Abstract:
A high capacity running tool sets and internally tests a casing hanger packoff during the same trip. The running tool has a stem and a body. The body is secured by threads to the stem of the running tool so that rotation of the stem relative to the body will cause the stem to move longitudinally. An engagement element connects the tool body to the casing hanger by engaging the inner surface of the casing hanger. Longitudinal movement of the stem relative to the body moves the engaging element between inner and outer positions and lines up ports in the stem and in the body for setting and testing functions.

Description:
FIELD OF THE INVENTION 
     This invention relates in general to tools for running casing hangers in subsea wells, and in particular to a high capacity tool that sets and internally tests a casing hanger packoff in one trip. 
     BACKGROUND OF THE INVENTION 
     A subsea well of the type concerned herein will have a wellhead supported on the subsea floor. One or more strings of casing will be lowered into the wellhead from the surface, each supported on a casing hanger. The casing hanger is a tubular member that is secured to the threaded upper end of the string of casing. The casing hanger lands on a landing shoulder in the wellhead, or on a previously installed casing hanger having larger diameter casing. Cement is pumped down the string of casing to flow back up the annulus around the string of casing. Afterward, a packoff is positioned between the wellhead bore and an upper portion of the casing hanger. This seals the casing hanger annulus. 
     Casing hanger running tools perform many functions such as running and landing casing strings, cementing strings into place, and installing and testing packoffs. Testing the packoff is traditionally performed by pressuring under the blow out preventer (BOP) stack, but more recent casing hanger running tool designs incorporate an “internal” or “down the drill pipe” test which isolates the test pressure to a small volume just above the hanger. An internal test has several benefits including reducing the annular pressure end load reacted against the hanger and making leak detection more direct, which is especially beneficial for sub-mudline casing strings which can be located several thousand feet from the BOP stack. The cost of the added functionality is complexity in the form of additional ports and seals. 
     Virtually all casing hanger running tools to date incorporate a cam that acts as a mechanical program for the tool. Rotational inputs to the cam drive it axially, causing it to drive engaging elements such as dogs radially, allows seal-setting pistons to communicate with the stem, and opens up additional ports for internal testing. Typically, cams occupy the radial space between the stem and the body of the running tool and must be thick enough to withstand radial loads generated by the dogs and pressure loads from setting and testing packoffs. If the cam could be eliminated, the radial space it normally occupied could be used to thicken up the body and the stem, thus increasing the hanging capacity of the tool. A need exists for a technique that addresses increased hanging capacity of a running tool, coupled with the ability to internally test a packoff. The following technique may solve one or more of these problems. 
     SUMMARY OF THE INVENTION 
     In an embodiment of the present technique, a high capacity running tool sets and internally tests a casing hanger packoff during the same trip. The running tool is comprised of a body and a stem. The body is secured by threads to the stem of the running tool so that rotation of the stem relative to the body will cause the stem to move longitudinally. An engagement element connects the tool body to the casing hanger by engaging an inner surface of the casing hanger. Longitudinal movement of the stem relative to the body moves the engaging element between an inner and outer position, thereby securely engaging the running tool and the casing hanger. Longitudinal movement of the stem relative to the body also lines up ports in the stem and the body for setting and testing functions, much like a cam in previous running tools. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a sectional view of a high capacity running tool constructed in accordance with the present technique with the piston cocked and the engagement element retracted. 
         FIG. 2  is a sectional view of the high capacity running tool of  FIG. 1  in the running position with the engagement element engaged. 
         FIG. 3  is a sectional view of the high capacity running tool of  FIG. 1  in the setting position. 
         FIG. 4  is a sectional view of the high capacity running tool of  FIG. 1  in the seal testing position. 
