Abstract:
A system, apparatus, and method to apply tension to completion tubing in a wellbore. The system, apparatus, and method comprises an inner and outer tubing hanger, with the string of tubing attached to the inner tubing hanger. A running tool lands the outer tubing hanger on a landing shoulder and continues to lower the inner tubing hanger into the wellbore until the lower end of the inner tubing hanger latches into a retaining device. The running tool then sets a seal which holds the outer tubing hanger in position and causes a ratcheting mechanism to move to an engaged position. The running tool then withdraws the inner tubing hanger a predetermined distance until the inner tubing hanger engages the ratcheting mechanism.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    The present invention relates in general to a method and apparatus to set and apply tension to casing or completion tubing in a wellbore, and in particular to a tubing hanger having an inner member and an outer member, and a running tool that sets the outer member, draws tension on the tubing by pulling the inner hanger, and then maintains the tension by locking the inner hanger into the outer hanger. 
         [0003]    2. Brief Description of Related Art 
         [0004]    Some wells, such as gas injection storage wells, have completion strings comprising tubing. The completion strings experience thermal expansion due to temperature variations when, for example, gas is injected into a storage well or withdrawn from a storage well. To compensate for the thermal expansion, the tubing may be placed under tension. With sufficient tension, the thermal expansion merely relaxes some of the tension. The travel distance associated with thermal expansion is less than the distance the tubing was stretched during the tensioning. Thus, even when the tubing expands due to increased temperatures, the tubing does not buckle within the wellbore. 
         [0005]    Tensioning devices currently used on gas storage wells use retractable load shoulder arrangements which are often based on blow-out preventer designs. These designs require through-wall penetrations in the main pressure-containing housing, thus creating potential leak paths. This type of design also results in increased cost of the wellhead as the main housing material has to increase in diameter to accommodate the actuating mechanisms, which results in increased manufacturing costs and in addition, costs for the retractable load shoulder mechanism. 
         [0006]    Modern well practice is to run various downhole safety valves and gauges through the wellbore. The existing retractable load shoulder type tensioning arrangement causes interference problems with the associated control lines descending below the tubing hanger. 
         [0007]    Whilst the retractable load shoulder arrangement is relatively simple from a mechanical standpoint, it leads to the use of elastomeric materials to provide the main well bore seals. It is widely known that elastomeric materials degrade over time and given that gas storage facilities are usually planned to have long service lives (up to forty years), this seal degradation causes problems in later years. 
       SUMMARY OF THE INVENTION 
       [0008]    A tubing hanger assembly is used to set and tension a string of tubing between a wellhead housing and a wellbore downhole tubing retaining device. A running tool is used to lower the tubing hanger and tubing into the wellhead housing. An outer portion of the tubing hanger lands in the wellhead housing and remains stationary. An inner portion of the tubing hanger, with a first end of the tubing attached, passes through the outer tubing hanger and is lowered until a second end of the tubing latches into the wellbore downhole retaining device. The running tool is pulled back, which lifts the inner tubing hanger and applies tension on the string of tubing. The inner tubing hanger latches into the outer tubing hanger as the inner tubing hanger is pulled up through the outer tubing hanger. The following is a more detailed description of the operation of an exemplary embodiment. 
         [0009]    A tubing hanger assembly is attached to a tubing hanger running tool and lowered into a wellhead housing. A string of casing, or tubing, is suspended from tubing hanger assembly. The tubing hanger assembly comprises an outer tubing hanger and an inner tubing hanger. The outer and inner tubing hangers are initially held together by one or more shear pins. 
         [0010]    The tubing hanger running tool lowers the hanger assembly until a shoulder of the outer tubing hanger lands on a wellhead housing shoulder. A ratchet ring, located within the outer tubing hanger, is held in a disengaged position, as will be explained subsequently, which allows further downward movement of the inner tubing hanger relative to the outer tubing hanger. The downward force of the conduit on the inner tubing hanger causes the shear pins to shear, thus freeing the inner tubing hanger from the outer tubing hanger. The operator continues to lower the tubing hanger running tool and inner tubing hanger, with the first end of the tubing still attached to the inner tubing hanger. A second end of the tubing latches into the wellbore downhole retaining device, such as a ratchet latch mechanism, which may be located within a gas storage well. The length of the tubing is calculated, in advance, so that the proper amount of tension is applied when the inner tubing hanger, and the attached tubing, is pulled back to the outer tubing hanger. Thus the running tool is advanced a predetermined distance from the point where the outer tubing hanger lands in the wellhead housing to the point where the second end of the tubing latches into the wellbore downhole retaining device. 
