Abstract:
A system for controlling a blowout preventer stack and subsea test tree connected to a subsea wellhead assembly, the system comprising: a marine riser engageable with the subsea wellhead assembly; a lower marine riser package configured to be attached to the marine riser in the subsea environment, wherein the blowout preventer is configured to be removably attached to the lower marine riser package; an umbilical located outside of the marine riser adapted to communicate control fluids, electrical signals and/or fiber optic communications to a subsea controller, wherein the subsea controller is configured to receive control fluids and/or signals from the umbilical and to provide functions to the blowout preventer stack and subsea test tree, further wherein the subsea controller stabs into the system above the subsea wellhead assembly. This out-of-marine riser design provides for simplification in design criteria associated with the subsea controller and umbilical system.

Description:
BACKGROUND 
     Drilling and producing offshore oil and gas wells includes the use of offshore facilities for the exploitation of undersea petroleum and natural gas deposits. Offshore systems often include a marine riser which connects surface equipment to a blowout preventer stack which is connected to a subsea wellhead. 
     Offshore systems are frequently equipped for well testing operations and include a safety shut-in system which automatically prevents fluid communication between the subsea wellhead and the surface. A typical safety shut-in system comprises a subsea test tree which is lowered through the riser and landed inside the blowout preventer stack. 
     A subsea test tree typically includes one or more safety valves that can automatically shut-in a well in the event of an emergency, such as a natural disaster. Hydraulic, electrical and fiber optic communications to, inter alia, operate the valves and devices in a blowout preventer stack are communicated from a surface control system by way of an umbilical. 
     Normally, when a subsea test tree is utilized in subsea applications, the subsea test tree comprises a subsea controller (e.g., multiplex controller) and umbilical system lowered with the subsea test tree and contained wholly within the marine riser. The subsea controller and umbilical system serve to operate the subsea test tree. These in-marine riser systems must work for extended periods of time with multiple installation and removal cycles within the confined space of a blowout preventer. 
     In addition, due to containment within the marine riser, the subsea controller and umbilical system must be designed to withstand both the fluids and temperatures associated with the harsh in-riser environment. Due to the unforgiving conditions, the typical life span for the subsea controller and umbilical system is less than two years. 
     Accordingly, there exists a need for a subsea controller and umbilical system that does not subject the devices to the harsh in-marine riser conditions and still provides for appropriate hydraulic, electrical and fiber optic communications to the valves and devices within a blowout preventer stack, including a subsea test tree. 
     SUMMARY 
     Disclosed is a system for controlling a blowout preventer stack and subsea test tree connected to a subsea wellhead assembly. The system includes a marine riser attachable to a lower marine riser package (“LMRP”), which is removably attached with the blowout preventer stack. An umbilical located outside of the marine riser communicates control fluids, electrical signals and/or fiber optic communications to a subsea controller. The subsea controller receives the control fluids and/or signals from the umbilical and controls the subsea test tree. The subsea controller ties into the drilling system above the subsea wellhead assembly by way of a function spool and corresponding stab plate. 
     The subsea controller and umbilical system are located in the out-of-marine riser environment, which provides substantial benefits. In particular, the out-of-marine riser design provides for simplification in design criteria associated with the subsea controller and umbilical system. Specifically, the devices incur reduced temperature, harsh fluid exposure, and marine riser loading and unloading. 
     Further, by removing the subsea controller and umbilical systems from the interior of the marine riser, the devices are no longer dependent on the diameter of the marine riser and can be designed larger or smaller depending on needs. Moving the subsea controller and umbilical system outside of the marine riser extends the lifespan of these components. 
    
    
     
       DRAWINGS 
       For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  shows a prior art schematic depicting a subsea control system utilizing an in-marine riser umbilical and in-marine riser control module. 
         FIG. 2  shows a prior art schematic depicting a subsea control system utilizing an out-of-marine riser umbilical and in-marine riser control module. 
         FIG. 3  shows one embodiment of the present invention depicting a subsea control system for controlling a subsea test tree utilizing an out-of-marine riser umbilical and out-of-marine riser control module wherein the subsea controller ties into a function spool located below the blowout preventer. 
         FIG. 4  shows another embodiment of the present invention depicting a subsea control system for controlling a subsea test tree utilizing an out-of-marine riser umbilical and out-of-marine riser control module wherein the subsea controller ties into a function spool located above the blowout preventer. 
         FIG. 5  shows a detailed view of the function spool illustrated in  FIGS. 3 and 4 . 
     