         FIG. 5  is a sectional view of the high capacity running tool of  FIG. 1  in the unlocked position with the engagement element disengaged. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Referring to  FIG. 1 , there is generally shown an embodiment for a high capacity running tool  11  that is used to set and internally test a casing hanger packoff. The high capacity running tool  11  is comprised of a stem  13 . Stem  13  is a tubular member with an axial passage  14  extending therethrough. Stem  13  connects on its upper end to a string of drill pipe (not shown). Stem  13  has an upper stem port  15  and a lower stem port  17  positioned in and extending therethrough that allow fluid communication between the exterior and axial passage of the stem  13 . A lower portion of the stem  13  has threads  19  in its outer surface. The outer diameter of an upper portion of stem  13  is greater than the outer diameter of the lower portion of stem  13  containing threads  19 . As such, a downward facing shoulder  21  is positioned adjacent threads  19 . A recessed pocket  23  is positioned in the outer surface of the stem  13  at a select distance above the downward facing shoulder  21 . 
     Running tool  11  has a body  25  that surrounds stem  13 , as stem  13  extends axially through the body  25 . Body  25  has an upper body portion  27  and a lower body portion  29 . The upper portion  27  of body  25  is a thin sleeve located between an outer sleeve  30  and stem  13 . Outer sleeve  30  is rigidly attached to stem  13 . A latch device (not shown) is housed in a slot  32  located within the outer sleeve  30 . The lower body portion  29  of body  25  has threads  31  along its inner surface that are engaged with threads  19  on the outer surface of stem  13 . Body  25  has an upper body port  33  and a lower body port  35  positioned in and extending therethrough that allow fluid communication between the exterior and interior of the stem body  25 . The lower portion  29  of body  25  houses an engaging element  37 . In this particular embodiment, engaging element  37  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  39  when the engagement element  37  is engaged with the casing hanger  39 . Although not shown, a string of casing is attached to the lower end of casing hanger  39 . The inner surface of the engaging element  37  is initially in contact with the threads  19  on the inner surface of stem  13 . 
     A piston  41  surrounds the stem  13  and substantial portions of the body  25 . Referring to  FIG. 3 , a piston chamber  42  is formed between upper body portion  27 , outer sleeve  30 , and piston  41 . Piston  41  is initially in a and upper or “cocked” position relative to stem  13 , meaning that the area of piston chamber  42  is at its smallest possible value, allowing for piston  41  to be driven downward. A piston locking ring  43  extends around the outer peripheries of the inner surface of the piston  41 . Locking ring  43  works in conjunction with the latch device (not shown) contained within outer sleeve slot  32  to restrict movement of the piston during certain running tool functions. A casing hanger packoff seal  45  is carried by the piston  41  and is positioned along the lower end portion of piston  41 . Packoff seal  45  will act to seal the casing hanger  39  to the wellbore (not shown) when properly set. While piston  41  is in the upper or “cocked” position, packoff seal  45  is spaced above casing hanger  39 . 
     A dart landing sub  47  is connected to the lower end of stem  13 . The landing sub  47  will act as a landing point for an object, such as a dart, that will be lowered into the stem  13 . When the object or dart lands within the landing sub  47 , it will act as a seal, effectively sealing the lower end of stem  13 . 
     Referring to  FIG. 1 , in operation, the high capacity running tool  11  is initially positioned such that it extends axially through a casing hanger  39 . The piston  41  is in a “cocked” position, and the stem ports  15 ,  17  and body ports  33 ,  35  are axially offset from one another. Casing hanger packoff seal  45  is carried by the piston  41 . The running tool  11  is lowered into the casing hanger  39  until the outer surface of the body  25  of running tool  11  slidingly engages the inner surface of casing hanger  39 . 
     Referring to  FIG. 2 , once the running tool  11  and casing hanger  39  are in abutting contact with one another, the stem  13  is rotated four revolutions. As the stem  13  is rotated relative to the body  25 , the stem  13  and piston  41  move longitudinally downward relative to body  25 . As the stem  13  moves longitudinally, the shoulder  21  on the outer surface of stem  13  makes contact with the engaging element  37 , forcing it radially outward and in engaging contact with the inner surface of casing hanger  29 , thereby locking body  25  to casing hanger  39 . As stem  13  moves longitudinally, stem ports  15 ,  17  and body ports  33 ,  35  also move relative to one another. 
