Abstract:
An apparatus and method is provided for fracturing a well in a a hydrocarbon bearing formation. The apparatus can include a valve subassembly that is assembled with sections of casing pipe to form a well casing for the well. The valve subassembly includes a sliding piston that is pinned in place to seal off ports that provide communication between the interior of the well casing and a production zone of the formation. A dart can be inserted into the well casing and propelled by pressurized fracturing fluid until the dart reaches the valve subassembly to plug off the well casing below the valve subassembly. The force of the fracturing fluid against the dart forces the piston downwards to shear off the pins and open the ports. The fracturing fluid can then exit the ports to fracture the production zone of the formation.

Description:
PRIORITY 
       [0001]    This application claims priority of U.S. Provisional Patent Application No. 61/328,770 filed Apr. 28, 2010 and U.S. Provisional Patent Application No. 61/376,364 filed Aug. 24, 2010 and hereby incorporates the same provisional applications by reference herein in their 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 in well casing that can be opened once the well casing has been cemented into place. These valve subassemblies or “subs” can use a ball valve seat mechanism that can receive a ball placed into the casing. 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 casing 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 casing 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 place in the casing string. In this manner, the further valve sub, the one having the smallest diameter opening can be closed by placing the matching sized ball into the casing, 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. 
         [0004]    One shortcoming of these known ball valve seat mechanisms is that they cannot be cemented into place with a casing string, as there is no way to clean or wipe the cement out of the valve seat mechanisms. These mechanisms have to be run on a liner with open hole packers in a well bore, which is more costly to carry out. 
         [0005]    Another shortcoming 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 well. 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, for example, a flow rate of 15 cubic metres per minute cannot be obtained through these valve subs. 
         [0006]    It is, therefore, desirable to provide a fracturing valve sub that overcomes the shortcomings of the prior art. 
       SUMMARY 
       [0007]    An apparatus and method for fracturing a well is provided. In one embodiment, the apparatus comprises a valve subassembly that is further comprised of a tubular valve body having upper and lower ends, the valve body comprising at least one port extending through a sidewall thereof nearer the upper end. In some embodiments, the cross-sectional area of the port or ports can be equal to the cross-sectional area of valve body inside diameter. In so doing, the apparatus can allow produced fluids to enter into the apparatus at or near the same rate of flow that the fluids can pass through the apparatus. The apparatus can further comprise a tubular piston slidably disposed within the valve body. The piston can move from a closed position where the at least port is closed to an open position where the at least one port is open. The apparatus can further comprise one or more shear pins disposed between the piston and the valve body to hold the piston in the closed position. When sufficient force is placed on the piston, the shear pins can shear away to allow the piston to move from the closed position to the open position. 
         [0008]    The apparatus can also comprise a tubular sleeve disposed within the piston. The sleeve or the piston can comprise grooves disposed on an interior side wall thereof extending from an upper end to a lower end thereof. The grooves can be configured to receive a dart configured to engage the sleeve or the piston so as to close off the passageway extending through the apparatus and to apply downward force against the sleeve that, in turn, places the downward force on the piston to move from the closed to open position. 
         [0009]    In operation, an apparatus can be placed in a casing string near a production zone in a well. In other embodiments, a plurality of the apparatuses can be placed at predetermined locations along the casing string to enable the fracturing of the well at a plurality of production zones disposed therein. The grooves disposed on the sleeve or the piston can be configured to allow keys disposed on a dart to either pass through the sleeve or piston, or to engage the sleeve or piston so at to open that particular apparatus. When a plurality of apparatuses are used in casing string, the apparatus nearest the top of the well can comprise sleeve grooves that are wider than the sleeve grooves of the next apparatus placed further down the casing string. Accordingly, each successive apparatus can comprise sleeve grooves narrower than the preceding apparatus. Therefore, the apparatus at the end of the casing string will have the narrowest sleeve grooves of all the apparatuses disposed in the casing string. Thus, when the dart for the last apparatus, that is, the dart with the narrowest keys, is inserted into the casing string and moved along by the pressurized fracturing fluid injected into the well following the dart, the keys of that dart can pass through the sleeve grooves of each apparatus that precedes the last apparatus. When this dart reaches the last apparatus, the dart keys can engage the sleeve grooves and hold the dart in place. The pressurized fracturing fluid contacts dart cups disposed on an upper end of the dart to apply downward force on the cups to engage the sleeve to thereby move the piston to the open position. Once the piston is in the open position, the pressurized fracturing fluid can pass through the valve port(s), breaking the casing cement to provide a path to the formation and then fracture the formation so as to allow produced fluids enter into the casing string through valve ports. As the dart keys can provide means to simply hold the dart in place against its corresponding sleeve until the pressurized fracturing fluid can contact the dart cups and, hence, the sleeve and piston, finer graduations in dart key width and corresponding sleeve groove width can be implemented. In so doing, the inventor believes that the number of apparatuses used in a single casing string can be in the range of 16 to 30 or more. In addition to this, the sleeve of each apparatus can have the same inside diameter from the first apparatus to the last apparatus in the casing string to thereby enable the same volume and flow rate of produced fluids through each apparatus as opposed to prior art devices. 