    
    
     DETAILED DESCRIPTION 
     The following discussion is directed to various embodiments of the invention. The drawing figures are not necessarily to scale. Certain features of the embodiments 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. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. 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. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment. 
     Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ” The use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components. 
     Referring now to  FIGS. 1 and 2 , schematic views of two embodiments of a prior art offshore drilling system  10  are shown. The prior art drilling system  10  comprises an offshore drilling platform  100  on or above a water surface  103  equipped with a derrick  101  and positioned over a subsea wellhead assembly  102 . The offshore platform may be an offshore floating platform, an anchored vessel or even a jack-up type of platform. 
     A marine riser  104  extends from the platform  100  to a lower marine riser package  112  (“LMRP”). A typical LMRP consists of a ball/flex joint coupled to the marine riser, marine riser adapter, kill and auxiliary lines and subsea control modules. The lower marine riser package  112  is operatively connected to a blowout preventer stack  105  (“BOP stack”). A typical BOP stack consists of one or more preventers, spools, valves, and nipples. The BOP stack  105  is operatively connected to a subsea wellhead assembly  102  which is, in turn, operatively connected to a subterranean well  106 . 
     The prior art drilling system illustrated in  FIG. 1  also includes a subsea test tree  107  (“SSTT”). A subsea test tree typically includes one or more safety valves that can shut-in a well in the event the platform  100  needs to be disengaged from the well  106 . As illustrated in prior art  FIG. 1 , the SSTT  107  is landed in the BOP stack  105  by way of the landing string  108  which is disposed within the marine riser  104 . 
     During operation, hydraulic, electrical and/or fiber optic communications are provided from a surface control system  110  to control actuatable devices in the BOP stack, including the SSTT  107 . The surface control system  110  is configured to provide hydraulic pressure feeding various hydraulically operated devices, such as valves in the SSTT. The surface control system  110  can also regulate and supply electrical signals to feed various electrically operated devices, such as latches in SSTT. 
     The surface control system  110  will also generally include a means for conveying hydraulic, electrical and/or fiber optic communications, such as an umbilical  109  extending from the surface control system  110  to the subsea equipment to be controlled. As illustrated in prior art  FIG. 1 , the umbilical  109  can be coupled to the landing string  108  and, accordingly, disposed within the marine riser  104 . Alternatively, as illustrated in prior art  FIG. 2 , the umbilical  209  can be external to the marine riser  204  in open water. In either prior art embodiment, unlike the present invention, the umbilical  109 ,  209  ties into the drilling system  10 ,  20  at the subsea wellhead assembly  102 ,  202  or production tree  113 ,  213 , but below the BOP stack  105 ,  205 . 
     As illustrated in prior art  FIGS. 1 and 2 , a subsea controller  111 ,  211  is located at the subsea wellhead assembly  102 ,  202  inside drilling system  10 ,  20 . The subsea controller  111 ,  211  could also be located at a subsea production tree  113 ,  213 , below the blowout preventer  105 ,  205  and subsea test tree  107 ,  207 . Because the subsea controller  111 ,  211  is located in the drilling system  10 ,  20 , movement between the physical components (e.g., marine riser  104 ,  204 , subsea test tree  107 ,  207 , retainer valves, etc.) and the sea currents may cause damage to the umbilical  109 ,  209  system and subsea controller  111 ,  211 , thus reducing the useful life of the system. 
     Referring to  FIG. 3 , one embodiment of the present invention as part of a drilling system  30  is shown. As seen in  FIG. 3 , a SSTT  307  is located within a BOP stack  305 , below a LMRP  312 . The SSTT  307  provides well isolation and latch and unlatch functionality, as well as hydrocarbon retention when conditions on the platform above and/or in the well below the subsea wellhead assembly  302  deviate from preset limits. This allows the floating platform (not shown in  FIG. 3 ) to relocate if needed by disengaging the riser  304  from the well. 
