Patent Abstract:
A production assembly for controlling production from a well, the assembly including a wellhead that includes a body and a bore through the body. The bore does not include a hanger support shoulder but does include an engagement profile extending into the body. The assembly also includes a tubing hanger assembly installable in the wellhead. The assembly includes a load shoulder including a load segment expandable into supporting engagement with the bore engagement profile. The assembly also includes a tubing hanger and attached production tubing capable of being run in with the load shoulder and supportable on the load shoulder when the shoulder is engaged with the wellhead.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a 35 U.S.C. §371 national stage application of PCT/US2009/066926 filed Dec. 7, 2009, which claims the benefit of U.S. Provisional Patent Application No. 61/138,773 filed Dec. 18, 2008, both of which are incorporated herein by reference in their entireties for all purposes. 
    
    
     BACKGROUND 
     Conventionally, wells in oil and gas fields are built up by establishing a wellhead housing and, with a drilling blow out preventer (BOP) adapter valve installed, drilling down to produce the borehole while successively installing concentric casing strings. The casing strings are cemented at their lower ends and sealed with mechanical seal assemblies at their upper ends. In order to convert the cased well for production, a production tubing string is run in through the BOP and a tubing hanger at its upper end is typically landed in the wellhead. Thereafter the drilling BOP is removed and replaced by a Christmas tree having one or more production bores containing valves and extending vertically to respective lateral production fluid outlet ports in the wall of the tree. 
     The tubing hanger is installed by a hanger running tool and the tool lowers the tubing hanger down the production bore until it lands on top of a stop shoulder. The stop shoulder is created with a decreased inner diameter portion of the housing in which the hanger is landed, which provides a permanent means to stop the lowering of the tubing hanger. 
     During subsequent operations, the difference in diameter of inner bore created by the permanent stop shoulder may present an inner diameter that can impede the progress of elements that are intended to be lowered past the stop shoulder. In this case, the utilization of the stop shoulder could present and inner diameter less than the inner diameter that would allow an element such as a workover tool to progress downward through the bore. If no stop shoulder were present, such and impedance would not occur and the maximum inner diameter of the production bore would be available to the operator. In addition, the standard amount of housing required between the production bore and a wellhead casing increases proportionally with the inner diameter of the production bore. If no stop shoulder is present, the amount of material can be decreased, per required standards. The absence of a stop shoulder would create “full” production bore, where the inner diameter of the production bore is limited only by the inner wall of the production bore itself. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings: 
         FIG. 1  is a sectional view of a full bore production system showing a production full-bore support casing. 
         FIG. 1A  shows a detailed sectional view showing a close up of some of the full bore production system components. 
         FIGS. 2-8  include sectional views of the full bore production system during installation. 
     
