Patent Publication Number: US-2020277833-A1

Title: Methods and apparatus for top to bottom expansion of tubulars within a wellbore

Description:
BACKGROUND 
     1. Field of the Disclosure 
     Generally, the present disclosure relates to various novel methods and an apparatus for top to bottom expansion of tubulars within a wellbore. 
     2. Description of the Related Art 
     Typically, as a well is drilled, the casing becomes smaller in diameter as the well is drilled deeper. The reduction in size (e.g., internal diameter) of the casing limits the size of tubing that can be run into the well for ultimate production. All other things being equal, operators of oil and gas wells prefer that the internal diameter of the wells be as large as possible so as to provide for the greatest flexibility in terms of tool and techniques that may be employed to stimulate and/or maintain production from the well. Additionally, in some cases, the existing casing with a well may become damaged or otherwise need repair. In some of these applications, it may be desirable to insert a patch through the existing casing, position the patch at the location of the damaged casing and expand the patch downhole to repair the damaged casing. In yet other situations, it may be desirable to expand a tubular downhole to isolate an unconsolidated (i.e., non-cased) portion of a formation that is being drilled. This can be accomplished by running a piece or section of un-expanded casing into the drilled wellbore, and perhaps through existing casing within the wellbore, and thereafter expanding the previously un-expanded section of casing against the formation. 
     The present disclosure is directed to various novel methods and an apparatus for top to bottom expansion of tubulars within a wellbore that may eliminate or at least reduce one of more of the problems identified above. 
     SUMMARY 
     The following presents a simplified summary of at least one disclosed embodiment in order to provide a basic understanding of some aspects of the subject matter disclosed herein. This summary is not an exhaustive overview of all of the subject matter disclosed herein. It is not intended to identify key or critical elements of the subject matter disclosed herein or to delineate the scope of any claims directed to any of the subject matter disclosed herein. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description that is discussed later in the application. 
     Generally, the present disclosure is directed to various novel methods and an apparatus for top to bottom expansion of tubulars within a wellbore. One illustrative method disclosed herein includes positioning a tubular, with an expansion mandrel positioned therein, within the well and expanding the tubular by forcing the expansion mandrel through the tubular in a down-hole direction of the well while forcing well fluid displaced by the expansion of the tubular into the formation. 
     One illustrative apparatus disclosed herein includes a tubular, a release sub operatively coupled to a first end of the tubular, an expansion cone operatively coupled to a first end of a cone mandrel, wherein the combination of the expansion cone and the cone mandrel is positioned within the tubular below the release sub, and a float collar operatively coupled to a second end of the cone mandrel, the float collar comprising an inverted check valve that, when closed, is adapted to block a flow of fluid through the inverted check valve in a down-hole direction of the well. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure may be understood by reference to the following description taken in conjunction with the accompanying drawings, in which like reference numerals identify like elements, and in which: 
         FIGS. 1-26  depict various illustrative novel methods and an apparatus for top to bottom expansion of tubulars within a wellbore. 
     
    
    
     While the subject matter disclosed herein is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION 
     Various illustrative embodiments of the invention are described below. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. 
     The present subject matter will now be described with reference to the attached figures. Various structures, systems and devices are schematically depicted in the drawings for purposes of explanation only and so as to not obscure the present disclosure with details that are well known to those skilled in the art. Nevertheless, the attached drawings are included to describe and explain illustrative examples of the present disclosure. The words and phrases used herein should be understood and interpreted to have a meaning consistent with the under-standing of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such a special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase. 
       FIGS. 1-26  depict various illustrative novel methods and an apparatus for top to bottom expansion of tubulars within a wellbore.  FIG. 1  is a side view of one illustrative embodiment of a tubular expansion apparatus  10  disclosed herein that is adapted for use in expanding tubulars, e.g., casing, pipe, etc., within a wellbore. The tubulars expanded using the method and apparatus disclosed herein may be of any size or configuration.  FIG. 2  is a cross-sectional view taken along the long axis of the apparatus  10  depicted in  FIG. 1 . The novel devices and methods disclosed herein may be employed on any type of well, e.g., cased or uncased well, and in any well irrespective of the orientation, e.g., vertical or horizontal, of any portion of the wellbore. Thus, use of relative terminology such as “upper,” “lower,” “top” or “bottom” to refer to various components described herein should not be considered to imply any particular orientation of the wellbore, e.g., such relative terminology should not be interpreted as meaning that the methods disclosed herein may only be employed in wells having a substantially vertically oriented wellbore. Rather, such relative terminology should be understood to describe the relative position of the component or features of the component in the wellbore with respect to the up-hole direction of the wellbore or the down-hole direction of the wellbore. For example, a component referred to as an “upper component” could equally be referred to as an “up-hole component.” Similarly, a “bottom” of a wellbore could be referred to as an “end” of the wellbore. 
     As shown in  FIG. 1 , in this illustrative example, the apparatus  10  comprises a clad release sub  12 , an upper expansion joint  11 , an intermediate tubular string  13 , a lower expansion joint  15  and an illustrative guide nose  26 . The upper expansion joint  11  comprises a tubular  14  with a pre-expanded housing section  14 A, an expandable section  14 B and a transition section  14 C. The tubular  14  may comprise a single section of pipe or casing or it may comprise a plurality of sections of casing or pipe joined together. With continuing reference to  FIG. 1 , the lower expansion joint  15  comprises a tubular  17  with a pre-expanded housing section  17 A, an expandable section  17 B and a transition section  17 C. The tubular  17  may comprise a single section of pipe or casing or it may comprise a plurality of sections of casing or pipe joined together. In terms of axial length, the tubulars  14 ,  17  may be of any desired length. 
