Patent Abstract:
Methods and devices are described for efficiently installing sea-borne wellhead components and tying back sub-sea wellhead components with them. In specific aspects, a single running and setting tool is used to land a tubing head housing upon the stem of a floating platform and tension and pressure testing casing string risers extending between a subsea wellhead and a floating vessel.

Full Description:
This application is a continuation of application Ser. No. 10/152,878, filed May 21, 2002 now abandoned, entitled—One-Trip Wellhead Installation Systems and Methods, which application claimed the priority of provisional patent application Ser. No. 60/293,456, filed May 24, 2001. 

   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The invention relates to methods and devices for assembly of portions of a sea-based, hydrocarbon production well. More specifically, the invention relates to methods and devices for efficiently installing sea-borne wellhead components and tying back sub-sea wellhead components with them. In specific aspects, the invention provides methods and devices for running and setting of a tubing head assembly upon the stem of a floating platform using a single trip by a single tool. In other aspects, the invention provides devices and methods for tensioning and pressure testing casing string risers using the same single tool. 
   2. Description of the Related Art 
   In sea-based wellhead systems, there is typically a sub-sea wellhead that is installed on the ocean floor and a surface wellhead that is located on a floating platform or rig above the sub-sea wellhead. The two wellheads are tied together with a riser system. Currently, it is necessary to employ different specialized tools to perform the various operations associated with landing and testing the tubing head portion of the surface wellhead upon the stem of the floating platform or rig as well as for testing the integrity of the riser or casing string. Unfortunately, this is a time-consuming and costly process since a number of separate tool runs must be made with the necessary specialized tools being installed and then removed. Time must be taken for each separate run of equipment as well as for refitting the running tool with new equipment. Prior art systems are capable of performing some of these tasks, but not all of them in an acceptable manner. 
   A solution to the problems of the prior art would be desirable. 
   SUMMARY OF THE INVENTION 
   A wellhead assembly system is described wherein a single running and setting tool is used to land the tubing head portion of a wellhead assembly on the stem of a floating platform. In operation, the running and setting tool supports the riser, tensions the riser string, sets the seal between the riser and the wellhead, and tests the packoff in a single trip. The running and setting tool also allows a means for a pressure test of the riser string and tieback connector prior to setting the wellhead. This provides a significant time-saving advantage over conventional systems wherein it is necessary to disassemble the tool following running and landing of the riser in order to run a special pack off setting and test tool. Blowout preventer nipple up operations may occur immediately thereafter. 
   In other aspects, the invention of the present system incorporates a load cell monitoring system within the tubing head assembly for use in precisely measuring tension load on the riser string. In a described embodiment, the load cell monitoring system is incorporated into a stem head to wellhead seal. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a side cross-sectional view of an exemplary wellhead running and setting tool constructed in accordance with the present invention affixed to a wellhead assembly and configured prior to landing of the wellhead assembly in the stem of a floating platform. 
       FIG. 1A  is a closeup view of components of a seal assembly within the wellhead assembly shown in  FIG. 1  shown without the running and setting tool. 
       FIG. 1B  is a closeup view of the seal assembly components with a running and setting tool engaged. 
       FIG. 1C  is a closeup view of the seal assembly and running/setting tool, as shown in  FIG. 1B  wherein the seal components now having been set. 
       FIG. 1D  is a closeup view of a ratchet suspension used within the wellhead assembly. 
       FIG. 2  is a side cross-sectional view of the tool and wellhead assembly shown in  FIG. 1  wherein a pressure test is being conducted of the casing string. 
       FIG. 3  is a side cross-sectional view of the tool and wellhead assembly shown in  FIGS. 1 and 2  after having been landed in a stem head and with the setting tool being energized. 
       FIG. 4  is a side cross-sectional view of the tool assembly shown in  FIGS. 1-3  wherein the tool assembly  10  is being locked down to the stem head. 
       FIG. 5  is a side cross-sectional view of the tool and wellhead assembly shown in  FIGS. 1-4  after the tool assembly  10  has been operated to set the riser seal. 
       FIG. 6  is a side cross-sectional view of the tool and wellhead assembly shown in  FIGS. 1-5  illustrating pressure testing of the riser seal. 
