Abstract:
A receptacle sub that increases the venting flowrate during retrieval of a running tool. The sub includes a sleeve with a bypass port in a central bore defined by a tubular body. The sleeve is selectively moveable from an upper position to a lower position. A seal on the sleeve seals the sleeve to the bore while a retainer holds the sleeve in the upper position. A bypass passage in the body is in fluid communication with the bypass port. A drop member lands on the sleeve, blocking downward flow through the sleeve and actuating a hydraulic function. The drop member receives a fluid pressure greater than the hydraulic function fluid pressure, releasing the retainer to move the sleeve to the lower position. This allows fluid communication from above the central bore through the bypass passage and through the bypass ports of the sleeve below the drop member.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates in general to drop balls, plugs, or darts used to operate running well tool functions and, in particular, to a bypass sleeve with a dart landing shoulder to variably allow fluid flow past the drop member following tool operation. 
     2. Brief Description of Related Art 
     Darts, drop balls, or plugs are often used to actuate hydraulic devices within a wellhead or wellbore during well drilling and completion. Typically, a running tool is run to a predetermined location in a wellhead. A drop ball is then dropped into the running string supporting the running tool and pumped down to land at a shoulder within or axially below the running tool. Fluid pressure behind the drop ball is then increased until the fluid pressure reaches a level sufficient to actuate the hydraulic functionality of the running tool. The running tool may then be retrieved from the wellbore. This may be accomplished in a wet retrieval process. In a wet retrieval process, the running tool is pulled without first removing the column of fluid resting on the drop ball. This requires a tremendous expenditure of energy, and due to the significant weight of water being pulled, it is incredibly time consuming. In addition, the amount of water introduced into the deck level of the drilling rig can cause a significant safety problem to operators and workers located on the working deck. 
     Some devices may be pulled in a dry retrieval process. These devices include fluid ports that allow communication from the central passageway of the running tool to the wellbore. The fluid ports remain open during the operation of the running tool; thus, the fluid ports must be small enough to allow fluid pressure to build up behind the ball or dart despite the open fluid communication between the central passage of the running tool and the wellbore. When the device is retrieved, the fluid behind the dart will flow through the fluid ports into the wellbore. This eliminates the safety risk of the wet retrieval process by allowing the column of fluid blocked by the dart to drain past the dart during retrieval. However, this dry retrieval process is still incredibly time consuming as the process must be conducted slowly enough to allow the fluid to drain through the fluid ports without needlessly introducing fluid onto the platform deck. 
     One attempt to overcome this problem has been to include a burst disc in the dart to allow for faster draining of the drill string. However, because the burst disc must fit within the dart, it is, by necessity, smaller than the diameter of the fluid column above it. Therefore, while it does provide a faster drainage process than the previously described fluid ports, the burst disc still restricts flow and cannot maintain a large enough flowrate to drain as fast as the drill string can be pulled. Thus, there is a need for an apparatus to allow for a dry retrieval process that will decrease the time to retrieve the running tool, thereby decreasing the rig time needed and the cost associated with operation of the rig. 
     SUMMARY OF THE INVENTION 
     These and other problems are generally solved or circumvented, and technical advantages are generally achieved, by preferred embodiments of the present invention that provide a receptacle sub, and a method for using the same. 
     In accordance with an embodiment of the present invention, a well tool is disclosed. The well tool includes a tubular body adapted to be connected to and lowered on a running tool string into a well conduit. The tubular body defines a central bore having an axis. The well tool also includes a sleeve in the central bore that is selectively moveable from an upper position to a lower position. The sleeve has at least one bypass port extending from an exterior to an interior of the sleeve. At least one retainer secures the sleeve in the upper position relative to the tubular body. The well tool includes a seal on the sleeve that seals the exterior of the sleeve to the bore while the sleeve is in the upper position, and a bypass passage in the body having an upper inlet portion and a lower outlet portion in fluid communication with the bypass ports. The well tool includes a drop member adapted to be lowered through the running tool string and to land on the sleeve. The drop member is adapted to be lowered through the running tool string and land on the sleeve. When the drop member is located in the sleeve, and the sleeve is in the upper position, the inlet portion of the bypass passage is blocked from fluid communication with the central bore. The retainer is adapted to selectively release the sleeve so that the sleeve moves downward to the lower position. When the sleeve is in the lower position, the bypass passage is in fluid communication with the bore and allows fluid communication from above the central bore through the bypass passage via the bypass ports of the sleeve. 
