Abstract:
An apparatus and method for providing a tubular connection in the form of a liner tieback connection or a liner hanger in a slim hole well as found in deep wells. When installing the casing sections, a first casing section having a profiled surface distinct from a surface of an adjacent casing section is provided. A liner is run into the first casing section and a part of a portion is radially expanded to morph against the inner surface of the first casing section at the profiled surface and form a sealed joint. Various arrangements of profiled surfaces are provided. The liner may also have a profiled surface. By adapting the casing section to receive the liner directly, a slim hole well construction is achieved.

Description:
FIELD OF THE INVENTION 
     The present invention relates to an apparatus and a method for connecting tubular members in a wellbore and more particularly, though not exclusively, to an apparatus and a method for providing a tieback connection in a slim hole well. 
     BACKGROUND TO THE INVENTION 
     Wellbores are typically formed by drilling a borehole to a first pre-determined depth and then lining the borehole with a steel casing. Typically, a number of sections of casing of decreasing diameter are used. A first section of casing is lowered into the wellbore and hung from the surface after the well has been drilled to a first designated depth. Cement is then circulated in the annulus between the outer wall of the casing and the borehole. The well is then drilled to a second designated depth and a second section of casing having a smaller diameter is run into the well. This process is typically repeated with additional casing sections of decreasing diameter until the well has been drilled to the total required depth. 
     According to one solution, the second section may be sufficiently long to extend to a wellhead and be “hung off” in the wellhead at surface. Once “hung off”, the second casing section is then cemented in the same manner as the first section. In some instances engineers prefer this solution to maintain well integrity. However, in certain environments, such as for example, in deepwater environments, long casing is often too heavy to risk as a single deployment. Also, Equivalent Circulating Density (ECD) with a long string can be too high causing the potential for circulation loss zones. Also, the annulus between the drillstring and the casing during drilling is relatively narrow all the way between the drilling assembly downhole and the wellhead meaning that higher pressure is needed to pump the drilling fluid through the annulus back to surface. Such high pressures may be high enough to cause the drilling mud to be pumped into the formation being drilled and thus cause damage or even destruction to the reservoir. 
     According to an alternative solution, the second section is fixed at a depth such that the upper portion of the second section overlaps the lower portion of the first section of casing. In this example, the casing which does not extend to surface is referred to as a “liner”. The liner section is then fixed to the first casing section, such as by using a device called a liner hanger. The liner section is then cemented in the same manner as the first casing section. As well design becomes more challenging, due to longer step outs and deeper targets, and reservoirs become depleted, there are more reasons to design well construction with critical casing strings run as liners. Also, in most wells, the use of liners mitigates the high mud pressure problem associated with the use of the long casing because when the liners are used, the annulus is relatively narrow only within the liner and becomes wider within the casing above the liner. 
     After the well has been drilled, it may be necessary to connect the liner string back to the surface (or a point higher up in the well). In this case, a string of casing is sealingly connected to the top of the liner section and runs all the way back to surface so that the liner is “tied back” to the surface (or a point higher in the well between the surface and the liner hanger). 
     The area above the production zone of the well is typically sealed using packers inside the casing or liner and connected to the surface via smaller diameter production tubing. This provides a redundant barrier to leaks, and allows damaged sections to be replaced. Also, the smaller diameter of the production tubing increases the velocity of the oil and gas. The natural pressure of the subsurface reservoir may be high enough for the oil or gas to flow to the surface. When this is not sufficient, such as for older wells, installing smaller diameter tubing may help the production, but artificial lift methods, such as gas lift, may also be needed. The well needs to be configured to receive the artificial lift apparatus. 
     Known methods for sealingly connecting a tie-back string of casing into a downhole liner section typically involve the use of a tool known as a polished bore receptacle (PBR). The PBR is a separate tool which is screwed to the top of the liner section. The PBR has a smoothed cylindrical inner bore configured to receive the lower end of the tieback casing. The tieback casing is landed in the PBR to form a sealed connection between the tieback casing and the liner. The lower portion of the tieback casing is configured with seals on its outer diameter and these seals seal within the PBR. 
