Patent Publication Number: US-6904975-B2

Title: Interventionless bi-directional barrier

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
   This application claims the benefit of an earlier filing date from U.S. Provisional Application Ser. No. 60/342,721 filed Dec. 19, 2001, the entire disclosure of which is incorporated herein by reference. 

   BACKGROUND 
   Subsurface valves are generally of the hydraulically operated spring loaded rod/piston type for use in the downhole environments of wellbores to regulate the flow of production fluids through the well. The valves provide barriers to restrain the uncontrolled flow of the fluid in the tubing string. Such valves generally provide regulation of fluid flow in the uphole direction as a result of pressure release from a production zone, but may not be adequately operable at extreme depths as a result of an excessive hydrostatic head in the tubing string. 
   A conventional valve incorporates a flapper mechanism biased to a normally closed position by a spring. Such a flapper mechanism is opened by the application of hydraulic control pressure to a piston that actuates the valve and positions it in an open position. If the hydraulic control pressure is lost, then the valve closes. 
   Control of such valves is, however, limited by the hydrostatic force applied to the piston. The hydrostatic force applied by the column of fluid in the control line varies with the depth at which the valve is positioned while the counteracting spring force biasing the valve closed is constant. The operability of the valve is, therefore, a function of its location in the well. If the valve is positioned at a depth such that the hydrostatic pressure generated by the column of fluid in the control line or tube is greater than the biasing force exerted by the spring mechanism, the valve will not close in response to a decrease in control pressure. 
   SUMMARY 
   An interventionless bi-directional barrier device of a downhole tool for use in a wellbore and a method of utilizing the barrier device to control the flow of production fluids in the wellbore are described herein. The barrier device includes a flapper mechanism having first and second flappers articulably linked together and articulably linked to a base member that is slidable within the downhole tool. The flapper mechanism provides a seal between opposing uphole-and downhole ends of the downhole tool upon actuation thereof. The method of controlling the flow of production fluids in the wellbore includes closing the barrier device to block flow through the tool, supporting the barrier device from a pressure exerted from a first direction, and supporting the barrier device from a pressure exerted from a second direction. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Referring now to the drawings wherein like elements are numbered alike in the several Figures: 
       FIG. 1  is a sectional view of a downhole end of a downhole tool showing a piston housing disposed at a bottom sub and an initiating piston annularly disposed therein; 
       FIG. 2  is a sectional view of a downhole tool showing a set-down sleeve disposed about a piston housing; 
       FIG. 3  is a sectional view of a downhole tool showing a spring disposed within a spring housing; 
       FIG. 4  is a sectional view of a downhole tool showing a flapper mechanism in an open position; 
       FIG. 5  is a sectional view of a downhole tool showing a body lock ring slidably disposed within an upper housing; 
       FIG. 6  is a sectional view of a downhole tool showing an upper housing having J-slot springs, a J-slot control ring, and a J-slot pin slidably disposed within the upper housing; 
       FIG. 7  is a sectional view of an uphole end of a downhole tool showing a top sub disposed at an upper housing; 
       FIG. 8  is a sectional view of a downhole tool in which a set-down sleeve disposed at a piston housing is inserted into a wellbore; 
       FIG. 9  is a sectional view of a downhole tool in which a flapper mechanism is closed; 
       FIG. 10  is a sectional view of a downhole tool in which an initiating piston slidably disposed within a bottom sub is engaged with a shoulder surface of the bottom sub; 
       FIG. 11  is a sectional view of a downhole tool in which a flapper mechanism is engaged by a flow tube from a downhole direction to support the flapper mechanism from the downhole direction; 
       FIG. 12  is a sectional view of a downhole tool in which a lock ring is translated in a downhole direction to support a flapper mechanism from an uphole direction; 
       FIG. 13  is a sectional view of a downhole tool in which a J-slot ring and a J-slot pin are translated in a downhole direction to effect the closing of a flapper mechanism; 
       FIG. 14  is a sectional view of a downhole tool in which a J-slot ring and a J-slot pin are translated in an uphole direction to effect the opening of a flapper mechanism; 
       FIG. 15  is a sectional view of a downhole tool in which an uphole translation of a J-slot ring and a J-slot pin effect the un-supporting of a lower dog; 
       FIG. 16  is a sectional view of a downhole tool in which a lock ring is engaged with an intermediate sub; 
       FIG. 17  is a sectional view of a downhole tool in which opening springs drive an inner mandrel in an uphole direction; 
       FIG. 18  is a sectional view of a downhole tool in which an upper seat and an upper seat extension translate in an uphole direction to open a flapper mechanism; and 
       FIG. 19  is a sectional view of a manual shifting tool inserted into a downhole tool. 