     In accordance with another embodiment of the present invention, a well tool assembly is disclosed. The well tool assembly includes a running tool adapted to be coupled to a running string and having at least one hydraulically actuated function. The assembly further includes a receptacle sub coupled to a lower end of the running tool so that when a drop member is landed in the receptacle sub, fluid flow through the receptacle sub is blocked and the hydraulically actuated function will actuate. The receptacle sub has a bypass passage that is opened in response to increased fluid pressure after the function is performed, the bypass passage extends below the drop member and has a cross-sectional flow area that is at least equal to a flow area cross section through a central passage of the running tool. 
     In accordance with yet another embodiment of the present invention, a method for operating a running tool is disclosed. The method begins by providing a well tool assembly. The well tool assembly includes a running tool adapted to be coupled to a running string and having at least one hydraulically actuated function, and a receptacle sub coupled to a lower end of the running tool. The method continues by dropping a drop member in the running string to land in the receptacle sub in an upper position, thereby blocking fluid flow through the receptacle sub. The method continues by supplying fluid pressure to the running tool at a first pressure to actuate the running tool to perform a function. Then, the method supplies fluid pressure to the running tool at a second pressure, greater than the first pressure, to drive the receptacle sub to a lower position, thereby opening a fluid flow bypass around the drop member. 
     In still another embodiment of the present invention, a system for setting an annular seal between a casing hanger and a wellhead is disclosed. The system includes a running tool and a receptacle sub. The running tool is adapted to be coupled to a running string and carries an annular seal for disposal between the casing hanger and the wellhead. The receptacle sub is coupled to a lower end of the running tool so that when a drop member is landed in the receptacle sub, fluid flow through the receptacle sub is blocked. The annular seal will energize in response to a resulting increased fluid pressure caused by the blocked receptacle sub, thereby sealing an annulus between the wellhead and the casing hanger. The receptacle sub includes a bypass passage that is opened in response to increased fluid pressure after the seal is energized. The bypass passage extends below the drop member and has a cross-sectional flow area that is at least equal to a flow area cross section through a central passage of the running tool so that the running tool may be pulled to the surface. 
     An advantage of a preferred embodiment is that it provides an apparatus for the actuation of a hydraulically actuated running tool with a dart or drop ball. The running tool may then drain the column of fluid blocked by the dart or drop ball at an increased rate to speed the process of running tool retrieval following tool actuation. This reduces the rig time needed to drill and complete the well. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the features, advantages and objects of the invention, as well as others which will become apparent, are attained, and can be understood in more detail, more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof which are illustrated in the appended drawings that form a part of this specification. It is to be noted, however, that the drawings illustrate only a preferred embodiment of the invention and are therefore not to be considered limiting of its scope as the invention may admit to other equally effective embodiments. 
         FIG. 1  is sectional view of a receptacle sub in accordance with an embodiment of the present invention. 
         FIG. 2  is a sectional view of the receptacle sub of  FIG. 1  with a dart in place within the receptacle sub. 
         FIG. 3  is a sectional view of the receptacle sub of  FIG. 1  during draining of a drill string above the receptacle sub. 
         FIG. 4  is a sectional view of a high capacity running tool constructed with a piston cocked, an engagement element retracted, and the receptacle sub of  FIG. 1  coupled to a lower end. 
         FIG. 5  is a sectional view of the high capacity running tool of  FIG. 4  in a running position with the engagement element engaged. 
         FIG. 6  is a sectional view of the high capacity running tool of  FIG. 4  in a setting position. 
         FIG. 7  is a sectional view of the high capacity running tool of  FIG. 4  in a seal testing position. 
         FIG. 8  is a sectional view of the high capacity running tool of  FIG. 4  in an unlocked position with the engagement element disengaged. 
