Patent Abstract:
A running tool delivers a string through a wellhead in the same trip as a hanger with a seal and locking assembly. The string is secured downhole and the running tool is manipulated to release a lock to hold the hanger in a sealed position in the wellhead prior to a tensile force being applied. A ratchet assembly permits the string to stretch and the tensile force is then locked in. The running tool is rotated out of the string and the tree is installed on the wellhead for subsequent procedures or production.

Full Description:
FIELD OF THE INVENTION  
       [0001]     The field of this invention relates to methods for running in and tensioning a tubular string to a wellhead and more particularly where the hanger is sealed and secured in a single trip when tensioning.  
       BACKGROUND OF THE INVENTION  
       [0002]     In an oil and gas well, one or more strings of casing will be cemented within the well. In one system used with offshore jack-up drilling rigs, a mudline hanger located in a subsea housing at the sea floor will support the string of casing in the well. A section of the casing will extend upward to a surface wellhead housing on the drill rig. The surface wellhead housing will be located above the sea and below the rig floor. The distance from the subsea housing to the surface wellhead could be as much as 500 feet with a large jack-up drilling rig.  
         [0003]     Cement will be pumped down the string to flow up the annulus to cement the casing in the well. The level of cement will be below the mudline hanger. The casing will be cut off at the surface wellhead. The blowout preventer will be removed, and a spear will be used to pull tension on the casing after cementing. Then slips will be inserted around the casing, which engage the wellhead housing and grip the casing to hold the casing in tension. A packoff will be installed between the casing hanger and the wellhead housing.  
         [0004]     A disadvantage of this system is that the blowout preventer must be removed while installing the slips and packoff. A danger of a blowout thus exists. Also, this system is time consuming and expensive. In addition to this, the sealing mechanisms are generally elastomer or on site machined to give metal-to-metal seals.  
         [0005]     In another design, described in U.S. Pat. No. 5,002,131 after cementing, dogs mounted to the exterior of the casing hanger are released. Each of the dogs has a set of circumferential grooves or wickers on the exterior for engaging the wellhead housing. The wellhead housing has a mating set of grooves or wickers. Springs urge the dogs outward.  
         [0006]     The running tool for the casing hanger has a sleeve retainer. This retainer holds the dogs in the retracted position during cementing. After cementing, rotating the running tool unscrews the running tool from the casing hanger. When this occurs, the sleeve moves upward, releasing the dogs to engage the wellhead housing.  
         [0007]     Before the running tool completely releases, tension is applied to the casing to the desired amount. The dogs ratchet over the wickers in the wellhead housing as the casing hanger moves up while the tension is applied. The dogs grip the wellhead housing, preventing the casing hanger from moving downward. The running tool and sleeve are then removed from the wellhead housing. Thereafter, in a separate trip, a seal assembly is installed to seal the annular gap between the string and the wellhead. A similar design is disclosed in U.S. Pat. No. 5,255,746. String tensioning devices are generally illustrated in U.S. Pat. Nos. 5,310,007 and 5,839,512.  
         [0008]     The present invention seeks to overcome some of the shortcomings of the prior designs. It provides a one-trip method to apply tension to the string and to seal the hanger in the annular space. It also has capability to lock the hanger in a sealed position in the same single trip. It accordingly minimizes the time the annular space is open and improves the safety of the operation by providing the isolation capability in that same single trip. These and other advantages of the present invention will become more apparent to those skilled in the art from a review of the description of the preferred embodiment and the claims that appear below.  