       FIG. 1  shows a known method of providing liner tieback connection in a wellbore  100  in which a second tube  10  is tied back to the surface using a first tube  12 . The wellbore  100  is dined with a casing  102  which incrementally decreases in diameter as the depth increases. Tubing  104  for gas lift, with an internal gas lift valve  106 , is provided within the casing  102 . The second tube  10  has a diameter of 9⅝ in (244 mm) and extends upwards into the upper adjacent casing which has a diameter of 13⅜ in (340 mm). A PBR  14  is connected to the upper end of the second tube  10 . A liner hanger  16  at an upper portion, and cement  108  at a lower portion, fix the second tube  10  within the wellbore  100 . The first tube  12  is lowered and the lower end of the first tube  12  fits within the polished bore of the PBR  14 . By itself, particularly in harsh environments, the PBR  14  may not be able to provide sufficient sealing and so a tie back packer  18  can be provided above the joint of the first and second tubes. The slidable sealing provided by the PBR  14  does not assist with supporting the first tube  12  in the wellbore  100  and so an anchor  20  may also be provided. 
     A major disadvantage of this known tieback connection is that the majority of the inside length of the PBR is exposed and is susceptible to damage as other downhole tools are run into the wellbore. A downhole tool being run through the PBR may impact the polished inside surface of the PBR on its way downhole. This can cause damage that reduces the sealing ability of the PBR. Also, drilling debris can degrade the PBR sealing surfaces. In addition, it is known that associated components, such as tie back stingers, seal stems and packers can leak, particularly in harsh environments. Furthermore, the PBR allows for thermal expansion and contraction of the tieback liner longitudinally, during which the liner seals can move up and down in the PBR. Over time this movement can cause the seals to wear and ultimately to fail. This is regarded to be one of the major limitations of a conventional PBR. A conventional seal stem relies on elastomeric seals to create the seal between the tie-back string and the liner within the PBR. Elastomeric seals are prone to damage during deployment and are inherently prone to wear over time and thus cannot be relied upon to last the life of well. In addition they will be worn due to relative movement when the well temperature changes during production and shut in cycles. Hence, elastomeric seals are no longer considered suitable for a well barrier in some areas. Still furthermore, the PBR is generally short (3-4 m) causing spacing out of the tieback string to be sometimes difficult to achieve successfully first time. In deep wells, especially subsea wellheads, this can have a substantial time and cost implication. It is usually not possible to lengthen the PBR due to the design of the liner hanger system. A PBR is prone to damage and a relatively minor score may compromise the seal. Furthermore, the use of elastomeric seals in the well barrier envelope is not allowed in certain places, e.g. in the Norwegian sector of the North Sea. For the above reasons, engineers sometimes prefer to run a long casing string. 
     The applicant has appreciated the need for an alternative means of connecting to a liner which eliminates the need for a PBR or which reduces the likelihood of damage to a PBR and provided such an alternative arrangement. This arrangement is described in WO2011/048426 A2 and illustrated in  FIGS. 2 to 5  as an alternative prior art method of providing liner tieback connection in a wellbore  100 . Like features are given like reference numerals to those of  FIG. 1 . A tieback profile device  30  is provided at the upper end of the second tube  10  such that it has a greater diameter than the diameter of the second tube  10 . The device  30  includes a number of internal recesses  32  at its internal bore. A 13⅜ in (340 mm) by 11¾ in (298 mm) liner hanger  34  is connected to the top of the device  30  and this attaches to the casing at the inner surface of the wellbore  100 . The liner hanger  34 , device  30  and upper portion of the second tube  10  are all configured to cross over from 13⅜ in (340 mm) to an outer diameter of 9⅝ in (244 mm).  FIGS. 3 to 5  illustrate the sequence for installing the first tube  12 . The first tube  12  is lowered so that its lower end is within the device  30  and lower than the internal recesses  32  of the device  30  ( FIG. 4 ). An expandable tool  40  is then run on the lower end of a string of drillpipe down through the bore of the first tube  12  until the tool  40  is aligned with the recesses  32  of the device  30 . The tool  40  includes a depth latch arrangement  42  for positioning at the correct vertical depth. The tool  40  includes a pair of seals which are vertically spaced apart by a distance greater than the vertical distance between the upper and lower recesses. The seals are actuated to form a seal between the outer surface of the tool  40  and the inner surface of the first tube  12  to define a chamber between the seals. Water is pumped through the drillstring, into the bore of the tool  40  and through apertures of the tool  40  and into the chamber. When the water pressure is sufficient, the first tube  12  expands by elastic then plastic deformation into the recesses  32 . This creates a mechanical fixing and metal to metal seal between the second tube  10  and the first tube  12  via the device  30 . The first tube  12  is now tied back to the surface. The seals can then be de-activated and the drill pipe string and tool  40  removed from the wellbore  100 . 