         FIG. 9  is a sectional view of the receptacle sub of  FIG. 1  being re-cocked for reuse. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention will now be described more fully hereinafter with reference to the accompanying drawings which illustrate embodiments of the invention. This invention may, however, be embodied in many different forms and should not be construed as limited to the illustrated embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Like numbers refer to like elements throughout, and the prime notation, if used, indicates similar elements in alternative embodiments. 
     In the following discussion, numerous specific details are set forth to provide a thorough understanding of the present invention. However, it will be obvious to those skilled in the art that the present invention may be practiced without such specific details. Additionally, for the most part, details concerning drilling rig operation, casing hanger landing and setting, and the like have been omitted inasmuch as such details are not considered necessary to obtain a complete understanding of the present invention, and are considered to be within the skills of persons skilled in the relevant art. 
     Referring to  FIG. 1 , a receptacle sub  11  includes a tubular sub body  13 . Tubular sub body  13  defines a central bore  15  for the passage of fluids. Central bore  15  has an axis  17 . Tubular sub body  13  also has an upper end  19  adapted to couple to a running tool ( FIG. 4 ), and a lower end  21  adapted to couple to a tubing string (not shown) such as by a threaded coupling connection. A person skilled in the art will understand that any suitable means may be used to couple lower end  21  to the tubing string. In the illustrated embodiment, upper end  19  has an exterior diameter greater than an exterior diameter of a main body  23  of tubular sub body  13 . A taper  25  transitions the exterior diameter of upper end  19  to the exterior diameter of main body  23 . 
     Central bore  15  further defines a bypass passage  27  and an upward facing shoulder  29 . In the illustrated embodiment, bypass passage  27  may be an annular recess formed in central bore  15 . A person skilled in the art will understand that bypass passage  27  may be any suitable fluid flow passage or passages and may comprise one or more separate passages. Bypass passage  27  is proximate to upper end  19  within central bore  15 , and upward facing shoulder  29  is proximate to lower end  21  within central bore  15 . Bypass passage  27  includes an upper inlet portion  26  and a lower inlet portion  28 . Main body  23  includes a plurality of windows  31  extending from the exterior surface of main body  23  into central bore  15 . 
     A bypass sleeve  33  is disposed within central bore  15 . Bypass sleeve  33  has an exterior diameter slightly smaller than central bore  15  such that bypass sleeve  33  may move axially within central bore  15 . Bypass sleeve  33  also defines a sleeve bore  34 . Bypass sleeve  33  includes an annular downward facing shoulder  35  on an exterior diameter portion of bypass sleeve  33 . Downward facing shoulder  35  extends from the exterior diameter surface of bypass sleeve  33  to a cylindrical protrusion  37 . Cylindrical protrusion  37  extends axially downward from a lower portion of bypass sleeve  33  into close engagement with the lower portion of central bore  15 . Bypass sleeve  33  includes upper and lower seals  36 . Upper and lower seals  36  are located axially above and below windows  31  such that bypass sleeve  33  will seal central bore  15  to prevent flow of fluid through windows  31 . As bypass sleeve  33  moves through central bore  15  from an upper position ( FIG. 1 ) to a lower position ( FIG. 3 ), upper and lower seals  36  will maintain sealing engagement with central bore  15 . 
     In the illustrated embodiment, bypass sleeve  33  includes a plurality of threaded bore holes  39 . At least one threaded bore hole  39  corresponds with each window  31 . A limiter screw  41 , is threaded into each threaded bore hole  39  through window  31 . When fully threaded into bore hole  39 , a head of each limiter screw  41  will protrude into window  31 . As bypass sleeve  33  moves axially within central bore  15 , the heads of each limiter screw  41  will move through window  31 , restraining movement of bypass sleeve  33  as the head of limiter screws  41  contact downward facing shoulder  43  of window  31  as shown in  FIG. 1 , and upward facing shoulder  45  of window  31  as shown in  FIG. 3 . Limiter screws  41  may also provide a visual indication of the location of bypass sleeve  33  within main body  23 . A person skilled in the art will understand that limiter screws  41  may comprise any suitable object that may provide a reactive force to limit axial movement of bypass sleeve  33  as described in more detail below. The stop limiters may comprise screws, pins, protrusions formed in bypass sleeve  33 , and the like. Similarly, windows  31  may comprise any suitable stop receptacle and have any suitable configuration such that a corresponding stop limiter my interact with the stop receptacle to limit axial movement of bypass sleeve  33 . 
