INVENTION BACKGROUND 
   Traditionally, a subsea christmas tree provides pressure control of a well completion system that comprises a centrally located well bore and a surrounding annulus conduit. The centrally located well bore is typically used for the extraction of reservoir hydrocarbons and is referred to as the production bore. The annulus conduit is typically used to service the well, for example allowing the circulation of fluids during well start up and shut down. During the production phase of the well, the annulus is often redundant and is monitored for pressure build up indicating a possible production tubing or packer leak from the production bore. Some wells employ the annulus for gas lift. Gas is pumped down the annulus and enters the production bore at specific locations thereby reducing the density and viscosity of the produced fluids. Electrical, optical and hydraulic service lines are also typically routed through the annulus for powering and control of downhole equipment such as valves and pumps, or for data transmission from downhole sensors. Chemical injection lines are likewise routed through the annulus. 
   Recent developments in expandable casing technology and reeled tubular technology dictate completion designs having decreased diameter well casing tubulars located external to the production tubing. The radial gaps between the tubulars are likewise reduced. 
   SUMMARY OF THE INVENTION 
   The present invention enables still further benefits to be gained from expandable casing technology. According to the invention, there is provided a completion system comprising a christmas tree mounted on a wellhead housing, a tubing hanger landed in the tree or wellhead housing, the wellhead housing being mounted on a casing string and a tubing string being suspended from the tubing hanger within the casing string; characterised in that, in use, the annulus defined between the tubing and the casing serves as a production bore and the tubing serves as a well service conduit; a second tubing string being expanded into sealing engagement with the casing string over at least a portion of their lengths. A second or outer tubing string surrounding that suspended from the tubing hanger may therefore be expanded to contact the production casing so that a seal is effected between these two tubulars, thereby eliminating the annulus conduit. The annulus conduit may only be absent at the base of the well in the case of a tapered well construction but uniform diameter, non-tapering wells are also possible in which the annulus is totally eliminated. 
   In this circumstance, it is no longer possible to circulate fluids in the well via the annulus and the central tubing string suspended from the tubing hanger performs the function that the annulus traditionally performs. The annulus conduit defined between the two tubing strings is now used for production. This has a significant impact on the configuration of the completion equipment, especially the tree. Further preferred features and advantages of the invention are in the dependent claims and the following description of preferred embodiments, made with reference to the drawings. 


   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a diagrammatic representation of a first completion system embodying the invention, shown during installation/testing; 
       FIG. 2  corresponds to  FIG. 1  but shows the system in production mode; 
       FIG. 3  diagrammatically represents a tubing hanger such as may be used in the system of  FIG. 1 ; 
       FIGS. 4 and 5  show an alternative tubing hangers; 
       FIGS. 6 ,  8 ,  10  and  12  are diagrams of second, third, fourth and fifth embodiments of the completion system respectively, all shown during installation/testing; 
       FIGS. 7 ,  9 ,  11  and  13  correspond to  FIGS. 6 ,  8 ,  10  and  12  respectively, but show the system in production mode; 
       FIG. 14  shows a modification of the embodiment of  FIG. 13 ; 
       FIG. 15  is a diagram of a first casing program that may be used in conjunction with the completion system of the invention; 
       FIG. 16  corresponds to  FIG. 15  but diagrammatically indicates a liner, an outer tubing string and completion riser run into the casing; 
       FIG. 17  is a diagram of the interface between the tree, wellhead housing and outer tubing hanger of the completion system of  FIG. 16 ; 
       FIG. 18  corresponds to  FIG. 17  but diagrammatically indicates a central circulation tubing string and liner top isolation valve installed in the well; 
       FIG. 19  is a diagrammatic cross-section through the central circulation tubing; 
       FIG. 20  is a diagram of a second casing program that may be used in conjunction with the completion system of the invention; 
       FIG. 21  corresponds to  FIG. 20  but diagrammatically indicates a liner and outer tubing run into the well; 
       FIGS. 22 and 23  show tubing expansion operations; 
       FIG. 24  is a diagram of the interface between the tree, wellhead housing and outer tubing of the completion system of  FIG. 21 ; 
       FIGS. 25 to 27  show modifications of  FIG. 24 ; 
       FIG. 28  is a diagram of a third casing program that may be used in conjunction with the completion system of the invention; 
       FIG. 29  corresponds to  FIG. 28  but diagrammatically indicates a liner, production casing and outer tubing run into the well, and 
       FIG. 30  is a diagram of the interface between the tree, wellhead housing and outer tubing hanger of the completion system of  FIG. 22 . 
   


   DESCRIPTION OF THE PREFERRED EMBODIMENTS 
   The preferred completion system includes a subsea christmas tree configuration that will allow the installation of a centrally located service conduit. The preferred well, construction also comprises the following components that are typically used in completions and accordingly the subsea tree design provides the appropriate interfacing equipment:
         SCSSV or functional equivalent   Downhole chemical injection   Gas lift mandrels   Downhole instrumentation, e.g. pressure and temperature gauges       