         [0010]    In some embodiments, each apparatus can comprise a corresponding dart with keys configured to only engage the sleeve or piston grooves of that apparatus. The grooves of the apparatus can be configured into particular profiles that will only match a corresponding profile on a matching dart. As such, a dart can pass through an apparatus where the profile do not match. Matching profiles will allow the dart to lock into the grooves and the pressurized fracturing fluid contacts dart cup disposed on an upper end of the dart to apply downward force on the cup to engage the piston to thereby move the piston to the open position. 
         [0011]    Broadly stated, in some embodiments, an apparatus is provided for fracturing a well, comprising: a tubular valve body comprising upper and lower ends defining communication therebetween, the valve body further comprising at least one port extending through a sidewall thereof nearer the upper end; a tubular piston slidably disposed in the valve body and configured to provide communication therethrough, the piston closing the at least one port in a closed position, the piston opening the at least one port in an open position; means for moving the piston from the closed position to the open position when a downward force is placed on the piston; and a tubular end cap disposed on the lower end of the valve body, the end cap configured to stop the piston when the piston moves from the closed position to the open position. 
         [0012]    Broadly stated, in some embodiments, the apparatus further comprises a dart comprising a longitudinal shaft comprising upper and lower ends, the lower end comprising a key, the key configured to engage the grooves disposed in the moving means, the upper end comprising at least one dart cup configured to seal off communication through the piston when the key has engaged the grooves. 
         [0013]    In some embodiments, a method is provided for fracturing a well in a formation, the method comprising the steps of: providing a valve sub apparatus and placing the apparatus in a casing string disposed in the well, the apparatus located near a production zone in the formation; placing a dart into the casing string; and injecting pressurized fracturing fluid into the casing string wherein the fracturing fluid moves the dart through the casing string into the apparatus until the keys of the dart engage the sleeve to place a downward force on the sleeve to move the piston from the closed position to the open position wherein the fracturing fluid can pass through the at least one port of the apparatus to fracture the formation. 
         [0014]    Broadly stated, in some embodiments, a system of darts and keys for use downhole in a well is provided, the system comprising: at least one apparatus, the apparatus comprising: a tubular valve body comprising upper and lower ends defining communication therebetween, the valve body further comprising at least one port extending through a sidewall thereof nearer the upper end; a tubular piston slidably disposed in the valve body and configured to provide communication therethrough, the piston closing the at least one port in a closed position, the piston opening the at least one port in an open position; means for moving the piston from the closed position to the open position when a downward force is placed on the piston; a tubular end cap disposed on the lower end of the valve body, the end cap configured to stop the piston when the piston moves from the closed position to the open position; and at least one dart comprising a longitudinal shaft comprising upper and lower ends, the lower end comprising a key, the key configured to engage the grooves disposed in the moving means, the upper end comprising at least one dart cup configured to seal off communication through the piston when the key has engaged the grooves, where the dart key is configured to specifically engage the moving means of a particular apparatus and the key can be targeted to the particular apparatus. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0015]      FIG. 1  is a side cross-sectional elevation view depicting a fracturing valve subassembly. 
           [0016]      FIG. 2  is a side cross-sectional elevation view depicting the body of the valve subassembly of  FIG. 1 . 
           [0017]      FIG. 3  is a side cross-sectional elevation view depicting the end cap of the valve subassembly of  FIG. 1 . 