     Also depicted in  FIG. 1  is a plurality of elastomer sealing bands  110  that are axially spaced apart along the axial length of the expandable sections  14 B,  17 B. As depicted, the clad release sub  12  is operatively coupled to the pre-expanded housing section  14 A, the transition section  14 C is operatively coupled to the up-hole side  13 A of the intermediate casing  13 , the pre-expanded housing section  17 A is operatively coupled to the down-hole side  13 B of the intermediate casing  13  and the transition section  17 C is operatively coupled to the guide nose  26 . In one illustrative embodiment, the guide nose  26  is coupled to the transition section  17 C by a plurality of shear pins (not shown). The connections between the upper expansion joint  11  and the intermediate casing  13 , as well as the connection between the lower expansion joint  15  and the intermediate casing  13 , may take a variety of forms. In one illustrative example, such connections may be flush joint casing connections. The elastomer bands  110  are pre-placed at various desired locations on the expandable sections  14 B,  17 B. In one illustrative application, the intermediate casing  13  is intended to straddle or cover a portion of the well (e.g., a portion of a perforated well casing or a portion of an un-cased well). Once the expansion process is completed, the elastomer bands  110  are compressed against the inside diameter of the existing tubular  42  (not shown in  FIG. 1 ) (whether perforated on not) or the wall of the un-cased wellbore. Once the expansion process is completed, the elastomer bands  110  tend to secure and seal the upper and lower expansion joints  11 ,  15  in position within the well and thereby secure the position of the intermediate casing  13  within the well. The location and number of the elastomer bands  110  may be determined by the configuration of the well and/or wellbore operating conditions. 
     As discussed more fully below, the apparatus  10  includes an expansion cone  16  (see  FIG. 2 ) that, when driven down-hole, is adapted to expand at least the expandable portions  14 B,  17 B of the tubulars  14 ,  17 , respectively. In terms of diameter, the intermediate casing  13  may be of any desired size as long as the inside diameter of the intermediate casing  13  less than the maximum outside diameter of the expansion cone  16  and the outside diameter of the intermediate casing  13  fits within the well (e.g., within the inside diameter of a pre-existing casing positioned in the well or the diameter of an open un-cased bore hole). In terms of axial length, the intermediate casing  13  may be of any desired length (up to allowable carrying capacity). In one illustrative example, the intermediate casing  13  may have an axial length of several thousand feet, e.g., 6000 feet. As will be described more fully below, the immediate casing  13  will not undergo any appreciable radial expansion when the expandable sections  14 B,  17 B are radially expanded using the methods disclosed herein. 
     In one illustrative embodiment, the apparatus  10  may be positioned within a pre-existing tubular  42  (not shown in  FIG. 1 ) that was previously positioned within a wellbore (not shown). The existing tubular  42  may or may not comprise a plurality of pre-existing perforations. In some applications, the methods and systems disclosed herein may be employed to cover a portion of existing casing that is simply damaged, e.g., due to corrosion. In other applications, the apparatus  10  may be positioned within an un-cased portion of a wellbore. The clad release sub  12  portion of the apparatus  10  is adapted to be directly coupled to a deployment string (not shown) extending from a surface location, e.g., a drilling rig, a vessel, etc. In one illustrative example, the apparatus  10  may be mechanically coupled to the deployment string via a box connection  78  on the clad release sub  12 . 
     With reference to  FIG. 2 , additional components of this illustrative embodiment of the tubular expansion apparatus  10  are disclosed. An illustrative pre-existing tubular  42  positioned in the wellbore is also shown in  FIG. 2 . Also depicted in  FIG. 2  are a shear sleeve  92  positioned within the clad release sub  12 , an expansion cone  16 , a cone mandrel  18  and a cone retainer  34 . Other aspects, details and components of the illustrative apparatus may not be depicted in  FIG. 2  so as not to overly complicate the drawings. However, such details of such additional components may be shown in more detailed drawings in the present application. 
       FIGS. 3-7  are slightly enlarged versions of portions of the axial length of the apparatus  10  shown in  FIG. 2 . More specifically,  FIG. 3  is a cross-sectional view that primarily shows the clad release sub  12  and includes a portion the expansion cone  16  and the cone mandrel  18 .  FIG. 4  is a cross-sectional view that primarily shows the upper portion of the expansion cone  16  and an upper portion of the cone mandrel  18 . The lowermost portion of the clad release sub  12  is also shown in  FIG. 4 .  FIG. 5  is a cross-sectional view that primarily shows the lower portion  48  of the cone mandrel clad release sub  12  and the cone guide assembly  22 . Also depicted in  FIG. 5  is the intermediate casing  13  and a portion of a float collar  24  included with the apparatus.  FIG. 6  is a cross-sectional view that primarily shows the float collar  24  and its engagement with the lower portion  48  of the cone mandrel  18 . The lower tubular  17  is also depicted in  FIG. 6 .  FIG. 7  is a cross-sectional view that primarily shows the guide nose  26  that is positioned at the lower end of the tubular  17 . 