   

   DETAILED DESCRIPTION 
   A downhole tool capable of providing control to the production fluids in a wellbore is described herein. The tool is a configuration of concentrically arranged tubular housings adjoined by subs. A bi-directional barrier is cooperably associated with the housings and the subs to control the flow of the production fluids from the downhole environment of the wellbore. In one embodiment, the inner tubular housings of the tool are configured to slide relative to the outer tubular housings of the tool in a telescopic fashion to effect the closure or opening of the bi-directional barrier. In another embodiment the tool may be rotationally actuated to open or close the bi-directional valve. The tool is installable in any position within a wellbore where bi-directional or even signal directional control is desired or required. In its fully open position, the barrier device allows full bore access to the wellbore. Operation of the downhole tool further allows the barrier device to be closed to form a plug capable of holding pressure from above or below the barrier, thereby effectively preventing fluid communication across the barrier. The barrier device may be reopened and full bore access may be re-established upon, for example, completion of a preselected number of tubing pressure cycles, a mechanical or electrical actuation caused from surface or downhole intelligent controller, or other method. The concept set forth above is further elucidated by reference to a specific embodiment thereof discussed hereunder. Those of skill in the art will recognize many substitutional components that do not depart from full scope of this disclosure and appended claims. 
   Referring now to  FIGS. 1 through 7 , the downhole tool is shown in portions. The entire tool, hereinafter referred to as “tool  10 ,” comprises a plurality of tubular housings arranged end-to-end (but could be fewer or even one housing if possible from a manufacturing standpoint), as well as various mechanisms slidably disposed within the tubular housings. The various mechanisms regulate fluid flow through tool  10 . The outermost geometry of each housing and each sub is of a cross-sectional dimension that allows tool  10  to be received in the tubing string (or in a casing) of the wellbore. The arrangement of tubular housings comprises a bottom sub  12 , a piston housing  14  disposed at an upper end of bottom sub  12 , a spring housing  16  disposed at an upper end of piston housing  14 , a flapper housing  18  disposed at an upper end of spring housing  16 , an intermediate sub  20  disposed at an upper end of flapper housing  18 , an upper housing  22  disposed at an upper end of intermediate sub  20 , and a top sub  24  disposed at an upper end of upper housing  22 . It will be understood by those of skill in the art that tool  10  is configured to be oriented in the tubing string of the wellbore such that bottom sub  12  is positioned deeper in the well than top sub  24 . It will further be understood by those of skill in the art that any element of tool  10  that is positioned deeper in the well than any other element is said to be “downhole” of the second element, while the second element is said to be “uphole” of the first element. 
   Referring to  FIG. 1 , the downhole end of tool  10 , particularly bottom sub  12 , is shown. Initiating piston  26  is disposed proximate the downhole end of tool  10  and is annularly arranged and slidable within bottom sub  12  and piston housing  14 . A first set of o-rings  28  is recessed into bottom sub  12  at an uphole end of bottom sub  12 . A chamber  27  is defined between the inner surface of piston housing  14  and the outer surface of initiating piston  26 . Chamber  27  is bounded on its downhole end by first set of o-rings  28  and is bounded on its uphole end by a second set of o-rings  30 , shown with reference to  FIG. 2 , and is at atmospheric pressure. Second set of o-rings  30  is recessed into the surface of initiating piston  26  at a point intermediate the opposing ends of initiating piston  26 . A third set of o-rings  32  is recessed into piston housing  14  at a point uphole from second set of o-rings  30 . Although each set of o-rings  28 ,  30 ,  32  is depicted as including two rings, it will be understood by those of skill in the art that any number of o-rings can be employed to define a set of o-rings. In addition, other types of seals capable of holding a pressure differential thereacross may be substituted. A setting port  34  defined by an opening, extends from a chamber  136  at the inner surface of piston housing  14  to the outer surface of piston housing  14 . 