     The improved arrangement provides a number of advantages over a conventional PBR. The metal to metal seal has sufficient resistance to the thermally generated axial loads. There is therefore little or no movement and so no wear. Also, the need for elastomeric seals is eliminated, so the device has no elastomeric material to wear out or get damaged. Also, the internal diameter of the device is not a polished seal surface and so its performance is much less affected by damage. Also, higher burst and collapse loads can be achieved. 
     However, while this method eliminates the need to use a PBR connection, it has a major limitation in that for certain wells the annular space between the outer casing string ID and the liner string OD too small to fit the expandable tieback connection. In a relatively narrow diameter or slim well construction, which is typical for e.g. the Caspian Sea or the Gulf of Mexico, there is very little annular space between the outer casing string and the liner. It is typical that the outer casing string has an outer diameter (OD) of 16 inches (40.6 cm) and an internal diameter (ID) of 14.6 inches (37.1 cm) and the liner string has an OD of 14 inches (35.6 cm). The annular space between the outer casing string ID and the liner string OD of 0.3 inches (0.8 cm) is too small to fit a PBR or the expandable tieback connection of WO2011/048426 A2. We consider any wellbore where the annular space is too small to fit a standard PBR as a slim hole well. 
     Accordingly, an object of at least one embodiment of the present invention is to provide an expandable tieback connection suitable for use in a slim well construction. 
     SUMMARY OF THE INVENTION 
     According to a first aspect of the present invention there is provided a tubular connection apparatus for use in a slim hole well, comprising:
         a plurality of casing sections, wherein at least a first casing section comprises a tubular member, the member having a profiled surface distinct from a surface of an adjacent casing section;   a liner, wherein a portion of the liner is located within the first casing section and at least a part of the portion has been radially expanded to form a sealed joint between the liner and the first casing section.       

     In this way, the liner is connected directly to the casing and a PBR or an expandable tieback connection is not required. Thus by adapting the casing section to receive the liner directly, the annular space between the outer casing string ID and the liner string OD only requires to be of a tolerance to allow the liner to be run into the casing string. This provides a slim hole well construction with the maximum inner bore diameter possible for the liner. 
     Preferably, the profiled surface is at least a portion of an inner surface having an inner diameter smaller than an inner diameter of the adjacent casing section. Preferably also, an outer surface of the first casing section is also profiled having at least a portion with an outer diameter greater than an outer diameter of the adjacent casing section. In this way, the first casing section is profiled to provide a greater wall thickness than the adjacent casing section. 
     Alternatively or additionally, the profiled surface includes one or more recesses. The profiled surface may be an inner surface of the first casing section and/or an outer surface of the first casing section. In this way, the first casing section is profiled to assist in anchoring the liner to the first casing section. 
     Preferably, the portion of the liner is a lower end of the liner. In this way, the apparatus is a liner tieback connection. 
     Alternatively, the portion of the liner is an upper end of the liner. In this way, the apparatus is a liner hanger connection. 
     In an embodiment, there is a first liner and a second liner wherein the portion, being an upper end, of the first liner is located within the first casing section and the portion, being a lower end, of the second liner is located within the first casing section axially upwardly spaced from the first liner. 
     Alternatively, the apparatus includes a further liner, the further liner being hung from a lower end of the first casing section by a known method and the liner is arranged to form a liner tieback connection according to the present invention. 
     Preferably, the first casing section and at least the part of the portion of the liner comprise metallic portions which form a metal-to-metal sealed joint when the part is expanded against the first casing section. 
     Preferably, a fluid excluding material is located into the one or more recesses. In one arrangement, the fluid excluding material comprises closed cell foam, such as, for example, metal foam or syntactic foam. 
     Alternatively, the one or more recesses include a valve, the valve being configured to allow fluid to exit the recess when the fluid is subjected to pressure from the part of the liner expanding into the recess. In one arrangement, the valve is a one-way valve that allows fluid to escape as the pressure in the recess increases, and is sealed shut by the part of the liner once the sealed joint with the first casing section has been formed. Alternatively, the valve may be a pressure relief valve that allows the fluid to escape into an atmospheric chamber when the pressure in the recess is higher than an opening value of the valve. 