           [0018]      FIG. 4  is a side cross-sectional elevation view depicting the piston of the valve subassembly of  FIG. 1 . 
           [0019]      FIG. 5  is a top plan view depicting the sleeve of the valve subassembly of  FIG. 1 . 
           [0020]      FIG. 6  is a side cross-sectional elevation view along section lines A-A depicting the sleeve of  FIG. 5 . 
           [0021]      FIG. 7  is a side elevation view depicting the dart of the valve subassembly of  FIG. 1 . 
           [0022]      FIG. 8  is a front elevation view depicting an embodiment of the dart of  FIG. 7 . 
           [0023]      FIG. 9  is a front elevation view depicting an alternate embodiment of the key of the dart of  FIG. 7 . 
           [0024]      FIG. 10  is a side cross-sectional view depicting a well in a formation with a plurality of the valve subassemblies of  FIG. 1 . 
           [0025]      FIG. 11  is a perspective cut-away view depicting a further embodiment of a fracturing valve subassembly in a closed position. 
           [0026]      FIG. 12A  is a side cross-sectional elevation view depicting the fracturing valve subassembly of  FIG. 11  in a closed position. 
           [0027]      FIG. 12B  is a side cross-sectional elevation view depicting the fracturing valve subassembly of  FIG. 11  in an open position. 
           [0028]      FIG. 13  is a perspective view depicting an embodiment of the dart of the valve subassembly of  FIG. 11 . 
           [0029]      FIG. 14  is a close-up side cross-sectional elevation view depicting the fracturing valve subassembly of  FIG. 12A  and a dart. 
           [0030]      FIGS. 15A-15D  are close-up side cross-sectional elevation view depicting possible embodiments of key profiles for the fracturing valve subassembly of  FIG. 12A  and the corresponding key profiles of the darts. 
       
    
    
     DETAILED DESCRIPTION OF EMBODIMENTS 
       [0031]    Referring to  FIGS. 1 to 6 , an embodiment of fracturing valve sub  10  is shown. The major components of valve sub  10  comprise valve body  12 , end cap  16  disposed on a lower end of body  12 , tubular piston  20  slidably disposed within body  12  and tubular sleeve disposed within piston  20 . When assembled, piston  20  is held position within body  12  by shear pins  25  disposed in holes  24 . Each valve sub  10  can further comprise a dart  22  that corresponds to a particular valve sub  10 . 
         [0032]    Referring to  FIG. 2 , one embodiment of valve body  12  is shown in more detail. In the illustrated embodiment, body  12  can comprise ports  14  extending through the sidewall of body  12  nearer the upper end thereof. Ports  14  provide a means for pressurized fracturing fluid to pass through and fracture a production zone of a formation. In a representative embodiment, the total cross-sectional area of ports  14  can be approximately equal to the cross-sectional area of the inside diameter of valve sub  10  itself such that there is little or no flow restriction of fluids passing through ports  14  in or out of valve sub  10 . In one embodiment, body  12  can comprises holes  24  disposed below ports  14  for receiving shear pin  25 , as shown in  FIG. 1 . In another embodiment, body  12  can comprise ratchet threads  26  disposed on the interior surface thereof. In a further embodiment, body  12  can comprise threads  27  disposed at a lower thereof for releasably coupling to end cap  16 , as shown in  FIG. 1 . 
         [0033]    Referring to  FIG. 3 , one embodiment of end cap  16  is shown in more detail. End cap  16  can comprise threads  17  disposed on an upper end therefor for releasably coupling with threads  27  disposed on body  12 . In another embodiment, end cap  16  can comprise cogs  28  disposed on its upper end for engaging with piston  20 , as described in more detail below. 
