Abstract:
A rupture assembly that may be employed in the oilfield industry facilitates the deployment of a tubing string in a well. The rupture assembly may be installed at the bottom of the tubing string for the purpose of trapping air in a lateral section of the tubing, between the rupture assembly and an upper sealing assembly. As a result, the buoyant force in the lateral section reduces the drag encountered while running the tubing through the casing, thereby significantly reducing rig time, or permitting operations where none were possible previously. Once at landing depth, surface pressure may be added to burst and remove the seal and rupture assemblies.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims the benefit of U.S. Provisional Application No. 62/238,001, filed on Oct. 6, 2015. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not Applicable 
       BACKGROUND OF THE INVENTION 
       [0003]    1. Field of the Invention 
         [0004]    The present invention generally relates to an apparatus and method for facilitating deployment of a tubular string (i.e., tubing) in a casing string or wellbore. More specifically, the present invention provides a rupture assembly for use at the bottom of a tubing string that in conjunction with a sealing assembly higher up in the tubing string, creates an airlock or buoyancy chamber in the tubing to allow a float environment during deployment of the tubing where in the rupture and sealing assemblies are designed to rupture from applied hydraulic pressure in a way to make for easy removal of the pieces once the tubing is set at the desired depth in the casing string or wellbore. 
         [0005]    2. Description of the Related Art Including Information Disclosed under 37 CFR 1.97 and 1.98 
         [0006]    For conventional wells, such as in steam-assisted gravity drainage (SADG) wells, it is often difficult to run or deploy the tubing, which tends to be large OD (outer diameter) tubing, to great depths due to the friction created between the tubing string and the casing. Such friction results in a substantial amount of drag on the tubing. This is particularly true in horizontal and/or deviated wells. In some cases, the drag on the tubing can exceed the available weight in the vertical section of the wellbore. If there is insufficient weight in the vertical section of the wellbore, it may be difficult or impossible to overcome drag on the tubing in the wellbore, such that the weight cannot overcome the friction forces and stops the progress of the tubing string downhole, or in some scenarios where the friction force can be overcome, the outside of the tubing or inside of the casing may be damaged as the tubing is forced downhole. 
         [0007]    Various attempts have been made to overcome the problem of drag and achieve greater well depths of the tubing in both vertical and horizontal sections of the well. For example, techniques to alter wellbore geometry are available; however these techniques are time-consuming and expensive. Also, techniques to lighten or “float” the tubing have been attempted to extend the depth of well. For example, there exists techniques in which the ends of a tubing string portion are plugged and the plugged portion is filled with a low density, miscible fluid to provide a buoyant force. After the plugged portion is placed in the wellbore, the plugs must then be drilled out so that the miscible fluid can be forced out into the wellbore. That extra step of drilling out the plugs increases completion time. Other flotation devices require a packer to seal the tubing above the air chamber. Another example of creating an air chamber is disclosed in U.S. Published Application No. 2014/0216756, entitled Casing Float Tool, the contents of which are hereby incorporated by reference in their entirety. 
         [0008]    Therefore, a need exists for an apparatus and method that facilitates deployment of a tubing string in a casing string by creating and maintaining an airlock or buoyancy chamber, which is easy and relatively inexpensive to install on the tubing string. Furthermore, it would be desirable if the apparatus was easily removed from the wellbore and/or that the removal results in full tubing ID so that various downhole operations could be readily performed and maximum flow rate following removal or opening of the buoyant chamber. 
       BRIEF SUMMARY OF THE INVENTION 
       [0009]    The present invention provides a rupture assembly that may be employed in the oilfield industry, such as in the SAGD area of the oil industry, to deploy the well&#39;s tubing string. The rupture assembly of the present invention may be installed at the bottom of the tubing string for the purpose of trapping air in a lateral section of the tubing, between the rupture assembly and an upper sealing assembly of one embodiment of the invention. As a result, the buoyant force in the lateral section minimizes the drag encountered while running the tubing through the casing, thereby significantly reducing rig time, or permitting operations where none were possible previously. Once at landing depth, surface pressure may be added to burst and remove the seal and rupture assemblies. 