     In all types of casing having one or more recesses on the outer surface or the inner surface, the recess shape, depth and width are adjusted to suit the strength and weight of the casing and/or the liner being expanded into it. Furthermore, preferably, the yield stress of the first casing section is selected higher than the yield stress of the part of the portion of the liner. 
     Preferably, the part of the portion of the liner comprises a tubular member having a wall defining an internal bore and first and second ends, the internal bore extending between the ends and having a profiled surface. 
     In one such arrangement, the internal bore of the part has a greater diameter at a region intermediate the ends and the internal bore tapers from the intermediate region to the ends. Preferably in this variation, the thickness of the wall of the part increases from the intermediate region to the ends. This ensures that the part begins to expand at the intermediate region and continues to expand towards the ends causing fluid at the interface between the liner and the first casing section to be expelled as the part expands thereby preventing the occurrence of a hydraulic lock. 
     In another variation, the internal bore of the part is tapered from one end to the other end. Preferably, in this variation, the thickness of the wall of the part increases from one end to the other end, so that the part begins to expand at the thinner end and continues to expand towards the thicker end causing fluid at the interface between the liner and the first casing section to be expelled as the part expands. 
     The part may be provided with circumferential seals on the outer surface to enhance the sealing performance between the liner and the first casing section. 
     The apparatus may further include a wear protection tubular cover. Preferably the wear protection cover is a sleeve. Preferably the cover includes a fastening arrangement to attach the cover to an inner surface of the first casing section. The fastening arrangement may be shear pins or a spring latching mechanism. The cover may be provided with a sealing mechanism on an outer surface of the cover, i.e. the surface which in use faces the inner surface of the casing, so that, in use, the sealing mechanism is positioned between the cover and the casing to prevent well debris from entering a space between the cover and the casing and from causing the cover to become jammed in place. 
     According to a second aspect of the present invention there is provided a method of forming a tubular connection for use in a slim hole well, the method comprising the steps of:
         a) installing a plurality of casing sections in a wellbore, wherein at least a first casing section comprises a tubular member, the member having a profiled surface distinct from a surface of an adjacent casing section;   b) setting the casing sections in the wellbore;   c) running a liner into the wellbore so that a portion of the liner is located within the first casing section; and   d) expanding at least a part of the portion of the liner radially against the first casing section at the profiled surface until a sealed joint is formed between the liner and the first casing section.       

     Preferably, the profiled surface is at least a portion of an inner surface having an inner diameter smaller than an inner diameter of the adjacent casing section. Preferably also, an outer surface of the first casing section is also profiled having at least a portion with an outer diameter greater than an outer diameter of the adjacent casing section. In this way, the first casing section is profiled to provide a greater wall thickness than the adjacent casing section. 
     Alternatively or additionally, the profiled surface includes one or more recesses. The profiled surface may be an inner surface of the first casing section and/or an outer surface of the first casing section. In this way, the first casing section is profiled to assist in anchoring the liner to the first casing section. 
     Preferably, in step (c) the portion of the liner is a lower end of the liner. In this way, a liner tieback connection is made. 
     Alternatively, in step (c) the portion of the liner is an upper end of the liner. In this way, a liner hanger connection is made. 
     In an embodiment, step (c) includes running a first liner into the wellbore so that a portion, being an upper end, of the first liner is located within the first casing section; and the method further includes the steps:
         e) running a second liner into the wellbore so that a portion, being a lower end, of the second liner is located within the first casing section axially upwardly spaced from the first liner; and   f) expanding at least a part of the portion of the second liner radially against the casing at the profiled surface until a sealed joint is formed between the liner and the first casing section.       

     In this way, both a liner hanger and a tieback connection are formed on the casing section. 
     Alternatively, the method may include the step of hanging a first liner from a lower end of the first casing section by a known art method prior to forming a liner tieback connection with a second liner according to the present invention. The first liner may be sealed to the first casing section using a suitable sealing arrangement, such as, for example, one or more packers. 
     Preferably step (d) includes elastically and plastically deforming the part of the portion of the liner. Preferably also, step (d) includes elastically deforming a portion of the first casing section. 
     Preferably, step (d) includes radially expanding the part of the liner so that an outer diameter of the part expands from a diameter which is smaller than an internal diameter of the casing to a diameter which matches the internal diameter of the first casing section. 