     As noted above, various aspects of the clad release sub  12  are depicted in  FIG. 3 .  FIG. 9  is a plan view of a portion of the tubular  14  and the clad release sub  12  showing some of the components described below. The clad release sub  12  comprises the above-mentioned box connection  78 , a plurality of fluid outlet openings  90 , a plurality of shear pins  94 , a shear sleeve  92 , a plurality of inwardly-biased spring-loaded dogs  100 , a biasing spring  102 , an outer recess  104  in the shear sleeve  92  and an alignment pin  82  that is positioned in a slotted opening  84  formed in the tubular  14 . A plurality of assembly access openings  101  are provided through the tubular  14  to permit installation of the spring loaded dogs  100 . In the run-in position shown in  FIG. 3 , the inner surface  100 X of the dogs  100  is biased against the outer surface of the shear sleeve  92  and a plurality of upper protrusions or lugs  100 Y of the dogs  100  engage corresponding recesses in the inner surface of the tubular  14  so as to thereby prevent relative vertical movement between the tubular  14  and the clad release sub  12 . The shear sleeve  92  comprises a through-bore  92 T. As best seen in  FIG. 9 , positioning the alignment pin  82  in the slotted opening  84  fixes the relative rotational orientation between the tubular  14  and the clad release sub  12  while still permitting disengagement between the pin  82  and the slotted opening  84  by causing relative vertical movement between the tubular  14  and the clad release sub  12  when the dogs  100  are retracted from engagement with the recesses in the tubular  14 . The shear pins  94  are installed through openings  95  in the tubular  14 . The shear pins  94  releasably couple the shear sleeve  92  to the clad release sub  12 . Also depicted in  FIG. 3  is a plurality of seals  86 ,  88  positioned between the outer diameter of the clad release sub  12  and the inside diameter of the tubular  14  on opposite sides of the fluid outlet openings  90 , and an upper seal  96  and a lower seal  98  positioned between the outside diameter of the shear sleeve  92  and the inside diameter of the clad release sub  12 . Also depicted are a plurality of seals  106 ,  108  positioned between the outside diameter of the clad release sub  12  and the inside diameter of the tubular  14 . Also depicted in  FIG. 3  is an illustrative drop ball  80 , the use of which will be described more fully below. 
     As will be appreciated by those skilled in the art after a complete reading or the present application, once released, the drop ball  80  is adapted to block the bore  92 T through the shear sleeve  92 . Once the ball  80  has landed, pressure above the ball  80  may be increased to shear the shear pins  94  and, thereafter force the shear sleeve  92  to travel in the down-hole direction within the clad release sub  12  until such time as a shoulder  92 A on the shear sleeve  92  engages a shoulder  12 X on the clad release sub  12 . Of course, the drop ball  80  could be replaced with another device such as, for example, a drop dart (not shown). As will also be appreciated by those skilled in the art after a complete reading of the present application, once the shear sleeve  92  is released and moved to its most down-hole position within the clad release sub  12 , i.e., when the shoulders  92 A and  12 X engage one another, the inwardly-biased spring-loaded dogs  100  will be urged into engagement with outer recess  104  thereby preventing further relative axial movement between the shear sleeve  92  and the clad release sub  12 . Movement of the dogs  100  into the outer recess  104  in the shear sleeve  92  also causes the protrusions or lugs  100 Y of the dogs  100  to disengage with the recesses in the tubular  14 , thereby permitting the clad release sub  12  to be disengaged from the tubular  14  by simply pulling up on the clad release sub  12 . Note that movement of the shear sleeve  92  to its most down-hole position will move the upper seals  96  down-hole of the fluid outlet openings  90 , thereby establishing fluid communication between the bore  12 T of the clad release sub  12  above the drop ball  80 . The establishment of this fluid flow path will be beneficial for reasons that will be discussed more fully below. 
     With reference to  FIGS. 4 and 5 , the cone mandrel  18  comprises an upper flange  44  and a lower end  48 . The flange  44  is adapted to be positioned within a recess  46  in the expansion cone  16 . The lower end  48  of the cone mandrel  18  is adapted to be positioned within a float collar recess  50  in the float collar  24 . At least one upper seal  28 , e.g., a lip seal, is provided between the expansion cone  16  and the inside diameter of the tubular  14 . The seal  28  will engage the inside diameter of the tubulars  14 ,  17  as the expansion cone  16  is driven downward through the tubulars  14 ,  17  as described more fully below. Another seal  30  and back up ring  32  are provided between the inside diameter of the expansion cone  16  and the outside diameter of the cone mandrel  18 . The cone retaining sleeve  34  is fixed to the cone mandrel  14  by a threaded connection  35 . The lower end  48  of the cone mandrel  18  is threadingly coupled to the float collar  24  by a threaded connection  51 . Another seal  38  and backup ring  40  are provided between the outside diameter of the lower portion  48  of the cone mandrel  18  and the inside diameter of the recess  50  in the float collar  24 . Also depicted in  FIG. 5  is a cone guide assembly  22  that is coupled to the outside of the cone mandrel  18  by a threaded connection  64 . Also depicted in  FIG. 5  is a lip seal  52  that is positioned between the outside diameter of the cone guide assembly  22  and the inside diameter of the transition section  14 C. The seal  52  will engage the inside diameter of the tubulars  14 ,  17  as the expansion cone  16  is driven downward through the tubulars  14 ,  17  as described more fully below. Also depicted is a seal  58  between the outside diameter of the cone mandrel  18  and the inside diameter of the cone assembly. 