         [0010]    In accordance with an exemplary embodiment, the present invention provides a rupture assembly used in conjunction with a sealing assembly to create a buoyancy chamber in a tubing string. The rupture assembly includes a first rupture member held in sealing engagement by a disengageable securing mechanism, and a second rupture member downhole from the first rupture member held in sealing engagement by an impact member. The impact member has at least one impact surface. The first rupture member may be a hemispherical dome formed of high heat strengthened glass that has a convex surface facing uphole into the air chamber created in the tubing. The second rupture member may be a hemispherical dome formed of high heat strengthened glass that has a convex surface facing downhole towards the open end of the tubing. Application of a threshold hydraulic pressure in the tubing string above the rupture assembly (after the airlock is breached and the tubing fills with fluid) that is less than a rupture burst pressure of the first rupture member releases the first rupture member from the securing mechanism forcing the first rupture member to move downhole and impact against the at least one impact surface of the impact member and shatter into very small fragments that impact the second rupture member, which along with the hydraulic pressure, causes the second rupture member to shatter into very small fragments. In a preferred embodiment, the first and second rupture members are hemispherical domes formed of high heat strengthened glass, but could be any other substance, such as carbide that could be designed to withstand necessary pressures, but also shatter into small pieces for easy removal. 
         [0011]    The present invention may also provide a tubing string that includes a length of tubing positionable in a wellbore, wherein said length corresponds generally to the length of the horizontal length of the tubing string for instance. A sealing member may be disposed at an upper end of the length of tubing for forming an upper boundary of an airlock or buoyancy chamber, and a rupture assembly may be disposed at a lower end of the tubing string for forming a lower boundary of the buoyancy chamber. The sealing assembly may be as shown in U.S. patent application Ser. No. 13/930,683 entitled Casing Float Tool and published as U.S. Pub. No. 2014/0216756, the contents of which are hereby incorporated by reference in their entirety. As the tubing is run into the hole, the rupture assembly is inserted into the tubing string at the bottom of the tubing string to prevent wellbore fluids and debris from entering the tubing string for the bottom of the string. As the tubing is run into the hole, air is filling the tubing string; in other embodiments other fluids could be used in the tubing string to create a similar buoyancy effect. Once the length of tubing equal to the expected horizontal length of tubing has been run into the hole, the sealing assembly can be inserted into the tubing string to seal the top of the airlock chamber to create the buoyancy section. Once the tubing has been run in to its final depth, the tubing above the sealing assembly can be filled with fluid so that a hydraulic pressure can be applied to the sealing element. When sufficient pressure is applied to for instance shear the securing mechanism, the first rupture member of the sealing element moves downhole and impacts the impact member and shatters, releasing the airlock. The remaining tubing can then be filled with fluid such that application of a threshold hydraulic pressure that is less than a rupture burst pressure of the first rupture member of the rupture assembly can be applied to release the first rupture member from the securing mechanism causing the first rupture member to impact against the at least one impact projection of the impact member and shatter into very small fragments that impact the second rupture member, which along with the hydraulic pressure, cause the second rupture member to shatter into very small fragments, opening the tubing string so that the shattered pieces can be circulated out of the well. 
         [0012]    Other objects, advantages and salient features of the invention will become apparent from the following detailed description, which, taken in conjunction with the annexed drawings, discloses a preferred embodiment of the present invention. 
