Patent Document

CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not Applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not Applicable. 
     BACKGROUND OF THE INVENTION 
     The present invention relates to the control and monitoring of the operation of subsea wells. More particularly, the present invention relates to a distributed system for the control and monitoring of a plurality of wells in a subsea field. 
     In practice, there are three types of wells to be controlled: production wells, wells that are being maintained (“work-over wells”), and drilling wells. Each is traditionally controlled from a surface platform by dedicated control equipment attached to a riser and a wellhead tree (in the production environment) or a blowout preventer (BOP) (in the drilling or work-over environment). Such dedicated control systems are expensive, heavy, and complex and, a dedicated system for each well is typical. Thus, there is a long-felt need to reduce the number of such control systems and to reduce the complexity of the risers that must be used with them. 
     In situations in which some wells are producing in an area near where other wells are being drilled or worked over, various types of vessels and control equipment are used. As described above, typically the control systems for the drilling operations are different from those for the production operation, and both are different from the work-over situation. Thus, there is a need to reduce the number and type of control and distribution systems in areas or fields in which production, drilling, and/or work-over operations are occurring in order to overcome some of the foregoing difficulties while providing more advantageous overall results. 
     SUMMARY OF THE INVENTION 
     Various of the above-described problems are addressed in the numerous aspects of the present invention, either alone or in combination. 
     A system comprising a surface installation in position above a plurality of subsea wells disposed within the watch circle of the surface installation. A plurality of flowlines directly couple at least one of the plurality of subsea wells to the surface installation. A control station, a hydraulic power unit, and an injection unit are disposed on the surface installation. A distribution body is disposed on the seafloor and is coupled to each of the control station, hydraulic power unit, and the injection unit via one or more umbilicals. A first wellhead component is disposed on one of the subsea wells and is coupled to the distribution body via one or more flying leads that provide electrical, hydraulic, and fluid communication. A second wellhead component is disposed on another one of the subsea wells and coupled to the distribution body via one or more flying leads that provide electrical, hydraulic, and fluid communication. The control station is operable to provide control functions to the first and second wellhead components during drilling, workover, and production activities. 
     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 
       For a more detailed understanding of the present invention, reference is made to the accompanying Figures, wherein: 
         FIG. 1  illustrates a subsea field having a distributed control system constructed in accordance with embodiments of the present invention; 
         FIG. 2  is a partial schematic representation of a multiplexed electro-hydraulic subsea distributed control system constructed in accordance with embodiments of the present invention; 
         FIG. 3  is a partial schematic representation of a separated electro-hydraulic subsea distributed control system constructed in accordance with embodiments of the present invention; 
         FIG. 4  is a partial schematic representation of an electro-hydraulic subsea direct control system constructed in accordance with embodiments of the present invention; 
         FIG. 5  is a partial schematic representation of a system for the installation of an umbilical and riser constructed in accordance with embodiments of the present invention; 
         FIG. 6  is a partial schematic representation of a directly controlled subsea tree constructed in accordance with embodiments of the present invention; 
         FIG. 7  is a partial schematic representation of a wellhead in a drilling configuration having a control system constructed in accordance with embodiments of the present invention; 
         FIG. 8  is a partial schematic representation of a wellhead in a production configuration having a control system constructed in accordance with embodiments of the present invention; 
         FIG. 9  is a partial schematic representation of a wellhead in a workover configuration having a control system constructed in accordance with embodiments of the present invention; 
         FIG. 10  is a partial sectional view of a subsea tree with an exterior production master valve; 
         FIG. 11  is a partial sectional view of a subsea tree with integral valves; 
         FIG. 12  is a partial sectional view of a subsea tree with vertical annulus and production strings; 
         FIG. 13  is a partial schematic view of a subsea hydraulic accumulator package; and 
         FIG. 14  is a partial schematic view of subsea distribution, control, and monitoring station. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     In the description that follows, like components 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. 
     Referring now to  FIG. 1 , floating platform  10  is positioned above a field of subsea wellheads  14 . Floating platform  10  is secured on location by mooring system  11  that allows the platform to be positioned at any location within watch circle  13 . Attached to some of subsea wellheads  14  are subsea trees  16 . Also seen on bottom  15  is distribution control and monitoring station  22 , which is coupled to subsea trees  16  by flying leads  24 . Floating platform  10  is connected to subsea trees  16  through risers  12 . Floating platform  10  performs distribution control and monitoring functions for subsea trees  16  through umbilicals  26  that terminate in subsea umbilical termination (SUT) assemblies including an electrical and hydraulic subsea umbilical termination assembly  18  and a chemical subsea umbilical termination assembly  20 . The subsea umbilical termination assemblies  18  and  20  are connected to distribution control and monitoring station  22  through flying leads  28  and  30 , respectively. 