   The central service conduit provided by a central coiled tubing string is preferably replaceable with minimum impact on the installed second or outer production tubing and subsea christmas tree equipment. The outer tubing string is terminated at the wellhead housing (either with or without a tubing hanger) and the tree seals to the wellhead housing with a seal stab. 
   Referring to  FIG. 1 , coiled tubing  14  is suspended from a coiled tubing hanger  12  in a horizontal christmas tree  10 . The tree  10  is locked and sealed to a wellhead housing  11 . No SCSSV is included in the system. For installation, the coiled tubing hanger  12  has a lock profile  16  by which it is attached to an installation test tool  18 . A central circulation/service valve  20  is situated in the coiled tubing hanger  12  for controlling fluid flows from/to the coiled tubing  14 . The coiled tubing hanger  12  is landed in a vertically extending through bore  15  in the tree  10 . The tubing hanger  12  is sealed and locked to the tree as schematically indicated, by annular seal  22  and lock profile  24 . Remote wet mate couplers  26  allow downhole service and control lines  28  to be connected to corresponding lines  30  in the installation test tool  18  and its installation string  32 . The outside diameters of the coiled tubing hanger  12 , installation test tool  18  and installation string  32  are compatible with the drift of a monobore completions riser which has, for example, a bore diameter of 17.1 mm (6.75″). 
   A production conduit  34  intersects with the through bore  15  below the tubing hanger seal  22 . A production master valve  36  and a production wing valve  38  are provided in the production conduit  34 . A pressure cap  40  is optionally installed on a wing outlet  42  of the tree  10  at the stage of installation and subsequent flow test. For flow testing, a production bypass conduit  44  containing a valve  46  extends between the production conduit  34  to the through bore  15  above the tubing hanger seal  22 . A service/circulation conduit  48  intersects with the through bore  15  above the tubing hanger seal  22 . The conduit  48  contains a valve  50  of equivalent function to the annulus wing valve of a “standard” horizontal tree. However, rather than communicating with a production tubing/production casing annulus as is conventional, the service/circulation conduit  48  is connected to the upper end of the coiled tubing  14 . A crossover conduit  45  containing a crossover valve  47  connects the bypass conduit  44  (and/or the production conduit  34  between the valves  36 ,  38 ) to the circulation/service conduit  48 . 
   The installation test tool  18  is connected between the coiled tubing hanger  12  and the installation string  32 . Upper and lower seals  52 ,  54  seal a lower end of the installation test tool  18  within the tree through bore  15 . A conduit  56  in the installation test tool  18  has a side outlet positioned between the seals  52 ,  54  for communication with the production bypass conduit  44 , and an upper end in communication with a riser conduit  58  in the installation string  32 . During flow testing, production fluid may therefore be led to the surface rig or vessel through the installation test tool interior and the riser conduit  58 . 
   The lower end of the installation test tool  18  also has a central bore  60  in communication with the coiled tubing interior via the central circulation/service valve  20 . A side outlet  61  leads from the bore  60  to the circulation/service conduit  48 . A workover conduit  62  containing a workover valve  64  extends from the circulation/service conduit  48  to the tree through bore  15  at a point above the installation test tool upper seal  52 . The other end of the installation test tool  18  comprises an upwardly extending spool  66  through which runs the conduit  56 . A BOP  68  is attached to the upper end of the tree  10 . Pipe rams  70  in the BOP  68  can be closed and sealed about the installation test tool spool  66 , thereby sealingly connecting the workover conduit  62  to a choke/kill line  72  of the BOP. 
   The installation test tool also allows controls to be hooked up to the down-hole lines  28  and for operation of the circulation/service valve  20  in the coiled tubing hanger  12 . Besides the remote subsea mateable couplers  26  to the top of the coiled tubing hanger  12 , the installation test tool  18  also includes further remote subsea mateable couplers  74  to the base of the installation string  32 . 
   The installation string  32  is latched and sealed to the top of the installation test tool  18  by a remotely operable connector  76  providing emergency disconnect capability. A monobore completions riser  78  is connected to the upper end of the BOP  68  by a lower marine riser package  80  which also provides for emergency disconnection. When disconnected, any fluids present in the riser conduit  58  are retained by a valve  82 . The couplers  74  connect the control lines  30  in the installation test tool  18  to a controls umbilical  84  attached to the installation string  32 . 
     FIG. 2  shows the tree in production mode. An internal tree cap  86  is installed through the BOP  68  in place of the installation test tool  18  and installation string  32 . The BOP  68  is then removed. The tree cap  86  locks and seals to the tree bore  15  above the production conduit  34  intersection as schematically illustrated by locking profile  88  and seal  90 . Remote subsea mateable couplers  26  are again provided for hook up of control lines to the central circulation/service valve  20  in the coiled tubing hanger  12  and to the downhole lines  28 . A controls cap  92  with remote wet mate couplers  94  connects the control lines to a jumper  96 . The central bore  60  and side outlet of the installation test tool are reproduced in the tree cap  86  to provide fluid communication between the coiled tubing interior and the circulation/service conduit  48 . 
   The completion system illustrated in  FIGS. 1 and 2  satisfies accepted double barrier pressure containment philosophy/industry practice. It provides communication to multiple down-hole electrical and hydraulic service lines, either via a controls umbilical run with the installation string, or via a controls cap and jumper in production mode. A central coiled tubing string  14  is suspended in the well, to provide a means of well circulation for well startup and well kill. It also provides a means for readily installing or removing (eg for servicing and repair) downhole equipment such as valves, pumps, gas lift and chemical injection mandrels and downhole instrumentation. This can be installed/replaced without disturbing the outer production tubing and tree. 
   The central coiled tubing string  14  is suspended within an outer tubing string  98  which is expanded into sealing contact with surrounding production casing  100  and the wellhead housing  11 . The need for tubing hangers and packers may thus be eliminated. If a tubing hanger is used to suspend the outer tubing string  98  which has its lower end expanded into contact with the production casing, the outer tubing hanger is landed in the wellhead  11  because the outer tubing  98  is permanently attached to the other well tubulars and cannot be retrieved. Landing the outer tubing hanger in the tree  10  would therefore prevent (or at least make difficult) the recovery of the tree. If tubing corrosion occurs, a new (thin wall) liner tubing can be expanded into place inside the old outer tubing. 