     
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S) 
         [0013]    A more complete appreciation of the invention and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawing figures wherein: 
           [0014]      FIG. 1  is a cross-sectional view of a wellbore incorporating the sealing and the rupture assemblies according to an exemplary embodiment of the present invention; 
           [0015]      FIG. 2  is a cross-sectional view of a rupture assembly of the tubular airlock assembly according to an exemplary embodiment of the present invention; 
           [0016]      FIG. 3  is an enlarged cross-sectional view of the rupture assembly illustrated in  FIG. 2 ; 
           [0017]      FIG. 4  is a cross-sectional end view of the rupture assembly taken along line  4 - 4  in  FIG. 3 ; 
           [0018]      FIG. 5  is a cross-sectional view in perspective of the rupture assembly illustrated in  FIG. 2 ; and 
           [0019]      FIG. 6  is a cross-sectional view of the sealing assembly of the tubular airlock assembly according to an exemplary embodiment of the present invention. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0020]    In one particular exemplary embodiment of the invention, a In the following description, directional terms such as “above”, “below”, “upper”, “lower”, “uphole”, “downhole”, etc. are used for convenience in referring to the accompanying drawings. One of ordinary skill in the art will recognize that such directional language refers to locations in downhole tubing either closer or farther from the wellhead and that various embodiments of the present invention may be utilized in various orientations, such as inclined, deviated, horizontal, vertical, and the like. 
         [0021]    Referring to  FIGS. 1-6 , the present invention relates to a tubular airlock assembly and method for facilitating deployment of a tubing string  10  into a wellbore  12 . The tubular airlock assembly of the present invention preferably includes a rupture assembly  100  disposed in the tubing  10 , that along with a sealing assembly  22 , maintains an airlock or buoyancy chamber  20  in the tubing  10  to assist in positioning the tubing  10  in the wellbore  12 , particularly in a horizontal section  14  of the wellbore  12 . Once the tubing  10  is fully deployed to its desired vertical depth and/or horizontal position in the wellbore  12 , the sealing assembly  22  is designed to easily rupture into very small fragments through application of hydraulic pressure allowing the buoyance chamber  20  to be filled with fluid from above. Once fluid fills the buoyancy chamber  20 , the rupture assembly  100  is designed to easily rupture into very small fragments through the application of hydraulic pressure so that the fragments of the sealing assembly  22  and rupture assembly  100  may be circulated out of the well. The sealing assembly  22  and rupture assembly  100  in a preferred embodiment, once ruptured, do not reduce the inner diameter ID 1  ( FIG. 2 ) of the tubing  10 . 
         [0022]    As seen in  FIG. 1 , the rupture assembly  100  of the present invention is preferably disposed at the toe or bottom of the tubing  10  to form a temporary isolation barrier to seal off the fluid from the wellbore  12  as the tubing  10  is being run therein, thereby maintaining and protecting the integrity of a buoyant chamber  20  in the tubing  10 . The buoyant chamber  20  may be filled with air, or any fluid that provide buoyancy, to provide float to the tubing  10 . The buoyant chamber  20  is formed between the rupture assembly  100 , which is the lower boundary of the chamber, and a sealing assembly  22  located at or near the heel or upper part of the tubing  10 , which is the upper boundary of the chamber. Air in the buoyant chamber  20  is trapped between the rupture assembly  100  of the present invention and the sealing assembly  22 . The buoyant chamber  20  in the tubing  10  may be created as a result of sealing of the lower or toe end  24  of the tubing  10  with the rupture assembly  100  of the present invention and sealing of the upper or heel end  26  of tubing  10  with the sealing assembly  22 . The distance between the rupture assembly  100  and sealing assembly  22  is selected to control the force tending to run the tubing into the hole and to maximize the vertical weight of the tubing. 
         [0023]    The buoyant chamber  20  is air-filled to provide increased buoyancy, which assists in running the tubing  10  to the desired depth. That eliminates the need to fill the tubing  10  with fluid prior to running the tubing  10  in the wellbore  12 , and there is no need to substitute the air in the tubing once installed in the well. The buoyant chamber  20  alternatively may be filled with other gases, such as nitrogen, carbon dioxide and the like. Light liquids may also be used. Generally, the buoyant chamber  20  is preferably filled with a fluid that has a lower specific gravity than the well fluid in the wellbore in which the tubing  10  is run. The choice of which gas or liquid to use may depend on factors, such as the well conditions and the amount of buoyancy desired. 