     A shown in  FIG. 1 , cylindrical protrusion  37  has a length such that cylindrical protrusion  37  will extend past upward facing shoulder  29  of main body  23  when bypass sleeve  33  is in a position of maximum upward movement. In this manner, cylindrical protrusion  37  provides a mechanism to prevent landing of drop members, such as drop balls, darts, or plugs, on upward facing shoulder  29 . This will prevent unintentional blockage of central bore  15  and sleeve bore  34  prior to landing of a drop member in bypass sleeve  33  as described in more detail below. Preferably, a wall of cylindrical protrusion  37  is as thin as possible to maintain the maximum size of sleeve bore  34 . 
     A plurality of retainers, such as shear pins  47 , will extend through bores in the sidewall of main body  23  of tubular sub body  13 . The retainers may comprise any device suitable for preventing movement of bypass sleeve  33  relative to tubular sub body  13  prior to actuation of a corresponding running tool. For example, retainers may be shear pins  47 , shear screws, a split ring retainer, or the like. Shear pins  47  will protrude into corresponding bores in an exterior diameter surface of bypass sleeve  33 , thereby preventing axial movement of bypass sleeve  33  relative to main body  23  prior to shearing of shear pins  47 . In the illustrated embodiment, each shear pin  47  has a shear rating of 1,000 psi, and receptacle sub  11  may include one to twelve shear pins  47 . In this manner, receptacle sub  11  may be configured to operate at relatively low pressures, as little as 1,000 psi, to relatively high pressures, as high as 12,000 psi. A person skilled in the art will understand that shear pins of different strength ratings and of different numbers may be used to adapt receptacle sub  11  to any desired pressure of operation. 
     Referring to  FIG. 1 , an upper end of bypass sleeve  33  defines a plurality of bypass sleeve ports  49 . Bypass sleeve ports  49  extend from a first position on the exterior surface of bypass sleeve  33  to a second position on sleeve bore  34  axially beneath the first position such that bypass sleeve ports  49  extend axially downward at an angle from the exterior of bypass sleeve  33  to sleeve bore  34 . When in the upper position as shown in  FIG. 1 , upper surfaces of bypass sleeve ports  49  on the exterior diameter surface of bypass sleeve  33  correspond with an upper inlet portion  26  of bypass passage  27 , blocking flow through bypass passage  27 . When in the lower position as shown in  FIG. 3 , a lower surface of each bypass opening  49  will coincide with lower inlet portion  28  of bypass passage  27  such that fluid may flow unobstructed from bypass passage  27  into bypass sleeve ports  49 . A person skilled in the art will understand that bypass sleeve ports  49  may provide alternative flow paths and arrangements, such as horizontal flow paths. 
     As shown in  FIG. 1 , an upper end of bypass sleeve  33  includes a taper  51  from an exterior diameter surface of bypass sleeve  33  to sleeve bore  34  at the upper end of bypass sleeve  33 . Bypass sleeve  33  includes a seal  38  interposed between the exterior diameter surface of bypass sleeve  33  and central bore  15  axially above bypass passages  27 . When bypass sleeve  33  is in the maximum upward axial position shown in  FIG. 1 , the upper end of bypass sleeve  33  will block bypass passage  27 , and seal  38  will prevent flow of fluid between bypass sleeve  33 , central bore  15 , and through bypass passage  27 , thereby maintaining all fluid flow through sleeve bore  34 . As shown in  FIG. 3 , when bypass sleeve  33  is the maximum downward axial position, seal  38  is within bypass passage  27 . Thus, seal  38  will allow flow from above bypass sleeve  33  into bypass passage  27 , allowing fluid to flow from central bore  15  through bypass passage  27  and into sleeve bore  34 . Taper  51  provides a greater flow area from above bypass sleeve  33  into bypass passage  27  when bypass sleeve  33  is in the lower position of  FIG. 3 . 