     As will be appreciated by those skilled in the art after a complete reading of the present application, the expansion cone  16 , the cone mandrel  18  and the cone guide assembly  22  may be considered to be part of an expander unit or assembly that travels together as a unit as the expansion cone  16  is forced downward within the tubulars  14 ,  17 . The point or area of interaction between the expansion cone  16  and the tubular to be expanded, e.g., the tubular  14 , may be referred to as the expansion face. During the expansion process, very high forces are present on this expansion face. Moreover, the interaction between the expansion cone  16  and the tubular during the expansion process creates a fluid-tight and pressure-tight seal between the expansion cone  16  and the tubular (e.g.,  14  or  17 ) at the expansion face. In the situation where the well is a cased-well with an existing casing  42  positioned therein, this fluid-tight and pressure-tight seal along with the down-hole movement of the expansion cone  16  (which is part of the expansion assembly  99 ) causes or forces the displacement and the downward flow of the wellbore fluid positioned between the expansion cone  16  and existing casing  42 . As discussed more fully below, in the examples depicted herein, the wellbore fluid displaced by the expansion of the tubular ( 14  or  17 ) is forced into the formation at some location below the expansion face between the expansion cone  16  and the tubular ( 14  or  17 ). This situation applies in the case where a tubular is expanded against the formation in an un-cased well and/or where the tubular is expanded against the formation at a location below an end or a bottom of any existing casing within the well. Additionally, the combination of the expansion cone  16 , the cone mandrel  18 , the cone guide assembly  22 , the inside surfaces of the tubulars  14 ,  13 ,  17  as well as the various seals disclosed herein (e.g.,  28 ,  30 ,  52 ,  58 ) define a lubrication chamber  45  that is adapted to retain a quantity of lubricant in front of the expansion cone  16  so as to lubricate the inside diameter of the tubulars  14  and  17  as the expansion cone  16  travels through those tubulars and expands the tubulars  14 ,  17 . The presence of the lubricants in the lubricant chamber  45  may also help to reduce frictional forces as the expansion cone  16  travels through the intermediate casing  13 . That is, a quantity of lubricant in the lubrication chamber  45  effectively travels with the combination of the expansion cone/cone mandrel/cone guide assembly as that combination of components travel through the tubulars  14 ,  13  and  17 . 
     With continued reference to  FIG. 5 , the cone guide assembly  22  comprises a lubricant fill line  74 , a check valve  72 , a lubricant bleed or vent line  66  and a plug  70 . The plug  70  may be coupled to the cone guide assembly  22  by a threaded connection. The valve  72  may be coupled to the cone guide assembly  22  by any technique, e.g., a press-fit connection, a welded connection, a threaded connection, etc. Although only a single fill line  74  and a single vent line  66  are depicted in the drawings, more of these lines can be provided if desired. The purpose of these lines and components is to permit the filling of the lubricant chamber  45  with lubricant, e.g., oil, prior to deployment of the apparatus  10  within a well. The lubricant may be added at an on-shore facility prior to shipping the apparatus  10  to a job location or the lubricant may (preferably) be added to the apparatus  10  at the job site location. In one illustrative example, the valve  72  may be a one-way check valve. With the plug  70  removed, a pressurized source of the lubricant may be coupled to the valve  72  and lubricant may be injected into the lubricant chamber  45  while air within the chamber  45  is free to vent via the open vent line  66 . Once the chamber  45  is full of lubricant, the plug  70  may be installed in the vent line  66  and the source of pressurized lubricant may be decoupled from the valve  72 . In one illustrative embodiment, the valve  72  may be what is generally referred to as a “crack” valve that permits some small amount of flow into the lubricant chamber  45  under certain circumstances. Typically, the expansion pressure that is applied above the expansion cone  16  during the expansion process is greater than the pressure in the lubricant chamber  45  due to the pressure-tight seal at the expansion face and/or the presence of the lip seal  28 . However, the viscosity of the lubricant is such that some of the lubricant should be drawn into the expansion face as the expansion cone  16  moves down-hole. Additionally, some loss of lubricant may occur as the lubricant chamber  45  moves over connections, etc., as the expansion process continues. Thus, for whatever reason, the quantity of lubricant lost during the expansion process may need to be replaced. These “crack” type check valves insure that a small amount of wellbore fluid is allowed to flow into the chamber  45  to replace the quantity of lubricant that bypasses the expansion interface or is otherwise lost during the expansion process. 
     As noted above,  FIG. 6  is a cross-sectional view that primarily shows the float collar  24  and its engagement with the lower portion  48  of the cone mandrel  18 . The intermediate casing  13  and the lower tubular  17  is also depicted in  FIG. 6 . Importantly, one illustrative novel aspect of one embodiment of the apparatus  10  disclosed herein involves the inclusion of an inverted check valve  25  in the float collar  24 . As depicted, the inverted check valve  25  is oriented such that, when the valve  25  is in the closed position, fluid flow through the valve  25  in the down-hole direction  27  is blocked and, conversely, when the valve  25  is open, fluid flow through the valve  25  in the up-hole direction  29  is permitted. This inverted arrangement is in direct contrast to the positioning and functioning of a traditional check valve in a traditional float collar. That is, in a traditional float collar, the traditional check valve is oriented such that when the traditional check valve is closed, fluid flow though the traditional check valve in the up-hole direction  29  is blocked, and, conversely, when the traditional check valve is open, fluid flow through the traditional check valve in the down-hole direction  27  is permitted. The unique functions and purposes of the inverted check valve  25  when used with the methods and systems disclosed herein will be discussed more fully below. 