   A set-down sleeve, shown generally at  36  in  FIG. 2 , is disposed circumferentially about the outer surface of a cross-section of piston housing  14 . Set-down sleeve  36  is retained on the outer surface of piston housing  14  with a snap ring  38 . A snap ring retainer  40  positioned at the uphole end of set-down sleeve  36  maintains snap ring  38  and set-down sleeve  36  in their proper respective positions on piston housing  14 . 
   Disposed at an inner surface of set-down sleeve  36  and an outer surface of piston housing  14  is a shear ring  42  (or other selective release mechanism). As is illustrated, shear ring  42  engages the shoulder surface of a notch at the outer surface of piston housing  14 . Shear ring  42  is engineered to fail upon the application of a pre-selected amount of stress applied thereto. The failure of shear ring  42  allows for the movement of piston housing  14  relative to set-down sleeve  36  during operation of tool  10 , as will be described below. 
   As stated above, spring housing  16  is disposed at the uphole end of piston housing  14 . In  FIG. 3 , a flow tube spring  44  is shown as it would be mounted annularly within spring housing  16  and adjacent to an outer surface of a flow tube  46 . A portion of the downhole end of flow tube  46  is, in turn, disposed annularly about the outer surface of the uphole end of initiating piston  26  that extends into flow tube  46  and spring housing  16 . Flow tube  46  and initiating piston  26  are disposed in fixed contact with each other at an inner surface of a downhole end of flow tube  46  and an outer surface of an uphole end of initiating piston  26  via a shear screw  54  (or other selective release mechanism). Shear screw  54  is engineered to fail when a pre-selected amount of stress is applied to initiating piston  26  due to hydrostatic pressure at the uphole end of initiation piston  26 . 
   An extension member  48 , which is supported at a shoulder surface of piston housing  14  (FIG.  2 ), supports flow tube spring  44  at a downhole end of flow tube spring  44 . A lower spring end stop  50  is annularly disposed at a shoulder in the uphole end of spring housing  16  at an outer surface of flow tube  46  to provide a surface at which flow tube spring  44  can be compressed. A debris barrier  52  is circumferentially disposed in a notch disposed at an outer surface of lower spring end stop  50  to prevent the contamination of flow tube spring  44  with debris, e.g., particulate matter suspended in wellbore fluids flowing through tool  10  during operation of tool  10 . 
   Referring now to  FIG. 4 , flapper housing  18  is illustrated and described. Flapper housing  18 , as stated above, is disposed at the uphole end of spring housing  16 . A flapper mechanism, shown generally at  56 , is operably disposed within flapper housing  18  to provide for the intervention-less bi-directional control of fluid communication through tool  10 . Flapper mechanism  56  is hingedly mounted at a lower base  58  supported by a lower seat  60 , which is in turn supported within spring housing  16 . The hinged mounting of flapper mechanism  56  at lower base  58  is effected via a lower pin assembly  62 . A lower seal  64 , fabricated of polytetrafluroethylene, is circumferentially disposed at an uphole end of lower seat  60  to effect the sealing of flapper mechanism  56  from flow tube  46  and prevention of flow through tool  10  upon actuation of flapper mechanism  56 . 