     Central bore  34  defines a dart shoulder  53  proximate to the upper end of bypass sleeve  33 . Dart shoulder  53  may be an upward facing shoulder axially above bypass sleeve ports  49 , as shown. Preferably, a drop member (such as a dart  55  of  FIG. 2 , a drop ball, a plug, or the like) may land on dart shoulder  53 , blocking sleeve bore  34  while not inhibiting fluid flow through bypass ports  49 . 
     Referring now to  FIG. 2 , dart  55  is shown in place within bypass sleeve  33  after landing on dart shoulder  53 . As illustrated, dart  55  may have a tapered lower end  58 . Tapered lower end  58  will coincide with the angle of the upper surface of bypass ports  49  so as to not obstruct flow from opening  49  into bypass sleeve  33 . After landing of dart  55 , fluid will be pumped down a running string (not shown) axially above receptacle sub  11 . Dart  55  will prevent passage of the fluid down sleeve bore  34 , thus as fluid continues to pump into the tubing string, the pumping will increase the pressure on shear pins  47  maintaining the axial position of bypass sleeve  33  relative to main body  23 . Once a predetermined pressure is reached, shear pins  47  will shear, as shown in  FIG. 3 . Bypass sleeve  33  will then move axially downward to the position shown. The heads of limiter screws  41  will contact upward facing shoulders  45  of windows  31 , and downward facing shoulder  35  may land on and abut upward facing shoulder  29 . When bypass sleeve  33  reaches the maximum downward axial position shown in  FIG. 3 , fluid axially above dart  55  will then flow through bypass passage  27  and into central bore  34 . 
     Referring to  FIG. 4 , there is generally shown an embodiment for a high capacity running tool  57  that is used to set and internally test a casing hanger packoff. High capacity running tool  57  is comprised of a stem  59 . Stem  59  is a tubular member with an axial passage  61  extending therethrough. Stem  59  connects on its upper end to a string of drill pipe (not shown). Stem  59  has an upper stem port  63  and a lower stem port  65  positioned in and extending therethrough that allow fluid communication between the exterior and axial passage of stem  59 . A lower portion of stem  59  has threads  67  in its outer surface. The outer diameter of an upper portion of stem  59  is greater than the outer diameter of the lower portion of stem  59  containing threads  67 . As such, a downward facing shoulder  69  is positioned adjacent threads  67 . A recessed pocket  71  is positioned in the outer surface of stem  59  at a select distance above downward facing shoulder  69 . 
     High capacity running tool  57  has a body  73  that surrounds stem  59 , as stem  59  extends axially through body  73 . Body  73  has an upper body portion  75  and a lower body portion  77 . Upper portion  75  of body  73  is a thin sleeve located between an outer sleeve  79  and stem  59 . Outer sleeve  79  is rigidly attached to stem  59 . A latch device (not shown) is housed in a slot  81  located within outer sleeve  79 . Lower body portion  77  of body  73  has threads  83  along its inner surface that are engaged with threads  67  on the outer surface of stem  59 . Body  73  has an upper; body port  85  and a lower body port  87  positioned in and extending therethrough that allow fluid communication between the exterior and interior of the stem body  73 . Lower body portion  77  of body  73  houses an engaging element  89 . In this particular embodiment, engaging element  89  is a set of dogs having a smooth inner surface and a contoured outer surface. The contoured outer surface is adapted to engage a complimentary contoured surface on the inner surface of a casing hanger  91  when engaging element  89  is engaged with casing hanger  91 . Although not shown, a string of casing is attached to the lower end of casing hanger  91 . The inner surface of engaging element  89  is initially in contact with threads  67  on the inner surface of stem  59 . 