       FIG. 7  illustrates the removal of the wellhead setting and running tool from the wellhead assembly. 
       FIG. 8  depicts the wellhead assembly after having a BOP stack installed atop it. 
       FIG. 9  illustrates testing of the BOP connection using a combination test plug and running tool. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
   Referring first to  FIG. 1 , there is shown a first exemplary embodiment for a running and setting tool, generally shown as  10 , that is disposed within and associated with the tubing head assembly  12  for a wellhead to be constructed on a floating platform (not shown). 
   The tubing head assembly  12  is made up of a generally cylindrical housing  14  that defines a central bore  16  therethrough with an NT-2 landing profile  18  at its upper end. A lateral fluid test port  20  is disposed through the side of the housing  14  and is initially closed off by a removable cover  22 . 
   The central portion of the housing  14  is seated upon a stem head adapter plate  24  that is shaped and sized to engage the stem of a floating platform in a complimentary manner. Three load cells  26  (one shown) are retained within the housing  14  and support the upper end of the housing  14  so as to measure the load placed upon the housing  14  by the weight of casing lengths being suspended from the housing  14 . The load cells  26  typically comprise an electronic measuring device useful for measuring weight loads. As  FIG. 1  illustrates, a cable  28  interconnects the load cells  26  with a device  30 , such as a computer, that is useful for recording, interpreting, reporting and/or storing the weight readings. 
   A lower wellhead assembly  32  extends downwardly from the housing  14 . The lower wellhead assembly  32  includes a casing sleeve  34  that encloses an enlarged tubular bore  36  that is shaped and sized to admit the passage of wellbore casing therethrough. In addition, the lower wellhead assembly  32  includes a riser seal assembly  38  and a ratchet suspension assembly  40  that retains a casing string within the sleeve  34 . 
     FIGS. 1A ,  1 B and  1 C further illustrate the details concerning the seal assembly  38  in greater detail while  FIG. 1D  illustrates the details relating to the ratchet suspension assembly  40  in greater detail.  FIG. 1A  depicts the seal assembly  38  apart from portions of the running and setting tool and in a configuration wherein the seal has been energized.  FIGS. 1B and 1C  show in greater detail the setting of the annular seal  48  using the running and setting tool. 
   The seal assembly  38  is known commercially as an MSCB seal. Since the construction and operation of this type of seal assembly is understood by those in the art, those details will be discussed only briefly herein. The seal assembly  38  is used to establish a fluid-tight seal above the hanger body  42  within the sleeve  34 . The upper end  44  of the hanger body  42  has a reduced external diameter thereby creating a seal pocket  46  between the hanger body  42  and the sleeve  34 . Annular seal member  48  has a U-shaped profile and is disposed within the pocket  46 . A wedge  50  is located within the annular seal member and, when moved downwardly into the seal  48 , the wedge  50  will set or energize the seal by urging its sides outwardly against the sleeve  34  and the hanger body  42 . A setting sleeve  52  is disposed above the seal  48  abutting wedge  50 . When the setting sleeve  52  is urged downwardly, the wedge  50  energizes the seal  48 . 
   As is best shown in  FIG. 1D , the ratchet suspension assembly  40  includes a ratchet member  54  that is secured by splines  56  to the casing sleeve  34 . The ratchet member  54  includes radially interior teeth  58  that interengage radially exterior ratchet teeth  60  on casing pup joint  62 . The pup joint  62  a specialized section of tubing that has ratchet teeth  60  on its radial exterior. An exterior collar  64  secures a standard casing section  66  to the casing pup joint  62 . As a result of the toothed engagement between the pup joint  62  and the ratchet member  54 , the pup joint  62  may be moved upwardly with respect to the ratchet member  54  but not moved downwardly unless rotated. Casing sleeve  34  and casing string  66  serve as a riser from tubing head  14  to the subsea well. 
   It will be understood that the casing section  66  is normally the upper portion of a much longer casing string that is being run from the lower wellhead assembly  32  to a subsea well (not shown). The casing string associated with the casing section  66  is typically run downwardly, in association with a riser (not shown), from a floating platform such as the Spar. The riser and casing string are run downwardly to a subsea wellhead (not shown) where the riser and casing string are landed thus “tying back” the subsea wellhead to the floating platform. 