     Referring to  FIG. 3 , once the running tool  11  and casing hanger  39  are locked to one another, the running tool  11  and casing hanger  39  are lowered down the riser into the subsea wellhead housing (not shown) until the casing hanger  39  comes to rest. Referring to  FIG. 3 , a solid dart  49  is then dropped or lowered into the axial passage  14  of stem  13 . The solid dart  49  lands in the landing sub  47 , thereby sealing the lower end of stem  13 . The stem  13  is then rotated four additional revolutions in the same direction. As the stem  13  is rotated relative to the body  25 , the stem  13  and piston  41  move further longitudinally downward relative to body  25  and casing hanger  39 . As the stem  13  moves longitudinally, stem ports  15 ,  17  and body ports  33 ,  35  also move relative to one another. Upper stem port  15  aligns with upper body port  33 , but lower stem port  17  is still positioned above lower body port  35 . This position allows fluid communication from the axial passage  14  of stem  13 , through stem  13 , into and through body  25 , and into piston  41 . Fluid pressure is applied down the drill pipe and travels through the axial passage  14  of stem  13  before passing through upper stem port  15 , upper body port  33 , and into chamber  42 , driving piston  41  downward relative to the stem  13 . As the piston  41  moves downward, the movement of piston  41  sets the packoff seal  45  between an outer portion of casing hanger  39  and the inner diameter of the subsea wellhead housing. 
     Referring to  FIG. 4 , once the piston  41  is driven downward and packoff seal  45  is set, the stem  13  is then rotated four additional revolutions in the same direction. As the stem  13  is rotated relative to the body  25 , the stem  13  moves further longitudinally downward relative to body  25  and casing hanger  39 . Stem  13  also moves downward at this point relative to piston  41 . As the stem  13  moves longitudinally, stem ports  15 ,  17  and body ports  33 ,  35  also move relative to one another. Lower stem port  17  aligns with lower body port  35 , allowing fluid communication from the axial passage  14  of stem  13 , through stem  13 , into and through body  25 , and into an isolated volume above packoff seal  45 . Upper stem port  15  is still aligned with upper body port  33 . The latch device located with the slot  32  on the outer sleeve  30  is activated by the movement of the stem  13  and will act in conjunction with piston locking ring  43  to restrict the upward movement of piston  41  beyond the latch device. Pressure is applied down the drill pipe and travels through the axial passage  14  of stem  13  before passing through lower stem port  15 , lower body port  33 , and into an isolated volume above packoff seal  45 , thereby testing packoff seal  45 . The same pressure is applied to piston  41 , creating an upward force, however, movement of the piston  41  in an upward direction is restricted by the engagement of the piston locking ring  43  and the latch device (not shown) positioned in the slot  32  on outer sleeve  30 . In an alternate embodiment, the size of the fluid chambers in the piston  41  and seal  45  areas could be sized such that the larger sized fluid chamber in the seal  45  area maintains a downward force on piston  41 , thereby eliminating the need for the latch device and the piston locking ring  43 . An elastomeric seal  51  is mounted to the exterior of piston  41  for sealing against the inner diameter of the wellhead housing. Seal  51  defines the isolated volume above packoff seal  45 . If packoff seal  45  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. 5 , once the packoff seal  45  has been tested, the stem  13  is then rotated four additional revolutions in the same direction. As the stem  13  is rotated relative to the body  25 , the stem  13  moves further longitudinally downward relative to the body  25 , casing hanger  39 , and piston  41 . As the stem  13  moves longitudinally downward, the engagement element  37  is freed and moves radially inward into recessed pocket  23  on the outer surface of stem  13 , thereby unlocking the body  25  from casing hanger  39 . Upper stem port  15  remains aligned with upper body port  33 . Lower stem port  17  remains aligned with lower body port  35 . The lower stem port  17  and lower body port  35  vent the column of fluid in the drill pipe, allowing dry retrieval of the running tool  11 . Running tool  11  can then be removed from the wellbore. 
     The technique has significant advantages. The elimination of a cam provides fewer leak paths and an increased hanging capacity due to the increase radial space within the running tool. 
     While the technique has been shown in only one of its forms, it should be apparent to those skilled in the art that it is not so limited but is susceptible to various changes without departing from the scope of the technique.