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
     In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. Any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. 
     Referring to  FIG. 1  there is shown a standard full bore production system  1  including a wellhead  4 , a BOP adapter  34 , and a hanger running tool  28 . The wellhead  4  is landed on top of a conductor casing  3 . The wellhead  4  controls and monitors flow, temperature, and pressure of the production fluid or gas via a plurality of valves and tubing (not shown) inside of the full bore production system  1 . The BOP adapter  34  is landed atop the wellhead  4  and bolted to wellhead  4  using bolts as shown or any other suitable attachment means. 
     A tubing hanger system  5  is lowered through the top of the BOP adapter  34  and landed in position inside the wellhead  4  via a hanger running tool  28 . The tubing hanger system  5  includes a hanger body  8  supporting a production tubing and a load shoulder  12  that includes a load segment  14 . The load shoulder  12  is designed to receive loading that may be transferred during construction and operation of the full bore production system  1 . The load shoulder  12  also includes an upper load sleeve  38  and a lower load sleeve  40 . The load sleeves  38 ,  40  move independently of each other and transfer applied loading via free-fall movement of tubing hanger body  8  and a stud force pin  16  respectively. Further, hanger system  5  includes an upper lock ring  36  that is manipulated between a locked and an unlocked position by the movement of a wedge  50 . 
     Loading transferred to the tubing hanger system  5  components in the full bore production system  1  may originate from a hanger running tool  28 . The hanger running tool  28  includes a sealed port  70  for fluid communication with the BOP adapter  34  and an outer sleeve  37 . The hanger running tool  28  is “run” by being lowered through the top of the BOP adapter  34  and temporarily landed inside of BOP adapter  34  using load pins  24 ,  25  that are manipulated between extended and withdrawn positions per operator discretion as discussed below. Although only two load pins  24 ,  25  are shown, it should be appreciated that as many load pins as desired may be used. The hanger running tool  28 , in use, applies pressure force to the full bore production system  1  via a chamber  35  and hydraulic fluid communicated through the pressure port  32  in the BOP adapter  34 . 
     In use, a downhole completion is initiated by drilling and completing an oil or gas production well in such a manner that the well can allow proper flow during the period in which the reservoir operates. The full bore production system  1  may be used for completing the well with the tubing hanger system  5  installed to allow communication and control of downhole functions and as a sealing mechanism for the production components that are utilized in the operation of the well. 
     The tubing hanger system  5  is positioned and installed by utilizing the hanger running tool  28  to insure proper placement and to keep the tubing and control lines from becoming entangled in the system. The hanger system  5  includes the upper lock ring mechanism  36 , the upper and lower load sleeves  38 ,  40 , the outer loading sleeve  37 , a stud force pin  16 , and the load segment  14  mechanism. These elements provide the means for running, setting, locking, and preloading the load segment  14  mechanism without requiring the use of a permanent stop shoulder in the wellhead  4 . This method will also limit the possibility of leakage in the system tubing due to the fact that the load segment mechanism can be run with the tubing hanger system  5  in a single approach—thus limiting the opportunities for potential leakage upon its removal. It should be noted that as shown in  FIGS. 1 and 1A , the full bore production system  1  is in the running position configuration. 
       FIGS. 2-8  show further installation of the hanger system  5 . Referring to  FIG. 2 , at least the load pins  24 ,  25  are set into the extended position in the direction of the hanger running tool  28 . (It should be noted that this embodiment could contain more than two load pins.) This movement may be actuated from variant sources, however, the conventional source is through manual operation. The purpose of moving the load pins  24 ,  25 , is to locate and temporarily support the hanger system  5  and to provide verification of the elevation of the casing. This setting is known as the run-in position for the full bore production system  1 . 
     Referring to  FIG. 3 , hydraulic fluid pressure is applied through the pressure port  32  orifice to set and lock the load shoulder  12 . Pressure is applied at pressure port  32  and this pressure load is introduced into the chamber  35  above an annular collar on the inside of the outer sleeve  37 , effecting a hydraulic piston. The increased pressure in the chamber  35  is transferred to the outer sleeve  37  through the collar, shifting the sleeve  37  downward and applying pressure force to the stud force pin  16 . This pressure loading of the stud force pin  16  transfers to the lower load sleeve  40 , causing it and a wedge  41  to move downward. Movement of the wedge  41  relative to the load segment  14  causes the load segment  14  to move in a radially outward motion towards a groove  44  machined into the inner bore of the wellhead  4  until the load segment  14  is set in the groove  44 . Once set, the load segment  14  may receive and support subsequent loading. 
     Referring to  FIG. 4 , with the load segment  14  extended, the hanger body  8  is supportable using the engagement of the load segment  14  with the groove  44  as a load shoulder. Transfer of the load to the load segment  14  is accomplished by retracting the load pins  24 ,  25  while holding the hanger body  8  using the running tool  28 , and then slowly releasing the hanger body  8 . With enough downward force, the hanger body  8  shears a force shear pin  42  located inside of a shear pin housing  48 , allowing the hanger body  8  to continue to move in a downward direction until the hanger body  8  is supported by the load shoulder  12 . 
     Referring to  FIG. 5 , once the hanger body  8  is landed, the pressure supplied to the system through pressure port  32  is terminated and the running tool  28  is removed. 
     Referring to  FIG. 6 , an overshot tool  54  and an overpull tool  56  are positioned in the location previously occupied by hanger running tool  28 . It should be appreciated that in the case that the tubing hanger body  8  is adjustable, overpull tool  56  may be used to position the adjustable hanger per the operator&#39;s specification and then to subsequently lock the hanger in place. 
     Referring to  FIG. 7 , once the hanger body  8  is positioned, the overshot tool  54  may be rotated to apply torque to the wedge  50 , which is threaded to the outside of the upper load sleeve  38 . Relative rotation of the wedge  50  to the upper load sleeve  38  drives the wedge  50  downward, applying an outward force to upper lock ring  36  and expanding the lock ring  36  into a groove  51 . The movement of upper lock ring  36  towards the groove  51  allows for movement of the adjustable tubing hanger body  8  per the user&#39;s discretion. With the wedge  50  moved downward and the upper locking ring  36  engaged with the groove  51 , the hanger body  8  is considered locked in position. The overshoot tool  54  may now be removed from the system as shown in  FIG. 8 . 
     Subsequent to installing the full bore system  1 , operations may need to be performed on the well that include removal of the hanger system  5  and the supported production tubing. Removal of the hanger system  5 , including the load shoulder  12  may be performed by unlocking and unsetting the hanger system  5  and then removing the system  5  from the wellhead  4 . When removed, the wellhead  4  offers full bore access for running in tools or elements downhole for performing well operations such as workover procedures. The wellhead  4  thus does not limit the size of elements run into the well to a reduced inner diameter of a permanent load shoulder in the wellhead  4 . 
     While specific embodiments have been shown and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.

Technology Classification (CPC): 4