Abstract:
Methods for deploying a subsea blowout preventer stack system comprising a lower marine riser package, a blowout preventer stack with a first ram blowout preventer, and an additional blowout preventer package releasably coupled to the blowout preventer stack and comprising a second ram blowout preventer. The subsea blowout preventer stack assembly can be deployed by coupling a drilling riser to the lower marine riser package that is releasably connected to the blowout preventer stack. The lower marine riser package and blowout preventer stack are then toward a subsea wellhead and then landed on the additional blowout preventer package that is coupled to the subsea wellhead.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is a continuation of U.S. application Ser. No. 12/134,958 filed Jun. 6, 2008, which claims the benefit of U.S. Provisional Patent Application No. 60/933,934 filed Jun. 8, 2007, both of which are incorporated herein by reference in their entireties for all purposes. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not Applicable. 
       BACKGROUND 
       [0003]    The present invention relates generally to the configuration and deployment of pressure control equipment used in drilling subsea wells. More particularly, the present invention relates to subsea blowout preventer stack systems. 
         [0004]    As drilling rigs venture into ever increasing water depths and encounter new challenges, well control has become increasingly problematic. As costs of floating mobile offshore drilling units escalate, traditional time-intensive operations are constantly being re-evaluated in an effort to reduce overall non-drilling time, thereby increasing the drilling efficiency of the rig. 
         [0005]    One of the most time-intensive operations is running the riser, which provides a plurality of parallel fluid conduits between the drilling rig at the surface and the blowout preventer (BOP) stack coupled to the wellhead at the seafloor. In order to facilitate handling of the riser on the rig, the riser is usually constructed by connecting a number of joints that are generally less than fifty feet in length. The riser is “run” by connecting a joint of riser to the BOP stack, lowering the riser-connected BOP stack a short distance, and then connecting another joint of riser to the uppermost end of the riser string. This process continues until the BOP stack is lowered to the wellhead at the seafloor. 
         [0006]    In water depths in excess of 5,000 ft., running the riser generally takes several days to complete. Thus, minimizing the number of times the riser must be run is critical to minimizing the time needed to drill and complete a well. Since the BOP stack is installed at the very bottom of the riser, attempts to increase the amount of time that the BOP stack can stay on the wellhead are being explored. One factor limiting the time a BOP stack can stay on the wellhead is for maintenance of the ram BOP packer seals. Ram BOP packer seals have a limited useful life and once that limit is reached the ram BOP cannot be used until the seals have been replaced. 
         [0007]    One common way to improve the time a BOP stack can stay on the wellhead is to increase the number of useable ram BOP cavities in the BOP stack to the point of having a “primary” and “secondary” ram BOP cavity for each size installed. In this way, the time that a BOP stack can remain operational on the wellhead would be effectively doubled. However, simply increasing the number of ram BOP cavities in a subsea BOP stack presents its own set of new challenges, such as increasing the size and weight of the BOP stack. 
         [0008]    Drilling in deep water has often utilized subsea BOP stacks having four to six ram BOP cavities. Increasing the number of ram BOP cavities, such as to eight or ten cavities would increase the weight of the BOP stack, in some cases to a million pounds or more. Many existing rigs do not have the capacity to handle and operate such a BOP stack. In order to safely operate such a system, enhancements would be required to not only the BOP stack handling equipment on the rig, but also to the drill floor equipment, the drawworks and other hoisting equipment, the rotary table, the derrick, and the riser. Enhancing all of this equipment would likely require expanding the basic rig design to allow it to carry the additional weight of all the enhanced equipment systems and provide room for handling and storing the BOP stack. 
         [0009]    Thus, there remains a need to develop methods and apparatus for allowing improved redundancy and operational times of subsea BOP stacks in order to overcome some of the foregoing difficulties while providing more advantageous overall results. 
       SUMMARY OF THE PREFERRED EMBODIMENTS 
       [0010]    The embodiments of the present invention are directed toward methods for deploying a subsea blowout preventer stack system comprising a lower marine riser package, a blowout preventer stack with a first ram blowout preventer, and an additional blowout preventer package releasably coupled to the blowout preventer stack and comprising a second ram blowout preventer. The subsea blowout preventer stack assembly can be deployed by coupling a drilling riser to the lower marine riser package that is releasably connected to the blowout preventer stack. The lower marine riser package and blowout preventer stack are then lowered toward a subsea wellhead and landed on the additional blowout preventer package that is already in place on the subsea wellhead. In certain embodiments, neither a drilling rig nor the drilling riser is used to deploy and land the first additional blowout preventer package on the subsea wellhead. During drilling operations, the ram blowout preventers in the first additional blowout preventer package can be used as the primary blowout preventers, leaving the ram blowout preventers in the blowout preventer stack unused. 