         [0024]    Rupture assembly  100  generally includes first and second rupture members  102  and  104 , a disengagable securing mechanism  106 , an impact member  108 , and a plurality of sealing O-rings  112 , as best seen in  FIGS. 3 and 5 . Each of the rupture members  102  and  104  is preferably a hemispherical dome that is formed of a material having a burst or rupture pressure (i.e. the pressure at which hydraulic pressure alone can break the rupture member) greater than the hydraulic pressure in the tubing when the tubing is being run in the wellbore, so as to avoid premature breakage of the rupture members  102  and  104 , thereby maintaining the seal for buoyant chamber  20 . In a preferred embodiment, the dome shape of the second rupture member  104  can withstand 3500 psi or more without bursting. Once the tubing  10  is properly deployed, the rupture members  102  and  104  are fractured in very small fragments to remove the assembly and clear the fluid passageway of the tubing  10 . 
         [0025]    The rupture assembly  100  is sealed between an upper tubular member  116  that is coupled to a lower tubular member  118  through which a fluid passageway is defined. Upper tubular member  116  may be coupled with lower tubular member  118  in such a way that the outer wall of lower tubular member  118  overlaps at least a portion of the outer wall of upper tubular member  116 . In the illustrated embodiment, the upper tubular member  116  and lower tubular member  118  are threadably coupled together at that overlap. Various other interconnecting means that would be known to a person skilled in the art are possible. A fluid seal between upper tubular member  116  and the lower tubular member  118  may be provided by one or more seals, such as O-ring seal  120 . 
         [0026]    The tubular members  116  and  118  provide a radially expanded area in the tubing  10  designed to accommodate the rupture assembly  100 , so as to maintain the same inner diameter of the tubing. In particular, an internal recessed area  122  is defined in the inner surface of the lower tubular member  118  that is sized to receive the components of the rupture assembly, as seen in  FIG. 2 . The internal recessed area  122  is preferably sized such that the inner diameter ID 1  ( FIG. 1 ) of the tubing  10  is substantially the same as the inner diameter ID 2  ( FIG. 4 ) of the rupture assembly  100 . The inner diameter may be 4.5 inches, for example. The recessed area  122  is flanked by an annular frusto-concial surface  124  of the upper tubular member  116  leading into the recessed area  122  and an annular frusto-conical surface  126  of the lower tubular member  118  behind the recessed area  122 . 
         [0027]    The rupture members  102  and  104  are preferably concentrically disposed in the tubular members  116  and  118  generally traverse to the longitudinal axis of the upper and lower tubular members  116  and  118  with the first rupture member  102  facing uphole and the second rupture member  104  facing downhole. The first rupture member  102  includes a portion  132  that is a hollow, hemispherical dome, with a concave surface  134  that faces downhole and a convex surface  136  that is oriented in the uphole direction. Hemispherical portion  132  is continuous with a cylindrical portion  138  which terminates in a circumferential edge  140  that abuts the disengagable securing member  106 . Likewise, the second rupture member  104  includes a portion  142  that is a hollow, hemispherical dome, with a concave surface  144  that faces uphole and a convex surface  146  that is oriented in the downhole direction. Hemispherical portion  142  is continuous with a cylindrical portion  148  which terminates in a circumferential edge  150  that abuts the impact member  108 . 
         [0028]    In a preferred embodiment, the disengageable securing member  106  is a shear ring. The shear ring  106  may be sandwiched between the inner wall of lower tubular member  118  and the cylindrical portion  138  of first rupture member  102 . An exemplary shear ring is described in U.S. Patent Application Publication No. 2014/0216756, incorporated herein by reference. The shear ring  106  provides for seating the first rupture member  102  in lower tubular member  118 , and acts as a disengageable constraint while also facilitating the rupture of the rupture member  102 , and generally being shearable in response to hydraulic pressure (e.g. being shearable or otherwise releasing the rupture member  102  in response to the application of a threshold hydraulic pressure that is less that the rupture burst pressure of the rupture member  102 ). The first rupture member  102  of the rupture assembly  100  is preferably designed so that up to  1800  psi of pressure may be applied before the securing member  106  releases or shears. 