   The running and setting tool  10  includes a radially enlarged tool piston body  70  that is affixed at its upper end by threaded connection  72  to a section of drill pipe  74 . The upper end of the drill pipe section  74  is shown secured by a collar  76  to a further section of drill pipe  78 . Those of skill in the art will understand that the drill pipe section  78  may be part of a longer string of drill pipe members that is used for manipulation of the running and setting tool  10  and for disposing sections of casing string into a subsea wellbore. 
   The lower end of the tool piston body  70  is secured by threaded connection  80  to drill pipe member  82 . The lower end of the drill pipe member  82  is secured by threaded connection  84  to a landing sub  86 . The landing sub  86  is provided with a radially outer setting shoulder  88 . A cap  90  is secured on the lower end of the landing sub  86 . It is noted that a continuous fluid flowbore  92  is defined centrally through the drill pipe sections  78 ,  74 , tool piston body  70 , drill pipe member  82 , landing sub  86  and cap  90 . The tool piston body  70  and drill pipe member  82  may be considered, collectively, to form a central piston assembly that is radially disposed within the housing  14  and is axially moveable therewithin. 
   The running and setting tool  10  also includes some upper setting tool portions which are indicated generally by the reference numeral  94  in FIG.  1 . The upper setting tool portions  94  include a radially enlarged sleeve  96  that presents an external profile  98  that is shaped to be complimentary to the landing profile  18  of the tubing head assembly housing  14 . The upper setting tool portions  94  may, therefore, be releasably latched or affixed to the tubing hanger assembly  14  by lowering the upper setting tool portions  94  into the tubing head assembly housing  14  so that the two profiles  18 ,  98  become interlocked. 
   An annular fluid chamber  100  is defined between the sleeve  96  on its radial exterior and the drill pipe section  74  on the radial interior. The lower end of the chamber  100  is provided by the upper piston surface  102  of the tool piston body  70  while the upper end of the chamber  100  is provided by a cap  104  that is secured by threading to the sleeve  96 . Various seals are used to make the chamber  100  fluid tight, as is known in the art. 
   The cap  104  is fitted with a fluid inlet  106  and a fluid outlet  108 . Hydraulic lines  110 ,  112 , shown schematically, are affixed to the each of these respective fittings. Hydraulic line  110  is used to transmit fluid to the fluid inlet  106  and into the chamber  100  from an external pressurized fluid source (not shown) while the hydraulic line  112  is used to receive used fluid exiting the chamber  100  through the fluid outlet  108  and transmit it to a fluid depository (not shown). 
   The running and setting tool is initially contained within the tubing head assembly  12 , as  FIG. 1  illustrates, and secured against axial movement therein by removable set screws  114  that are disposed through the tubing head assembly housing  14  and into engagement with the tool piston body  70 . Because the set screws  114  engage the tool piston body  70  and the upper setting tool portions  94  are secured within the tubing head assembly  12 , the running and setting tool  10  is initially interconnected with the tubing head assembly  12  in the manner shown in FIG.  1 . Those of skill in the art will understand that, as a result of this interconnection, the tubing head assembly  12  may be lifted by lifting upwardly on the drill pipe section  78 . 
     FIG. 2  illustrates the running and setting tool assembly  10  and the tubing head assembly  12  after the casing string and riser have been run and landed at the subsea wellhead on the ocean floor. Pressurized fluid  116  is directed into the flowbore  92  from a point above the portion shown of drill string member  78 . The fluid  116  fills the flowbore  92  as well as the string of casing members  66  below the tool  10 . A pressure test is thereby conducted that allows operators to determine the presence and location of fluid leaks in the casing. 
     FIG. 2  also depicts a stem head assembly  118  which, those of skill in the art will understand, is an opening and seating area that is provided on the upper end of a floating structure or platform, such as a spar floating platform. The stem head assembly  118  is shaped and sized to receive therein the stem head adapter plate  24  in a latched seating which is shown in FIG.  3 . 