     The SSTT  307  is landed in the BOP stack  305  on landing string  308  through marine riser  304 . The SSTT  307  may include a valve assembly comprising safety valves and latches. The safety valves may act as master control valves during testing of the well. The latch allows an upper portion of landing string  308  to be disconnected from the SSTT  307  if desired. The BOP stack  305  may include one or more ram preventers and one or more annular preventers. The embodiments are not limited to the particular embodiments of SSTT  307  and BOP stack  305  shown in  FIGS. 3-5 , but any other combination of electrically powered valves and preventers that control flow of formation fluids through the landing string  308  may also be used. For instance, a single preventer could be used rather than a BOP stack. Further, the safety valves could comprise, e.g., flapper valves and ball valves. 
     A retainer valve  315  is arranged on the landing string  308  to prevent fluid in an upper portion of the landing string  308  from draining into the riser  304  when disconnected from the SSTT  307 . An out-of-riser umbilical  309  provides a path for conveying the electrical power for operating the SSTT  307  and retainer valve  315 . The out-of-riser umbilical  309  also provides a path for connecting a surface operator/control system (such as for example surface control system  210  in  FIG. 2 ) to the subsea controller  318 . The subsea controller  318  can include a control circuit and other electrical elements such as subsea telemetry boards, a power regulator and a battery. These other electrical elements are not shown in the exemplary embodiments in the Figures, but are commonly known to those of ordinary skill in the art. 
     As noted above with regard to the prior art, subsea test trees traditionally relied on control fluids and/or electrical signals supplied from an in-marine riser control system. As seen in the embodiment shown in  FIG. 3 , the umbilical system  309  and subsea controller  318  supplying control fluids and/or electrical signals are located outside the marine riser  304  and stab into a function spool  311  located above the subsea wellhead assembly  302 , but below the blowout preventer stack  305 . The subsea controller  318  is operatively and removably coupled to the system  30  by way of the function spool  311  located above the subsea wellhead  302 . In  FIG. 3 , the function spool  311  is located above the subsea production tree  313 . The function spool  311  includes a stab plate  314  which includes a series of fluid connectors hydraulically connectable to the subsea controller  318  and out-of-riser umbilical  309 . Each of the fluid connectors includes a check valve that prevents fluid expulsion from the connectors while the connectors are disengaged, and allows bidirectional fluid flow while the connectors are engaged. The subsea controller  318  and umbilical  309  contain similar fluid connectors mateable with the stab plate  314 . When the subsea controller  318  and stab plate  314  are mated, the subsea controller  318  can provide hydraulic fluids and control signals to operate any actuatable devices in the BOP stack  305 , including the SSTT  307 . More detail on the function spool is explained below. 
     Referring now to  FIG. 4 , another embodiment of the present invention as part of a drilling system  40  is illustrated in which the umbilical system  409  and subsea controller  418  supplying control fluids and/or electrical signals are located outside the marine riser  404  and stab into a function spool  411  located above the lower marine riser package  412 . 
     The subsea controller  418  is operatively and removably coupled to the system  40  by way of the function spool  411  located above the subsea wellhead  402 . In the embodiment in  FIG. 4 , the function spool  411  is located above the BOP stack  405 . The function spool  411  includes a stab plate  414  which includes a series of fluid connectors hydraulically connectable to the subsea controller  418  and out-of-riser umbilical  409 . Each of the fluid connectors includes a check valve that prevents fluid expulsion from the connectors while the connectors are disengaged, and allows bidirectional fluid flow while the connectors are engaged. The subsea controller  418  and the umbilical  409  contain similar fluid connectors mateable with the stab plate  414 . When the subsea controller  418  and stab plate  414  are mated, the subsea controller  418  can provide hydraulic fluids and control signals to operate any actuatable devices in the blowout preventer stack  405 , including the subsea test tree  407 . 
     Referring to  FIG. 5 , the out-of-riser umbilical  509  and subsea controller  518  mate with the function spool  511  to provide hydraulic fluids and/or electrical signals to the subsea test tree  507 . Hydraulic fluid is delivered to the function spool  511  via the stab plate  514  and through galleries  515  that provide fluid paths to the drilling system through the functional spool  511 . From there, internal porting  516  delivers the control fluids to the subsea test tree  507 . The galleries  515  are disposed between a sealing surface  517  within the function spool  511 . Electrical conduits may be used for transmitting electrical signals to the subsea test tree  507 .