   Flapper mechanism  56  comprises a double flapper including a lower flapper  66  and an upper flapper  68  articulatively linked to each other via a link pin  70 . Link pin  70  is retained on flapper  66 ,  68  with pins (not shown) and nuts (not shown). As stated above, the downhole end of lower flapper  66  is hingedly connected at lower base  58  via lower pin assembly  62 . Lower pin assembly  62  comprises an alignment rod (not shown) supported through the downhole end of lower flapper  66 . Torsion springs (not shown) urge the flappers against the seats. The flow tube holds the flappers back against the flapper housing. The uphole end of upper flapper  68  is hingedly connected at an upper base  72  with an upper pin assembly  74 . Upper base  72  is fixedly disposed at an upper seat  76 , which is in turn fixedly disposed at an upper seat extension  78 . Upper pin assembly  74  is substantially similar to lower pin assembly  62 . Upper seat extension  78  is slidably and annularly disposed within flapper housing  18 , intermediate sub  20 , and upper housing  22 . An upper seal  65 , which may be fabricated of polytetrafluroethylene, is circumferentially disposed at a downhole end of upper seat  76  to effect the sealing of flapper mechanism  56  from the portion of tool  10  uphole of flapper mechanism  56 . 
   An upper base extension  80  is also fixedly disposed at upper seat  76 . Upper base extension  80  includes two slots (not shown) milled into a surface thereof. The first slot extends in a straight line longitudinally along the length of upper base extension  80 . An upper seat pin  67  disposed in upper seat  76  engages the first slot and maintains the alignment of upper seat  76  and upper base  72 . Translation of upper seat pin  67  along the first slot ensures that the sinusoidal profiles of upper seat  76  and upper flapper  68  are aligned during operation of tool  10 . A seat control pin  82  disposed at a seat control ring  84  disposed circumferentially about upper seat extension  78  is received in the second slot, which is profiled. Engagement of the second slot by seat control pin  82  causes seat control ring  84  to rotate as upper base extension  80  translates in the downhole direction during the opening of flapper mechanism  56 . 
   Referring now to  FIGS. 5 and 6 , a lock ring support  86  is supported by an inner mandrel  95  at an uphole end of upper seat extension  78 . Lock ring support  86  is positioned within upper housing  22 . A body lock ring  88  disposed uphole of lock ring support  86  is held in place by lower dogs  90  supported on a dog support mandrel  92  annularly positioned within inner mandrel  95 . Opening springs  94 , J-slot springs  96 , a spring separator  98 , a spring retainer  100 , and an upper spring end stop  102  are positioned between the inner surface of upper housing  22  and the outer surface of inner mandrel  95 . A piston  104  supported in a cylinder sub  140  disposed between upper housing  22  and inner mandrel  95  effects the compression of springs  96  during operation of tool  10 . Dynamic seals  144  are disposed at the uphole end of piston  104 . 
   A hook mandrel  106  is supported at the uphole end of piston  104 . Hook mandrel  106  is in communication with a J-slot ring/pin assembly  108  disposed at a J-slot sub  110  supported within upper housing  22  by dog support mandrel  92 . J-slot ring/pin assembly  108  comprises a J-slot control ring  112  slidably disposed about an outer surface of J-slot sub  110 . A J-slot pin  114  is retained in a groove that extends circumferentially about the outer surface of J-slot control ring  112 . A J-slot C-ring  116  also extends circumferentially about the outer surface of J-slot control ring  112 . 
   J-slot sub  110  includes a slot (not shown) having a milled profile. An upper dog retainer  118  having upper dogs  120  extending laterally therefrom is slidably supported between upper housing  22  and dog support mandrel  92  and is in drivable communication with J-slot ring/pin assembly  108 . A split ring  122  retains an upper dog housing  124  between upper dog retainer  118  and dog support mandrel  92 . An opening sub  128  is supported at the uphole end of dog support mandrel  92 . Top sub  24  is shown in  FIG. 7  as it would be disposed at upper housing  22 . 
   The operation of tool  10  is described with reference to  FIGS. 8 through 19 . In general, the operation of tool  10  comprises running tool  10  into a wellbore, closing flapper mechanism  56 , locking flapper mechanism  56  closed, performing the relevant wellbore operations as determined by an operator of tool  10 , and opening flapper mechanism  56  subsequent to the completion of the wellbore operations. 