     With reference to  FIG. 7 , the guide nose  26  is operatively coupled to the lower end of the tubular  17 . In one illustrative example, the guide nose may be coupled to the tubular  17  by a plurality of shear pins (not shown). The guide nose  26  comprises a bore or opening  26 T. In general, the guide nose  26  is provided to assist running the apparatus  10  into the wellbore. 
     In the embodiment shown in  FIGS. 1-7 , the apparatus  10  comprises the intermediate casing  13  with the upper expandable tubular  14  and the lower expandable tubular  17  positioned on opposite sides of the intermediate casing  13 , wherein the guide nose  26  is coupled to the bottom end of the lower expandable tubular  17 . However, as will be appreciated by those skilled in the art after a complete reading of the present application, the systems and methods disclosed herein are very versatile and have numerous applications other than the illustrative example shown in  FIGS. 1-7  above. For example,  FIG. 8  is a cross-sectional view depicting an embodiment of the apparatus wherein only a single expandable tubular  14  is expanded using the apparatus  10 . That is, in this example, the intermediate casing  13  and the lower expandable tubular  17  are omitted and the guide nose  26  is coupled to the bottom of the tubular  14 . All other operational aspects of the system are substantially the same and may be used in the same manner so as to expand the tubular  14 . As noted above, the tubular  14  may comprise one or more sections of pipe. Of course, as previously noted, the systems and methods disclosed herein may be applied in many different applications and situations. For example, the systems and methods disclosed herein may be employed in applications involving expanding a single expandable tubular (comprised of one or more sections of pipe) against pre-existing casing (e.g., damaged or perforated sections of casing) positioned in a well or against the formation in an un-cased well. The methods and systems disclosed herein may also be applied in an application such as that described above wherein first and second expandable tubulars  14 ,  17  were placed on opposite ends of an intermediate casing  13  (that does not undergo any appreciable expansion, and wherein each of the tubulars may be expanded against a section of pre-existing casing (e.g., damaged or perforated sections of casing) positioned in a well or against the formation in an un-cased well. In this latter application, the intermediate casing  13  may span across one or more sections of casing (e.g., casing that is damaged or perforated) and/or across un-cased portions of a well. 
     In one illustrative example, the expansion cone  16  may be made of a tool steel and it may comprise a substantially conical leading that substantially matches the taper within the pre-expanded housing sections  14 A,  17 A of the tubulars  14 ,  17 , respectively. As noted above, expansion cone  16  is carried on the cone mandrel  18 . The lip seal  28  on the expansion cone  16  provides a seal against pressure above the expansion cone  16 . 
     In some alternative embodiments, the expansion cone  16  may be subjected to various treatments to improve its performance, e.g., it may be boronized, carburized, and/or nitrided, etc. These industry standard processes are known to reduce friction and decrease wear. In general, high contact forces between metal surfaces during expansion processes are known to cause galling. Galling can be alleviated by increasing the difference in hardness between the expansion cone  16  and the expansion face, i.e., the point or area where the expansion cone  16  contact the portion of the tubular that is to be expanded. In some other application, a hardened surface may be formed on the expansion cone  16 . As noted above, in one illustrative example, the apparatus includes a lubrication reservoir  45  that is located down-hole relative to the expansion cone  16 , i.e., the lubrication reservoir  45  is positioned in front of the direction of travel of the expansion cone  16  during the expansion process. 
     As noted above, the deployment string (not shown) from the surface is directly mechanically coupled to the clad release sub  12 , and the tubular member  14  is operatively coupled to the deployment string by virtue of the direct mechanical coupling between the tubular  14  and the clad release sub  12  (by virtue of the dogs  100 ). However, unlike at least some prior art systems, the expansion assembly  99  (that includes at least the expansion cone  16 , the cone mandrel  18  and the float collar  24 ) is not mechanically coupled (directly or indirectly) to the deployment string. Rather, the expansion assembly  99  is free to move, and the movement of the expansion assembly  99  is controlled by hydraulic pressure applied to the system. 
       FIG. 10  is a simplistic depiction of an embodiment of the apparatus  10  disclosed herein after the expandable sections  14 B,  17 B of the tubulars  14 ,  17 , respectively, have been expanded such that the elastomer bands  110  engage the inner surface  42 A of the illustrative pre-existing casing  42 . Certain components of the apparatus  10 , e.g., the clad release sub  12  that is located above the tubular  14  and the guide nose  26  that is located below the tubular  17  are not depicted in  FIG. 10 . In this illustrative example, the existing casing  42  within the wellbore comprises a plurality of simplistically depicted perforations  115  that will be effectively covered by the intermediate casing  13 . As noted above, in the example depicted herein, the intermediate casing  13  does not undergo any appreciable radial expansion as the expandable sections  14 B,  17 B of the tubulars  14 ,  17 , respectively, expand. Thus, at the completion of the expansion process, there will be a radial gap  117  between the inside surface  42 A of the existing casing  42  and the outer surface  13 A of the intermediate casing  13 . However, the magnitude of this radial gap  117  may be relatively small depending upon the particular application, e.g., about 0.125 inches in some cases. As a result, after the expansion process is completed, the intermediate casing  13  covers the perforations  115  in the pre-existing casing  42 . Thereafter, the removable portions of the apparatus  10  may be removed from the well and/or left in the bottom of the well as described more fully below. At that point, traditional fracking tools and techniques may be used to form perforations (not shown) in portions of the casing  42  above the tubular  14  or below the tubular  17 . 