     Preferably, step (d) includes excluding fluid from the one or more recesses arranged on the surface of the first casing section during expansion. In an embodiment the fluid may exit the recess through a valve. The method may include the step of sealing the valve with the part of the liner following expansion. 
     The above described methods all help to eliminate or reduce the risk of occurrence of a hydraulic lock. 
     Preferably the method includes the step of running a fluid expansion tool on a tubular string through a bore of the liner. The method may include the step of aligning the expansion tool with the portion of the first casing section against which the liner is expanded. The method may include using a depth latch arrangement to position the expandable tool at the correct vertical depth. 
     Preferably, the method includes the steps of: actuating a pair of seals of the expansion tool, the seals being spaced apart over the part of the portion of the liner; creating a sealed chamber between an outer surface of the tool and the inner surface of the liner; supplying a fluid into the chamber; apply fluid pressure against the inner surface of the part of the portion of the liner to thereby cause expansion of the part against the inner surface of the first casing section and form a sealed joint between the outer surface of part of the portion of the liner and the inner surface of the first casing section. Preferably the fluid is a high pressure liquid (e.g. pressure in excess of 20,000 psi or 138 MPa). Preferably, the part is morphed against the inner surface of the first casing section such that the part takes up the shape of the inner surface of the first casing section. 
     In some circumstances it is desirable to run and set the first casing section, hang a liner from the first casing section and then start drilling the next section of open hole, before tying back the liner to the wellhead. On these occasions, the portion of the inner surface of the first casing section against which the liner is expanded to form the sealed joint may remain exposed to well fluids and a rotating drill string for a considerable period of time (days or weeks) and become damaged by the drill string and the fluids. Therefore, advantageously, the method includes the step of installing a wear protection tubular cover over the inner surface of the first casing section. The method may then include the step of removing the cover prior to step (c). This may be done by using a pulling tool or a standard casing spear to release a fastening arrangement between the cover and the first casing section. 
    
    
     
       DETAILED DESCRIPTION OF THE INVENTION 
       Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings in which: 
         FIG. 1  is a sectional side view of a method of providing a liner tieback connection according to the prior art; 
         FIG. 2  is a sectional side view of a further prior art method of providing a liner tieback connection; 
         FIGS. 3 to 5  are sectional side views of stages of the prior art method of  FIG. 2 ; 
         FIGS. 6 to 9  are sectional side views of a number of different embodiments of a first casing section that can be used in the method of providing a tubular connection according to the present invention; 
         FIG. 10  is a sectional side view showing a cover used in conjunction with the first casing section used in the method of the present invention; 
         FIGS. 11 to 13  are sectional side views of a part of a portion of a liner for connecting with the first casing section of  FIGS. 6 to 10 ; 
         FIGS. 14 to 17  are sectional side views of stages of the method according to the present invention (making use of the embodiment of first casing section of  FIG. 7 ); and 
         FIGS. 18 to 25  are sectional side views showing stages of connecting liner into embodiments of first casing sections used in the method according to the present invention. 
     
    
    
     Referring to  FIGS. 6 to 25 , these show a method of providing a tubing connection in a slim hole wellbore  200  according to the present invention. 
     Referring initially, to  FIGS. 14 to 17 , the wellbore  200  is lined with a casing  300  as shown in  FIG. 14  where the casing  300  is in accordance with the present invention. Casing  300  will be arranged adjacent to other standard casing as is known in the art. 
     In an embodiment, a first tubular member (not shown in the drawings), typically, a downhole liner, is hung in the wellbore  200  so that an upper end portion of the first tubular member is located about a lower end  302  of the casing  300  and overlaps with the lower end  302  of the casing  300 , similar to the arrangement shown in  FIG. 1 . The first tubular member is sealed to the casing  300  using a suitable sealing arrangement, such as one or more packers, similar to packers  18  in  FIG. 1 . The next step in the method, as shown in  FIG. 15 , is for a second tubular member  400 , typically tieback liner  400 , to be run into the wellbore  200  and it is manoeuvred in the casing  300  so that a lower end  402  of the second tubular member  400  is located towards the lower end  302  of the casing  300  and above and vertically spaced from the upper end portion of the first tubular member. It should be noted that, although the method of  FIGS. 14 to 17  shows the use of the embodiment of casing  300  of  FIG. 7 , any of the embodiments of casing  300  from  FIG. 6  or  FIGS. 8 to 10  can also be used. 