   The running of tool  10  into the wellbore is referred to as the initiation phase and is described with reference to FIG.  8 . In the initiation phase, tool  10  is run into the wellbore to a depth such that set-down sleeve  36  engages a liner top  130  positioned within the wellbore. When a sufficient amount of weight is “slacked off,” shear ring  42  will shear. Once shear ring  42  shears, set-down sleeve  36  is slidably translatable along the outer surface of piston housing  14  between the top edge of liner top  130  and a shoulder surface, shown at  132  in  FIGS. 2 and 8 . Tool  10  can then be further inserted into the wellbore until shoulder surface  132  engages a shoulder surface, shown at  134  in  FIGS. 2 and 8 , on the uphole end of set-down sleeve  36 . 
   Once shoulder surface  132  engages shoulder surface  134  and tool  10  is fully inserted into the wellbore, setting port  34  is disposed at the engagement of shoulder surface  132  and shoulder surface  134 . Because the inner surface of liner top  130  and the outer surface of initiating piston  26  are only loosely engaged, fluid communication is maintained therebetween. Such fluid communication typically comprises the flow of wellbore fluids. Because setting port  34  is disposed at the engagement of shoulder surface  132  and shoulder surface  134 , fluid communication can be maintained across setting port  34  with chamber  136  defined between the inner surface of piston housing  14  and the outer surface of initiating piston  26  and bounded on opposing ends by second set of o-rings  30  and third set of o-rings  32 . The fluid communication maintained across setting port  34  with chamber  136 , which is at hydrostatic pressure, causes chamber  136  to expand and drives initiating piston  26  in the downhole direction. As initiating piston  26  is driven in the downhole direction, initiating piston  26 , which is connected at its uphole end to the downhole end of flow tube  46  via shear screw  54 , pulls flow tube  46  in the downhole direction and compresses flow tube spring  44 . Flow tube  46  is pulled in the downhole direction until flow tube  46  engages a shoulder surface  138  on piston housing  14 . 
   Referring now specifically to  FIGS. 8 and 9 , the closing of flapper mechanism  56  to effectively prevent the flow of wellbore fluids through tool  10  is shown. In closing flapper mechanism  56 , the movement of flow tube  46  in the downhole direction pulls the uphole end of flow tube  46  clear of flapper mechanism  56 . Once flow tube  46  is clear of flapper mechanism  56 , flappers  66 , 68  are free to collapse and swing closed under the action of the torsion springs of lower pin assembly  62  and upper pin assembly  74 . 
   The hydrostatic pressure continues to act on initiating piston  26  even after flow tube  46  engages shoulder surface  138  on piston housing  14 . Such hydrostatic pressure continues to bias initiating piston  26  in the downhole direction within the inside diameter liner top  130 , while flow tube  46  and piston housing  14  remain biased on the top edge of liner top  130 . The continued pressure exerted on initiating piston  26  causes shear screw  54 , which maintains the connection between initiating piston  26  and flow tube  46 , to shear (or otherwise release, as noted above). 
   Initiating piston  26  then continues to move in the downhole direction reducing the volume of chamber  27 , as is shown in FIG.  10 . As the volume of chamber  27  is reduced, the pressure therein is increased until first set of o-rings  28  unseats, thereby relieving the pressure in chamber  27  and causing chamber  27  to flood with wellbore fluids. At this point, initiating piston  26  may engage bottom sub  12 . Once shear screw  54  shears, the compression of flow tube spring  44  is relieved and flow tube  46  is driven in the uphole direction until the uphole end of flow tube  46  engages flapper mechanism  56 , as is shown in FIG.  11 . Once flapper mechanism  56  is closed, lower flapper  66  engages lower seal  64  on lower seat  60 , thereby rendering flapper mechanism  56  capable of holding pressure from the uphole direction. Because of the geometry of flapper mechanism  56 , flow tube  46  is prevented from forcing flapper mechanism  56  to open. 