         [0011]    After the second end of the tubing is latched into the retaining device, the operator stops the running tool and then installs a seal. To install the seal, the operator partially energizes a hydraulic ram arrangement associated with the tubing hanger running tool, which causes an energizing ring to push the seal into position between the outer tubing hanger and the wellhead housing body. The seal causes a lock ring to engage a lock ring groove on the wellhead housing body, thus preventing upward movement of the outer tubing hanger. The seal also pushes against a release pin, which causes the ratchet ring to collapse inward. 
         [0012]    The running tool is pulled upward, which lifts the inner tubing hanger. As the inner tubing hanger is lifted, it moves upward relative to the outer hanger, applying tension to the section of tubing between the wellbore downhole retaining device and the wellhead housing. The ratchet ring ratchets on the external threads of the inner tubing hanger. The length of the tubing, and the distance of the pull of the running tool, are predetermined so that the desired amount of tension is reached when the inner tubing hanger is engaged by the ratchet ring. The ratchet ring holds the tension in the tubing by transmitting the load to the outer hanger and from there to the wellhead housing. The operator may then increase the hydraulic pressure on the ram to fully set the seal. The running tool is released from the outer hanger by rotation of the running tool. This results in the running tool unscrewing from lifting threads to allow retrieval. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]    So that the manner in which the features, advantages and objects of the invention, as well as others which will become apparent, are attained and can be understood in more detail, more particular description of the invention briefly summarized above may be had by reference to the embodiment thereof which is illustrated in the appended drawings, which drawings form a part of this specification. It is to be noted, however, that the drawings illustrate only a preferred embodiment of the invention and is therefore not to be considered limiting of its scope as the invention may admit to other equally effective embodiments. 
           [0014]      FIG. 1  is a sectional view of an exemplary embodiment of a running tool and internal lockdown tubing hanger system. 
           [0015]      FIG. 2  is a sectional view of an exemplary embodiment of the running tool of  FIG. 1 . 
           [0016]      FIG. 3  is a detail view of the seal and lockdown ring of the tubing tensioning system of  FIG. 1 . 
           [0017]      FIG. 4  is a sectional view of the communication collar of the tubing tensioning system of  FIG. 1 . 
           [0018]      FIG. 5  is a sectional view of the tubing hanger of the tubing tensioning system of  FIG. 1 . 
           [0019]      FIG. 6  is a sectional detail view of the locking mechanism of the tubing tensioning system of  FIG. 1 . 
           [0020]      FIG. 7  is a partial cut-away side view of the ratchet ring of the tubing tensioning system of  FIG. 1 . 
           [0021]      FIG. 8  is a partial sectional view of the ratchet ring of the tubing tensioning system of  FIG. 1 . 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
       [0022]    The present invention will now be described more fully hereinafter with reference to the accompanying drawings which illustrate embodiments of the invention. This invention may, however, be embodied in many different forms and should not be construed as limited to the illustrated embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Like numbers refer to like elements throughout, and the prime notation, if used, indicates similar elements in alternative embodiments. 
         [0023]    Referring to  FIG. 1 , wellhead housing  100  is supported above a wellhead or is located inside a wellbore. The wellhead may be a surface wellhead or a subsea wellhead. 
         [0024]    Single trip running tool (“STRT”)  101  comprises a generally cylindrical body  102  having threads  104  on a first end for attaching the STRT  101  to conduit such as a drill string (not shown). STRT  101  may have hydraulic pistons  106 ,  108  for actuating an energizing running tool outer body  110 , which acts as a ram, for applying force to an adapter sleeve  114 . In an exemplary embodiment, STRT  101  has two sets of hydraulic ports  116 ,  118  near the threaded end. The energizing hydraulic port  116  is connected to one or more hydraulic pistons  106  that cause running tool outer body  110  to axially extend along the length of STRT body  102 . 