         [0029]    The shear ring  106  has tabs  152  or other projections that can be sheared in response to hydraulic pressure, as seen in  FIGS. 3-5 . The tabs  152  are adapted to be eliminable from the tubing  10 . The plurality of tabs  152  are preferably spaced around the circumference of a rim of the shear ring  106 . Although shear ring  106  serves as the disengageable constraint or securing mechanism for the first rupture member  102  in the illustrated embodiment, other securing mechanisms to hold the rupture member  102  in sealing engagement within the tubing  10  may be possible, provided that rupture member  102  is free to move suddenly downward or across in the direction of the second rupture member  104 , when freed or released from the constraints of the securing shear ring  106 . 
         [0030]    The first rupture member  102  may be sealed to shear ring  106  by means of one or more sealing O-rings  112 . Each O-ring  112  may be disposed in a groove or void, circumferentially extending around the cylindrical portion  138  of the shear ring  106 . Various back-up ring members may be present. The O-rings ensure a fluid tight seal as between the shear ring  106 , the rupture member  102 , and the upper and lower tubulars  116  and  118 . The sealing engagement of the first rupture member  102  within shear ring  106  and the sealing engagement of shear ring  106  against the lower tubular member  118  together with the O-ring seals create a fluid-tight seal between the upper tubing and the tubing downhole of rupture assembly  100 . 
         [0031]    Tabs  152  of the shear ring  106  may be bendable or shearable upon application of force (e.g. hydraulic force). For example, tabs  152  may shear at 1000 to 2000 psi. This threshold pressure at which the securing mechanism  106  shears, releasing the first rupture member  102 , is less than the rupture burst pressure of the rupture member  102  (i.e. the pressure at which the rupture member  102  would break in response to hydraulic pressure alone). Shear ring  106  may be made of any material that allows the tabs  152  to be suitably sheared off, such as metal (like brass, aluminum, and various metal alloys) or ceramics. The tabs  152  are also small enough that when sheared, they do not affect wellbore equipment or function. 
         [0032]    Once all of the tabs  152  are sheared, the first rupture member  102  may be freed or released from the constraints of shear ring  106 . The rupture member  102  then moves suddenly towards the impact member  108  in response to hydraulic fluid pressure already being applied to convex surface  136  of the first rupture member  102  such that it is pushed through the circumferential aperture of shear ring  106 . Once disengaged or otherwise released from shear ring  106 , the rupture member  102  will hit the impact member  108  and break into very small fragments as a result. 
         [0033]    The impact device  108  is configured to provide at least one impact surface against which the first rupture member  102  breaks once the shear ring  106  releases the rupture member  102 . Any surface of the impact device  108  may be the impact surface of the present invention, provided that the impingement of the first rupture member  102  with that surface causes the rupture member  102  to fracture. In a preferred embodiment, the impact device  108  is a carrier ring that includes one or more inwardly extending impact projections  160 . The projections  160  may be annularly arranged and spaced from one another. Each projection  160  includes a first side surface  162  that faces toward the first rupture member  102 , an opposite second side surface  164  faces toward the second rupture member  104 , and an end face  166  extending between the side surfaces  162  and  164 . The second side surfaces  164  may act as an abutment against the circumferential edge  150  of the second rupture member  104 . The inner diameter ID 2  formed by the end faces  166  of the projections  160  is preferably substantially the same as the inner diameter ID 1  of tubing  10 . That is, the structure of impact carrier ring  108  and the projections  160  facilitate the restoration of the tubing inner diameter because no or few portions of the impact carrier ring  108  and projections  160  extend into the inner diameter of the tubing  10 . 
         [0034]    The second rupture member  104  may be sealed to impact device  108  by means of a seal, such as the O-rings  112  disposed in one or more grooves circumferentially extending around a cylindrical portion  148  of the impact carrier ring  108 . Various back-up ring members may be present. The O-rings ensure a fluid tight seal as between the impact carrier ring  106 , the rupture member  104 , and the upper and lower tubulars  116  and  118 . The sealing engagement of the second rupture member  104  within impact carrier ring  108  and the sealing engagement of impact carrier ring  108  against the lower tubular member  118  together with the O-ring seals create a fluid-tight seal between the upper tubing and the tubing downhole of rupture assembly  100 . 
