US20120111572A1 - Emergency control system for subsea blowout preventer - Google Patents
Emergency control system for subsea blowout preventer Download PDFInfo
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- US20120111572A1 US20120111572A1 US13/292,280 US201113292280A US2012111572A1 US 20120111572 A1 US20120111572 A1 US 20120111572A1 US 201113292280 A US201113292280 A US 201113292280A US 2012111572 A1 US2012111572 A1 US 2012111572A1
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- bop
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- stack
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Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
- E21B43/0122—Collecting oil or the like from a submerged leakage
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
- E21B33/0355—Control systems, e.g. hydraulic, pneumatic, electric, acoustic, for submerged well heads
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
- E21B33/064—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers specially adapted for underwater well heads
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/0007—Equipment or details not covered by groups E21B15/00 - E21B40/00 for underwater installations
Definitions
- Embodiments of the present invention generally relate to an emergency control system for a subsea blowout preventer.
- an emergency control system (ECS) for a subsea blowout preventer (BOP) includes a frame having a mud mat for engaging a seafloor; an ECS accumulator connected to the frame; a BOP interface connected to the frame and operable to connect to a stack interface of a BOP stack; a valve connected to the frame and operable to supply hydraulic fluid from the ECS accumulator to the interface; an acoustic receiver; and a controller operable to receive an instruction signal from the acoustic receiver and open the valve.
- a method of safeguarding a subsea drilling operation includes: lowering an emergency control system (ECS) to a seafloor, the ECS comprising: an ECS accumulator, a BOP interface, a hydraulic line extending from the ECS accumulator to the BOP interface, and a valve disposed in the hydraulic line; and operating a remotely operated vehicle (ROV) to connect the BOP interface to a stack interface of a subsea blowout preventer (BOP) stack, wherein the ECS is located at a substantial distance from the BOP stack.
- ECS emergency control system
- FIG. 1 illustrates a subsea blowout preventer (BOP) stack, according to one embodiment of the present invention.
- BOP blowout preventer
- FIG. 2 is a flow diagram of an emergency control system (ECS) connected to the BOP stack.
- ECS emergency control system
- FIG. 3A-3F are operational diagrams illustrating installation and use of the ECS.
- FIG. 1 illustrates a subsea blowout preventer (BOP) stack 1 , according to one embodiment of the present invention.
- FIG. 2 is a flow diagram of an emergency control system (ECS) 100 connected to the BOP stack 1 .
- ECS emergency control system
- the BOP Stack 1 may be employed to control the well during drilling operations in the event of erratic formation pressure causing loss of pressure control, i.e., a kick, which may otherwise lead to a blowout 290 ( FIG. 3D ).
- the BOP stack 1 may also be used to secure and disconnect a marine riser 255 (see FIG. 3A ) from a wellhead 2 in the event of a mobile offshore drilling unit (MODU) 250 losing position due to automatic station keeping failure, weather, sea state, or mooring failure.
- MODU mobile offshore drilling unit
- the BOP Stack 1 may be arranged in two sections, including an upper section (aka Lower Marine Riser Package (LMRP)) 5 u which may interface with the riser 255 via a riser adapter 22 located at a top thereof.
- the LMRP 5 u may further include a flex joint 23 which may accommodate angular movement to compensate for MODU offset.
- the flex joint 23 may interface with an upper single or dual element hydraulically operated upper annular BOP 12 u for the stripping of drill pipe or tubulars which are run in and out of a wellbore (not shown).
- the LMRP 5 u may further include a hydraulically operated connector 26 for connection to a mandrel at a top of the BOP stack lower section 5 b.
- the BOP stack lower section 5 b may include one or more hydraulically operated ram preventers 10 b,p , such as a blind-shear preventer 10 b and a pipe preventer 10 p , connected together via bolted flanges.
- Each ram preventer 10 b,p may include two opposed rams disposed within a body.
- the body may have a bore that is aligned with the wellbore.
- Opposed cavities may intersect the bore and support the rams as they move radially into and out of the bore.