         [0025]    The de-energizing hydraulic port  118 , also located on the first end (the drill-string thread  104  end) of STRT  101 , is connected to one or more hydraulic pistons  108  that cause the running tool outer body  110  to retract. When hydraulic pressure is applied through the de-energizing hydraulic port  118  to the de-energizing hydraulic pistons  108 , the pistons cause the running tool outer body  110  to retract axially along the length of STRT  101 , towards drill string threads  104 . In an exemplary embodiment, running tool outer body  110  is able to travel an axial distance of 1.2 meters relative to STRT body  102 . The force exerted by the energizing pistons  106  is determined by the amount of hydraulic pressure applied to the pistons. In some embodiments, the hydraulic pressure may be 9,000 psi or more. STRT running tool outer body  110  has connectors  120  for attaching to an adapter sleeve  114 . In a preferred embodiment, the connector  120  is a thread profile. 
         [0026]    The first end of STRT may have connectors  121  for connecting hydraulic lines to pass-through passages  122 . The second end of passages  122  may have fittings or connectors  123 . Connectors  123  may attach to similar fittings on, for example, the comm collar  126 . 
         [0027]    The second end of the STRT body  102  has connectors  124  for connecting STRT  101  to another component, such as comm collar  126  or a tubing hanger assembly  130 . Connector  124  may be a threaded connector having threads on the ID of the second end of the STRT body  102 . In such embodiments, operator lands STRT  101  on comm collar  126  and then rotates 8-9 turns in the right-hand direction to make up STRT  101  and comm collar  126 . After comm collar  126  is attached to STRT body  102 , torque keys (not shown) may be used to prevent comm collar  126  from rotating on the STRT  101 . In an exemplary embodiment, STRT  101  is an extended version of a commercially available running tool, Vetco Gray part number R117920-1. 
         [0028]    Referring to  FIG. 2 , adapter sleeve  114  is an annular sleeve attached at a first end to the running tool outer housing  110  on the lower end of STRT  101  ( FIG. 1 ). The second end of adapter sleeve  114  is attached to seal releasing latch ring  132 . The inner diameter of adapter sleeve  114  is larger than the outer diameter of comm collar  126 , allowing the adapter sleeve  114  to pass over the outside of comm collar  126 . 
         [0029]    Seal releasing latch ring  132  is an annular ring connected between adapter sleeve  114  and the energizing ring  133 . Threaded connectors  134  on the second end of the seal adapter sleeve  114  attach to mating threaded connectors  136  on seal releasing latch ring  132 . In an exemplary embodiment, adapter sleeve  114  is attached to the seal releasing latch ring  132  by threads having a left-hand rotation and is locked in place by a series of locking screws (not shown) to prevent detachment during operation. A slotted left-hand thread profile  138  located at the lower end of seal releasing latch ring  132  is used to connect to seal assembly  140 . The slotted left-hand thread profile  138  allows the tubing hanger running tool to disconnect from the seal by straight upward movement. 
         [0030]    Referring to  FIG. 3 , seal assembly  140  is releasably carried by seal releasing latch ring  132  ( FIG. 2 ). Seal assembly  140  lands in the pocket between wellhead housing  100  exterior wall and tubing hanger inner body  174 . Seal assembly  140  is made up entirely of metal components. These components include a generally U-shaped seal member  146 . Seal member  146  has an outer wall or leg  148  and a parallel inner wall or leg  150 , the legs  148 ,  150  being connected together at the bottom by a base and open at the top. The inner diameter of outer leg  148  is radially spaced outward from the outer diameter of inner leg  150 . This results in an annular clearance between legs  148 ,  150 . The inner diameter and the outer diameter are smooth cylindrical surfaces parallel with each other. Similarly, the inner diameter of inner leg  150  and the outer diameter of outer leg  148  are smooth, cylindrical, parallel surfaces. 
         [0031]    Energizing ring  133  is employed to force legs  148 ,  150  radially apart from each other into sealing engagement with sealing surfaces  156 ,  158 . Sealing surfaces  156 ,  158  may be any kind of sealing surface including, for example, wickers. Energizing ring  133  has an outer diameter that will frictionally engage the inner diameter of the seal outer leg  148 . Energizing ring  133  has an inner diameter that will frictionally engage the outer diameter of the seal inner leg  150 . The radial thickness of energizing ring  133  is greater than the initial radial dimension of the clearance of the clearance between seal legs  148 ,  150 . The energizing ring  133  pushes the seal legs apart, causing the seal legs to compressively engage the sealing surfaces  156 ,  158  on wellhead housing  100  and tubing hanger inner body  174 . 
