  170   b  towards the elastomeric covering  168 ,  268  causing the O-ring  172  to be disengaged from the groove  174 . Further expansion of the packers  156 ,  256  causes the centraliser  170  to be pushed towards the left in  FIG. 7   a  so that it does not interfere with the radial expansion of the end  106   a , although it will remain engaged with the apparatus  150  and can be retrieved from the casing  100  therewith. 
   Where centraliser  180  is used ( FIG. 9 ), the relatively hard (and thus incompressible) rubber transfers the expansion force of the packer  156  as it expands to the end  106   a  of the conduit  106 . This causes the end  106   a  to be radially expanded whilst the centraliser  180  remains in place on the apparatus  150  and can be withdrawn from the casing  100  therewith. 
   It will be appreciated that as the elastomeric coverings  168 ,  268  expand, they become shorter in the axial direction. Thus, the shear screws  194 ,  294  that retain the second and third centralisers  190 ,  290  in place shear off, and the second and third centralisers  190 ,  290  can move towards the left in  FIGS. 7   b  and  7   i  as the coverings  168 ,  268  contract. It will be appreciated that as the apparatus  150  has been correctly located and the expansion process has begun, there is no requirement to keep the conduit  106  centralised with respect to the longitudinal axis x of the apparatus  150 . The shear screws  194 ,  294  are typically rated to shear at around 500 psi. 
   It will also be appreciated that the conduit  106  does not need to be retained in contact with the apparatus  150  during the expansion process. Thus, and with reference to  FIG. 7   c , as the pressure reaches around 500 psi, the shear screws  209  shear and fluid enters an annular chamber  211  at the left hand side of the piston  202  through a port  213  that transfers pressure from the bore  164 . The piston  202  is pushed to the right in  FIG. 7   c  and the fluid pressure in chamber  208  is vented to outside the apparatus  150  through the port  206 . As the piston  202  moves to the right, the outer surface  202   s  no longer engages the radial pistons  210  and they can move radially inward so that they no longer engage the conduit  106 . 
   The pressure in bore  164  is increased causing the packers  156 ,  256  to expand the ends  106   a ,  106   b  until the pressure reaches around 3000 psi. At this pressure, the shear screws  308  that retain the ball seat  304  in the location shown in  FIG. 7   i  shear, and the ball seat  304  is forced to the right to the position shown in phantom in  FIG. 7   i . The ball seat  304  engages the shoulder  310  so that it is retained within apparatus  150  for retraction from the casing  100  therewith. With the ball seat  304  having moved to engage the shoulder  310 , this opens the ports  312  and allows pressure from within the bore  164  to be vented to outwith the apparatus  150 . The venting of the pressure in the bore  164  allows the packers  156 ,  256  to deflate as the pressure in the annular chambers  176 ,  276  is vented into the bore  164  through ports  166 ,  266  and out of the apparatus  150  through the ports  312 . 
   It will be appreciated that the inflation of the packer  256  can cause a seal in the annulus between the apparatus  150  and the casing  100  at or near the ball catcher  300 , and it is sometimes the case that the ball seat  304  cannot be forced to the right as shown in  FIG. 7   i  to release the pressure in the bore  164  because there exists a pressure lock or the like between the packer  256  and some point below ball catcher  300 . In this case, the ball seat  304  will not move to the right as the pressure in the annulus around the ball catcher  300  is greater than the pressure within the bore  164 . 
   However, the apparatus  150  is provided with pressure release channels  350 ,  352  that are located near the packers  156 ,  256  respectively (see  FIGS. 7   a ,  7   b ,  7   c ,  7   g ,  7   h  and  7   i ). The release channels  350 ,  352  provide a path through the apparatus  150  that allows the pressure trapped at or near the ball catcher  300  to be vented to the left of the apparatus in  FIG. 7   a . The pressure at or near the ball catcher  300  enters the release channel  352  through a port  354  ( FIG. 7   i ). The pressure then travels through the release channel  352  and by-passes the packer  256  to be vented to the annulus between the two intermediate subs  220 ,  240 , the locating sub  230  and the conduit  106  through a port  356 . The pressure then enters release channel  350  through a further port  358  ( FIG. 7   b ) and travels through release channel  350  to be vented to the left of the apparatus  50  in  FIG. 7   a  via a further port  360 . This equalises the pressure around the apparatus  350  and allows the pressure within the bore  164  to be vented as the ball seat  304  can now move to engage shoulder  310 , thus allowing the pressure to bleed off through ports  312  and also through the release channels  350 ,  352  if required. Thus, the packers  156 ,  256  can then deflate as described above. 
   In the event that the ball seat  304  cannot be moved under pressure to engage the shoulder  310  and thus vent the pressure in the bore  164 , the pressure can be increased to around 4000 psi. At this pressure, the burst discs  198 ,  298  rupture and pressure can be vented from the bore  164  through the ports  166 ,  266  to the chambers  176 ,  276  where it is retained by an O-ring seal  177 ,  277  and thus vented to outwith the apparatus  150  through the ports  196 ,  296 . 
   Thus, the present invention provides a method and apparatus for performing remedial and installation operations that in certain embodiments uses at least one inflatable element to expand portion of a lightweight and/or heavyweight expandable member. The present invention in certain embodiments also provides a method and apparatus for creating a conduit between an opening drilled into a casing to form a lateral borehole and a flange on a hook hanger. 
   Modifications and improvements may be made to the foregoing without departing from the scope of the present invention.

Summary:
Aspects of the invention relate to apparatus and methods for remedial and repair operations downhole. Certain embodiments of apparatus include a lightweight expandable member ( 22 ) that can be radially expanded to increased its inner and outer diameters using an inflatable element ( 34 ). The lightweight member ( 22 ) can be used to repair a fautly safety vavle flapper ( 12 ) for example. The invention also relates to lateral tubular adapter apparatus and a method of hanging a lateral from a cased borehole.