   The use of expandable well tubulars also results in a more gradually tapering, or even uniform diameter, well. Thus the upper tubulars and completion equipment are of reduced size and weight compared to conventional wells of equivalent depth, giving materials savings and reduced operational costs. The marine riser system/BOP stack used at installation only needs a bore similar to a completions riser. Therefore it is very similar to a lightweight intervention system. Faster drill penetration rates can be achieved and the use of lower cost vessels with lower lift capacity is made possible. 
   Flow tests may be conducted via the installation string and workover access is provided via the coiled tubing string. The tree has a similar cost and complexity to known horizontal trees. No subsea test tree is needed during installation and workover. There is potential to adapt the system for a dual zone completion, for the use of ESP&#39;s, or for downhole separation. The effective production tubing size can be reduced as the well matures, by increasing the diameter of the coiled tubing, or a velocity string can be fitted. The completion system offers improved control of well circulation via the subsea tree for well kill or gas lift applications. 
     FIGS. 3–5  illustrate various alternatives for the coiled tubing hanger configuration.  FIG. 3  shows a single body coiled tubing hanger  12  with an integral ball valve  20  and hydraulic actuator. Down hole control lines  102  pass through the hanger body and are connected to control lines  104  external to the coiled tubing  14  via couplers  106 . The down hole controls lines are therefore exposed to produced fluids and mechanical damage during the trip in the hole. The remote mateable couplers  26  must be made very small. 
     FIG. 4  shows a single, multi-pin, self orienting subsea mateable connector  108  instead of the multiple connectors  26 . This system is particularly suitable if the down hole lines  104  are all of the same type, e.g electrical, optical or hydraulic. It is less suitable if there is a combination of different line types. 
     FIG. 5  shows a split hanger arrangement in which the coiled tubing hanger comprises two separable parts  12   a ,  12   b , joined by a seal stab  110 . The lower part  12   b  is prefabricated as part of the coiled tubing string and the service line couplers  112  are factory tested. The lower part  12   b  is assembled to the upper part  12   a  at the drill floor. This design may have multiple single-pin subsea mateable couplers as shown, or a multi-pin connector similar to  108 ,  FIG. 4 . 
     FIG. 6  shows a modification of the system of  FIG. 1 , in which the coiled tubing hanger  12  has a blind top, i.e. no vertical through bore is provided. Comparing with the  FIG. 1  embodiment, in  FIG. 6  the central circulation/service valve  20  has been moved from the coiled tubing hanger  12  to the circulation/service conduit  48  in the tree  10 . The workover conduit  62  still joins the central circulation/service conduit  48  between the valve  20  and the wing valve  50 . The lower seal  54  on the installation test tool  18  has been eliminated and an additional upper seal  114  provided on the coiled tubing hanger  12 . A side outlet  116  in the tubing hanger  12 , analogous to the installation test tool side outlet  61  in  FIG. 1 , communicates with the circulation/service conduit  48 , between the tubing hanger upper and lower seals  114 ,  22 . In other respects, the  FIG. 6  arrangement is structurally and functionally similar to that of  FIG. 1 . 
     FIG. 7  shows the system of  FIG. 6  in production mode. It is analogous to  FIG. 2 , but having a simplified internal tree cap  86 , as the bore  60  and side outlet  61  are eliminated. A controls cap  92  and a controls jumper  96  are again provided. 
     FIG. 8  shows a third embodiment, similar to  FIG. 6 , except that a second production bypass valve  43  is provided in the production bypass conduit  44 , in series with the valve  46 . This enables the tree cap  86  to be eliminated in production mode ( FIG. 9 ), as the valve  43  can serve as a second pressure barrier in series with the valve  46 , when the production master valve  36  is open. If desired, a secondary lockdown device  118  can be provided for the coiled tubing hanger  12  in production mode. The controls cap  92  and couplers  94  interface directly with the coiled tubing hanger  12 . The embodiment of  FIGS. 1 and 2  may be modified in similar manner. 
     FIG. 10  shows a further modification of the  FIG. 6  embodiment. The production bypass conduit  44  and bypass valve  46  have been eliminated, likewise the side outlet in the installation test tool  18  below the seal  52 . Instead, the coiled tubing hanger  12  is provided with flow by slots or a flow by conduit  120  extending from the annulus defined between the tubing strings  14 ,  98  below the tubing hanger  12 , to the tree through bore  15  above the tubing hanger  12 . The installation test tool  18  no longer interfaces with the tubing hanger lock profile  16 . Instead, a separate tubing hanger running tool (not shown) is used to install the tubing hanger  12 . Upper and lower swab valves  122 ,  124  (e.g. large diameter gate valves) are provided in the tree through bore  15  between the installation test tool  18  and the coiled tubing hanger  12 . In production mode ( FIG. 11 ) these swab valves are closed to provide a double pressure barrier, so that no tree cap is needed. The workover conduit  62  extends from the circulation/service conduit, to the through bore  15  above the installation test tool lower seal  52 , for fluid communication with BOP choke/kill lines  72 , as previously described. Hook up to the downhole service lines  28  is by means of horizontal penetrators in the tree  10 , which interface with the coiled tubing hanger  12 . The coiled tubing hanger  12  is effectively pressure balanced and theoretically needs no lock down. The lower end of the coiled tubing string  14  is not fixed so thermal expansion does not provide an upthrust. Notional lock down is provided by the horizontal penetrators  126  from the tree  10 . 
     FIG. 12  shows a modification of the  FIG. 10  embodiment, for which the installation process is similar to a conventional christmas tree, in that a BOP stack is not used on the tree. The BOP stack and marine riser are removed from the wellhead  10  prior to tree installation and a lower riser package  128 , emergency disconnect package  130  and an open water riser  132  are used for the coiled tubing hanger installation and flow test. A sealed connection interface  134  is provided for coupling the workover conduit  62  in the tree  10  to a port  136  in the lower riser package  128 , of equivalent function to a conventional lower riser package annulus port. An installation test tool is not required for installing and flow testing the completion. The lower riser package 128 /emergency disconnect package  130  system may have a controls umbilical  142 , for example connectable to the tree  10  via remote wet mate couplers  144 , for hook up to the tree valves and to the downhole service lines  28  via the horizontal penetrators  126 . Installation and recovery of the coiled tubing string may be carried out from a lightweight intervention vessel, without the use of a BOP. The lower riser package includes upper and lower valves  138 ,  140  (for example large bore gate valves) at least one of which may, if required in an emergency, be used to shear the coiled tubing string.  FIG. 13  shows the tree in production mode with the EDP/LRP and riser removed and the swab valves  122 ,  124  closed above the coiled tubing hanger  12 . 
   Finally,  FIG. 14  corresponds to  FIG. 13  but shows a modification in which the production conduit  34  intersects with the tree through bore above the coiled tubing hanger  12 , rather than below it. 
   Table 1 sets out barrier matrices for the completions described above, for various procedures and conditions. 
   