- a bonnet may be connected to the body on the outer end of each cavity and may support an actuator that provides the force required to move the rams into and out of the bore.
- Each actuator may include a hydraulic piston to radially move each ram and a mechanical lock to maintain the position of the ram in case of hydraulic pressure loss.
- the lock may include a threaded rod, a motor (not shown) for rotationally driving the rod, and a threaded sleeve. Once each ram is hydraulically extended into the bore, the motor may be operated to push the sleeve into engagement with the piston.
- Each actuator may include single or dual pistons (dual piston shown in FIG. 1 , single piston shown in FIG. 2 ).
- the pipe preventer 10 p may include pipe rams operable to engage and seal against an outer surface of drill pipe, thereby closing the annulus.
- the blind-shear preventer 10 p may include blind-shear rams operable to cut through drill pipe and seal the well. The upper portion of the severed drill string may be freed from the ram while the lower drill string portion may remain in the wellbore.
- the BOP stack may include a separate blind preventer and a separate shear preventer which may act together to perform the function of the blind-shear preventer.
- the lower section 5 b may include additional pipe preventers (not shown) for engaging and sealing against an outer surface of other tubulars, such as casing (not shown), and/or a redundant drill pipe preventer.
- the BOP stack lower section 5 b may further include a lower annular BOP 12 b .
- the BOP stack lower section 5 b may further include a hydraulically latched wellhead connector 8 connected to a bottom ram preventer via a flange.
- the wellhead connector 8 may connect to the wellhead 2 .
- the wellhead 2 may lead to the wellbore.
- the LMRP 5 u may further include one or more control pods, such as a primary pod 24 p and a backup pod 24 r .
- Each pod 24 p,r may be in electrical or hydraulic communication with the MODU via a control line 30 .
- Each pod 24 p,r may include one or more control valves 24 a - d and a controller 24 m .
- Each valve 24 a - d may be in electric or hydraulic communication with the controller 24 m via an electric or hydraulic control line (unnumbered dashed lines).
- the BOP stack lower section 5 b may further include one or more accumulators 16 for storing pressurized hydraulic fluid.
- the BOP stack lower section 5 b may further include a frame 28 for supporting the accumulators 16 .
- the accumulators 16 may be in fluid communication with one or more of the control valves 24 a - d for operating the various functions of the BOP stack 1 , such as the annular 12 u,b and ram preventers 10 b,p (only blind-shear preventer 10 b shown connected to the pod 24 ).
- a hydraulic fluid charge line (not shown) may extend from the accumulators 16 to the MODU 250 for charging the accumulators.
- the control valves 24 a - d may alternatively be directional control valves, thereby combining functionality of two valves into one valve.
- the controller 24 m may receive instruction signals form the MODU 250 via the control line 30 and operate the appropriate valves 24 a - d in response to the instruction signals.
- Each control pod 24 p,r may also include a dead-man's switch (not shown) for closing the preventers 10 b,p , 12 u,b in response to a loss of communication with the MODU 250 .
- Each pod 24 p,r may be hydraulically latched to the BOP stack 1 to facilitate maintenance of the pods.
- a choke and/or kill line 13 may also extend between the MODU 250 and a port 11 p formed through a body of the pipe preventer 10 p .
- the choke/kill line 13 line may connect to the stack lower section 5 b at connector 20 .
- a shutoff valve 14 may be disposed at the preventer port 11 p .
- the shutoff valve 14 may be operated by the pods 24 p,r via an electric or hydraulic control line.
- a separate choke line and a separate kill line may extend between the MODU 250 and respective ports 11 p formed through the pipe preventer body.
- the choke/kill line 13 may connect to a separate spool (not shown) of the stack lower section 5 b .
- the LMRP 5 u may further include additional pipe ram preventers (not shown) and each pipe ram preventer may have port(s) to receive the choke/kill line to allow circulation through the BOP Stack column depending on which individual preventer is closed.
- the choke/kill line 13 may be used to bypass the riser 255 during a well control event, such as a kick.
- a choke valve (not shown) on the MODU 250 may then be operated to exert backpressure on the annulus while circulating mud through the drill string.