     The second tubular member  400  comprises an expandable portion  404  at the lower end  402 . The expandable portion  404  is a part of the second tubular member  400 . Initially, the expandable portion  404  has an outer diameter smaller than the internal diameter of the casing  300  so that the expandable portion  404  can be advanced in the casing  300  to the correct location within the casing  300 . Once positioned at the correct location, the expandable portion  404  of the second tubular member  404  is deformed and expanded radially outwardly against an inner surface  308  of the casing  300  by means of an expansion tool  600  (see  FIG. 16 ), as will be described below in more detail, until a sealed connection is formed (see  FIG. 17 ) between an outer surface  466  of the second tubular member  400  and the inner bore of the casing  300 . Upon expansion, the outer diameter of the expandable portion  404  matches the internal diameter of the casing  300 . The casing  300  and the second tubular member  400  are made from metal. Thus, when the second tubular member  400  is expanded against the casing  300 , a metal-to-metal sealed joint is created. 
     As shown in  FIG. 14 , the first embodiment of the casing  300  comprises a profiled surface  304  having engaging elements in the form of circumferential recesses  306  (see also  FIGS. 7, 10, 24 and 25 ) in the inner surface  308  of the casing  300 . The recesses  306  are adapted to cooperate with the expandable portion  404  of the second tubular member  400  upon expansion of the expandable portion  404  to form a seal therewith. In the embodiment of  FIGS. 14 to 17  the recesses  306  are provided in the form of a plurality of longitudinally spaced apart grooves formed in the inner bore of the casing  300 . As shown in  FIGS. 17 and 25 , the expandable portion  404  of the second tubular member  400  is expanded into the recesses  306  to form circumferential protrusions  408  on the exterior of the second tubular member  400  which enter the corresponding recesses  306  to form the sealed joint with the casing  300 . 
     In order to allow the second tubular member  400  to be expanded into the recesses  306  the recesses  306  must be fluid free. In the embodiment shown in  FIGS. 14 to 17  (and also in  FIGS. 7, 24 and 25 ), closed cell foam  310 , such as, for example, metal foam or syntactic foam, is placed into the one more recesses  306 . The foam  310  fills the recesses  306  before the second tubular member  400  is expanded (thereby preventing fluid from entering the recesses  306 ) and becomes compressed to allow the protrusions  408  to enter the recesses  306  when the second tubular member  400  is expanded. Additionally or alternatively, fluid can be removed from the recesses  306  by placing a valve  312  in or through the sidewall of the casing  300  in line with each recess  306  (see  FIGS. 7 and 10 ). The valve  312  is configured to allow the fluid to exit the recess  306  when the fluid is subjected to pressure from the protrusions  408  of the second tubular member  400  expanding into the recess  306 . The valve  312  can be, for example, a one-way valve that allows fluid to escape as the pressure in the recess increases and is sealed shut by the protrusions  408  of the second tubular member  400  once the sealed joint with the casing  300  has been formed. Alternatively, the valve  312  can be a pressure relief valve that allows the fluid to escape into an atmospheric chamber when the pressure in the recess  306  is higher than the opening value of the valve  312 . 
       FIGS. 6 to 9  show modifications of the profiled surface of the casing  300 . In  FIG. 6 , the casing  300  has a profiled surface  314  comprising a thickening on a tubular wall of the casing. The thickening acts as the engaging member of the profiled surface  314  when the second tubular member  400  is expanded against the thickening to form the sealed joint with the casing  300  (see also  FIGS. 18 and 19 ).  FIG. 7  shows the casing  300  that is used for illustration purposes in the method of  FIGS. 14 to 17 , where the upper half of the recesses  306  use a valve  312  and the lower half of the recesses use foam  310 . 