     
       
             
           
             
             
             
           
         
             
                 
             
             
               Abbreviations 
             
             
                 
             
           
           
             
                 
             
           
        
         
             
                 
               BOP 
               Blowout preventer 
             
             
                 
               CSV 
               Circulation/service valve 
             
             
                 
               CT 
               Coiled tubing 
             
             
                 
               CTH 
               Coiled tubing hanger 
             
             
                 
               CXT 
               Conventional tree 
             
             
                 
               HXT 
               Horizontal tree 
             
             
                 
               ITC 
               Internal tree cap 
             
             
                 
               ITT 
               Installation test tool 
             
             
                 
               LRP 
               Lower riser package 
             
             
                 
               LSV 
               Lower swab valve 
             
             
                 
               LTIV 
               Liner top isolation valve 
             
             
                 
               PBV 
               Production bypass valve 
             
             
                 
               PMV 
               Production master valve 
             
             
                 
               PWV 
               Production wing valve 
             
             
                 
               SSTT 
               Subsea test tree 
             
             
                 
               TH 
               Tubing hanger 
             
             
                 
               USV 
               Upper swab valve 
             
             
                 
               ITC 
               Internal tree cap 
             
             
                 
               WOV 
               Workover valve 
             
             
                 
                 
             
           
        
       
     
   
   
     
       
             
           
             
             
           
             
             
             
             
             
           
             
             
             
             
             
             
             
             
             
           
             
           
             
             
             
             
             
             
             
             
             
           
             
           
             
             
             
             
             
             
             
             
             
           
             
           
             
             
             
             
             
             
             
             
             
           
             
           
             
             
             
             
             
             
             
             
             
           
             
             
             
           
             
             
             
             
             
           
             
             
           
             
             
             
             
             
           
             
             
           
             
             
             
             
             
           
             
             
           
             
             
             
             
             
           
             
             
           
             
             
             
             
             
           
         
             
               TABLE 1 
             
             
                 
             
             
               (follows) 
             
             
                 
             
           
           
             
                 
             
           
        
         
             
                 
               COMPLETION TYPE 
             
           
        
         
             
                 
               FIGS. 1 and 2 
               FIGS. 6 and 7 
               FIGS. 8 and 9 
               FIGS. 10 and 11 
             
           
        
         
             
               PROCEDURE 
               1 st  Barrier 
               2 nd  Barrier 
               1 st  Barrier 
               2 nd  Barrier 
               1 st  Barrier 
               2 nd  Barrier 
               1 st  Barrier 
               2 nd  Barrier 
             
             
                 
             
           
        
         
             
               Foundation 
             
           
        
         
             
               Drill 36″ hole 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               Run and cement 30″ conductor 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               and LP housing 
                 
                 
                 
                 
                 
                 
                 
                 
             
             
               Drill 12-1/4″ hole 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               Drilling 
                 
                 
                 
                 
                 
                 
               N/A 
               N/A 
             
             
               Run and cement 6″ casing and 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               wellhead housing 
                 
                 
                 
                 
                 
                 
                 
                 
             
             
               Run BOP stack and marine riser 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               Drill 8″ hole 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Run 6″ liner 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Drill 8″ hole 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Run 6″ liner 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Drill 8″ hole 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Run 6″ liner 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Drill 8″ hole 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               Run 6″ liner and lower 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               completion with LTIV 
             
             
               Run 5″ upper completion and 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               expand onto the 6″ liner 
             
             
               Set casing plugs 
               Caing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
             
             
               Tree Installation 
                 
                 
                 
                 
                 
