Method for gate valve failsafe actuators

Abstract

In a subsea blowout preventer stack system with valves in the choke and kill lines with the need for failsafe operation or automatic movement of a safe position when the operating control signal is lost, a method of providing failsafe operation to the safe position comprising providing a hydraulic cylinder having a piston with a piston rod connected to the valve closure member, providing a first hydraulic supply at a first pressure to a first side of the piston to move the valve closure member to an actuated position, providing a second hydraulic supply at a second pressure lower than the first pressure to a second side of the piston to move the valve closure member to the safe position when the first hydraulic supply is removed.

Description

TECHNICAL FIELD

This invention relates to the method of providing failsafe gave valve actuators, especially at it applies to large gate valves and 20,000 p.s.i. blowout preventer stacks.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable

REFERENCE TO A “MICROFICHE APPENDIX”

Not applicable

BACKGROUND OF THE INVENTION

Deepwater offshore drilling requires that a vessel at the surface be connected through a drilling riser and a large blowout preventer stack to the seafloor wellhead. The seafloor wellhead is the structural anchor piece into the seabed and the basic support for the casing strings which are placed in the well bore as long tubular pressure vessels. During the process of drilling the well, the blowout preventer stack on the top of the subsea wellhead provides the second level of pressure control for the well. The first level being provided by the weighted drilling mud within the bore.

During the drilling process, weighted drilling mud circulates down a string of drill pipe to the drilling bit at the bottom of the hole and back up the annular area between the outside diameter of the drill pipe and the inside diameter of the drilled hole or the casing, depending on the depth.

Coming back up above the blowout preventer stack, the drilling mud will continue to travel back outside the drill pipe and inside the drilling riser, which is much large than the casing. The drilling riser has to be large enough to pass the casing strings run into the well, as well as the casing hangers which will suspend the casing strings. The bore in a contemporary riser will be at least twenty inches in diameter. It additionally has to be pressure competent to handle the pressure of the weighed mud, but does not have the same pressure requirement as the blowout preventer stack itself.

As wells are drilled into progressively deeper and deeper formations, the subsurface pressure and therefore the pressure which the blowout preventer stack must be able to withstand becomes greater and greater. This is the same for drilling on the surface of the land and subsea drilling on the surface of the seafloor. Early subsea blowout preventer stacks were of a 5,000 p.s.i. working pressure, and over time these evolved to 10,000 and 15,000 p.s.i. working pressure. As the working pressure of components becomes higher, the pressure holding components naturally become both heavier and taller. Additionally, in the higher pressure situations, redundant components have been added, again adding to the height. The 15,000 blowout preventer stacks have become in the range of 800,000 lbs. and 80 feet tall. This provides enormous complications on the ability to handle the equipment as well as the loadings on the seafloor wellhead. In addition to the direct weight load on the subsea wellheads, side angle loadings from the drilling riser when the surface vessel drifts off the well centerline are an enormous addition to the stresses on both the subsea wellhead and the seafloor formations.

When the blowout preventer stack working pressure is increased to 20,000 p.s.i. some estimates of the load is that it increases from 800,000 to 1,200,000 lbs. The height also increases, but how much is unclear at this time but it will likely approach 100 feet in height.

Another complication is that gate valves used in the choke and kill lines on these stacks must be rated at 20,000 p.s.i. also and must be automatically closed when there is a loss of the control signals. The high frictions caused by the high forces caused by potential 20,000 p.s.i. differentials are conventionally handled by large metal spring cartridges. The springs are extremely hard to design and obtain for these forces and in combination with the necessary housings they are installed in become not only very heavy but also relatively large. There are always at least six of these assemblies on the over weight crowded subsea blowout preventer stacks.

This has been the situation is subsea blowout preventer stacks since their early use in the 1960s and is more of a problem now than ever as the size and working pressure of this equipment both keep getting larger.

BRIEF SUMMARY OF THE INVENTION

The object of this invention is reduce the weight, size, and cost of subsea blowout preventer stacks.

A second object of this invention is to provide a failsafe means for gate valves on subsea blowout preventer stacks which do not depend on large spring cartridges.

A third object of this invention is to make a valve which can be switched form failsafe closed to failsafe hose by simply changing the fitting connections.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a view of a contemporary deep-water riser system.

FIG. 2 is a perspective view of a blowout preventer stack utilizing the features of this invention.

FIG. 3 is a perspective view of a subsea wellhead housing which the blowout preventer stack of this invention would land on.

FIG. 4 is a perspective view of the lower portion of the blowout preventer stack of FIG. 2, generally called the lower BOP stack.

FIG. 5 is a perspective view of the upper portion of the blowout preventer stack of FIG. 2, generally called the lower marine riser package or LMRP.

FIG. 6 is a perspective view of a section of the drilling riser which will be used to lower the blowout preventer stack.

FIG. 7 is a view of the blowout preventer stack of FIG. 2, taken along lines “7-7.

FIG. 8 is a view of the blowout preventer stack of FIG. 2, taken along lines “8-8.

FIG. 9 is a top view of FIG. 8.

FIG. 10 is view of a pair of block valves similar to item 128 in FIG. 4.

FIG. 11 is taken along lines “11-11” of FIG. 10 showing the body of a block valve.

DETAILED DESCRIPTION OF THE INVENTION

Referring now to FIG. 1, a view of a system 20 which might use the present invention is shown. It shows a floating vessel 22 on a body of water 24 and having a derrick 26. Drill pipe 28, drilling mud system 30, control reel 32, and control cable 34 are shown. A riser system 40 including a flex joint 42 is shown. During drilling the drilling mud circulated from the drilling mud system 30, up the standpipe 44, down the drill pipe 28, through the drill bit 46, back up through the casing strings 48 and 50, through the blowout preventer stack 60, up thru the riser system 40, and out the bell nipple at 62 back into the mud system 30.