         [0034]    Referring to  FIG. 4 , one embodiment of piston  20  is shown in more detail. As shown, piston  20  can comprise a tubular member further comprising one or more seal grooves  34  disposed along the length of piston  20 , the grooves extending circumferentially around piston  20 . Seal grooves  34  can be configured to receive o-rings or any other suitable sealing member as well known to those skilled in the art. In the illustrated embodiment, two seal grooves  34  are disposed at an upper end of piston  20  whereas another pair of seal grooves  34  can be disposed nearer the middle of piston and a single seal groove  34  disposed near the lower end of piston  20 . In one embodiment, piston  20  can comprise shoulder  21  disposed on the interior surface thereof for retaining sleeve  18  in position, as shown in  FIG. 1 . Piston  20  can further comprise holes  36  disposed on the exterior surface thereof to receive shear pins  25 , as shown in  FIG. 1 . In another embodiment, piston  20  can comprise ratchet ring  38  disposed around the lower end thereof, which is configured to engage ratchet threads  26  disposed on the interior surface of body  12 . In a further embodiment, piston  20  can comprise cogs  40  disposed on the lower end thereof, cogs  40  being configured to engage cogs  28  on end cap  16 . 
         [0035]    Referring to  FIGS. 5 and 6 , an embodiment of sleeve  18  is shown. In this embodiment, sleeve  18  can be comprised of a tubular member comprising peaks  30  disposed on one end thereof, and keyways  32  extending therethrough on an interior surface thereof. As shown in  FIG. 1 , sleeve  18  is disposed within piston  20  sitting on shoulder  21 . 
         [0036]    Referring to  FIGS. 7 and 8 , an embodiment of dart  22  is shown. Dart  22  can comprise of shaft  23 , one or more dart cups  44  disposed on the upper end thereof and one or more keys  42  disposed nearer the lower end thereof, keys extending substantially perpendicular to shaft  23 . Dart cups  44  can be circular in configuration, when viewed from the top, or of any other configuration such that darts cups  44  can substantially contact the interior surface of piston  20  when pressurized fracturing fluid is injected into the well. In this embodiment, keys  42  can comprise an oval cross-sectional shape. In another embodiment, keys  42  can comprise a keystone shape, as shown in  FIG. 9 . In some embodiments, dart  22  can be comprised of rubber, metal, a combination of rubber and material or any other suitable material, or other combinations thereof, as well known to those skilled in the art. 
         [0037]    Referring to  FIG. 10 , a cross-sectional view of a horizontal well comprising the apparatus described herein is shown. In this example, well  46  in formation  48  comprises well casing  49  comprising a plurality of valve subs  10  displaced along well  46 . In installing liner  49 , float shoe  50  can be run into well  46  where float shoe  50  comprises a float collar, a cement stage collar with a latching wiper plug and a hydraulic burst sub, as well known to those skilled in the art, followed by a section of casing, then followed by a valve sub  10 . This is then followed by another section of casing and another valve sub  10 , and so on. The number of valve subs  10  and the spacing between the valve subs to be determined by the size of formation  48  and the number of production zones  54  contained in formation  48 . Once well casing  49  is in place in well  46 , well casing  49  can be cemented in place. A wiper dart can then be pumped into well casing  49  with flush cleaning fluid to clean all valve subs  10  and keyways  32  contained in each valve sub  10 . 
         [0038]    After well casing  49  has been set in well  46  and pressure tested, well casing  49  is then ready for stimulation. In other embodiments, the apparatuses and methods described herein can also be used with conventional open-hole packers and liner packers. 
         [0039]    To stimulate well casing  49 , pressurized fracturing fluid can be injected into well casing  49  until the pressure of the fluid in well casing  49  reaches the burst pressure of the burst sub. Once the burst sub opens, the dart  22  for the valve sub  10  located at the end of well casing  49  can be inserted into well casing  49 . As described above, each valve sub  10  has a corresponding dart  22 , wherein the keys  42  of a particular dart  22  will only engage the keyways  32  of its corresponding valve sub  10 . The keys  42  of the valve sub  10  at the end of well  46  being the narrowest, with the keys  42  becoming progressively wider with each successive valve sub  10  disposed in well casing  49  towards the top of well  46 . 
         [0040]    When the first dart  22  is pumped into well casing  49  with the pressurized fracturing fluid, the dart will encounter the first valve sub  10  with the keys  42  of the dart contacting sleeve  18  of that valve sub. Peaks  30  on the sleeve serve to turn keys  42  either clockwise or counterclockwise thereby guiding keys  42  through keyways  32 . As keyways  32  of each valve sub  10  are wider than the keyways of the valve sub  10  located at the end of well  46 , keys  42  of the first dart  22  will pass through the first valve sub  10  and each successive valve sub  10  until the first dart  22  reaches the last valve sub  10  where keys  42  land into and engage the keyways  32  of the last valve sub  10 . In so doing, the pressurized fracturing fluid causes the dart cups  44  to seat in piston  20  of valve sub  10  and cause a high-pressure seal. As noted above, dart cups  44  can comprise a circular shape to seal against piston  20 . In other embodiments, dart cups  44  can comprise any other shape that are configured to function equivalently to seal against piston  20 . 