         [0035]    Any one of the first side surfaces  162  of the impact projections  160  may act as the impact surface of the present invention against which the first rupture member  102  is forced and breaks. When hydraulic pressure is applied to the rupture assembly  100  within the tubing  10 , there is a combination of hydraulic pressure acting on the first rupture member  102 , as well as compressive forces forcing the rupture member  102  into the impact device  108  (onto the one or more impact surfaces  162 ). The combination of the hydraulic force and the impact force against the impact surfaces  162  allow for shattering of the rupture disc  102 . 
         [0036]    The sudden release of energy from the impact of the first rupture disc  102  with the impact projections  160  in combination with the debris of the first disc  102  travelling past the projections  160 , impacts the convex surface  146  of the second disc  104  and breaks the second disc  104  into very small fragments as well. The second rupture disc  104  may also impact any inner surface of the lower tubular member  118 , such as frusto-conical surface  126 , to further assist in fracture of the second rupture member  104 . The shattering of the rupture discs  102  and  104  results in opening of the passageway of the lower tubular member  118 , such that the tubing&#39;s inner diameter in that region of the lower tubular member  118  may be restored to substantially the same inner diameter as the rest of the tubing  10  (i.e. the tubing above and below the tubular or region in which the rupture assembly  100  was installed). 
         [0037]    The first and second rupture members  102  and  104  are preferably made of a frangible material that shatters into very small fragments. Each very small fragment may not exceed more than 1 inch in any dimension, and preferably no more than ⅜ inch in any dimension. An exemplary material for the rupture members  102  and  104  is high heat strengthened glass. The high heat strengthened glass preferably has a nominal thickness of 0.100 inch to 0.500 inch, a refractive index of 1.489, a density of 2.33 g/cc, a linear thermal expansion of 43 E-7/C, a strain temperature of 482° C., a transition temperature of 512° C., an annealing temperature of 526° C., and a deformation temperature of 660° C. High heat strengthened glass is also preferably used for the sealing assembly  22 . Other possible materials include carbides, ceramic, metals, plastics, porcelain, alloys, composite materials, and the like. These materials are frangible and rupture in response to the pressure differential when high pressure is applied. Hemispherical domes for the rupture members  102  and  104  are preferred because of their ability to withstand pressure from their convex sides  136  and  146 . The convex side  146  of the second rupture member  104  in particular must have sufficient rupture strength to prevent premature fracture when the tubing  10  is run into the wellbore  12 . In a preferred embodiment, the convex side  146  of the second rupture member  104  can withstand up to 3500 psi. Due to the nature of the dome shape of the second rupture member  104 , the concave side  144  of the rupture disc  104  is much weaker than its convex side  146 . As a result, the second rupture member  104  easily fractures due to impact with the ruptured pieces of the first rupture member  102 . Thus, the structure and material of the rupture assembly  100  provides a way for a sealed tubing  10  to become unsealed while requiring less hydraulic pressure than prior art rupture disc approaches and without increasing the inner diameter of the tubing  10 . 
         [0038]    There is no need to send weights, sharp objects or other devices (e.g. drop bars or sinker bars) down the tubing  10  to break the rupture assembly  100  of the present invention like in some prior art techniques. In the present arrangement, the rupture assembly  100  is arranged so that the rupture discs  102  and  104  fracture into sufficiently small fragments those fragments can be easily removed by fluid circulation, without damaging the tubing  10 . In addition, full tubing inner diameter ID 1  is restored after the rupture members  102  and  104  are broken, so that there is no need to drill out any part of the assembly  100 . Once the rupture discs  102  and  104  have ruptured, normal operations may be performed. The rupture assembly  100  is straight-forward to install, avoids the cost and complexity of many known tubing flotation methods and devices, and decreases completion time. 