     Referring now to  FIG. 2 , an electro-hydraulic multiplex control system for controlling subsea trees  16  from floating platform  10  ( FIG. 1 ) is seen. Topside primary control station  200 , hydraulic power unit  202 , master control station  203 , blowout preventer control system  205 , and injection unit  206  are all disposed on floating platform  10 . Topside primary control station (PCS)  200  communicates to master control station  203  through communications link  200 A. Master control station  203  includes an electrical power unit (EPU) and an uninterruptible power supply (UPS). Master control station  203  and hydraulic power unit (HPU)  202  are coupled to electrical-hydraulic umbilical line  26  that terminates on sea floor  15  in electrical-hydraulic umbilical termination assembly  18 , which is connected to distribution, control, and monitoring (DCM) station  22  through electrical-hydraulic flying lead  30 . 
     Electrical-hydraulic flying lead  30  provides electric control signals and pressurized hydraulic fluid to DCM station  22 , which comprises subsea distribution unit  22 D and control unit  22 E that includes control modules  22 C and hydraulic accumulator package  22 A. A variety of subsea control modules  22 C and accumulator packages  22 A that are alternative embodiments of the invention will occur to those of skill in the art without need for further description. Control unit  22 E is connected to subsea tree  16  by electrical flying lead  24 E that carries electrical signals between the control unit and the subsea tree. Distribution unit  22 D is connected to subsea tree  16  by hydraulic control flying lead  24 H that provides hydraulic communication between the distribution unit and the subsea tree. 
     Chemical injection unit  206  is connected through chemical umbilical  26 C to chemical injection umbilical termination assembly  20  on bottom  15 . Chemical injection umbilical termination assembly  20  is connected to subsea distribution unit  22 D by chemical flying lead  28 . Chemical injection is provided to subsea tree  16  by flying lead  24 C. 
     Also seen in  FIG. 2  is a BOP (blowout preventer) control system  205  that resides on floating platform  10  and is connected to electrical-hydraulic umbilical  26 . Various BOP control systems  205  will occur to those of skill in the art, as will various chemical injection units  206 , all of which are example embodiments of the invention and require no further explanation. Likewise, flying leads  28 ,  30 ,  24 C,  24 E, and  24 H, will be understood by those with skill in the art without further elaboration, and installation of such flying leads between the termination assemblies  18  and  20 , and subsea distribution unit  22 , will also be understood by those of skill in the arts to be accomplished in various example embodiments of the invention by using a remote operated vehicle (ROV—not shown). Likewise, the connections of flying leads  24 C,  24 E, and  24 H, between subsea distribution unit  22  and subsea tree  16  are accomplished in various example embodiments of the invention through the use of an ROV. 
     Referring now to  FIG. 3 , an alternative embodiment is seen in which topside PCS  200  is connected to hydraulic power unit  202 , well control panel  204 , and chemical injection unit  206 . Hydraulic power unit  202  and chemical injection unit  206  are also connected to well control panel  204 . Thus, well control panel  204  controls, from floating platform  10 , subsea trees  16  on bottom  15 . Such control is accomplished through electrical umbilical  26 E and hydraulic umbilical  26 H. Electrical umbilical  26 E is connected to electrical subsea umbilical termination assembly  18 E and control unit  22 E, as shown. Likewise, hydraulic umbilical  26 H is connected to distribution unit  22 D. Well control panel  204  communicates with chemical injection unit  206 , which is connected to chemical injection umbilical  26 C for umbilical communication with chemical injection umbilical termination assembly  20 . The subsea distribution unit  22  is connected to the chemical injection umbilical termination assembly  20  via chemical injection flying lead  28 . Subsea distribution unit  22 D provides hydraulic communication to subsea tree  16  through hydraulic flying lead  24 H and chemical injection communication to subsea tree  16  through flying lead  24 C. Control  22 E provides electrical communication to subsea tree  16  through flying lead  24 E. 
     Although not shown in  FIGS. 2 and 3 , it will be understood by those of skill in the art that multiple wells  16  are controlled, as seen in  FIG. 1 , through a single set of distribution control and monitoring components. Thus, the need for a single umbilical to each subsea tree  16  is eliminated and multiple wells are controlled, monitored, or have fluids distributed to them through single umbilicals  26 E,  26 H, and  26 C. At the same time, simplified risers  12  ( FIG. 1 ) connect in a substantially vertical manner to subsea trees  16 , allowing for insertion and removal of various tools useful in drilling, production, and work-over. Such insertion and removal of tools is not possible in systems in which production occurs through conduits that communicate to a central distribution control or monitoring station on the sea-floor, due to the acute angle between the well bore and the fluid conduit. 