                 
                 
                 
             
             
               Retrieve BOP 
               Caing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
             
             
               Run HXT 
               Caing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
             
             
               Run BOP/LRP 
               Caing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
               Casing plug 
               Fluid 
             
           
        
         
             
               Completion 
             
           
        
         
             
               Drill out/remove casing plugs 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
               Drill 8″ hole 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Run 6″ liner and lower 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               completion with LTIV 
                 
                 
                 
                 
                 
                 
                 
                 
             
             
               Pull HXT bore protector 
               LTIV 
               Fluid/BOP 
               LTIV 
               Fluid/BOP 
               LTIV 
               Fluid/BOP 
               LTIV 
               Fluid/BOP 
             
             
               Run 5″ upper completion 
               LTIV 
               Fluid/BOP 
               LTIV 
               Fluid/BOP 
               LTIV 
               Fluid/BOP 
               LTIV 
               Fluid/BOP 
             
             
               (outer tubing) and expand 
                 
                 
                 
                 
                 
                 
                 
                 
             
             
               onto the 6″ liner 
             
             
               Run CTH, lock and test 
               LTIV 
               Fluid/BOP/ 
               LTIV 
               Fluid/BOP/ 
               LTIV 
               Fluid/BOP/ 
               LTIV 
               Fluid/BOP 
             
             
                 
                 
               CTH 
                 
               CTH 
                 
               CTH 
                 
               CTH 
             
           
        
         
             
               Flow Test 
             
           
        
         
             
               Circulate to lighter fluid 
               LTIV 
               CSV 
               LTIV 
               CSV 
               LTIV 
               CSV 
               LTIV 
               CSV 
             
             
               Overpressure the LTIV and 
               PWV 
               Pressure Cap 
               PWV 
               Pressure cap 
               PWV 
               Pressure Cap 
               PMV 
               PWV 
             
             
               flow test the well 
               CSV 
               WOV 
               CSV 
               WOV 
               CSV 
               WOV 
               CSV 
               WOV 
             
             
                 
               ITT 
               BOP 
               ITT 
               BOP 
               ITT 
               BOP 
               ITT 
               BOP 
             
             
               Isolate well at HXT 
               PMV 
               PWV 
               PMV 
               PBV 
               PMV 
               PBV 
               USV 
               LSV 
             
             
               Run ITC 
               CTH 
               ITC and 
               CTH 
               ITC and 
               N/A 
               N/A 
               N/A 
               N/A 
             
             
                 
                 
               BOP 
                 
               BOP 
             
             
               Run CTH 2ary lockdown 
               N/A 
               N/A 
               N/A 
               N/A 
               CTH 
               BOP 
               N/A 
               N/A 
             
             
               Pull BOP/LRP 
               CTH 
               ITC 
               CTH 
               ITC 
               CTH upper 
               CTH lower 
               USV 
               LSV 
             
             
                 
                 
                 
                 
                 
               seal 
               seal 
                 
                 
             
             
               Install controls cap by ROV 
               CTH 
               ITC 
               CTH 
               ITC 
               CTH upper 
               CTH lower 
               N/A 
               N/A 
             
             
                 
                 
                 
                 
                 
               seal 
               seal 
             
             
               Produce to flow lines 
               CTH 
               ITC 
               CTH 
               ITC 
               CTH upper 
               CTH lower 
               USV 
               LSV 
             
             
                 
                 
                 
                 
                 
               seal 
               seal 
             
           
        
         
             
               Tubing access workover with BOP 
             
           
        
         
             
               Pull controls cap 
               CSV 
               ITC 
               CTH 
               ITC 
               CTH upper 
               CTH lower 
               N/A 
               N/A 
             
             
                 
                 
                 
                 
                 
               seal 
               seal 
             
             
               Pull ITC 
               CSV 
               BOP 
               CTH 
               BOP 
               CTH 
               BOP 
               N/A 
               N/A 
             
             
               Run LRP/ 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               N/A 
               USV 
               LSV 
             
             
               BOP + marine riser 
                 
                 
                 
                 
                 
                 
                 
                 
             
             
               Run ITT 
               CSV 
               BOP 
               CTH 
               BOP 
               CTH 
               BOP 
               USV 
               LSV 
             
             
               Circulate the well to kill weight 
               Fluid 
               CSV + BOP 
               Fluid 
               CTH + BOP 
               Fluid 
               CTH + BOP 
               Fluid 
               BOP 
             
             
               Pull CTH 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Replace CTH 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
               Fluid 
               BOP 
             
             
               Circulate the well to light weight 
               CSV 
               CSV + BOP 
               CTH 
               CSV + BOP 
               CTH 
               BOP 
               USV 
               LSV 
             
             
               Pull ITT 
               CSV 
               CSV + BOP 
               CTH 
               CSV + BOP 
               CTH 
               BOP 
               USV 
               LSV 
             
             
               Run ITC 
               CSV 
               ITC 
               CTH 
               ITC 
               CTH 
               BOP 
               N/A 
               N/A 
             
             
               Pull BOP stack + 
               CSV 
               ITC 
               CTH 
               ITC 
               CTH upper 
               CTH lower 
               USV 
               LSV 
             
             
               marine riser/LRP 
                 
                 
                 
                 
               seal 
               seal 
             
             
               Install controls cap 
               CSV 
               ITC 
               CTH 
               ITC 
               CTH upper 
               CTH lower 
               N/A 
               N/A 
             
             
                 
                 
                 