         [0032]    Referring to  FIG. 4 , communication collar (“comm collar”)  126  is an annular sleeve that may be connected to STRT body  102  ( FIG. 1 ). The upper end of comm collar  126  has a connector  162  such as a threaded connector for attaching the comm collar  126  to corresponding connectors  124  on STRT body  102  ( FIG. 1 ). The lower end of the comm collar  126  has connectors  164  such as threaded connectors. 
         [0033]    Referring to  FIG. 2 , comm collar  126  is attached to tubing hanger elongated neck  178  by right-hand threads. An anti-rotation device, such as anti-rotation bushings or torque keys (not shown) may be used to prevent the comm collar  126  from rotating in relation to the tubing hanger 
         [0034]    Referring back to  FIG. 4 , comm collar  126  may have tubes or passages  166  through the collar and fittings  168  suitable for attaching lines such as hydraulic lines at the lower end of the tubes or passages  166 . A hydraulic hose (not shown) from the surface may be attached to hydraulic port  118  on STRT  101 . A second hydraulic hose (not shown) may be attached to fitting  168  at the second end of the tube or passage. The second hydraulic hose may descend through the wellbore. In some embodiments, other types of lines may be connected through the comm collar  126 , such as signal lines or power lines. 
         [0035]    Referring to  FIG. 5 , a string of tubing  170  is lowered through a wellhead housing assembly  100  ( FIG. 2 ) and into a wellbore  172  located below wellhead housing  100 . Inner tubing hanger  174 , a cylindrical member, is connected to the top of string of tubing  170  and becomes a part of the string of tubing  170 . Inner tubing hanger  174  is also part of tubing hanger assembly  130 , and may be considered an inner hanger portion of a tubing hanger. Inner tubing hanger  174  has a set of external grooves  176 , which are formed by parallel circumferential ridges on the outer diameter of inner tubing hanger  174 . Inner tubing hanger  174  has an elongated neck  178 , which protrudes above tubing hanger outer body  160 . Elongated neck  178  may be attached to connector  164  of comm collar  126 . 
         [0036]    The tubing string  170  suspended from the tension set tubing hanger comprises a typical tubing that is well known in the art. The second end of the tubing (the end opposite the tubing hanger) is latched to a subsurface fixture by a conventional latching mechanism. In an exemplary embodiment, the lower end of the tubing is latched using a ratcheting locking device (“ratch-latch”). 
         [0037]    Outer hanger  160 , a cylindrical member, is carried on inner tubing hanger  174 , forming a second part of a tubing hanger assembly  130 . Outer hanger  160  includes a load ring  182  and a ratchet ring  184 . Load ring  182  has a downward facing landing shoulder  186  for landing on wellhead housing assembly load shoulder  188  ( FIG. 2 ). Ratchet ring  184  is carried within an inner recess in load ring  182  for engaging the inner tubing hanger threads  176 . 
         [0038]    Referring to  FIG. 3 , lockdown ring  190 , which can be a split ring, will engage groove  192  in wellhead housing assembly  100  to latch load ring  182  in place. Lockdown ring  190 , which is inwardly biased, does not engage groove  192  in wellhead housing assembly  100  in its relaxed state. A chamfer on the lower surface of seal  146  engages a chamfer on the upper surface of lockdown ring  190  when the seal  146  is set in place by the energizing ring  133 . The seal causes the lockdown ring  190  to expand and engage the groove  192  on wellhead housing assembly  100 , and remain engaged as long as the seal  146  remains set in place. 
         [0039]    Referring to  FIG. 6 , ratchet ring  184  is a modified version of the ratchet ring shown in U.S. Pat. No. 4,607,865, David W. Hughes, issued Aug. 26, 1986. Ratchet ring  184  has internal teeth  194  which engage external threads  176  on inner tubing hanger  174 . Ratchet ring  184  has external load shoulders  196  which engage internal load shoulders  198  in load ring  182 . Shear pins  202  serve to initially hold outer hanger  160  on inner tubing hanger  174  at the base of the external threads  176 . Any number of shear pins  202  may be used. In a preferred embodiment, four shear pins  202  are distributed circumferentially around tubing hanger assembly  130 . Shear pins  202  will shear after load ring  182  lands on load shoulder  188  ( FIG. 1 ) and additional weight from conduit  170  ( FIG. 5 ) is applied. This allows inner tubing hanger  174  to move downward relative to load ring  182 . Ratchet ring  184  allows this downward movement because it is held initially in an expanded position such that it will not engage mandrel external threads  176  to prevent downward movement of inner tubing hanger  174 . 
