System for controlling in-riser functions from out-of-riser control system

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.

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.

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 .

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 .