Abstract:
Apparatus and methods are provided for fracturing a well in a hydrocarbon bearing formation. The apparatus can include one or more valve sub-assemblies assembled into a tubing string inserted into an unlined well. The valve sub-assembly can include a sliding piston initially pinned in place to seal off ports that provide communication between the interior of the tubing string and a production zone of the formation. A ball can be inserted into a tubing string and moved along the tubing string by injected pressurized fracturing fluid until the ball sits on a valve seat of a valve sub-assembly coupled to the sliding piston to close off the tubing string below the valve. The force of the fluid forces the piston downwards to shear off the pins and open the ports. Fracturing fluid can then exit the ports to fracture the production zone of the formation.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This is a continuation of International Application No. PCT/CA2011/000944 filed on Aug. 23, 2011 which claims priority of U.S. Provisional Patent Application No. 61/376,364 filed Aug. 24, 2010 and hereby incorporates the same provisional application by reference herein in its entirety. 
     
    
     TECHNICAL FIELD 
       [0002]    The present disclosure is related to the field of apparatuses and methods for fracturing a well in a hydrocarbon bearing formation, in particular, down-hole valve subassemblies that can be opened to fracture production zones in a well. 
       BACKGROUND 
       [0003]    It is known to use valve subassemblies placed down into a well using tubing, such as an uncased horizontal well that can be opened to fracture an oil producing formation to increase the flow of oil from the formation. These valve subassemblies or “subs” can comprise a ball valve seat mechanism that can receive a ball, which is placed into the tubing and travels down the tubing until it reaches the ball valve seat mechanism. Once the ball is seated in the valve seat, flow through the valve sub is cut off. The pressure of fracturing fluid injected into the tubing will cause the closed valve seat mechanism to slide a piston forward in the valve sub thereby opening ports in the wall of the valve sub to allow the pressure of the fracturing fluid penetrate into a production zone of a hydrocarbon bearing formation. The ball valve seat mechanism can be comprised of varying sized openings. Typically, a number of the valve subs are placed in series in the tubing at predetermined intervals in spacing along the well into the formation. The largest diameter valve seat is placed nearest the top of the well with progressively smaller diameter valve seats with each successive valve sub placed further along the tubing string. 
         [0004]    In this manner, the furthest valve sub, the one having the smallest diameter opening can be closed by placing the matching sized ball into the tubing, which can pass through all of the preceding valve subs, each having larger diameters than the valve sub being closed, until the ball reaches its matching valve sub. One shortcoming of these known ball valve seat mechanisms is that the volume of fluid, and the rate of fluid flow, is constricted by the progressively decreasing diameter of the ball valve seat mechanism disposed in each of the valve subs, which becomes increasingly restricted with each successive valve sub in the tubing string. While the number of these valve subs can be as high as 23 stages, put in place with a packer system, the flow-rate that can be obtained through these valve subs is not high. 
         [0005]    Another shortcoming of these known ball valve seat mechanisms is that the ball seats constrict the well bore with their presence. As such, full production and the ability to run conventional tools for production, work-overs and isolation testing are not possible. Current systems have balls and seats left in the well bore restricting production and plugging off sections of the liner with sand and balls. It is known to drill out balls and seats to achieve full production and access, however, the bore is still not full drift and is left with a restricted diameters inhibiting conventional tool use. In addition, these drill-outs are very costly and time consuming. 
         [0006]    It is, therefore, desirable to provide a fracturing valve sub that overcomes the shortcomings of the prior art. 
       SUMMARY 
       [0007]    An apparatus for fracturing a well in a formation is provided. The apparatus includes a tubular valve body with an upper end and a lower end, and a valve passageway extending therethrough, the valve body further including at least one valve port extending through a sidewall thereof, the at least one valve port located nearer the upper end; a tubular piston valve slidably disposed in the valve passageway and configured to provide communication therethrough, the piston valve configured to move from a raised position where the at least one valve port is closed to a lowered position where the at least one valve port is open; a ball seat sub-assembly slidably disposed in the valve passageway between the piston valve and the lower end, the ball seat sub-assembly including a ball seat passageway extending therethrough; and an inner piston sub-assembly releasably coupled to the piston valve and configured to disengage from the piston valve when pulled away from the ball seat. The ball seat sub-assembly is configured to move the piston valve from the raised position to the lowered position when downward force is applied to the ball seat sub-assembly. 