     A piston  93  surrounds stem  59  and substantial portions of body  73 . Referring to  FIG. 6 , a piston chamber  95  is formed between upper body portion  75 , outer sleeve  79 , and piston  93 . Piston  93  is initially in an upper or “cocked” position relative to stem  59 , meaning that the area of piston chamber  95  is at its smallest possible value, allowing for piston  93  to be driven downward. A piston locking ring  97  extends around the outer peripheries of the inner surface of piston  93 . Piston locking ring  97  works in conjunction with the latch device (not shown) contained within outer sleeve slot  81  to restrict movement of the piston during certain running tool functions. A casing hanger packoff seal  99  is carried by piston  93  and is positioned along the lower end portion of piston  93 . Casing hanger packoff seal  99  will act to seal casing hanger  91  to the wellbore (not shown) when properly set. While piston  93  is in the upper or “cocked” position, casing hanger packoff seal  99  is spaced above casing hanger  91 . 
     Receptacle sub  11  is connected to the lower end of stem  59 . Receptacle sub  11  will operate as described above with respect to  FIGS. 1-3 . When dart  55  lands within receptacle sub  11 , it will act as a seal, effectively sealing the lower end of stem  59 . 
     Referring to  FIG. 4 , in operation, high capacity running tool  57  is initially positioned such that it extends axially through a casing hanger  91 . Piston  93  is in a “cocked” position, and the stem ports  63 ,  65  and body ports  85 ,  87  are axially offset from one another. Casing hanger packoff seal  99  is carried by piston  93 . High capacity running tool  57  is lowered into casing hanger  91  until the outer surface of body  73  of high capacity running tool  57  slidingly engages the inner surface of casing hanger  91 . 
     Referring to  FIG. 5 , once high capacity running tool  57  and casing hanger  91  are in abutting contact with one another, stem  59  is rotated four revolutions. As stem  59  is rotated relative to body  73 , stem  59  and piston  93  move longitudinally downward relative to body  73 . As stem  59  moves longitudinally, shoulder  69  on the outer surface of stem  59  makes contact with engaging element  89 , forcing it radially outward and in engaging contact with the inner surface of casing hanger  91 , thereby locking body  73  to casing hanger  91 . As stem  59  moves longitudinally, stem ports  63 ,  65  and body ports  85 ,  87  also move relative to one another. 
     Referring to  FIG. 6 , once high capacity running tool  57  and casing hanger  91  are locked to one another, high capacity running tool  57  and casing hanger  91  are lowered down the riser into the subsea wellhead housing (not shown) until casing hanger  91  comes to rest. Referring to  FIG. 6 , a dart  55  is then dropped or lowered into axial passage  61  of stem  59 . Dart  55  lands in receptacle sub  11 , thereby sealing the lower end of stem  59 . Stem  59  is then rotated four additional revolutions in the same direction. As stem  59  is rotated relative to body  73 , stem  59  and piston  93  move further longitudinally downward relative to body  73  and casing hanger  91 . As stem  59  moves longitudinally, stem ports  63 ,  65  and body ports  85 ,  87  also move relative to one another. Upper stem port  63  aligns with upper body port  85 , but lower stem port  65  is still positioned above lower body port  87 . This position allows fluid communication from axial passage  61  of stem  59 , through stem  59 , into and through body  73 , and into piston  93 . Fluid pressure is applied down the drill pipe and travels through axial passage  61  of stem  59  before passing through upper stem port  63 , upper body port  85 , and into chamber  95 , driving piston  93  downward relative to stem  59 . As piston  93  moves downward, the movement of piston  93  sets the casing hanger packoff seal  99  between an outer portion of casing hanger  91  and the inner diameter of the subsea wellhead housing. 