     FIGS. 2 and 3  depict the operation of landing the running and setting tool assembly  10  upon the stem head assembly  118 . In  FIG. 2 , the lower wellhead assembly  32  is disposed within the stem head assembly  118 . However, the stem head adapter plate  24  is not yet seated upon the stem head  118 . Fluid  120  is then pumped into chamber  100  through the hydraulic line  110  and fluid inlet  106 . The set screws  114  are then loosened so that the tool piston body  70  of the running and setting tool  10  can move axially with respect to the tubing head assembly housing  14 . Consequently, the tubing head assembly  12  is freed to move axially downward with respect to the running and setting tool  10  until the stem head adapter plate  24  is seated upon the stem head assembly  118 . As the tubing head assembly  12  descends, the fluid  120  is expelled from the chamber  100  through the fluid outlet  108  and hydraulic line  112 . The operation of expelling the fluid  120  slows the downward movement of the tubing head assembly  12  and, thereby, assures that the tubing head assembly  12  is landed onto the stem head  118  in a controlled manner. The tubing head assembly  12  is then secured to the stem head assembly  118 , as depicted in  FIG. 4 , using split rings  122  and retainer bolts  124 . The details of such securing operations are known in the art and, therefore, will not be detailed here. 
   Once the tubing head assembly  12  has been secured to the stem head assembly  118 , the running and setting tool  10  is then tensioned to test the riser. At this point, the seal assembly  38  is then energized or set.  FIG. 5  illustrates the seal assembly  38  being set or energized. Fluid  120  is again pumped into chamber  100  and exerts fluid pressure upon piston surface  102  of the piston body  70 . Because the tubing head assembly is secured to the stem head  118 , the fluid pressure moves the piston body  70  downwardly within the tubing head housing  14 . The setting shoulder  88  of the landing sub  86  urges the setting sleeve  52  downwardly, thereby setting the seal assembly  38 . 
   A subsequent pressure test of the seal assembly  38  may then be conducted. The test is illustrated in  FIG. 6  which shows that cover  22  has been removed from the lateral fluid test port  20  in the tubing head housing  14 . A test pressure port  126  is affixed to the test port  20 . Fluid  128  is then pumped through the test port  20  and into the annular space between the tubing head housing  14  and the drill pipe member  82 . Fluid pressure may be increased in accordance with a user&#39;s requirement or to a pressure at which it is desired to ensure that the seal assembly  38  will contain fluid. 
   Once pressure testing of the seal assembly  38  has been conducted, the running and setting tool  10  is removed from the tubing head assembly  12  by detachably separating the external profile  98  of the radially enlarged sleeve  96  from the interior profile  18  of the tubing head housing  14 . In the exemplary embodiment depicted in  FIG. 7 , the upper drill string portions  78 ,  74  are rotated in a clockwise manner to unthread the profile  98  from the profile  18 . The running and setting tool  10  may then be completely removed from the tubing head  12  by pulling upwardly on the drill string section  78 . 
   After the running and setting tool  10  has been removed from the tubing head housing  14 , a blowout preventer (or BOP)  130  is installed atop the tubing head housing  14 .  FIG. 8  illustrates such an installation. The structure and operation of BOP&#39;s is well known and understood in the art and, therefore, will not be described here. The BOP  130  includes a downwardly directed narrowed neck  132  having an exterior profile  134  that is shaped and sized to be complimentary to the interior profile  18  of the tubing head housing  14 . The BOP  130  is secured to the tubing head assembly  12  by latching the neck  132  into the profile  18 . 
     FIG. 9  illustrates conduct of a subsequent pressure test. A combination test plug/running and retrieving tool  136  is disposed downward through the BOP and into the flowbore  36  of the installed tubing head assembly  12 . The test plug/running and receiving tool  136  includes an enlarged piston head  138  that is threadedly secured to a section of drill pipe  140 . Pressurized fluid  142  is then inserted into the flowbore  36  above the piston head  138 . 
   The invention may be considered to provide a wellhead assembly system that is useful for both installing tubing head components onto a floating platform as well as conducting operations required for “tying back” a subsea wellhead to the sea-borne tubing head. These latter operations include tension and pressure testing integrity checks for the riser or casing string. This wellhead assembly system may be considered to be made up, generally, of the running and setting tool  10 , the tubing head assembly  12  along with the affixed casing sleeve  34 . 
   While the invention has been shown in only some 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 invention.

Technology Classification (CPC): 4