                 
                 
               seal 
               seal 
             
             
               Tubing access workover with LWI 
             
             
               Vessel 
             
             
               Similar to above 
             
             
               Outer tubing retrieval workover 
             
             
               with BOP 
             
             
               Assumed to be impossible due to 
             
             
               tubing being expanded onto previous 
             
             
               casing 
             
             
                 
             
           
        
         
             
                 
               COMPLETION TYPE 
                 
             
             
                 
               FIGS. 12, 13 and 14 
                 
             
           
        
         
             
                 
               PROCEDURE 
               1 st  Barrier 
               2 nd  Barrier 
               COMMENTS 
             
             
                 
                 
             
           
        
         
             
                 
               Foundation 
             
           
        
         
             
                 
               Drill 36″ hole 
               N/A 
               N/A 
                 
             
             
                 
               Run and cement 30″ conductor 
               N/A 
               N/A 
               Assuming that well 
             
             
                 
               and LP housing 
                 
                 
               foundation is needed as per 
             
             
                 
                 
                 
                 
               FIG. 15 
             
             
                 
               Drill 12-1/4″ hole 
               N/A 
               N/A 
             
             
                 
               Drilling 
             
             
                 
               Run and cement 6″ casing and 
               N/A 
               N/A 
               HP housing has 6–8½″ nom. 
             
             
                 
               wellhead housing 
                 
                 
               bore and no casing hanger 
             
             
                 
                 
                 
                 
               landing shoulder.H-4 profile 
             
             
                 
                 
                 
                 
               per 18¾″ system to allow 
             
             
                 
                 
                 
                 
               wide range of BOP stacks. 
             
             
                 
               Run BOP stack and marine riser 
               N/A 
               N/A 
               18¾″ system or smaller 6″ 
             
             
                 
                 
                 
                 
               minimum ID 
             
             
                 
               Drill 8″ hole 
               Fluid 
               BOP 
             
             
                 
               Run 6″ liner 
               Fluid 
               BOP 
             
             
                 
               Drill 8″ hole 
               Fluid 
               BOP 
             
             
                 
               Run 6″ liner 
               Fluid 
               BOP 
             
             
                 
               Drill 8″ hole 
               Fluid 
               BOP 
             
             
                 
               Run 6″ liner 
               Fluid 
               BOP 
             
             
                 
               Drill 8″ hole 
               Fluid 
               BOP 
             
             
                 
               Run 6″ liner and lower 
               Fluid 
               BOP 
             
             
                 
               completion with LTIV 
             
             
                 
               Run 5″ upper completion and 
               LTIV 
               Fluid/BOP 
             
             
                 
               expand onto the 6″ liner 
             
             
                 
               Set casing plugs 
               Casing plug 
               Fluid 
             
             
                 
               Tree Installation 
                 
                 
               Alternatively, install the tree at the 
             
             
                 
                 
                 
                 
               same time as the WH housing and 
             
             
                 
                 
                 
                 
               drill thru tree. 
             
             
                 
               Retrieve BOP 
               Casing plug 
               Fluid 
             
             
                 
               Run HXT 
               Casing plug 
               Fluid 
             
             
                 
               Run BOP/LRP 
               Casing plug 
               Fluid 
               LRP used in FIGS. 12–14 
             
           
        
         
             
                 
               Completion 
             
           
        
         
             
                 
               Drill out/remove casing plugs 
               Fluid 
               LRP 
                 
             
             
                 
               Drill 8″ hole 
               N/A 
               N/A 
               Drill into formation 
             
             
                 
               Run 6″ liner and lower 
               N/A 
               N/A 
               Assumes LTIV That can be 
             
             
                 
               completion with LTIV 
                 
                 
               opened by overpressure or 
             
             
                 
                 
                 
                 
               cyclic pressure 
             
             
                 
               Pull HXT bore protector 
               N/A 
               N/A 
             
             
                 
               Run 5″ upper completion 
               N/A 
               N/A 
               Assumes that no packer is 
             
             
                 
               (outer tubing) and expand 
                 
                 
               used 
             
             
                 
               onto the 6″ liner 
             
             
                 
               Run CTH, lock and test 
               LTIV 
               Fluid/LRP/ 
               Assumes no SSTT needed. 
             
             
                 
                 
                 
               CTH 
               CTH run on CT installation 
             
             
                 
                 
                 
                 
               string, FIGS. 1, 6, 8 
             
           
        
         
             
                 
               Flow Test 
             
           
        
         
             
                 
               Circulate to lighter fluid 
               LTIV 
               CSV 
               Open CSV. Close when 
             
             
                 
                 
                 
                 
               complete 
             
             
                 
               Overpressure the LTIV and 
               PMV 
               PWV 
               Flow test via PBV and ITT, 
             
             
                 
               flow test the well 
               CSV 
               WOV 
               FIGS. 1–11. Disconnect/drive 
             
             
                 
                 
               USV 
               LSV 
               off by closing HXT values =&gt; 
             
             
                 
                 
                 
                 
               no SSTT needed 
             
             
                 
               Isolate well at HXT 
               USV 
               LSV 
               Close PMV and PBV 
             
             
                 
               Run ITC 
               N/A 
               N/A 
             
             
                 
               Run CTH 2ary lockdown 
               N/A 
               N/A 
               Maybe unnecessary 
             
             
                 
               Pull BOP/LRP 
               USV 
               LSV 
               Assumed acceptable as seals 
             
             
                 
                 
                 
                 
               independently testable and on 
             
             
                 
                 
                 
                 
               different seal bores. LRP 
             
             
                 
                 
                 
                 
               use for FIGS. 12–14 
             
             
                 
               Install controls cap by ROV 
               N/A 
               N/A 
             
             
                 
               Produce to flow lines 
               USV 
               LSV 
               Open PMV and PWV 
             
           
        
         
             
                 
               Tubing access workover with BOP 
             
           
        
         
             
                 
               Pull controls cap 
               N/A 
               N/A 
                 
             
             
                 
               Pull ITC 
               N/A 
               N/A 
             
             
                 
               Run LRP/ 
               USV 
               LSV 
               BOP FIGS. 10, 11 18¾″ or 
             
             
                 
               BOP + marine riser 
                 
                 
               smaller. 9″ min. ID. 
             