       SUMMARY OF THE INVENTION  
       [0009]     A running tool delivers a string through a wellhead in the same trip as a hanger with a seal and locking assembly. The string is secured downhole and the running tool is manipulated to release a lock to hold the hanger in a sealed position in the wellhead prior to a tensile force being applied. A ratchet assembly permits the string to stretch and the tensile force is then locked in. The running tool is rotated out of the string and the tree is installed on the wellhead for subsequent procedures or production. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0010]      FIG. 1  is a section view, in elevation, of one embodiment of the running tool shown supporting a string to be inserted into a wellhead;  
         [0011]      FIG. 2  is an enlargement of the lower end of  FIG. 1  showing the ratchet assembly in more detail;  
         [0012]      FIGS. 3A and 3B  show alternative designs for the locking dog in the ratchet assembly;  
         [0013]      FIG. 4  is the assembly of  FIG. 1  landed in a wellhead;  
         [0014]      FIG. 5  is the view of  FIG. 4  after the hanger is locked and sealed in the wellhead;  
         [0015]      FIG. 6  is the view of  FIG. 5  showing tension being pulled on the running tool;  
         [0016]      FIG. 7  is the view of  FIG. 6  with the running tool removed and a tubing head adaptor installed;  
         [0017]      FIG. 8  is an alternative design to  FIG. 1  featuring a hydraulic piston on the running tool;  
         [0018]      FIG. 9  is the view of  FIG. 8  with the tubing tied back at its lower end in the wellbore;  
         [0019]      FIG. 10  is the view of  FIG. 9  showing tension on the string and operation of the hydraulic piston to land the hanger in the wellhead;  
         [0020]      FIG. 11  is the view of  FIG. 10  with the tensile force removed and the tension locked in with the ratchet and the hydraulic piston actuating the hanger into final position where it will be locked in after rotation of the running tool; and  
         [0021]      FIG. 12  is the view of  FIG. 11  with the running tool removed and a tubing head adaptor installed. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0022]     Referring to  FIGS. 1 and 2 , a string  10  is supported by a running tool  12  at thread  14 . String  10  is also secured to inner ratchet sleeve  16 , which has a groove  18  in which is disposed a dog  20 . Two different embodiments of dog  20  are shown in  FIGS. 3A and 3B . In  FIG. 3A , dog  20  has two peak surfaces  22  and  24  separated by a valley surface  26 . In the  FIG. 3B  embodiment, the dog  20  has a single sloping surface  28  adjacent a cylindrical surface  30 . Outer ratchet sleeve  32  surrounds inner ratchet sleeve  16  and seal  34  seals between them. Those skilled in the art will appreciate that seal  34  can be mounted on the inner sleeve  16  or the outer sleeve  32 . Similarly, the ratchet assembly now being described can be reversed as between these two sleeves without departing from the scope of the invention. In the preferred embodiment, outer sleeve  32  has a ratchet rack  36  defining a plurality of depressions  38  that conform in shape to peak surfaces  22  and  24  shown in  FIG. 3A  or surfaces  28  and  30  shown in  FIG. 3B . Preferably, dog  20  is a split ring having a c-shape with a built in outward bias out of groove  18 . Those skilled in the art will appreciate that other forms of bias can be applied to dog  20  external to its structure and still be within the scope of the invention. As shown in  FIGS. 1 and 2  inner sleeve  16  can move up with respect to outer sleeve  32  and dog  20  will simply jump from one depression  38  to another as its diameter decreases to allow such movement. Relative movement in the reverse direction will be precluded by dog  20  expanding into the most adjacent depression  38  and locking the sleeves  16  and  32  to each other.  
         [0023]     Referring again to  FIG. 1 , outer sleeve is connected to hanger  40  at thread  42 . Seals  44  and  46  are supported on hanger  40  for sealing contact with surface  48  of wellhead  50 , as shown in  FIG. 4 . Referring back to  FIG. 1 , a lock retainer sleeve  52  holds in a locking ring  54  when running the string  10  into the wellhead  50 . Rotation of running tool  12  backs out thread  14  and allows sleeve  52  to rise away from locking ring  54 . When this happens, locking ring  54  can snap out into a groove  56  in wellhead  50  (see  FIG. 4 ).  