       FIG. 11  depicts an embodiment similar to that shown in  FIG. 10 , except in this case the apparatus  10  has been used to install the intermediate casing  13  in the area of the existing casing  42  where some erosion or loss of the casing material (as referenced by the numeral  119 , has occurred. Note that, in this application, the portion of the existing casing  42  covered by the intermediate casing  13  does not contain any fracture perforations. 
     As will be appreciated by those skilled in the art after a complete reading of the present application, the apparatus disclosed herein is not limited to the particular application wherein expandable tubulars (e.g.,  14  and  17 ) are positioned on opposite sides of an intermediate casing  13  that does not undergo any appreciable expansion. For example, with reference to  FIG. 12 , in one illustrative embodiment, the apparatus  10  may only comprise a single tubular member  14  (that may be comprised of one or more sections of pipe) that is adapted to be positioned within a wellbore and expanded to engage an existing casing  42  or the formation (in the situation of an uncased well). Also note that the clad release sub  12  and guide shoe  26  have been simplistically depicted in  FIG. 12 . As depicted, in this embodiment, the expansion cone  16  is forced through the entirety of the tubular  14  to cause the tubular  14  to radially expand. Thus, at the completion of the expansion process, the expanded tubular  14  covers the perforations  115  in the casing  42 . Relative to the embodiment shown in  FIG. 10 , in the embodiment shown in  FIG. 12 , the guide shoe  26  is operatively coupled to the lower end of the tubular  14 . 
     One illustrative embodiment of a method disclosed herein will be discussed in the context of  FIGS. 13-20 . These figures schematically depict a method that involves use of the illustrative apparatus  10  shown in  FIG. 1 , wherein the apparatus  10  comprises the clad release sub  12 , the expandable tubular  14 , the intermediate tubular string or casing  13 , the expandable tubular  17  and the illustrative guide nose  26 . Also schematically depicted in these drawings is what may be referred to as some of the components of a traveling expander assembly  99  that may include, among other things, the combination of the expansion cone  16  that is coupled to the upper end of the cone mandrel  18  and the float collar  24  that is operatively coupled to the lower end of the cone mandrel  18 . As noted above, this traveling expander assembly  99  may comprise fewer or more components than those mentioned immediately above. The float collar  24  comprises the above-described inverted check valve  25 . Of course, as noted above, the methods and devices disclosed herein may be employed to expand a single expandable liner  14  within a wellbore, as simplistically depicted in  FIG. 12 . 
     At the point shown in  FIG. 13 , the apparatus  10  is depicted at a point where the apparatus has been positioned in a well at a desired location within a pre-existing casing  42  that was previously positioned in the well. As noted above, the casing  42  may have a plurality of perforations (not shown). In other applications, the casing  42  may not be present and the apparatus  10  may be employed to expand the tubulars  14 ,  17  against the formation. There will typically be formation fluids in the well prior to the point in time where the apparatus  10  is initially run down-hole. The apparatus  10  will typically be lowered into the well with a relatively low pressure (P 1 ) in the drill string (not shown) above the clad release sub  12 . The pressure P 1  may be relatively low so as to permit existing formation fluid to flow in the up-hole direction through the inverted check valve  25 , thereby allowing the apparatus  10  to be lowered into position without having to force the apparatus  10  down-hole against a column of formation fluid within the well. Note that, in this initial position, the expansion cone  16  of the expander assembly  99  is positioned within the pre-expanded housing section  14 A of the upper tubular  14 . At this point, the expansion cone  16  has not been used to expand any portion of the tubular  14 . 