     Referring now to  FIG. 4 , still another embodiment of well control is seen in which direct control to each well is accomplished. In the  FIG. 4  embodiment, PCS  200  communicates with chemical injection unit  206 , hydraulic power unit  202 , and well control panel  204 . In the illustrated embodiment, a single umbilical  26  is used for all electrical, hydraulic, and chemical injection functions and is separate from riser  12 . Riser  12  and umbilical  26  are connected directly to subsea trees  16 , as shown. 
     Referring now to  FIG. 5 , a system and method of installation of an umbilical  26  with riser  12  to a tree  16  is seen. Tree connector  500  and guide sleeve  502  are mounted on deck  510  of floating platform  10  ( FIG. 1 ). Umbilical  26  comprises a flexible, reel-held conduit that is supported by turndown sheave  520  and spooled on reel  504 . Umbilical  26  is fed from reel  504  through turndown sheave  520 , guide sleeve  502 , and tree connector  500 . From tree connector  500 , umbilical  26  is fed through the keel  525  of floating platform  10  at guide sleeve  504 . Through the use of an ROV, umbilical  26  is connected to subsea tree  16 . 
     Referring now to  FIG. 6 , a more detailed view of a direct control of subsea trees  16  is seen. Umbilical  26  (hydraulic or electro-hydraulic in an alternative embodiment) is supported by umbilical tensioner  600 . Umbilical  26  is attached to hose reel  612  and control/hydraulic unit  614  as will be understood by those of skill in the art. Umbilical  26  passes through umbilical tensioner  600  and tree connector  500  to which surface tree  604  is attached. A flow line  606  is connected to the top of surface tree  604  and supported by flow line tensioner  608 . Flow line  606  terminates in topside equipment  610  as well be understood by those of skill in the arts. 
     Referring now to  FIG. 7 , a more detailed view of a well in a drilling mode being controlled by multiplex systems of the type seen in  FIGS. 2 and 3  is illustrated. A pressure control device, such as surface blowout preventer  700 , is connected to a drilling or work-over riser  710  that is, in turn, connected to a subsea blowout preventer  720  through tieback connector  722 . Subsea blowout preventer  720  is mounted on wellhead  14  by tree connector  726 . Surface blowout preventer  700  is mounted on floating platform  10  ( FIG. 1 ) that can be positioned directly above wellhead  14  by moving the platform within its watch circle by the adjustment of the platform&#39;s mooring system. 
     Subsea blowout preventer  720  has various controls, as are known to those of skill in the art, which are coupled to subsea distribution unit  22  by flying leads  24 . Subsea distribution unit  22  includes subsea control module  22 C and subsea accumulator package  22 A. In various embodiments, subsea accumulator package  22 A includes a high-pressure accumulator, a low-pressure accumulator, and a “return” pressure accumulator. Subsea distribution unit  22  is mounted on subsea distribution unit docking platform  728  and is connected to floating platform  10  ( FIG. 1 ) via umbilicals  26  (as described in reference to  FIGS. 2 and 3 ). 
     Referring now to  FIG. 8 , the well of  FIG. 7  is shown in a production mode being controlled by the same multiplex system. A pressure control device, such as surface tree  800 , is connected to tubing riser  12 , which is connected to riser connecter  812  and subsea tree  16  as is understood by those of skill in the art. Subsea tree  16  includes master valves  816  and annulus valves  818  for access and control of the annulus between tubing  820  of wellhead  14  and the other components of the wellhead. Control and instrumentation junction plate  825 , which serves as a connector for subsea flying lead  24 . 
     Referring now to  FIG. 9 , an example embodiment is shown with the well in a work-over configuration. A pressure control device, such as surface blowout preventer or tree  900 , resides on floating platform  10  ( FIG. 1 ), and work-over riser  910  is connected to tie-back connector  922 . Subsea blowout preventer  720  is connected to subsea tree  16  via tree connector  726  and subsea flying lead umbilical  24  is connected to control and instrumentation junction plate  825  and subsea distribution unit  22 . As in the drilling mode of  FIG. 7 , floating platform  10  ( FIG. 1 ) that can be positioned directly above wellhead  14  by moving the platform within its watch circle by the adjustment of the platform&#39;s mooring system. 
     While a specialized subsea distribution unit  22  is useful in some embodiments for production, and a specialized subsea distribution unit  22  is useful in other example embodiments for drilling or work-over configurations, the examples seen in  FIGS. 7-9  show a common type of subsea distribution unit  22  having similar components. This allows for efficiencies in that the control and distribution functions for drilling, work-over, and production, are provided in one unit on the sea floor that can interface with a variety of equipment, such as risers  710 ,  810 , and  910 , subsurface blowout preventer  720 , and subsea tree  16 . Likewise, subsea flying lead umbilical  24  may include all control lines for all three operational modes or any combination of two modes. Examples of the controls provided in various embodiments include: BOP control, connector lock/unlock, tree control, DSSV control, chemical injection, annulus monitoring, instrumentation communication, and others. 