         [0024]     The method proceeds as follows. The running tool  12  supports the string  10  as well as the hanger  40  and the sleeve  52  in a position where it is retaining the locking ring  54  in a retracted position. Initially, the string  10  is tagged downhole to a seal bore or packer (not shown). In any event, the lower end of string  10  is secured downhole. A shoulder  58  on hanger  40  (see  FIG. 1 ) is landed on a shoulder  60  in wellhead  50 . This is the position in  FIG. 4 .  
         [0025]     In  FIG. 5 , the running tool  12  is rotated to back out thread  14  and raise sleeve  52  away from locking ring  54  to allow it to snap out into groove  56 . The hanger  40  is thus locked to the wellhead  50  and seals  44  and  46  seal between the two.  
         [0026]     In  FIG. 6 , thread  14  is still engaged so that an upward pull on the running tool  12  puts tension on string  10  while inner sleeve  16  moves up with string  10  as the tension is being applied. Dog  20  skips along ratchet rack  36 . Outer sleeve  32  is stationary at this time because the hanger  40  is secured to wellhead  50  by locking ring  54  and outer sleeve  32  is secured to hanger  40  at thread  42 . After the appropriate tension is pulled on the running tool  12  the pulling force is removed. Groove  18  with dog  20  move down until dog  20  can spring out into a depression  38 . At that point the one trip procedure is concluded. The necessary tension is on the string  10  and hanger  40  is locked to wellhead  50  by lock ring  54 . Seals  44  and  46  also seal the hanger  40  to wellhead  50 . Those skilled in the art will appreciate that one or more seals can be used and they can be mounted in the wellhead  50  instead of or in addition to the hanger  40 .  
         [0027]      FIG. 7  shows the running tool  12  released at thread  14  and pulled out of the well. In its place a tubing head adapter  62  is installed. Alternatively other equipment could be installed depending on the nature of the string  10  being run into the well.  
         [0028]      FIG. 8  is an alternative embodiment to  FIG. 1  and is identical except that it features a hydraulic cylinder  64  mounted to the running tool  12  with the capability of stroking a piston  66  to selectively slide sleeve  52  along the running tool  12  for reasons that will be explained below. Mechanical equivalents such as a rack and pinion are also contemplated.  
         [0029]     As before, the string  10  is shown inserted into the wellhead  50  to allow the operation of a downhole tool or to secure the lower end of the string  10  to a seal bore or some other anchor (not shown). Securing the lower end of the string  10  allows for tension to be pulled on it.  
         [0030]      FIG. 10  shows the tension applied to the running tool  12 , which extends the string  10  and moves up inner sleeve  16  and dog  20  along with ratchet rack  36 . With the tension applied to running tool  12 , piston  66  is stroked to move down hanger  40  until its contact surface  58  engages shoulder  60  in wellhead  50 . Piston  66  can be stroked as the tension is being applied or before or after. Seals  44  and  46  are now in sealing engagement in the wellhead  50 .  
         [0031]      FIG. 11  shows the tension removed to allow dog  20  to engage ratchet rack  36  as previously described to hold in the applied tension. The running tool  12  is rotated to allow sleeve  52  to move away from locking ring  54  so it can spring out into groove  56  in wellhead  50 . The running tool can be removed after thread  14  is fully undone.  
         [0032]     Thereafter, a tubing head adapter  62  or some other device depending on the nature of the string  10  is fitted to the wellhead  50 .  
         [0033]     In either embodiment, the result is that in a single trip a tensile force is applied to the string  10  and the hanger  40  is placed in a sealing relationship to the wellhead  50  using seals  44  and  46 . In the same trip the hanger is locked in position with locking ring  54  or an equivalent structure. In the preferred embodiment of  FIGS. 1-7  the act of sealing the hanger  40  is independent of locking it to wellhead  50 . These two operations can also be combined or one made dependent on the other. A separate trip to install a seal or locking device is eliminated.  
         [0034]     The above description of the preferred embodiment is merely illustrative of the optimal way of practicing the invention and various modifications in form, size, material or placement of the components can be made within the scope of the invention defined by the claims below.

Technology Classification (CPC): 4