         [0008]    In some embodiments, the apparatus further includes means for holding the piston valve in the lowered position when it is moved from the raised position. 
         [0009]    In some embodiments, the apparatus further includes means for holding the piston valve in the lowered position when it is moved from the raised position and the holding means includes a ratchet ring disposed on the piston valve and corresponding ratchet threads disposed on an end-subassembly, wherein the end-subassembly is disposed at the lower end of the valve body. 
         [0010]    In some embodiments, the apparatus further includes means for holding the piston valve in the lowered position when it is moved from the raised position and the holding means includes fingers disposed on the piston valve and a corresponding groove disposed on an end-subassembly, wherein the end-subassembly is disposed at the lower end of the valve body. 
         [0011]    In some embodiments, the ball seat sub-assembly further includes a bypass port extending therethrough for allowing fluid circulation through the ball seat sub-assembly. 
         [0012]    In some embodiments, the ball seat sub-assembly further includes a bypass port extending therethrough for allowing fluid circulation through the ball seat sub-assembly, the inner piston sub-assembly is releasably coupled to the ball seat sub-assembly, and the inner piston sub-assembly is configured to pull away from the ball seat sub-assembly to open the bypass port. 
         [0013]    In some embodiments, the apparatus includes a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body. 
         [0014]    In some embodiments, the apparatus includes a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body, and the removal tool includes a tubular upper body with an upper removal tool end configured for coupling to coil tubing and a tubular lower body configured for coupling to the inner piston sub-assembly, the lower body coupled to a lower end of the upper body, wherein the upper body and lower body define a passageway extending through the removal tool. 
         [0015]    A method for fracturing a well in a formation is provided. The method includes the steps of providing an apparatus including a tubular valve body with an upper end and a lower end, and a valve passageway extending therethrough, the valve body further including at least one valve port extending through a sidewall thereof, the at least one valve port located nearer the upper end; a tubular piston valve slidably disposed in the valve passageway and configured to provide communication therethrough, the piston valve configured to move from a raised position where the at least one valve port is closed to a lowered position where the at least one valve port is open; a ball seat sub-assembly slidably disposed in the valve passageway between the piston valve and the lower end, the ball seat sub-assembly including a ball seat passageway extending therethrough; and an inner piston sub-assembly releasably coupled to the piston valve and configured to disengage from the piston valve when pulled away from the ball seat. The ball seat sub-assembly is configured to move the piston valve from the raised position to the lowered position when a downward force is applied to the ball seat sub-assembly. The method further includes placing the apparatus in a tubing string disposed in the well, the apparatus located near a production zone in the formation; placing a ball configured to seal off the ball seat passageway when seated on the ball seat sub-assembly into the tubing string; and injecting pressurized fracturing fluid into the tubing string wherein the fracturing fluid moves the ball through the tubing string into the apparatus until the ball is seated on the ball seat sub-assembly and places the downward force on the ball seat sub-assembly to move the piston valve from the closed position to the open position, wherein the fracturing fluid can pass through the at least one valve port of the apparatus to fracture the formation. 
         [0016]    In some embodiments, the piston valve is held in the lowered position when it is moved from the raised position. 
         [0017]    In some embodiments, the piston valve is held in the lowered position when it is moved from the raised position by a ratchet ring disposed on the piston valve and corresponding ratchet threads disposed on an end-subassembly, wherein the end-subassembly is disposed at the lower end of the valve body. 