     In a profiled surface  316  of  FIG. 8 , a set of recesses  318  are formed in the outer surface  320  of the casing  300  but will similarly result in the creation of circumferential protrusions  408  and also to some extent result in the creation of recesses  306  (as shown in  FIG. 21 ) during the step of expanding the second tubular member  400  against the inner surface  308  of the casing  300  to form the sealed joint with the casing  300 . As illustrated in  FIGS. 8, 20 and 21 , a set of recesses  318  is pre-formed in an outer surface  320  of the casing  300  thereby creating corresponding regions in the casing  300  having decreased thickness, i.e. thinnings  322 . The provision of the thinnings  322  facilitates the deformation of the casing  300  by the second tubular member  400  to then in effect create the recesses  306  in the inner surface  308  of the casing  300  and simultaneously, in effect, create the circumferential protrusions  408  formed on the exterior of the second tubular member  400  thereby facilitating the formation of the sealed joint. Furthermore, providing the recesses  318  in the outer surface  320  of the casing  300  helps to eliminate or reduce the risk of occurrence of a hydrostatic lock during the expansion of the second tubular member  400 . 
     In a profiled surface  324  of  FIG. 9 , like in the profiled surface  316  of  FIG. 8 , the recesses  318  are also formed in the outer surface  320  of the casing  300 . Additionally, the inner surface  308  also has a profiled surface as profiled regions are provided in the form of inward protrusions  326  on the inner surface  308  of the casing  300 . The protrusions  326  facilitate the creation of increased counteracting forces at an interface between the second tubular member  400  and the casing  300  during the expansion of the second tubular member  400  thereby facilitating the formation of an efficient sealed joint between the second tubular member  400  and the casing  300  (see also  FIGS. 22 and 23 ). 
     In all types of casing  300  having one or more recesses  306 ,  318  on the respective inner surface  308  or the outer surface  320 , the recess shape, depth and width are adjusted to suit the strength and weight of the casing  300  and/or the second tubular member  400  being expanded into the casing  300 . The yield stress of the casing  300  is selected higher than the yield stress of the second tubular member  400 . 
     In  FIGS. 11 to 13 , three different respective variations of the expandable portion  404  of the second tubular member  400  are illustrated each showing a profiled inner surface. In all these variations, the respective expandable portion  404   a ,  404   b ,  404   c  is provided in the form of a tubular member having a wall  406   a ,  406   b ,  406   c  defining an internal bore  418   a ,  418   b ,  418   c  extending between opposite ends  410 ,  412 . The expandable portion  404   a ,  404   b ,  404   c  is expanded by applying radial outward force to an inner surface  414  of the expandable portion  404   a ,  404   b ,  404   c . The expandable portion  404   a ,  404   b ,  404   c  is suitable for being expanded by way of hydraulic deformation with high pressure liquid (e.g. pressure in excess of 20,000 psi or 138 MPa) until it comes into compliant contact with the casing  300  and forms the sealed joint therewith. The expandable portion  404   a ,  404   b ,  404   c  is configured so as to optimise the sealed contact and the strength of the joint between the second tubular member  400  and the casing  300 . For this purpose, in  FIG. 11  the internal bore  418   a  of the expandable portion  404   a  has a greater diameter at a region centrally located between the ends  410 ,  412  and the internal bore  418   a  tapers from the centrally located region to the ends  410 ,  412  and the thickness of the wall  406   a  of the expandable portion  404   a  increases from the centrally located region to the ends  410 ,  412 . This ensures that the expandable portion  404   a  begins to expand at the centrally located region and continues to expand towards the ends  410 ,  412  causing fluid at the interface between the second tubular member  400  and the casing  300  to be expelled as the expandable portion  404   a  expands thereby preventing the occurrence of a hydraulic lock therebetween. In  FIG. 12 , the internal bore  418   b  of the expandable portion  404   b  is tapered from one end  410 , to the other end  412 , whereas the thickness of the wall  406   b  of the expandable portion  404   b  increases from one end  410  to the other end  412 , so that the expandable portion  404   b  begins to expand at the thinner end  410  and continues to expand towards the thicker end  412  causing the fluid at the interface between the second tubular member  400  and the casing  300  to be expelled as the expandable portion  404   b  expands radially. In  FIG. 13 , the expandable portion  404   c  is provided with circumferential seals  416  on the outer surface  466  to enhance the sealing performance between the second tubular member  400  and the casing  300  (see also  FIGS. 18 and 19 ). 