Blowout preventer stack 60 is landed on a subsea wellhead system 64 landed on the seafloor 66. The blowout preventer stack 60 includes pressurized accumulators 68, kill valves 70, choke valves 72, choke and kill lines 74, choke and kill connectors 76, choke and kill flex means 78, and control pods 80.

Referring now to FIG. 2, the seafloor drilling system 100 comprises a lower blowout preventer stack 102, a lower marine riser package 104, a drilling riser joint 106, and control cables 108.

Referring now to FIG. 3, a subsea wellhead is shown which the seafloor drilling system lands on. It is the unseen upper portion of the subsea wellhead system 64 shown in FIG. 1.

Referring now to FIG. 4, the lower blowout preventer stack 102 comprises a lower structural section 120, vertical support bottle 122, and upper structural section 124, accumulators 126, choke and kill valves 128, blowout preventers 130 and an upper mandrel 132 which will be the connection point for the lower marine riser package.

Referring now to FIG. 5 the lower marine riser package 104 is shown comprising a lower marine riser package structure 140, an interface 142 for a remotely controlled vehicle (ROV), annular blowout preventers 146, choke and kill flex loops 148, a flexible passageway 150, a riser connector 152, and an upper half of a riser connector 154.

Referring now to FIG. 6, a drilling riser joint 106 is shown having a lower half of a riser connector 160, a upper half of a riser connector 154, and buoyancy sections 162.

Referring now to FIG. 7, is a view of seafloor drilling system 100 taken along lines “7-7” of FIG. 1 showing wellhead connector 170, lower marine riser connector 172, a man 174 for size perspective, and choke and kill valves 176.

Referring now to FIG. 8, is a view of seafloor drilling system 100 taken along lines “8-8” of FIG. 1.

Referring now to FIG. 9, is a top view of seafloor drilling system 100.

Referring now to FIG. 10, block valves 200 and 202 are shown to be similar, except valve block 202 does not have a lower outlet. The block valves are connected directly together requiring that the flow from the lower block valve passes through the valve 204 of the upper block valve 200. As a practical matter, the valve 206 on lower block valve 202 can be eliminated and the lower valve block can depend upon valve 204 as the back up valve. The block valves 200 and 202 are attached to the blowout preventer stack by flanges 208 and 210 as can be seen as item 128 in FIG. 4. The valves are normally actuated by ports such as indicated at 212 which is distal from the valve body. The return side of the gate valve actuators are connected with lines 214 proximate to the valve body as will be described later.

Referring now to FIG. 11 which is taken along lines “11-11” of FIG. 10 showing the body 220 of a block valve, the gate 222 in the open position on one side of the centerline and in the closed position on the other side of the centerline, a clamp style bonnet connection 224, a fitting 226 for filling the operating cylinder 228 with actuating fluid, and a return chamber 230. On a conventional valve the return chamber 230 would be large and filled with mechanical springs to return to the closed or failsafe position if the control system failed. The failsafe position would be considered to be the safe position of the valve. As the forces on these valves with a 20,000 p.s.i. differential are great, it is very difficult to design springs to provide this service. Additionally, as the return chamber with springs changes volume when the valve is actuated, extra consideration must be taken to accommodate the fluid volume. The valve of this invention rather utilizes a constant differential accumulator just like the large ones on the blowout preventer stack providing the fluid for operating cylinder 228, only smaller and at half the pressure charge. If the main accumulators are working at 3000 p.s.i., the smaller accumulators 232 will be charged to approximately 1500 p.s.i. so that the 3000 p.s.i. will be able to overwhelm the 1500 p.s.i. on the return side to operate, but when the 3000 p.s.i. operating signal is dropped to zero, the 1500 p.s.i. will close the valves safely. Constant differential accumulators such as this are described U.S. Pat. No. 6,202,753. On accumulator 232, working fluid is stored in chamber 234 and is communicated to the return chamber 230 through line 236. Nitrogen gas charge pressure is in chamber 238. Compensating seawater pressure is introduced into chamber 240 and chamber 242 has a vacuum or simply standard air pressure in it.

In some cases it is beneficial to have the valve move to the failsafe opened position rather than the failsafe closed position. In the case of gate valves, this usually means making installing a special gate with the hole in the gate in a different position. In the case of this operator, the line attached to fitting 226 needs to be moved to the fitting 244 and the line 236 needs to be moved to the fitting 226.

This method will apply to gate valves, ball valve, plug valves and other type valves. The safe position is typically the closed position of a valve, but in some cases the operational safe position has been the open position.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. In a subsea blowout preventer stack system with valves in the choke and kill lines with the need for failsafe operation or automatic movement of a safe position when the operating control signal is lost,

a method of providing failsafe operation to the safe position comprising

providing a valve closure member,

providing a hydraulic cylinder having a piston with a piston rod connected to the valve closure member,

providing a first hydraulic supply at a first pressure to a first side of the piston to move the valve closure member to an actuated position,

providing a second hydraulic supply at a second pressure lower than the first pressure to a second side of the piston to move the valve closure member to the safe position when the first hydraulic supply is removed,

2. The method of claim 1, providing the valve closure member is a gate.

3. (canceled)

4. (canceled)

5. The method of claim 1, providing the second hydraulic supply is from a constant different accumulator.

6. The method of claim 1, providing the failsafe position is the valve is closed.

7. The method of claim 1, providing the failsafe position is the valve is opened.

8. The method of claim 5, providing the first hydraulic supply is from a constant differential accumulator.

9. The method of claim 8, providing the first hydraulic supply pressure relative to ambient is approximately twice the second hydraulic supply pressure relative to ambient.