       FIG. 14  depicts the apparatus  10  after an expansion pressure (Pe) was applied above the expansion assembly  99  thereby tending to force the expansion assembly  99  downward within the well. As indicated, the expansion cone  16  portion of the traveling expander assembly  99  has moved a portion of the way through the expandable tubular  14  thereby causing radial expansion of a portion of the axial length of the expandable tubular  14 . Note that some of the elastomer bands  110  on the tubular  14  have been forced or urged into engagement with the inner surface of the existing casing  42 . The inverted check valve  25  in the float collar  24  is in the closed position and thereby retains the expansion pressure (Pe) above the traveling expander assembly  99 . The absolute value of the expansion pressure (Pe) may vary depending upon the particular application. In general, the expansion pressure (Pe) is of sufficient magnitude so as to force the expansion cone  16  (part of the traveling expander assembly  99 ) to travel down-hole and thereby expand the expandable tubulars  14 ,  17 . Note that, during this top-down (up-hole to down-hole) tubular expansion process, there will be some existing wellbore fluid  75  (which may include formation fluids and/or other fluids added to the well and/or water) in the annular spaces (or gap) between the outer surfaces of the tubulars  14 ,  13  and  17  and the inner surface of the existing casing  42 . There will also be some of these existing wellbore fluids  75  in the annular space (or gap) between the outer surface of the tubular  17  and the inner surface of the existing casing  42 . As the expansion of the tubular  14  continues, the wellbore fluids  75  in these annular spaces that is displaced by the expansion process will be forced out of these annular spaces and flow in a down-hole direction toward the bottom or end of the well, as indicated by the arrow associated with the numeral  75 . In some applications, the wellbore fluids  75  forced out from the annular spaces may flow upward through the opening or bore  26 T in the guide nose  26 . If that were to occur, in almost all situations, the expansion pressure (Pe) applied above the inverted check valve  25  will be greater than the pressure below the inverted check valve  25  (due to the flow of the forced wellbore fluids  75 ), thereby insuring that none of the displaced wellbore fluids  75  will flow upward through the inverted check valve  25  in the float collar  24 . Rather, these displaced wellbore fluids will flow out into the formation at some location below the expanded tubular  17  (in this particular example of the apparatus). That is, the wellbore fluids  75  displaced by the expansion process may flow outwardly into the formation via one or more perforations (not shown) formed in the existing casing  42  below the location of the apparatus and/or into an open-hole portion of the well below any cased portion of the well. Of course, in the case of a non-cased well, these displaced wellbore fluids may simply be forced into the formation at some point below the apparatus. This is a unique aspect of the methods and systems disclosed herein as compared to prior art methods and systems where wellbore fluids displaced by a tubular expansion process were typically returned to the surface via an annular flow path in the well. 
       FIG. 15  depicts the apparatus  10  at a later point in the process wherein the expansion cone  16  portion of the traveling expander assembly  99  has moved to a location within the intermediate casing  13 . As indicated, expansion pressure (Pe) is still applied above the traveling expander assembly  99 . 
       FIG. 16  depicts the apparatus  10  at a later point in the process wherein the expansion cone  16  portion of the traveling expander assembly  99  has moved a portion of the way through the expandable tubular  17  thereby causing radial expansion of a portion of the axial length of the expandable tubular  17 . As indicated, expansion pressure (Pe) is still applied above the traveling expander assembly  99 . Note that, at this point in the process flow, the bottom of the float collar  24  is at a location where it is about to contact the upper surface of the guide nose  26 . 
       FIG. 17  depicts the apparatus after several actions were taken. First, the traveling expander assembly  99  was urged further downward so as to cause the float collar  24  to engage the guide nose  26  and thereby cause the shear pin connection between the guide nose  26  and the lower end of the tubular  17  to be broken. This action releases the guide nose  26  and, in one embodiment, allows the guide nose  26  to simply fall toward the bottom or end of the well. The force applied to break the shear pin connection between the guide nose  26  and the tubular  17  may be applied by simply applying additional weight to the apparatus  10  by controlling known lift mechanisms at the surface. This shearing force could also be applied by increasing the pressure above the traveling expander assembly  99 , but such an increase in pressure could lead to an abrupt separation of the guide nose from the tubular  17 . Next, after the guide nose is released, expansion pressure (Pe) is continued to be applied above the traveling expander assembly  99  so as to cause expansion of the entirety of the tubular  17 . The expansion cone  16  continues to travel downward until such time as the lip seal  28  (see  FIG. 6 ) on the expansion cone  16  moves past the lower end of the tubular  17 . At that point, internal pressure within the tubular  17  above the traveling expander assembly  99  is released to the well, as indicated by the arrows  77 . 
       FIG. 18  depicts the apparatus  10  after the traveling expander assembly  99  has fully exited the lower tubular  17 . In one embodiment, the traveling expander assembly  99  is simply allowed to fall toward the bottom or end of the well. The guide nose  26  is not depicted in  FIG. 18 . 
       FIG. 19  depicts the apparatus  10  after a drop ball  80  has landed in the shear sleeve  92  (not separately shown—see  FIG. 7 ) in the clad release sub  12 . At that point, the pressure above the clad release sub  12  is increased to a pressure (Ps) sufficient to cause the shear pins  94  to shear thereby releasing the sleeve  92  to travel downward within the bore  12 T of the clad release sub  12 . The travel of the sleeve  92  continues until it stops on the shoulder  12 X. At that time, recesses  104  in the outer surface of the sleeve  92  are aligned with the inwardly biased spring-loaded dogs  100 . The spring-loaded dogs  100  extend inwardly to engage the recesses  104  thereby preventing any further relative axial movement between the sleeve  92  and the clad release sub  12 . When the sleeve  92  has shifted to the position where it engages the shoulder  12 X, the upper surface  92 S of the sleeve  92  is positioned down-hole of the openings  90  that extend through the body of the clad release sub  12 . 
       FIG. 20  depicts the apparatus wherein the clad release sub  12  is lifted completely free of tubular  14  by upward movement of the deployment string (not shown) that is coupled to the clad release sub  12 . The clad release sub  12  may be retrieved to the surface. To the extent there are any fluids in the deployment string, those fluids may drain from the deployment string into the well via the openings  90  in the clad release sub  12 . 