         [0011]    In one deployment method, a first additional blowout preventer package is deployed on a first wellhead and a second additional blowout preventer package is deployed on a second subsea wellhead. The BOP stack is landed on the first additional blowout preventer package and drilling operations performed through the first wellhead using the ram blowout preventers of the first additional blowout preventer package as the primary blowout preventers. Once drilling is complete at the first wellhead, the blowout preventer stack is disconnected from the first additional blowout preventer package landed on the second additional blowout preventer package. In this method, the blowout preventer stack can stay subsea while drilling several wells using more than one additional blowout preventer package. 
         [0012]    In some deployment methods, a second additional blowout preventer package is deployed to a subsea parking pile. Once the useful life of the first additional blowout preventer package has been reached the blowout preventer stack is disconnected from the first additional blowout preventer package and landed on the second additional blowout preventer package. The first additional blowout preventer package is then disconnected from the subsea wellhead and retrieved to the surface while the blowout preventer stack and the second additional blowout preventer package are landed on the subsea wellhead. Thus, the blowout preventer stack can remain subsea with minimal disruption to the drilling program while the additional blowout preventer packages are retrieved and maintained. 
         [0013]    Thus, the present invention comprises a combination of features and advantages that enable it to overcome various problems of prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0014]    For a more detailed description of the preferred embodiment of the present invention, reference will now be made to the accompanying drawings, wherein: 
           [0015]      FIG. 1  is an elevation view of a blowout preventer stack system constructed in accordance with embodiments of the present invention; 
           [0016]      FIG. 2  is an isometric view of a blowout preventer stack system constructed in accordance with embodiments of the present invention; 
           [0017]      FIGS. 3A and 3B  illustrate the deployment and utilization of a blowout preventer stack system constructed in accordance with embodiments of the present invention with a single wellhead; 
           [0018]      FIG. 4  illustrates the deployment and utilization of a blowout preventer stack system constructed in accordance with embodiments of the present invention with a single wellhead and a parking pile; and 
           [0019]      FIGS. 5A-5C  illustrate the deployment and utilization of a blowout preventer stack system constructed in accordance with embodiments of the present invention with a plurality of wellheads. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0020]    Referring now to  FIG. 1 , subsea BOP stack system  10  comprises lower marine riser package (LMRP)  12 , BOP stack  14 , and additional BOP package (ABP)  16 . Stack system  10  is shown in  FIG. 1  landed on subsea wellhead  18 . LMRP  12  comprises a flex joint/riser connector  20 , annular BOP  22 , wellbore connector  23 , control pods  24 , and choke/kill line connectors  26 . BOP stack  14  comprises annular BOP  22 , ram BOP&#39;s  28 , choke/kill line connectors  26 , choke/kill valves  30 , wellbore connector  32 , and auxiliary control pods  34 . ABP  16  comprises ram BOP&#39;s  28 , choke/kill valves  30 , and wellbore connector  32 . 
         [0021]    LMRP  12  and BOP stack  14  are coupled together by wellbore connector  23  that is engaged with a corresponding mandrel on the upper end of stack  14 . As is shown in  FIG. 2 , BOP stack  14  is similarly coupled to ABP  16  by connector  32  that engages mandrel  33  on ABP  16 . Both LMRP  12  and BOP stack  14  comprise re-entry and alignment systems  40  that allow the LMRP  12 /BOP stack  14  and stack  14 /ABP  16  connections to be made subsea with all the auxiliary connections (i.e. control pods, choke/kill lines) aligned. Choke/kill line connectors  26  interconnect choke/kill lines  36  and choke/kill valves  30  on stack  14  and ABP  16  to choke/kill lines  38  on riser connector  20 . 