         [0018]    In some embodiments, the piston valve is held in the lowered position when it is moved from the raised position by fingers disposed on the piston valve and a corresponding groove disposed on an end-subassembly, wherein the end-subassembly is disposed at the lower end of the valve body. 
         [0019]    In some embodiments, the ball seat sub-assembly includes a bypass port extending therethrough for allowing fluid circulation through the ball seat sub-assembly. 
         [0020]    In some embodiments, the inner piston sub-assembly is releasably coupled to the ball seat sub-assembly, and the inner piston sub-assembly is configured to pull away from the ball seat sub-assembly to open the bypass port. In some embodiments, the method further includes providing a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body; and separating the ball seat sub-assembly and the inner piston sub-assembly from the valve body with the removal tool. 
         [0021]    In some embodiments, the method includes providing a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body; and separating the ball seat sub-assembly and the inner piston sub-assembly from the valve body with the removal tool. The removal tool includes a tubular upper body with an upper removal tool end configured for coupling to coil tubing and a tubular lower body configured for coupling to the inner piston sub-assembly, the lower body coupled to the lower end of the upper body, wherein the upper body and lower body define a passageway extending through the removal tool. 
         [0022]    In some embodiments, the method further includes providing a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body; separating the ball seat sub-assembly and the inner piston sub-assembly from the valve body with the removal tool; providing a shifting tool; and shifting the piston back to the raised position with the shifting tool. 
         [0023]    A system for use downhole in a well is provided. The system includes at least one apparatus, the apparatus including a tubular valve body with an upper end and a lower end, and a valve passageway extending therethrough, the valve body further including at least one valve port extending through a sidewall thereof, the at least one valve port located nearer the upper end; a tubular piston valve slidably disposed in the valve passageway and configured to provide communication therethrough, the piston valve configured to move from a raised position where the at least one valve port is closed to a lowered position where the at least one valve port is open; a ball seat sub-assembly slidably disposed in the valve passageway between the piston valve and the lower end, the ball seat sub-assembly including a ball seat passageway extending therethrough; and an inner piston sub-assembly releasably coupled to the piston valve and configured to disengage from the piston valve when pulled away from the ball seat. The ball seat sub-assembly is configured to move the piston valve from the raised position to the lowered position when downward force is applied to the ball seat sub-assembly. The system further includes at least one ball configured to seal off the ball seat passageway when seated on the ball seat sub-assembly wherein the at least one ball is configured to specifically engage the ball seat sub-assembly of a particular apparatus and the at least one ball is targeted to the particular apparatus. 
         [0024]    In some embodiments, the at least one apparatus further includes means for holding the piston valve in the lowered position when it is moved from the raised position. 
         [0025]    In some embodiments, the at least one apparatus further includes a ratchet ring disposed on the piston valve and corresponding ratchet threads disposed on an end-subassembly, wherein the end-subassembly is disposed at the lower end of the valve body. 
         [0026]    In some embodiments, the at least one apparatus further includes fingers disposed on the piston valve and a corresponding groove disposed on an end-subassembly, wherein the end-subassembly is disposed at the lower end of the valve body. 
         [0027]    In some embodiments, the ball seat sub-assembly further includes a bypass port extending therethrough for allowing fluid circulation through the ball seat sub-assembly. 
         [0028]    In some embodiments, the ball seat sub-assembly further includes a bypass port extending therethrough for allowing fluid circulation through the ball seat sub-assembly, the inner piston sub-assembly is releasably coupled to the ball seat sub-assembly, and the inner piston sub-assembly is configured to pull away from the ball seat sub-assembly to open the bypass port. 
         [0029]    In some embodiments, the system further includes a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body. 
         [0030]    In some embodiments, the system further includes a removal tool configured to separate the ball seat sub-assembly and the inner piston sub-assembly from the valve body, and the removal tool includes a tubular upper body with an upper removal tool end configured for coupling to coil tubing and a tubular lower body configured for coupling to the inner piston sub-assembly, the lower body coupled to the lower end of the upper body, wherein the upper body and lower body define a passageway extending through the removal tool. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS  
         [0031]      FIG. 1  is a cross-section elevation view depicting a first embodiment of a frac valve with the valve closed. 