         [0039]    In a preferred embodiment, the sealing assembly  22  is a rupture disc assembly, as seen in  FIG. 6  and described in commonly owned U.S. Patent Application Publication No. 2014/0216756, the entire contents of which are hereby incorporated by reference. The sealing assembly  22  may be any conventional sealing mechanism for tubing and casing strings. The rupture disc assembly may consist of an upper tubular member  16  coupled to a lower tubular member  18 , and a rupture disc  30  sealingly engaged between upper tubular member  16  and lower tubular member  18 . The rupture disc  30  is preferably made of high heat strengthened glass, similar to rupture discs  102  and  104 . Upper tubular member  16  may be coupled with lower tubular member in a manner similar to tubular members  116  and  118 . 
         [0040]    Lower tubular member  18  may include a radially expanded region  25  with a tapered internal surface  58 , which may be a frusto-conical surface (e.g. lead-in chamfer). The radially expanded region  25  is continuous with a constricted opening (represented by dash line  27 ). Various surfaces on lower tubular member  18 , most notably surface  58 , can form impact surfaces for shattering the rupture disc  30 . Upper tubular member  16  also has a radially expanded portion  29  to help accommodate disc  30 . 
         [0041]    Rupture disc  30  may be concentrically disposed traverse to the longitudinal axis of the upper and lower tubular members  16  and  18 . In the illustrated embodiment, a portion  32  of rupture disc  30  is a hollow, hemispherical dome, with a concave surface  38  that faces downhole and a convex surface  36  that is oriented in the uphole direction. Hemispherical portion  32  is continuous with cylindrical portion  34  which terminates in a circumferential edge  39  having a diameter that is similar to the inner diameter of the radially expanded region  25  of lower tubular member  18  at shoulder  26 . Rupture disc  30  is constrained from upward movement by tapered surface  60  on upper tubular member  16 . 
         [0042]    Shear ring  44  is an example of a securing mechanism for disc  30 , the securing mechanism generally serving the purpose of holding the rupture disc  30  in the lower tubular member  18  helping to seal the rupture disc  30  in the tubing string  10 , facilitating the rupture of the disc  30 , and generally being shearable in response to hydraulic pressure (i.e. being shearable or otherwise releasing the rupture disc  30  in response to the application of a threshold hydraulic pressure that is less that the rupture burst pressure of the disc  30 ). As seen in  FIG. 6 , the shear ring  44  may be sandwiched between the inner wall of lower tubular member  18  and the walls of cylindrical portion  34  of rupture disc  30 . Similar to shear ring  106 , shear ring  44  provides for seating rupture disc  30  in lower tubular member  18 , and acts as a disengageable constraint. A circular rim  40  of the shear ring  44  acts as seating for the circumferential edge  39  of rupture disc  30 . Shear ring  44  preferably has tabs  46  or other projections extending inwardly from rim  40  that can be sheared in response to hydraulic pressure like tabs  152 . The tabs  46  may be spaced around the circumference of the rim  40 . 
         [0043]    Shear ring  44  may be held between shoulder  26  of lower tubular member  18  and end  28  of upper tubular member  16  and may be sealed to lower tubular member  18  by an O-ring  50 . Rupture disc  30  may be sealed to shear ring  44  by an O-ring  52 . O-ring  52  may be disposed in a groove or void, circumferentially extending around the cylindrical portion  34  of disc  30 . The O-rings ensure a fluid tight seal as between the shear ring  44 , the rupture disc  30 , and the upper and lower tubulars  16  and  18 . 
         [0044]    The threshold pressure at which the securing mechanism  44  shears, releasing the rupture disc  30 , is less than the rupture burst pressure of the disc  30  (i.e. the pressure at which the disc would break in response to hydraulic pressure alone). Tabs  46  support and/or seat rupture disc  30 . Once all of the tabs  46  are sheared, rupture disc  30  may be freed or released from the constraints of shear ring  44 . Rupture disc  30  then moves suddenly downward in response to hydraulic fluid pressure already being applied to convex surface  36  of rupture disc  30 , being pushed through the circumferential aperture  39  of shear ring  44 . Once disengaged or otherwise released from shear ring  44 , rupture disc  30  will impinge upon some portion of lower tubular member  18  (e.g. tapered surface  58 , herein referred to as an example of an impact surface) and break into very small fragments as a result, preferably fragments that are less than ⅜ of an inch in any dimension. Thus, surface  58  serves as an impact surface. Surface  58 , because it is angled, provides a wall against which the rupture disc is forced, and thus causes the disc to rupture. Any portion of the lower tubular  18  may constitute an impact surface, provided that the impingement of disc  30  with the surface causes the disc to rupture. 