         [0041]    Once dart cups  44  are sealed against piston  20 , the hydraulic force of the pressurized fracturing fluid applies a downward force on piston  20  until the force exceed the shear force rating of shear pins  25  such that shear pins  25  shear thereby allowing piston  20  slide downwards from a closed position, where ports  14  are sealed off, to an open position where ports  14  are revealed. As piston  20  moves to the open position, ratchet ring  38  can engage ratchet threads  26  to lock piston  20  in place and to prevent piston  20  from sliding upwards to the closed position. In another embodiment, cogs  40  disposed on piston  20  can engage cogs  28  disposed on end cap  16  to prevent piston  20  from rotating within body  12  once in the open position. 
         [0042]    Once dart  22  is in place in piston  20 , dart  22  plugs well casing  49  below valve sub  10  thereby directing fluid to flow through ports  14  to fracture cement casing  52  and production zone  54  in formation  48 . As all valve subs  10  have the same inside diameter, there is no restriction of flow throughout well casing  49 . Because the valve subs have the same inside diameter throughout the casing string, the valve subs  10  can be used on liners with open hole packers or it can be incorporated into a casing string that can be cemented into a well bore, as well known to those skilled in the art, unlike the prior art devices that can only be used on liners with open hole packers. Accordingly, using the valve subs  10  on a casing string that can be cemented in place can reduce the cost of producing substances from the well. In addition, because the valve subs  10  all have the same inside diameter, this can allow a fracturing operator to pump fluid and sand down well casing  49  at higher rates (for example, 15 cubic metres per minute) without any friction pressure or pressure drops that would otherwise exist using prior art devices due to restrictions arising from the narrow internal diameters of the prior art devices. After the first dart  22  has been placed to fracture the first production zone  54 , the dart  22  for the next valve sub  10  along well casing  49  can be placed to fracture the next production zone  54 . This process can be then be repeated for each successive valve sub  10  along well casing  49 . Fracturing at high fluid rates can now be a continuous process by pumping a dart to open each valve, which can dramatically reduce the fracturing time for each interval, that is, for each valve sub  10 . 
         [0043]    Once the fracturing program for well  46  has been completed, coil tubing or conventional tubing can be run into well casing  49  with a mud motor and mill. An operator can then circulate fluid to the first valve sub  10  and set 1000 daN of string weight, as an example, so that the mill can grind up the dart  22  in the valve sub. In so doing, the operator will notice rubber and metal cuttings at a flow back tank based on the calculated fluid volumes per the depth of each valve sub  10 . After a few minutes, the mill will cut the dart and its keys into tiny pieces and move through the valve sub. The operator can then pull the mill up back through the valve sub, and then run back through the valve sub to ensure full drift inner diameter. The operator can then continue on to the next valve sub  10  and dart  22 . This process can be repeated until all darts  22  have been drilled out of the valve subs  10 . The operator can then pull the mill to the surface and well  46  will be ready for production. 
         [0044]    Referring to  FIG. 11 , in some embodiments, fracture valve sub  10  can comprise a valve body  12  and piston  20  without sleeve  18 . In some embodiments, circumferential grooves disposed along the inner wall of piston  20  can comprise key profile  54 . Key profile  54  can further comprise locking shoulder  56 .  FIG. 12A  shows an embodiment of fracture valve sub  10  in a closed position.  FIG. 12B  shows an embodiment of fracture valve sub  10  in an open position. 
         [0045]    Referring to  FIG. 13 , an embodiment of dart  22  with a dart profile  58  is shown. In some embodiments, more than one dart profile  58  can be disposed around the exterior circumference of dart  22 . 