     In some circumstances it is desirable to run and set the casing  300  and hang the first tubular member (not shown in the drawings) off the casing  300  and then start drilling the next section of open hole, before tying back the first tubular member to the wellhead. On these occasions, the inner profiled surface  304 ,  314 ,  316 ,  324  of the casing  300  may remain exposed to well fluids and a rotating drill string for a considerable period of time (days or weeks) and become damaged by the drill string and the fluids. For this purpose, a wear protection tubular cover is installed in the casing  300  prior to running the casing  300  into the well.  FIG. 10  shows a profiled surface  304  having a wear protection cover in the form of a sleeve  500  covering the inner surface  308  of the casing  300 . The sleeve  500  is secured in place by shear pins  502  and is provided with a sealing ring  504  on an outer surface  506  of the sleeve  500  which in use is sandwiched between the cover  500  and the casing  300  to prevent well debris from entering the space between the sleeve  500  and the casing  300  and from causing the sleeve  500  to become jammed in place. When the second tubular member  400  is to be run in the casing  300 , the sleeve  500  is removed by using a pulling or fishing tool (not shown) or a standard casing spear (not shown) to release the shear pins  502  and remove the sleeve  500  from the well. 
     While the  FIGS. 14 to 17  illustrate a tieback connection with the second tubular member  400  having a portion at a lower end inserted in the casing  300 , it will be apparent that the second tubular member  400  could be inserted through the casing  300  so that a portion of an upper end of the second tubular member  400  is located in a lower end of the casing  300 . 
     With all embodiments according to the present invention, since both the first tubular member and the second tubular member  400  are fixed directly to the inner surface  308  of the outer casing  300 , inner and outer diameters of the first tubular member substantially correspond to the respective inner and outer diameters of the second tubular member  400 . 
       FIG. 16  shows a fluid expansion tool  600  for expanding the second tubular member  400  in a manner similar to that described in connection with the prior art method of  FIGS. 3 to 5 . To do this, the expansion tool  600  is run on a drill string  602  through a bore  418  of the second tubular member  400 . The expansion tool  600  is then aligned with the expandable portion  404  of the second tubular member  400  which in turn is aligned with the profiled surface  304  of the casing  300 . The tool  600  includes a depth latch arrangement  604  for positioning the tool  600  at the correct vertical depth. The tool  600  includes a pair of seals  608  which are vertically spaced apart by a distance greater, the same as or less than (but preferably greater or the same as) the vertical distance between the upper and lower recesses  306  of the profiled surface  304 . The seals  608  are actuated to form a seal between an outer surface  610  of the tool  600  and the inner surface  414  of the expandable portion  404  to define a chamber  614  between the seals  608 . Hydraulic fluid (which could be oil or water) is then pumped through the drillstring  602 , into an internal bore (not visible in the drawing) of the tool  600  and through apertures (not shown) in the tool  600  into the chamber  614 . When the hydraulic fluid pressure is sufficient, the expandable portion  404  expands and thus contacts the inner surface  308  of the casing  300  and, due to the recesses  306  or  318 , protrusions  408  are formed by initially elastic and then plastic deformation and the protrusions  408  expand into the recesses  306  or  318 . This creates a mechanical fixing and also a metal to metal seal between the second tubular member  400  and the casing  300 . The first tubular member, which is hung off the lower end  302  of the casing  300 , thus becomes tied back to the surface by the second tubular member  400  via the casing  300 . The seals  608  of the tool  600  can then be de-activated and the drillstring  602  and tool  600  removed from the wellbore  200 . 
     The sealed joint according to the above-described embodiments can be formed between the casing and the second tubular member at any suitable depth, and for any suitable length, to provide the required connection. A conventional PBR is very short (e.g. 10 ft or 3 m) making correct spacing out difficult to achieve at the first attempt, whereas multiple attempts take considerable time and therefore have a significant cost. A tieback connection according the method and apparatus of an embodiment of the invention can be very long and therefore the spacing out can likely always be achieved on the first attempt; provides a greater internal bore diameter than that achieved using a conventional PBR and thus eliminates the problem of high mud pressure in the wellbore; dispenses with the need to use elastomeric seals and eliminates the problem of a PBR being prone to damage in the wellbore; and fits compactly within existing casing construction and is thus suitable for slim well construction, unlike the prior art liner tieback connections. 
     Thus, the method and apparatus of the invention eliminates or mitigates the problem of lack of annular space associated with providing liner hanger and tieback connections in slim wells using prior art techniques. The liner tie back connection or hanger connection of the present invention fits compactly within existing casing  300  and is thus suitable for slim well construction, unlike the prior art liner tieback and hanger connections. 
     Whilst specific embodiments of the present invention have been described above, it will be appreciated that modifications are possible within the scope of the present invention.