         [0045]    The sealing assembly  22  and rupture assembly  100  are preferably used in a method of installing the tubing  10  in the wellbore  12 . Running a tubing  10  in deviated wells and in long horizontal wells, in particular, can result in significantly increased drag forces. The tubing may become stuck before reaching the desired location. This is especially true when the weight of the tubing in the wellbore produces more drag forces than the weight tending to slide the tubing down the hole. If too much force is applied to push the tubing into the well, damage to the tubing can result. The rupture assembly  100  of the present invention helps to address some of these problems. 
         [0046]    To install the tubing  10  in the wellbore  12 , the tubing  10  is initially assembled at the surface including the incorporation of the sealing assembly  22  and the rupture assembly  100 , trapping air therebetween in the buoyant chamber  20 . The buoyant chamber  20  provides float to counteract any friction drag between the tubing walls with the walls of the wellbore  12 . As the tubing  10  is run into the wellbore  12 , the convex surface  146  of the second rupture member  104  resists fracture and remains intact against the hydrostatic pressure from the wellbore fluid. That is the hydrostatic pressure during run-in must be less than the rupture burst pressure of the second rupture disc  104 , to prevent premature rupture of the rupture disc  104 . Generally, the rupture disc  104  may have a pressure rating of at least 3500 psi, for example. 
         [0047]    Once the tubing has run and landed, the sealing assembly  22  and the rupture assembly  100  can be easily removed from the system and circulating equipment may be installed. The removal involves first bursting the sealing assembly  22  near the top of the tubing  10  by puncturing the same or applying sufficient fluid pressure. After the sealing assembly  22  is burst, and fluid fills the buoyancy chamber  20 , sufficient fluid pressure is applied again to subsequently burst the rupture assembly  100 . Alternatively, the sealing assembly  22  and the rupture assembly  100  can be burst at the same time using the same fluid pressure application. The fluid pressure (e.g., from the surface) is applied through the tubing  10  and exerts enough force on the first rupture member  102  and the shear ring  106 , particularly tabs  160 , to release the first rupture member  102 . The first rupture member  102  of the rupture assembly  100  is preferably designed so that up to 1800 psi of pressure may be applied before the securing ring  106  releases or shears. That initiates the sequence of rupturing the first and second rupture members  102  and  104  and clearing the tubing fluid passageway, as described above. 
         [0048]    Once the rupture assembly  100  has been ruptured, the inside diameter of the tubing  10  in the region of the rupture assembly  100  is substantially the same as that in the remainder of the tubing (i.e. the inner diameter ID 1  is restored following rupture of the rupture assembly  100 ). That is accomplished in the present invention by installing the rupture assembly  100  in the radially expanded area of the tubular members  116  and  118  along with sizing the tabs  152  (e.g. to form a 4.48 inch inner diameter) of the shear ring  106  and the projections  160  (e.g. to form a 4.15 inner diameter) of the impact carrier ring  108  to have an inner diameter that is substantially the same or greater than the inner diameter of the tubing. The ability to restore full tubing inner diameter is useful in achieving maximum flow rate quickly. It also allows downhole tools and the like to be deployed without restriction into the tubing  10 . Also, further work can be done without the need to remove any parts from the tubing  10 . 
         [0049]    The foregoing presents particular embodiments of a system embodying the principles of the invention. Those skilled in the art will be able to devise alternatives and variations which, even if not explicitly disclosed herein, embody those principles and are thus within the scope of the invention. Although particular embodiments of the present invention have been shown and described, they are not intended to limit what this patent covers. One skilled in the art will understand that various changes and modifications may be made without departing from the scope of the present invention as literally and equivalently covered by the following claims.