         [0040]    Referring to  FIGS. 7 and 8 , key  204  holds ratchet ring  184  in the expanded disengaged position. Key  204  is located in the split of ratchet ring  184 , which is resilient. The split of ratchet ring  184  includes two opposed edges  206 . Each edge  206  has a pair of rectangular recesses  208 . Key  204  has two lugs  210 , each extending laterally from an opposite side of the body of key  204 . Lugs  210  will engage edges  206  when key  204  is in the upper position shown. This holds ratchet ring  184  in an expanded position. When key  204  is moved downward, lugs  210  enter recesses  208 . This allows the resiliency of ratchet ring  184  to contract ratchet ring  184  to the engaged position. 
         [0041]    The mechanism for releasing key  204  includes a rod  212  which extends upward and is secured by a pin or screw  214  to key  204 . Rod  212  extends through a slot  216  formed in the load ring  182  and is held in the upper position by a key shear pin  218  to prevent premature activation of the ratchet ring  184 . Slot  216  incorporates a hole through which pin or screw  214  extends. Key  204  is located on an inner recess portion of load ring  182  while rod  212  is located in slot  216  on the outer side of load ring  182 . Rod  212  is pushed downward by a surface on the annular seal  146  ( FIG. 3 ) when the annular seal  146  is set in place by the energizing ring  133  ( FIG. 3 ). 
         [0042]    Referring back to  FIG. 2 , wellhead housing  100  is a tubular member located at the upper end of a well, such as a gas storage well. It has a cylindrical bore  220 , and may have one or more valve assemblies  222 . Wellhead housing  100  has an upward facing shoulder  188  for landing tubing hanger assembly  130 . Groove  192  (best shown in  FIG. 3 ) is located on the inner diameter of the wellhead housing  100  for receiving a tubing hanger lock-ring  190  for securing outer tubing hanger  160  in place. Referring to  FIG. 3 , wellhead housing  100  also has a sealing surface  156 , wherein annular seal  146  is pressed to form a seal against the sealing surface. Sealing surface  156  may or may not have circumferential grooves, or wickers, for forming a seal. 
         [0043]    Referring to  FIG. 2 , in operation, inner tubing hanger  174  is located in the bore of tubing hanger outer body  160  and held in place by one or more shear pins  202 . Casing or tubing conduit  170  is attached to inner tubing hanger  174 , and is lowered through wellhead housing  100  into wellbore  172 . Seal  146  ( FIG. 3 ) is attached to energizing ring  133 , which is attached to seal releasing latch ring  132 , which in turn is attached to adapter sleeve  114 . Adapter sleeve  114  is attached to the running tool outer body  110  of the STRT  101 . STRT body  102  is attached to the communication collar  126 , which in turn is attached to extended neck  178  of inner tubing hanger  174 . 
         [0044]    The assembly, comprising STRT  101 , comm collar  126 , inner tubing hanger  178 , tubing hanger outer body  160 , adapter sleeve  114 , seal releasing latch ring  132 , energizing ring  133 , and seal  146 , and further comprising tubing  170  attached to inner tubing hanger  178 , is lowered into wellhead housing  100  on a conduit (not shown). The tubing hanger outer body  160  lands on the upward facing load shoulder  188  ( FIG. 1 ) of wellhead housing  100 . The weight of the tubing  170  pulling on the inner tubing hanger  174 , and/or the force from the drill-string conduit (not shown) cause the shear pins  202  to shear. The now-landed tubing hanger outer body  160  ceases further downward movement. 
         [0045]    STRT  101 , comm collar  126 , and inner tubing hanger  174  continue to move downward relative to wellhead housing  100  and now-stationary tubing hanger outer body  160 . The portion of inner tubing hanger  174  having external grooves  176  passes through the tubing hanger outer body  160  and moves further downward. In an exemplary embodiment, inner tubing hanger  174  descends up to 1.2 meters after the tubing hanger outer body  160  has landed on the wellhead housing  100 . Extended neck  178  of inner tubing hanger  174  and the lower portion of comm collar  126  may or may not pass through tubing hanger outer body  160 , depending on the tensioning requirements of the tubing application. 