     Referring now to  FIG. 10 , an example embodiment of the subsea tree with an exterior production master valve is seen, in which riser connector  1000  attaches to subsea tree  1002  that includes sea plug  1004 . Master valves  1006 A and  1006 B control access on either side of sea plug  1004 . Annulus access valves  1010 A,  1010 B, and  1010 C control access to the subsea tree annulus on each side of sea plug  1004 . In various operational situations, pressure in an annulus can increase to an unacceptable level. In such cases, it is desirable both to monitor the annulus (e.g., through annulus valves  1010 A-C), and/or to provide fluids (e.g., drilling mud or cement) into the annulus through valves  1010 A-C. Likewise, should the annulus line attach to annulus access valve  1010 A be insufficient to carry the desired fluid into the annulus (for example, in embodiments in which the annulus line is sized merely for monitoring), then master valves  1006 A and  1006 B are manipulated such that a fluid (e.g., cement) is pumped down through a riser (connected to riser connecter  1000 ) and into annulus access passage  1011 . Annulus access valves  1010 A-C are manipulated such that the fluid then passes through annulus access passage  1012  into annulus  1020 . From the illustrated embodiment, and the above description, it will be understood by those of skill in the art how various other annulus control and access operations are performed through manipulation of master valves  1006 A and B and annulus access valves  1010 A-C. 
     Referring now to  FIG. 11 , an alternative embodiment of a subsea tree is seen in which the valves are integral with a spool piece. Rather than have master valves  1006 A and  1006 B controlling flow line access passage  1030  master valves  1106 A and  1106 B control the flow line  1101  directly. 
     Referring now to  FIG. 12 , still a further alternative embodiment is seen in which a subsea tree with a vertical annulus and production string is illustrated. Flow line  1201  is controlled by production master valves  1206 A and  1206 B housed within subsea tree  1202 . Also within subsea tree  1202  is cross-over valve  1250  which controls flow and a cross-over access passage  1252  that, in turn, controls communication between annulus access passage  1254  and flow line  1201 . Annulus master valve  1256  is provided an annulus access passage  1254  for providing access to annulus  1020 . 
     Referring now to  FIG. 13 , a hydraulic accumulator package is seen in which accumulator  1301  and accumulator  1302  are in connection with hydraulic supply line  1304  and hydraulic return line  1306  through hydraulic control valve  1308  (located on the bottom). Accumulators  1301  and  1302  are also in communication with another hydraulic control valve  1310 , which is located on the topside. As seen,  1308  and  1310  are two-position, single-throw valves. Other valves will occur to those of ordinary skill in the art as alternative examples. Supply pressure source  1312  is connected through valve  1310  to accumulator  1301  and through valve  1308  to hydraulic supply line  1304 , which is connected to the various well-control systems described above. The use of subsea accumulators as illustrated provides for multiple efficiencies in the hydraulic operations. 
     Referring now to  FIG. 14 , an example of DCM station  22  from  FIG. 1  is seen. DCM station  22  comprises hydraulic connectors  1401 , electrical connectors  1403 , accumulator bank  1405 , subsea control modules  1406 , electro-hydraulic umbilical connector  1407 , and injection umbilical connectors  1409 A-B. Hydraulic connectors  1401  and electrical connectors  1403  provide termination connection points for a plurality of hydraulic and electric flying leads that are connected to individual wellheads. Accumulator bank  1405  includes a plurality of hydraulic accumulators that store a predetermined volume of hydraulic fluid at a selected pressure. There may be fewer accumulators than there are connectors for flying leads because not all wells will require hydraulic circuit control with significant accumulators at the same time. 
     Subsea control modules  1406  house the various electrical circuits and control systems that connect to electrical connectors  1403 . An electrical-hydraulic umbilical connection  1407  connects to an electro-hydraulic flying lead that provides electrical signal and hydraulic communication with a floating platform. Likewise, injection connectors  1409 A and  1409 B are provided for the connections needed for the chemical injection flying leads. 
     Thus, DCM station  22 , through control modules  1406  and the multiplexers and valve-selectable manifolds disposed within the station, provides electrical and fluid communication between a plurality of distributed wells and a single floating installation so as to control equipment disposed on the wellheads as well as fluid injection capabilities. 
     The above description is given by way of example only and not intended to limit the scope of the invention as claimed. Other examples will occur to those of skill in the art, which are within the scope of the invention.

Technology Category: 0