             
                 
                 
                 
                 
               LRP FIGS. 12–14 
             
             
                 
               Run ITT 
               N/A 
               N/A 
             
             
                 
               Circulate the well to kill weight 
               Fluid 
               LRP 
               Open CSV. Close BOP rams 
             
             
                 
                 
                 
                 
               on the ITT and circulate via 
             
             
                 
                 
                 
                 
               choke/kill, FIGS. 1–11 
             
             
                 
               Pull CTH 
               Fluid 
               LRP 
               Open USV, LSV, FIGS. 10–14 
             
             
                 
               Replace CTH 
               Fluid 
               LRP 
             
             
                 
               Circulate the well to light weight 
               USV 
               LSV 
             
             
                 
               Pull ITT 
               N/A 
               N/A 
             
             
                 
               Run ITC 
               N/A 
               N/A 
             
             
                 
               Pull BOP slack + 
               USV 
               LSV 
             
             
                 
               marine riser/LRP 
             
             
                 
               Install controls cap 
               N/A 
               N/A 
             
             
                 
               Tubing access workover with LWI 
             
             
                 
               Vessel 
             
             
                 
               Similar to above 
             
             
                 
               Outer tubing retrieval workover 
             
             
                 
               with BOP 
             
             
                 
               Assumed to be impossible due to 
             
             
                 
               tubing being expanded onto previous 
             
             
                 
               casing 
             
             
                 
                 
             
           
        
       
     