         [0046]    Inner tubing hanger  174  is located a predetermined travel distance below tubing hanger outer body  160 . The travel distance is calculated such that when the tubing is stretched by the amount of the travel distance, the tubing will have the desired amount of tension. The travel distance may be uniquely calculated for each application. In general, the travel distance is calculated to be greater than the thermal expansion distance expected for the tubing  170 . The thermal expansion may occur during filling and discharge of a gas through the wellbore  172  in applications such as gas storage. The distance of thermal expansion may be a few centimeters or up to 1.2 meters, and thus inner tubing hanger  174  may be lowered anywhere from a few centimeters up to 1.2 meters below tubing hanger outer body  160 . At a point generally coincident with the travel distance, the bottom end of the tubing  170  engages a latching device (not shown) in wellbore  172 , such as a ratcheting latch, thus fixing the bottom end of the tubing  170  in place. The bottom end of tubing  170  and the latching device may be located in an underground storage well. 
         [0047]    While the inner tubing hanger  174  is being lowered, an operator on the surface applies hydraulic pressure to the energizing hydraulic port  116 . The hydraulic pressure is regulated by the operator to hold outer tubing hanger body  160  down on the load shoulder  188  in wellhead housing  100  without setting the seal  140  or energizing the lockdown ring  190 . As the STRT body  102  is drawn up through the wellbore, hydraulic pressure on energizing port  116  is proportionately increased to maintain outer tubing hanger body  160  in position on load shoulder  188  without setting the seal  140  or energizing the lockdown ring  190 . During the upward vertical travel, the inner tubing hanger  174  is pulled back through the outer tubing hanger  160 , and thus through ratchet ring  184 . Tension is increased in tubing  170  during this upward movement. 
         [0048]    At the end of the pre-determined upward vertical travel, the inner tubing hanger  174  returns to a fixed point within the outer tubing hanger body  160  and at this point, the hydraulic pressure on the energizing port  116  is increased to the maximum, thereby actuating the outer housing  110  which acts as a ram to push the adapter sleeve  114 , seal releasing latch ring  132 , energizing ring  133 , and seal  146  down relative to the STRT body  102 . This force causes seal  146  to land in the seal pocket between the wellhead housing  100  and inner tubing hanger  174 . 
         [0049]    As seal  146  lands in the seal pocket, it causes lockdown ring  190  ( FIG. 3 ) to expand outwards into the lockdown groove  192  ( FIG. 3 ) of the wellhead housing  100 . The seal  146  also engages rod  212  ( FIG. 7 ), causing it to move down relative to outer tubing hanger  160 . In some embodiments, seal  146  may actuate lockdown ring  190  and rod  212  before inner tubing hanger  174  is drawn back. 
         [0050]    When rod  212  moves down, it pushes key  204  down, relative to ratchet ring  184 . As lugs  210  clear edges  206  of ratchet ring  184 , ratchet ring  184  collapses inward to its inwardly biased position and engages the external threads  176  of the inner tubing hanger  174  with the internal teeth  194  of the ratchet ring  184 . The external load shoulders  196  of the ratchet ring  184  remain in contact with the internal load shoulders  198  of the outer tubing hanger  160 . Thus weight and the subsequent tension on inner tubing hanger  174  is transferred to outer tubing hanger  160 , via ratchet ring  184 . The weight and tension is transferred from outer tubing hanger  160  to the wellhead housing  100  via load shoulder  188  ( FIG. 1 ). The axial travel distance of inner tubing hanger  174  is known in advance, and thus the ratchet ring  184  may be sized and located to engage inner tubing hanger  174  at the desired location. Thus ratchet ring  184  has an axial length that may be much smaller than the travel distance. In some embodiments, the operator does not pull up on inner tubing hanger  174  after ratchet ring  184  has collapsed and thus the ratchet ring  184  does not actually ratchet, but rather holds the inner tubing hanger  174  in position. In other embodiments, the operator may pull up on inner tubing hanger  174  after ratchet ring  184  has collapsed, thus causing a ratcheting engagement. 
         [0051]    With the weight and tension of the tubing now supported by wellhead housing  100 , STRT  101  may be disengaged, leaving the tubing hanger assembly  130 , comm collar  126 , and seal assembly  140  in the wellbore. 
         [0052]    While the invention has been shown or described in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes without departing from the scope of the invention.