     The unique configuration of the apparatus disclosed herein also permits continued operations under sometimes unique and unexpected operating situations. For example, during the process of supplying expansion pressure (Pe) above the traveling expander assembly  99  so as to cause expansion of the tubular  14  and/or  17 , and thereby forcing the displaced wellbore fluids into the formation below the apparatus, the pressure below the inverted check valve  25  might, under some circumstances, become relatively large. One option would to be to continually increase the magnitude of the expansion pressure (Pe) so as to keep the inverted check valve  25  closed and continue to drive the traveling expander assembly  99  downward through the tubulars  14 ,  17 . However, depending on the pressure differential across the inverted check valve  25  (which is also present across the expansion cone  16 ), the rate of travel of the traveling expander assembly  99  may become relatively slow, thereby increasing the time required for the expansion process to be completed. Additionally, continuing to increase the expansion pressure (Pe) can require larger and more expensive pumping equipment. 
     However, due to the unique inverted check valve  25  in the float collar  24  herein, when it is determined that the expansion pressure (Pe) is required to be larger than desired due to an increase in pressure below the inverted check valve  25  (hereinafter the formation pressure), various actions may be taken to alleviate this condition. For example, the formation pressure may be reduced by reducing the pressures above the traveling expander assembly  99  to a very small value, thereby allowing fluid below the inverted check valve  25  to flow upward through the inverted check valve  25 , the cone mandrel  18 , the clad release sub  12  and the deployment string to the surface. This process can be continued until such time as formation pressure below the inverted check valve  25  is within acceptable limits. At that time, the pressure above the traveling expander assembly  99  may again be increased to the desired expansion pressure (Pe) and the expansion of the tubular  14  and/or  17 . 
     As noted above, in one illustrative embodiment, the traveling expander assembly  99  may simply be left at the bottom of the well or it may be retrieved to the surface depending upon the requirements of the well and/or operator preference. In an alternative embodiment of the system, the top of the cone mandrel  18  may be configured for retrieval by the use of conventional fishing equipment. In yet another embodiment, a latch (not shown) may be provided at the lower end of the cone mandrel  18  that mates with the guide nose  26  after or near the end of the expansion operation. For example, the guide nose  26  may be provided with a receptacle (not shown) for the latch and a releasable connection to the mandrel  18  so that once the guide nose  26  is latched to the mandrel  18 , the combination of the traveling expander assembly  99  and guide nose  26  may be retrieved to the surface in one trip. 
       FIGS. 21-26  depict one illustrative method that corresponds to the methods described above in the context of  FIGS. 13-20 . However, in  FIGS. 21-26  the system was employed to expand one single tubular  14  within the wellbore, instead of the two expandable tubulars  14 ,  17  shown in  FIGS. 13-20 . Of course, as before, the tubular  14  may itself be comprised of a single section of pipe or multiple sections of pipe coupled together.  FIG. 21  corresponds to the situation depicted in  FIG. 13  above, i.e., at a point in the process where the apparatus has been positioned in a well at a desired location within a pre-existing casing  42 .  FIG. 22  corresponds to the situation depicted in  FIG. 14 , i.e., after the expansion pressure (Pe) was applied above the expansion assembly  99  thereby tending to force the expansion assembly  99  downward within the well. As indicated, the expansion cone  16  portion of the traveling expander assembly  99  has moved a portion of the way through the expandable tubular  14  thereby causing radial expansion of a portion of the axial length of the expandable tubular  14 . 
       FIG. 23  corresponds to the situation depicted in  FIG. 16  wherein the traveling expander assembly  99  has moved further down through the expandable tubular  14  to the point where the bottom of the float collar  24  is at a location where it is about to contact the upper surface of the guide nose  26 .  FIG. 24  depicts the situation corresponding to  FIG. 17  wherein the traveling expander assembly  99  was urged further downward so as to cause the float collar  24  to engage the guide nose  26  and thereby cause the shear pin connection between the guide nose  26  and the lower end of the tubular  17  to be broken. As before, this action releases the guide nose  26  and, in one embodiment, allows the guide nose  26  to simply fall toward the bottom or end of the well. As before, the expansion cone  16  continues to travel downward until such time as the lip seal  28  (see  FIG. 6 ) on the expansion cone  16  moves past the lower end of the tubular  14 . At that point, internal pressure within the tubular  14  above the traveling expander assembly  99  is released to the well, as indicated by the arrows  77 .  FIG. 25  depicts the situation corresponding to  FIG. 18 , i.e., after the traveling expander assembly  99  has fully exited the lower tubular  14 . In one embodiment, the traveling expander assembly  99  is simply allowed to fall toward the bottom or end of the well. The guide nose  26  is not depicted in  FIG. 25 .  FIG. 26  depicts the apparatus after the steps shown in  FIGS. 19 and 20  were taken, e.g., after the drop ball  80  has landed in the shear sleeve  92  in the clad release sub  12 , after the pressure above the clad release sub  12  was increased so as shear the shear pin connection between the shear sleeve  92  and the clad release sub  12  thereby allowing the shear sleeve  92  to travel downward within the bore  12 T of the clad release sub  12 , etc.  FIG. 26  also depicts the apparatus wherein the clad release sub  12  is lifted completely free of tubular  14  by upward movement of the deployment string (not shown) that is coupled to the clad release sub  12 . 
     The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. For example, the process steps set forth above may be performed in a different order. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is there-fore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Note that the use of terms, such as “first,” “second,” “third” or “fourth” to describe various processes or structures in this specification and in the attached claims is only used as a shorthand reference to such steps/structures and does not necessarily imply that such steps/structures are performed/formed in that ordered sequence. Of course, depending upon the exact claim language, an ordered sequence of such processes may or may not be required. Accordingly, the protection sought herein is as set forth in the claims below.