           [0032]      FIG. 2  is a cross-section elevation view depicting the frac valve of  FIG. 1  with the valve open. 
           [0033]      FIG. 3  is a cross-section elevation view depicting a second embodiment of a frac valve with the valve closed. 
           [0034]      FIG. 4  is a cross-section elevation view depicting the frac valve of  FIG. 3  with the valve open. 
           [0035]      FIG. 5  is a side cross-sectional view depicting a well in a formation with a plurality of the valve subassemblies of  FIG. 1 . 
           [0036]      FIG. 6  is a cross-section elevation view depicting a removal tool for the frac valve of  FIG. 1 . 
           [0037]      FIG. 7  is a cross-section elevation view depicting the frac valve of  FIG. 1  with the removal tool of  FIG. 5  inserted therein to attach to a innen piston sub-assembly. 
           [0038]      FIG. 8  is a cross-section elevation view depicting the frac valve of  FIG. 6  with the removal tool of  FIG. 5  raising the inner piston subassembly. 
           [0039]      FIG. 9  is a cross-section elevation view depicting the frac valve of  FIG. 7  with the removal tool pushing the inner piston sub-assembly towards another frac valve. 
       
    
    
     DETAILED DESCRIPTION OF EMBODIMENTS 
       [0040]      FIGS. 1 and 2  illustrate an embodiment of fracturing valve subassembly (“sub”)  10 . Referring to  FIG. 1 , the major components of valve sub  10  can comprise tubular valve body  12  having box end  9 , tubular end sub-assembly  22  having pin end  8  disposed on a lower end of body  12  and tubular piston  14  slidably disposed within body  12 , defining passageway  7  extending through from box end  9  to pin end  8 . When assembled, piston  14  can be held in a raised or closed position within body  12  by shear screws  54  to close off valve ports  16  that provide communication through the sidewall of body  12 . In some embodiments, piston  14  can further comprise ratchet ring  18  disposed on a lower end thereof. Ratchet ring  18  can be configured to engage ratchet threads  42  disposed on an interior surface of end subassembly  22  and hold piston  14  in a lower position to keep ports  16  open when piston  14  is moved from the raised or closed position to the lowered or open position. 
         [0041]    In some embodiments, valve sub  10  can further comprise ball seat sub-assembly  36  slidably disposed within body  12 . Ball seat sub  36  can comprise ball seat  40  disposed at an upper end thereof, latching threads  52  disposed at a lower end thereof and passageway  46  providing communication therebetween. In further embodiments, ball seat sub  36  can further comprise ports  44  to provide communication between passageway  46  to the exterior of ball seat sub  36 . In some embodiments, valve sub  10  can further comprise inner piston sub-assembly  13  (as more clearly shown in  FIG. 9 ) that can operatively couple ball seat sub  36  to piston  14 . Inner piston sub  13  can further comprise latching sleeve  26 , lower inner piston  24  and upper inner piston  20 . In some embodiments, the lower end of latching sleeve  26  can be coupled to ball seat sub  36  with set screws  38 . The upper end of latching sleeve  26  can comprise latching fingers  28  configured to engage groove  30  disposed on the inner surface of piston  14 . When unassembled, latching fingers  26  can be biased to move inwards towards each other. When assembled in valve sub  10 , latching fingers  26  can be pushed outwards by upper inner piston  20  to engage groove  30  of piston  14  to operatively couple inner piston sub  13  to piston  14 . In some embodiments, lower inner piston  24  can threadably couple to upper inner piston  20 . Lower inner piston  24  can couple to latching sleeve  26  with shear screws  56 . Lower inner piston  24  can be further configured to slidably engage the upper end of ball seat sub  36 . In some embodiments, lower inner piston  24  can butted out against ball seat sub  36 . Such positioning can allow for the use of a high formation breakdown pressure, for example, up to 15,000 psi, because lower inner piston  24  will not move from hydraulic downward force as it is already against ball seat sub  36 . 