         [0046]    Referring to  FIG. 14 , in some embodiments, key profile  54  can be mirrored by dart profile  58  on dart  22 . In some embodiments, dart  22  can comprise biasing means to bias dart profile  58  towards the inner wall of piston  20  to engage key profile  54  and lock on locking shoulder  56  when dart profile  58  matches key profile  54 . In some embodiments, biasing means can comprise spring  60 , although it would be understood and appreciated by a person skilled in the art that any biasing means performing the same equivalent function can be used in place of, or in combination with, spring  60 . 
         [0047]    Referring to  FIGS. 15A ,  15 B,  15 C,  15 D, some embodiments of possible key profile  54  and dart profile  58  configurations are shown. It would be apparent to one skilled in the art that any shape or pattern of key or dart profile that can interlock and perform the same function can be used. It is contemplated by the inventor, and would be apparent to one skilled in the art, that this system of key and dart profiles can have a wide range of application. For example, the system can be used for pump-down bridge plugs for isolating intervals, or multiple acidizing tools or plugs. 
         [0048]    In operation of the embodiments of fracture valve  10  depicted in  FIGS. 11-15 , a dart  22  can travel through casing  49  until is reaches a matching key profile  54 , and can latch into piston  20 , locking at shoulder  56 . The top of dart cup  44  on dart  22  can form a seal within valve body  12 . As noted above, dart cups  44  can comprise a circular shape to seal against piston  20 . In other embodiments, dart cups  44  can comprise any other shape that are configured to function equivalently to seal against piston  20 . This seal can create a hydraulic pressure on locked dart  22  and piston  20 . With a seal formed, shear pins  25  can shear under the pressure and piston  20  will be allowed to travel with the dart  22  into an open position, for example, as shown  FIG. 12B . As piston  20  travels down well, it can either ratchet with a ring and a ratchet thread to remain in an open position as described above, or it can latch with a set of latching fingers  62  into the open position. Once fracture valve sub  10  is in an open position, ports  14  can be open to allow fracturing fluid to be released. This system can allow for a full fracturing diameter to the well surface during the fracturing operation. 
         [0049]    As described above, each valve sub  10  can have a corresponding dart  22 . The dart profile  58  of a particular dart  22  will only engage the key profile  54  of its corresponding valve sub  10 . As depicted in  FIGS. 10 ,  15 A,  15 B,  15 C, and  15 D, sets of fracture valve subs  10  and sets of darts  22  can be used where key profile  54  and dart profile  58  are varied such that shoulder  56  is located in different positions in each key profile  54 . 
         [0050]    When the first dart  22  is pumped into well casing  49  with the pressurized fracturing fluid, the dart can encounter the first valve sub  10  with dart profile  58  contacting key profile  54 . If the profiles do not match, the dart  22  will not lock and it will progress down well until it meet a valve sub  10  with a key profile  54  that is complimentary to the dart profile  58  of that particular dart  22 . 
         [0051]    After the first dart  22  has opened first valve sub  10  to fracture the first production zone  54 , the dart  22  for the next valve sub  10  along well casing  49  can be placed to fracture the next production zone  54 . This process can be then be repeated for each successive valve sub  10  along well casing  49 . Fracturing at high fluid rates can now be a continuous process by pumping a dart to open each valve, which can dramatically reduce the fracturing time for each interval, that is, for each valve sub  10 . 
         [0052]    In some embodiments, once the fracturing program for well  46  has been completed, conventional removal tools, as well known to those skilled in the art, can then be inserted in the tubing string to retrieve any darts. Darts  22  can be retrieved individually, in groups, or all at once. In some embodiments, dart  22  can comprise a latch (not shown) disposed at its lower end so that it can contact and connect with a further downstream dart. Latched darts can then be pulled to surface together. In some embodiments, dart  22  can comprise bypass outlets disposed on shaft  23  to assist in breaking any seal that was created by cup  44  and facilitate the removal of dart  22 . The removal of the darts  22  can then allow for a full drift inner diameter of the well. In some embodiments, removed darts  22  can be reused to open closed valve subs  10 . 
         [0053]    Following the removal of dart  22 , an operator can then shift valves  10  to a closed position and well  46  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 dart  22  has been removed. The shifting tool can allow for a locking of the piston  20  in a closed position in the absence of the shear pin. In some embodiments, fingers  62  can engage profile gap  64  on interior of valve body  12  in order to relock shifted piston  20  into a closed position, so that valve  10  may be reused. 
         [0054]    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.