   Still referring to  FIG. 11 , after flapper mechanism  56  is closed, flapper mechanism  56  is locked. To lock flapper mechanism  56 , the tubing string is pressurized such that a pressure is exerted on lower flapper  66 . Such a pressurization creates a pressure differential across the area between the outer seals of the cylinder sub and the seals of the intermediate sub and causes the translation of the componentry uphole of flapper mechanism  56  in the downhole direction until upper seat  76  engages upper flapper  68  via upper seal  65 . During the translation of the componentry in the downhole direction, upper seat  76  and upper base  72  translate in the downhole direction. As stated above, the engagement of upper seat pin  67  with the first slot milled into upper base extension  80  maintains the alignment of upper seat  76  and upper base  72  to ensure that the sinusoidal profiles on upper seat  76  and upper flapper  68  are properly aligned during operation of tool  10 . 
   Referring now to  FIG. 12 , as lock ring support  86  translates downhole, body lock ring  88  attached to lock ring support  86  engages a set of teeth which may be one way threads and in one embodiment are wicker threads  142  disposed at an inner surface of upper housing  22 . Wicker threads  142  are configured such that body lock ring  88  is prevented from moving in the uphole direction upon an application of pressure from the wellbore downhole from wicker threads  142 . At such a point, flapper mechanism  56  is sandwiched between lower seat  60  and upper seat  76  and locked closed, as shown in  FIG. 11 , thereby allowing flapper mechanism  56  to support tubing pressure from either the uphole direction or the downhole direction. Wellbore operations can then be undertaken. 
   Once the wellbore operations requiring closure of tool  10  are complete, tool  10  can be opened. Although tool  10  can be opened in a number of different ways, one way of causing tool  10  to open is the application of tubing pressure cycles uphole of flapper mechanism  56  allowing for the indexing of the opening mechanism. The opening mechanism may be actuated upon the application of pressures of up to about 3000 psi or greater. 
   The opening mechanism employs a ratcheting scheme to retract flappers  66 ,  68  back against the inner surface of flapper housing  18 , as is shown and described with reference to  FIGS. 13 through 18 . To actuate the opening mechanism with the ratcheting scheme, pressure is applied to the tubing uphole of flapper mechanism  56 . Such pressure acts across dynamic seals  144  ( FIG. 13 ) in the downhole direction to drive piston  104  downhole, thereby compressing J-slot springs  96  via upper spring end stop  102 . As piston  104  is driven downhole, piston  104  pulls hook mandrel  106 , which in turn pulls J-slot control ring  112 . J-slot pin  114  disposed in J-slot control ring  112  engages a milled profile  146  on J-slot sub  110 . As J-slot control ring  112  translates along J-slot sub  110  in the downhole direction, J-slot pin  114  follows milled profile  146 , thereby causing J-slot control ring  112  to rotate. If the tubing pressure in the wellbore is great enough to compress the J-slot spring sufficiently, J-slot control ring  112  will translate downhole (while rotating) until J-slot pin  114  engages a lower limit of milled profile  146  in J-slot sub  110 . 
   Referring to  FIG. 14 , upon bleeding the tubing pressure off, piston  104  is biased in the uphole direction in response to the loading of J-slot spring  96 . J-slot control ring  112  then translates in the uphole direction while rotating in response to engagement of J-slot pin  112  in the milled profile on J-slot sub  110 . The bleeding off of the tubing pressure and the movement of J-slot control ring  112  in the uphole direction can be effected a pre-selected number of times without opening the flapper mechanism. The illustrated exemplary embodiment of tool  10  is configured to enable the pressure to be bled off seven times without opening flapper mechanism  56 . The upward translation of J-slot control ring  112  is limited by the engagement of J-slot pin  114  with the top edge of the profile on J-slot sub  110 . It will be understood by one of skill in the art that as many or as few steps as desired may be built into J-slot control ring  112 . 