         [0042]    Disposed throughout valve sub  10  are o-rings  11  to provide sealing means, as well known to those skilled in the art, between components that are assembled together and components that move with respect to one another. 
         [0043]    When valve sub  10  is assembled to be placed in a tubing string, piston  14  can be positioned in the raised position to close valve ports  16 , and ball seat sub  36  and inner piston assembly  13 , which are operatively coupled to piston  14 , can be in a retracted position in passageway  7  disposed nearer pin end  8 . 
         [0044]    Referring to  FIGS. 3 and 4 , in some embodiments, piston  14  can further comprise piston fingers  19  disposed on a lower end thereof. Piston fingers  19  can be configured to engage valve body groove  43  disposed on an interior surface of end sub-assembly  22  and hold piston  14  in a lower position to keep ports  16  open when piston  14  is moved from the raised or closed position to the lowered or open position. Piston fingers  19  can be biased to move outwards away from each other. Referring to  FIG. 3 , when in the raised or closed position, piston fingers  19  can be held inwards by valve body  12 . Referring to  FIG. 4 , when in the lowered or open position, piston fingers  19  can engage valve body groove  43 . 
         [0045]    Referring to  FIGS. 2 and 4 , valve sub  10  is shown with ball  41  seated on ball seat  40 . When ball  41  is placed in the tubing string connected to box end  9  of valve sub  10 , it can move along the tubing string by pressurized fracturing fluid injected into the tubing string. Ball  41  can flow down the tubing string until it reaches valve sub  10  and enters into passageway  7 . Once in passageway  7 , ball  41  can seat on ball seat  40  thereby closing off passageway  46 . The pressurized fracturing fluid can then force ball seat sub  36  downwards. When the force of the fracturing fluid exceeds the shear force required to shear shear screws  54 , piston  14  can be drawn downwards to a lowered or open position to open ports  16 . In the lower position, ratchet ring  18  disposed on piston  14  can engage ratchet threads  42  to keep piston  14  in the lower position. In some embodiments, piston fingers  19  disposed on piston  14  can engage valve body groove  43  to keep piston  14  in the lower position. In order for ball  41  to seal off ball seat sub  36 , the diameter of ball  41  must be greater than the diameter of passageway  46 . 
         [0046]    Referring to  FIG. 5 , a cross-sectional view of a horizontal well comprising the apparatus described herein is shown. In this example, well  146  in formation  148  comprises tubing string  149  further comprising a plurality of valve subs  10  disposed along well  146 . In installing tubing string  149 , float shoe  150  can be run into well  146  through casing  158  and liner packer  156  into open hole horizontal well  152 . Float shoe  150  can comprise a float collar, as well known to those skilled in the art, followed by a section of tubing  149 , then followed by a valve sub  10 . This can then be followed by another section of tubing  149  and another valve sub  10 , and so on. A number of valve subs  10  can be placed in a single tubing string  149 . This can be accomplished by each valve sub  10  having ball seat subs  36  with an increasingly larger diameter for passageway  46 . For example, the valve sub  10  furthest along tubing string  149 , or the one closest to float shoe  150 , will have the narrowest diameter passageway  46 . Each successive valve sub  10  from float shoe  150  would then have a diameter for passageway  46  larger than the valve sub  10  after it. Furthermore, the diameters of passageway  46  can be selected to allow the balls  41  for the valve subs  10  located further down to pass through until ball  41  reaches the valve sub  10  it is configured to seal off and open ports  16  thereof. In some embodiments, the diameter of passageway  46  can range from 0.830 inches to 2.430 inches, increasing in 0.100 inch increments. The diameter of ball  41  can, correspondingly, range from 0.900 inches to 2.500 inches, increasing in 0.100 inch increments. This arrangement can, therefore, provide up to  17  distinct or unique combinations of valve subs  10  and balls  41 . The number of valve subs  10  and the spacing between the valve subs to be determined by the size of formation  148  and the number of production zones  154  contained in formation  148 . 