     Referring to  FIG. 7 , once piston  93  is driven downward and casing hanger packoff seal  99  is set, stem  59  is then rotated four additional revolutions in the same direction. As stem  59  is rotated relative to body  73 , stem  59  moves further longitudinally downward relative to body  73  and casing hanger  91 . Stem  59  also moves downward at this point relative to piston  93 . As stem  59  moves longitudinally, stem ports  63 ,  65  and body ports  85 ,  87  also move relative to one another. Lower stem port  65  aligns with lower body port  87 , allowing fluid communication from axial passage  61  of stem  59 , through stem  59 , into and through body  73 , and into an isolated volume above casing hanger packoff seal  99 . Upper stem port  63  is still aligned with upper body port  85 . The latch device located with slot  81  on outer sleeve  79  is activated by the movement of stem  59  and will act in conjunction with piston locking ring  97  to restrict the upward movement of piston  93  beyond the latch device. Pressure is applied down the drill pipe and travels through axial passage  61  of stem  59  before passing through lower stem port  63 , lower body port  85 , and into an isolated volume above casing hanger packoff seal  99 , thereby testing casing hanger packoff seal  99 . The same pressure is applied to piston  93 , creating an upward force, however, movement of piston  93  in an upward direction is restricted by the engagement of piston locking ring  97  and the latch device (not shown) positioned in slot  81  on outer sleeve  79 . In an alternate embodiment, the size of the fluid chambers in piston  93  and seal  99  areas could be sized such that the larger sized fluid chamber in seal  99  area maintains a downward force on piston  93 , thereby eliminating the need for the latch device and piston locking ring  97 . An elastomeric seal  101  is mounted to the exterior of piston  93  for sealing against the inner diameter of the wellhead housing. Seal  101  defines the isolated volume above casing hanger packoff seal  99 . If casing hanger packoff seal  99  is not properly set, a drop in fluid pressure held in the drill pipe will be observed as the fluid passes through the seal area. 
     Referring to  FIG. 8 , once the casing hanger packoff seal  99  has been tested, stem  59  is then rotated four additional revolutions in the same direction. As stem  59  is rotated relative to body  73 , stem  59  moves further longitudinally downward relative to body  73 , casing hanger  91 , and piston  93 . As stem  59  moves longitudinally downward, the engaging element  89  is freed and moves radially inward into recessed pocket  71  on the outer surface of stem  59 , thereby unlocking body  73  from casing hanger  91 . Upper stem port  63  remains aligned with upper body port  85 . Lower stem port  65  may remain aligned with lower body port  87 . Lower stem port  65  and lower body port  87  may partially vent the column of fluid in the drill pipe. 
     As described above with respect to  FIG. 3 , fluid pressure will be increased 15% to 20% more than needed to test casing hanger  91 . In so doing, shear pins  47  will shear, causing bypass sleeve  33  to move axially downward from the upper position shown in  FIG. 1  to the lower position shown in  FIG. 3  and  FIG. 8 . Fluid above dart  55  will then flow through bypass passage  27  and bypass sleeve ports  49 . In the illustrated embodiment, bypass ports  49  are of a sufficient size and shape such that the flow through bypass ports  49  is greater than the flow through the cross-sectional area of the drill string. This allows fluid to flow unrestricted past dart  55  for dry retrieval of running tool  57  or pressure access to a stinger or other device axially below receptacle sub  11 . 
     Referring to  FIG. 9 , receptacle sub  11  is shown after actuation and removal from a well. Dart  55  has been removed from its landing location on dart shoulder  53 , clearing sleeve bore  34 . A re-cocking tool  103  may then be coupled to bypass sleeve  33  and used to reposition bypass sleeve  33  into the position of  FIG. 1 . As shown in  FIG. 4 , receptacle sub  11  may then be refitted with additional shear pins  47  and reattached to a running tool, such as running tool  57 , for repeated use. 
     Accordingly, the disclosed embodiments provide numerous advantages. For example, the disclosed embodiments provide an apparatus for the actuation of a hydraulically actuated running tool using a dart or drop ball. The apparatus then allows for a dry retrieval that drains the column of fluid blocked by the dart or ball at an increased rate to speed the process of running tool retrieval. This significantly reduces the rig time needed to pull the running tool following use of the running tool while maintaining or increasing safety at the rig deck. 
     It is understood that the present invention may take many forms and embodiments. Accordingly, several variations may be made in the foregoing without departing from the spirit or scope of the invention. Having thus described the present invention by reference to certain of its preferred embodiments, it is noted that the embodiments disclosed are illustrative rather than limiting in nature and that a wide range of variations, modifications, changes, and substitutions are contemplated in the foregoing disclosure and, in some instances, some features of the present invention may be employed without a corresponding use of the other features. Many such variations and modifications may be considered obvious and desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.