         [0022]    Control pods  24  of LMRP  12  provide control signals to BOP stack  14  while auxiliary control pods  34  on BOP stack  14  provide control signals to ABP  16 . In certain embodiments, ram BOP&#39;s  28  in ABP  16  are controlled by auxiliary control pods  34 , which may be communicatively linked to control pods  24  via umbilical jumpers or some other releasable connection. In certain embodiments, the control functions for rain BOP&#39;s  28  of ABP  16  (as well as control functions for other equipment) may be integrated into control pods  24  on LMRP  12 , thus eliminating the need for auxiliary control pods  34 . Because ABP  16  is operated with BOP stack  14 , hydraulic accumulator bottles  42  mounted on the BOP stack can be used to support operation of the ABP. ABP  16  may also comprise a remotely operated vehicle (ROV) panel that provides control of the ABP functions by an ROV. 
         [0023]    LMRP  12  and BOP stack  14  are similar to, and can operate as, a convention two-component stack assembly. ABP  16  is installed between wellhead  18  and BOP stack  14  and provides additional rain BOP&#39;s  28  to provide redundancy and increase effective service life. In certain embodiments, ABP  16  will not be lowered from the rig to the wellhead on a conventional riser with the rest of the BOP stack but will be deployed separately. This separate deployment can be accomplished on drill pipe, heavy wireline, or any other means, either from the drilling rig if it has a dual activity derrick, from another rig (perhaps of lesser drilling capabilities), or from a heavy duty workboat or tender vessel. In addition to being run, the ABP  16  could be stored and serviced by a vessel other than the drilling rig, thus eliminating the need for additional storage space and handling capacity on the drilling rig. 
         [0024]    Referring now to  FIGS. 3A and 3B , a single ABP  16  can be landed on wellhead  18  via drill string, wireline, or other non-riser system by service vessel  48  prior to drilling rig  50  arriving on site. Drilling rig  50  would then run the BOP stack  14  and LMRP  12  assembly on conventional drilling riser and land the stack on ABP  16 . Normal drilling operations could utilize the rain BOP&#39;s of ABP  16  until their useful life was reached. At that point, drilling could continue with the rain BOP&#39;s of BOP stack  14  without disturbing the stack assembly, thus increasing drilling time before having to bring the stack to the surface for maintenance. 
         [0025]    Referring now to  FIG. 4 , a drilling site may comprise a wellhead  18  and a parking pile  52 . Parking pile  52  provides a location for the subsea storage of an additional ABP  16 . A first ABP  16  can be run as described above in reference to  FIG. 3A  by service vessel  48 . BOP stack  14  and LMRP  16  can then be run by a drilling rig and drilling operations performed using the rain BOP&#39;s in ABP  16 . Before the useful life of the rain BOP&#39;s in ABP  16  is reached, a replacement ABP  16 A can be run by a service vessel and landed on parking pile  52 . When the first ABP  16  needs to be serviced, stack  14  and LMRP  12  can be disconnect from the ABP but remain subsea. Once ABP  16  is pulled to the surface for servicing, replacement ABP  16 A can be disconnected form parking pile  52  and landed on wellhead  18 . Replacement ABP  16 A can be moved from parking pile  52  to wellhead  18  by drilling rig  50  by landing BOP stack  14  on ABP  16 A and then moving the entire assembly together. Replacement ABP  16 A can also be moved onto wellhead  18  by a service vessel as BOP stack  14  is supported by the drilling rig. 
         [0026]    Referring now to  FIGS. 5A-5C , multiple ABP systems  16 A- 16 B can be used to drill multiple wells on a plurality of wellheads  18 A- 18 C. A first ABP  16 A can be deployed onto wellhead  18 A with BOP stack  14  and LMRP  12  being run and landed atop ABP  16 A and drilling operations commenced. While the first well is being drilled, a second ABP  16 B is deployed and landed onto the next wellhead  18 B. When the first well is completed, the BOP stack  14  and LMRP  12  can simply be unlatched, lifted, relocated the second wellhead  18 B and landed on second ABP  16 B. While the second well is being completed, the first ABP  16 A can be retrieved from the first wellhead  18 A and moved to a third wellhead  18 C, or brought back to the surface for maintenance or repair. 
         [0027]    Under any of the uses of an ABP as described above, the rain BOP cavities in the ABP can be considered the primary cavities while the rain BOP cavities in the BOP stack would then be considered the secondary cavities. This would allow the BOP stack and LMRP to stay down almost indefinitely because the secondary cavities in the BOP stack would only be utilized after the primary cavities in the ABP were rendered inoperable. And the primary BOP cavities in the ABP could be retrieved to the surface and maintained while the BOP stack and LMRP were drilling atop another ABP. 
         [0028]    While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied, so long as the override apparatus retain the advantages discussed herein. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.