         [0047]    In some embodiments, tubing string  149  can further comprise open hole packers  160  disposed on tubing string  149  before and after each valve sub  10  to isolate the production zones  154  from one another. In other embodiments, packers  160  can comprise dual elements. 
         [0048]    To stimulate the production of formation  148 , ball  41  for the last valve sub  10  disposed in tubing string  149  can be inserted in the string followed by pressurized fracturing injected into tubing string  149 . Ball  41  passes through all valve subs  10  until it reaches the last valve sub  10  to close off passageway  46  in ball seat sub  36 . 
         [0049]    The hydraulic force of the pressurized fracturing fluid applies a downward force on ball seat sub  36  and piston  14  until the force exceeds the shear force rating of shear screws  54  thereby allowing piston  14  slide downwards from a closed position, where ports  16  are sealed off, to an open position where ports  16  are opened. As piston  14  moves to the open position, ratchet ring  18  can engage ratchet threads  42  to lock piston  14  in place and to prevent piston  14  from sliding upwards to the closed position. In some embodiments, piston fingers  19  can engage valve body groove  43  to lock piston  14  in place and to prevent piston  14  from sliding upwards to the closed position. 
         [0050]    After ball  41  has been placed, pressurized frac fluid can flow through ports  16  to hydraulically fracture production zone  164 . After production zone  164  has been fractured, ball  41  for the next valve sub  10  along tubing string  149  can be inserted in the tubing string so that the next valve sub  10  can be opened, and the next production zone  154  can be fractured. This process can be then be repeated for each successive valve sub  10  along tubing string  149  until production zone  162  has been fractured. 
         [0051]    Once the fracturing program for well  146  has been completed, the inner piston sub-assembly  13  in each valve sub  10  can be removed. Referring to  FIGS. 6 to 9 , one embodiment of inner piston removal tool  60  is shown. In some embodiments, removal tool  60  can comprise tubular upper body  62  and tubular lower body  64  disposed on the lower end of upper body  62  at junction  65 , defining a passageway from inlet  84  to outlet  88 . Lower body  64  can further comprise latch threads  68  configured to engage latching threads  50  disposed on upper inner piston  20 . In some embodiments, removal tool  60  can further comprise latching sleeve  70  disposed in upper body  62  as means to couple upper body  62  to lower body  64 . Latching sleeve  70  can be held in place inside upper body  62  by shear screws  76 . Lower body  64  can further comprise of plurality of latching fingers  78 , each have a head  80  at a distal end thereof. Latching fingers  78  can be further configured such that each  80  is biased inwardly towards each other. When removal tool  60  is assembled to couple upper body  62  to lower body  64 , latch sleeve  70  can urge latching fingers  78  outwardly such that heads  80  fit into groove  82  to positively couple upper body  62  to lower body  64 . Upper body  62  can further comprise box end  66  for coupling to coil tubing, which can be inserted into the tubing string (by coil tubing, which is not shown in the figure) to advance removal tool  60  from the surface to the first valve sub  10 . 
         [0052]    Referring to  FIG. 7 , removal tool  60  is shown being inserted into valve sub  10  wherein latching threads  68  can engage latching threads  50  of upper inner piston  20  until shoulder  69  contacts upper inner piston  20 . Once removal tool  60  engages upper inner piston  20 , the coil tubing (not shown) can be raised to lift removal tool  60  within valve sub  10 , as shown in  FIG. 8 . In some embodiments, with sufficient force, for example 1000 lbs, raising removal tool  60  will cause shear screws  56  to shear allowing both upper inner piston  20  and lower inner piston  24  to lift away from ball seat sub  36  until shoulder  32  on lower inner piston  24  contacts shoulder  34  of latching sleeve  26 . When this happens, upper inner piston  20  can rise relative to piston  14 , which can allow latching finger  28  to disengage from groove  29  and couple with catch  30  disposed on upper inner piston  20 . In addition, lower inner piston  24  can rise from ball seat sub  36  to now allow communication between ports  44  and passageway  7  and equalize the pressure of frac fluid above and below ball  41 . In other words, if lower inner piston  24  is pulled away from ball seat sub  36 , a bypass is opened through the ball seat allowing for fluid circulation either in forward or reverse. Once latching fingers  28  have pulled in from piston  14  and engage catch  30 , ball seat sub  36  and inner piston sub  13  can move unrestricted in passageway  7 . 