   
     FIGS. 15–18  are highly schematic half-sectional representations of a casing program that may be used with the wellhead housing  11  of the previous figures.  FIGS. 15 and 16  are prior to tree installation; and  FIG. 18  shows the tree  10  installed. Initially, a foundation is established using conductor casing  146 , for example a 13⅜″ conductor or larger. The size of the LP housing and foundation is substantially independent of the size of the rest of the system. 
   A hole section is then drilled, a first casing section  100  is run and cemented and the wellhead housing  11  established. This may be of small diameter (21.6 mm, 8½″ drift). A further hole section is then drilled and an expandable casing section  148  run, cemented and expanded to the bore diameter of the first casing section  100 . Expansion seals the casing section to the previously installed casing without the use of packers or the like. Methods for installing expandable tubulars are known in the art and will not be further elaborated here. The expansion pig may be run either from the top down or from the bottom up. However, the bottom up method is preferred, as then no hangers are needed. 
   Drilling continues and as many further casing sections  150 ,  152  as may be needed to reach the reservoir  154  are installed successively. All casing sections are expanded to the bore diameter of the initial section  100  (e.g. 6″), to produce a parallel sided well. When needed, the BOP  68  is installed on the wellhead housing  11 . All casing sections are capable of withstanding the reservoir pressure. 
   Drilling is continued into the reservoir  154  as shown in  FIG. 16  and a liner section  156  is installed and expanded to the casing diameter. The outer tubing string  98  is then run and expanded (preferably using the bottom up method) into sealing contact with the liner  156 , casing and wellhead  11 . Therefore no tubing hanger or packers are needed to support the tubing  98  and seal it in the wellhead housing  11 : see  FIG. 17 . Also, the final top location of the tubing is not accurately predictable due to axial shrinkage during radial expansion. The liner  156  is perforated and a liner top isolation valve  160  or similar isolation device installed. Also shown in  FIG. 17  is a tree stab  158  for sealing the tree  10  to a corresponding pocket in the wellhead housing  11 . 
     FIG. 18  shows the tree  10  attached to the wellhead housing  11  in place of the BOP and the BOP reinstalled on the tree. The coiled tubing string  14  and coiled tubing hanger  12  is then run on the installation string  32  and landed in the tree  10 . The coiled tubing string  14  may be used to carry downhole instrumentation, chemical injection and gas lift mandrels  162 ,  164 , ESP&#39;s, separation equipment and the like, as discussed above, as well as any required service lines. These may be secured to the coiled tubing exterior as shown in  FIGS. 3 and 4 . Preferably however they are enclosed within the coiled tubing bore as indicated in  FIGS. 1 ,  2  and  5 – 14 .  FIG. 19  is a diagrammatic cross-section through the coiled tubing, showing two fluid containing service lines  166 ,  168  and an electrical or optical service line  170 . 
     FIGS. 20–22  show an alternative casing program. Again no casing hangers are required at the wellhead housing  11  and each casing section is capable of withstanding the reservoir pressure. The casing sections are each expanded into seating contact with the previously installed section, but are of successively smaller diameters. For example a 30″ conductor casing  146  may be used, with the other casing diameters (when expanded) as follows:
 100: 9⅝″; 148: 8⅝″; 150: 7⅝″; 152: 6⅝″ 
   Referring to  FIG. 21 , the final well section is drilled into the reservoir  154  and a (for example) 5⅝″ liner  156  and liner top isolation valve are  160  installed. The liner is expanded into sealing contact with the lowermost casing section  152 . 
   As shown in  FIG. 21 , the outer tubing string  98  is run on a completion riser  174  and expanded at its lower end onto the production liner  156 . The tubing string  98  is suspended from an outer tubing hanger  172  landed, sealed and locked down in the wellhead housing  11 . No production packer is needed. 
   There are several possible methods of setting the outer tubing hanger  172  and facilitating the expansion of the outer tubing  98  onto the liner  156 . The preferred methods are based on the “top down” expansion principle. This is better for this particular well construction due to the tapering casing strings. The outer tubing  98  only eliminates the tubing/production casing annulus at the lower section. A “bottom up” approach is only readily usable if a correspondingly tapered outer tubing  98  is used. This is inconvenient due the number of trips required to set the different sizes of pig and the increased tubing costs at the top sections. 
     FIG. 22  shows a first setting method. The outer tubing hanger  172  is run on a tool  174  and drill pipe  176 . The expansion pig  178  is attached to coiled tubing  180 . The pig  178  is pumped down by pressurised fluid supplied through the drill pipe/coiled tubing annulus. The coiled tubing  180  provides a return path up the tool string. However there may be difficulties in running coiled tubing at the same time as drill pipe. 
   A preferred alternative is as shown in  FIG. 23 . The bores of the THRT  174  and of the running string  176  are made large enough to drift the pig  178 . The pig is easier to install as the coiled tubing  180  can be run after the tubing hanger  172  has landed. The coiled tubing annulus again provides the pressurised fluid flow path for expansion of the outer tubing  98 , and the coiled tubing bore the return path. 
   There are various options for the seal interface between the wellhead housing  11  and the tree  10 . One consideration is the need to isolate the VX gasket from the produced fluids.  FIG. 24  shows a wellhead/tree seal arrangement for a completion including an outer tubing hanger  172 . A seal pocket is provided at the upper internal diameter of the wellhead housing to interface a seal stab  158  on the tree. This corresponds somewhat to the  FIG. 17  arrangement. The tree seal stab  158  has a drift diameter that allows passage of the tubing hanger to the bore of the well. This arguably is a single barrier to the environment if the VX gasket is discounted. 
   Alternatively, a seal pocket may be provided at the upper inside diameter of the outer tubing hanger  172  to interface a seal stab  158  on the tree, as shown in  FIG. 25 . With this option, the outer tubing  98  must be installed prior to tree installation. However the arrangement is arguably closer to that found in a conventional christmas tree and may therefore more readily gain industry acceptance and/or regulatory approval. 
   The arrangement shown in  FIG. 26  is similar to that shown in  FIG. 24 , but includes a further seal pocket at the wellhead housing  11  inside diameter, to interface a further seal stab  182  from the coiled tubing hanger  12  or another component to be located in the bore  15  of the tree  10 . The arrangement shown in  FIG. 17  may be modified likewise, so that the wellhead housing  11  accommodates a further seal stab e.g. from the coiled tubing hanger  12 .  FIG. 27  is similar to  FIG. 26 , except that the pocket for the further seal stab  182  is at the outer tubing hanger  172  upper inside diameter. 
     FIGS. 28–30  are diagrams of a third drilling program. Casing hangers are used in the wellhead housing  11  to suspend concentric casing strings  149 ,  151 ,  153  and production casing  157 . Each string is successively landed and expanded into sealing contact with the next outer string, preferably using a top down method such as shown in  FIGS. 22  or  23 . Prior to expansion, a temporary annulus exists between a given casing string and the next outer casing string. This can be used for circulation/cementing. Packoffs are not needed due to the seal effected between the concentric strings. The expanded casing sizes may be as follows:
 100: 9⅝″; 149: 7½″; 151: 7″; 153: 6½″; 157: 6″ 
   As shown in  FIG. 29 , outer tubing  98  is suspended in the wellhead  11  from tubing hanger  172 . The tubing  98  is then expanded onto the production liner  157 . Again the production liner has an isolation device such as a liner top isolation valve. No packer is needed and the tubing hanger  172  need not itself be sealed and locked to the wellhead housing  11 . (The expanded outer tubing  98  is sealed to the production casing  157 ). 
     FIG. 30  is a diagram showing the outer string hanger  172  and casing hangers  186 ,  188 ,  190 ,  192  for the successive casing strings  149 ,  151 ,  153 ,  157 , landed in the (consequently elongated) wellhead housing  11 . An interface with the tree seal stab  158  is also shown. Modification is of course possible in accordance with any of  FIGS. 25–27 .
A completion system comprises a christmas tree ( 10 ) mounted on a wellhead housing ( 11 ), a tubing hanger ( 12 ) landed in the tree or wellhead housing, the wellhead housing ( 11 ) being mounted on a casing string ( 100 ) and a tubing string ( 14 ) being suspended from the tubing hanger within the casing string; wherein, in use, the annulus defined between the tubing ( 14 ) and the casing ( 100 ) serves as a production bore. A second tubing string ( 98 ) is expanded into sealing engagement with the casing string ( 100 ) over at least a portion of their lengths. The annulus normally used to provide well service functions is thus eliminated. Well servicing is instead provided via the tubing string ( 14 ), which may be coiled tubing.