   In the illustrated exemplary embodiment, on bleeding off the tubing pressure after the eighth time, J-slot pin  114  engages a section of milled profile  146  that enables J-slot control ring  112  to translate in the uphole direction until J-slot control ring  112  engages the downhole end of upper dog retainer  118  and biases upper dog retainer  118  in the uphole direction. Upper dog retainer  118  is translated in the uphole direction until upper dog retainer  118  engages opening sub  128 . 
   The load exerted on opening sub  128  by the translation of upper dog retainer  118  in the uphole direction biases opening sub  128  in the uphole direction. When upper dog retainer  118  moves clear of upper dog  120 , opening sub  128  and dog support mandrel  92  move uphole until dog support mandrel  92  engages split ring  122 . Such upward movement causes lower dog  90  to be de-supported, as is shown with reference to  FIG. 15 , thereby allowing lower dog  90  to extend through windows in inner mandrel  95  to effectively de-couple inner mandrel  95  from lock ring support  86 . Opening springs  94  are then free to pull the flapper mechanism open by driving lock ring support  86  in the downhole direction to engage intermediate sub  20 , as is shown in FIG.  16 . The engagement of lock ring support  86  with intermediate sub  20  effectively closes off a port  148  disposed in upper housing  22  that provides fluid communication between the tubing string (in which tool  10  is disposed) and the annulus of the wellbore. 
   Simultaneous with the engagement of lock ring port  86  with intermediate sub  20 , opening springs  94  drive inner mandrel  95  in the uphole direction, as shown in FIG.  17 . Because opening springs  94  are in mechanical communication with inner mandrel  95  via retainer segments  150  disposed at spring retainers  100 , the upward movement of inner mandrel  95  causes upper seat  76  and upper seat extension  78  to also move in the uphole direction, as is shown in FIG.  18 . As upper seat extension  78  translates in the uphole direction, seat control ring  84  is likewise pulled in the uphole direction. Seat control pin  82  thereby engages the profiled slot at upper base extension  80 . As seat control pin  82  is pulled in the uphole direction through the profiled slot, flapper mechanism  56  is pulled into the open position. As flapper mechanism  56  opens, flow tube  46  is biased in the uphole direction as a result of the decompression of the flow tube spring. Once flapper mechanism  56  is fully open, flow tube  46  maintains flapper mechanism  56  in the open position, and flow can be maintained through tool  10 . Normal operation of the wellbore can then be resumed. 
   Referring now to  FIG. 19 , a mechanical intervention procedure for opening the flapper mechanism is described and illustrated. Mechanical intervention may be required when tool  10  does not open in response to repeated tubing pressure cycles or when an operator of tool deems it necessary or desirable to open the flapper mechanism manually. In the mechanical intervention procedure, a shifting tool  152  is run into the uphole end of tool  10 . A tab  154  extending from shifting tool  152  engages a profile disposed at the inner surface of opening sub  128 . By biasing shifting tool  152  in the uphole direction, load can be applied to opening sub  128 , through dog support mandrel  92 , into upper dog  120 , and into upper dog housing  124 . Such load is transmitted through tool  10  through the J-slot sub and the inner mandrel to the body lock ring. When the applied load is sufficient (i.e., reaches a pre-calculated limit), a calibrated parting section  156  fails allowing opening sub  128  and dog support mandrel  92  to be moved in the uphole direction, thereby un-supporting the lower dog. The lower dog, in a manner similar to that as described above, drops through the window in the inner mandrel, de-coupling the inner mandrel from the lock ring support. The opening springs then drive the inner mandrel upward, pulling the upper seat, the upper seat extension, and the seat control ring. The seat control pin engages the profiled slot on the upper base extension and pulls the upper base and the flapper mechanism into the open position, allowing the flow tube to extend upward and retain the flapper mechanism in the open position, thereby opening tool  10 . Once fully opened, shifting tool  152  is manually disengaged from opening sub  128  and retracted from the wellbore. 
   While the disclosure has been described with reference to a preferred embodiment, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the disclosure. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the disclosure not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this disclosure, but that the disclosure will include all embodiments falling within the scope of the appended claims.