         [0053]    The coil tubing can then be lowered further, wherein removal tool  60  and inner piston sub  13  can be pushed further down tubing string  90  (as shown in  FIG. 9 ) until the next valve sub  10  is encountered. Threads  52  and shoulder  53  of ball seat sub  36  can be configured to engage threads  50  on upper inner piston  20  of the next valve sub, wherein the procedure to disengage inner piston sub  13  from piston  14  can be repeated for the next valve sub  10 . This procedure can then be repeated for each subsequent valve sub  10  until all of the inner piston subs  13  of all the valve subs  10  are stacked together and attached to removal tool  60 . Once all the inner piston subs  13  have been removed from the valve subs  10 , the coil tubing can be raised to bring all of the inner piston subs  13  to the surface. 
         [0054]    Some embodiments can be configured as a pull release to overcome difficulties of releasing in a horizontal section of well  146 . As would be understood by one skilled in the art, it can be easier to pull than push tubing string  90 , as coupled tubing or coil can lose weight in a horizontal section of well  146 . In addition, a pull release feature can eliminate the use of expensive fishing tools such as hydraulic accelerators, drill collars, hydraulic jars, and hydraulic bumper subs as would be known to one skilled in the art. In some embodiments, the pull release can allow for inner piston subs  13  to be removed from valve subs  10  with a low shear force, for example 500 lbs, with coil tubing. 
         [0055]    When all inner piston subs  13  have been removed, the inside diameter of each valve sub  10  can be substantially the same, which can allow for a higher flow rate of substances from the well through tubing string  90 . In addition, when all inner piston subs  13 , balls  41  and ball seats  40  have been removed, the inside diameter of each valve sub  10  can be full-drift and allow for regular tools to run in the well bore for isolation testing or work-overs. 
         [0056]    In the event that removal tool  60  or any of the removed inner piston subs  13  become stuck in the tubing string, upper body  62  of removal tool  60  can be separated from lower body  64  by inserting a ball (not shown) into the coil tubing until it seats on ball seat  74  to close off passageway  74  (as shown in  FIG. 6 ) and injecting pressurized fluid into the coil tubing to exert downward force on latching sleeve  70  until screws  76  shear wherein latching sleeve  70  can slide downwardly in passageways  63  and  67  and allow heads  80  of latching fingers  78  to disengage groove  82 , whereupon upper body  62  can be pulled away from lower body  64 . Conventional removal tools, as well known to those skilled in the art, can then be inserted in the tubing string to remove the remainder of removal tool  60  and removed inner piston subs  13 . 
         [0057]    Following the removal of removal tool  60 , ball seat  40 , and inner piston sub  13 , an operator can then shift valves  10  to a closed position and well  146  can be ready for production. Fracture valve sub  10  can be allowed to shift closed with a conventional shifting tool, as well known to those skilled in the art, after removal tool  60 , ball seat  40 , and inner piston sub  13  have been removed. The shifting tool can allow for a locking of the piston  14  in a closed position in the absence of shear pins  54 . In some embodiments, piston fingers  19  can engage profile gap  45  on interior of valve body  12  in order to relock shifted piston  14  into a closed position, so that valve  10  may be reused. 
         [0058]    Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications might be made without departing from the scope of the invention. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof, it being recognized that the invention is defined and limited only by the claims that follow.