- the choke/kill line 13 may be used to bullhead the wellbore.
- the lower stack section 5 b may further include an interface, such as a junction plate 50 .
- a choke/kill tie-in line 54 may extend from the stack junction plate 50 to the choke/kill line 13 at a lower section of the choke/kill line 13 between the valve 14 and the port 11 p .
- a shutoff valve 56 may be disposed in the choke/kill tie-in 54 .
- the shutoff valve 56 may have an electric or hydraulic actuator in communication with the stack junction plate 50 so that the valve 56 may be operated from the ECS 100 .
- the valve 56 may be operated manually by a remotely operated vehicle (ROV) 205 ( FIG. 3A ) at the stack junction plate 50 .
- ROV remotely operated vehicle
- An injection line 52 may extend from the stack junction plate 50 to a port 11 b formed through a body of the blind-shear preventer 10 b .
- a check valve 55 may be disposed in the injection line 52 and operable to allow flow from the junction plate 50 to the preventer port 11 b and prevent reverse flow therethrough.
- a hydraulic tie-in line 57 (shown in FIG. 2 only) may extend from the stack junction plate 50 to an extension actuation port 15 of the blind-shear actuator.
- a check valve 58 may be disposed in the injection line 52 and operable to allow flow from the stack junction plate 50 to the actuator port 15 and prevent reverse flow therethrough.
- the ECS 100 may include a skid frame 128 , a controller 105 , a battery 106 , a receiver 110 , an accumulator 116 , one or more interfaces, such as junction plates 150 b,v , an injection line 152 , a hydraulic line 157 , and a choke/kill line 154 .
- Each of the ECS components may be connected to the skid frame 128 and the skid frame may include retractable legs and a mud mat for supporting and stabilizing the ECS 100 from a floor 201 f of the sea 201 ( FIG. 3A ).
- the ECS accumulator 116 may store sufficient fluid energy to extend the blind-shear preventer 10 b one or more times, such as twice.
- the hydraulic line 157 may provide fluid communication between the accumulator 116 and the BOP junction plate 150 b .
- a shutoff valve 158 may be disposed in the hydraulic line 157 and have an actuator in hydraulic or electrical communication with the controller 105 via a control line.
- a support vessel such as a light or medium intervention vessel 200 ( FIG. 3A ), may connect to the vessel junction plate 150 v via a vessel umbilical 151 v .
- the vessel umbilical 151 v may include one or more fluid conduits and an electrical cable.
- the junction plate 150 v may connect the electrical cable to the controller 105 for providing electricity from the vessel 200 to the controller and providing data communication between the vessel and the controller.
- One of the vessel umbilical conduits may connect to the choke/kill line 154 via the vessel junction plate 150 v .
- the choke/kill line 154 may provide fluid communication between the vessel junction plate 150 v and the BOP junction plate 150 b .
- a shutoff valve 156 s and choke valve 156 c may be disposed in the hydraulic line 157 and each have an actuator in hydraulic or electrical communication with the controller 105 via a control line.
- Leads (not shown) may connect the battery 106 and the receiver 110 to the controller 105 .
- the battery 106 may provide electricity to the ECS controller 105 before connection of the vessel umbilical 151 v and the receiver 110 may allow an instruction signal to be sent wirelessly from the vessel 200 before connection of the vessel umbilical 151 v .
- a second of the vessel umbilical conduits may connect to the injection line 152 via the vessel junction plate 150 v .
- the injection line 152 may provide fluid communication between the vessel junction plate 150 v and the BOP junction plate 150 b .
- a check valve 155 may be disposed in the injection line 152 and allow fluid flow from the vessel junction plate 150 v to the BOP junction plate 150 b and prevent reverse flow therethrough.
- a BOP umbilical 151 b may connect the junction plates 50 , 150 b .
- the BOP umbilical 151 b may have a substantial length D, such as greater than or equal two-hundred fifty, five-hundred, or one-thousand feet, such that the vessel 200 may connect to the ECS 100 while being clear from the BOP stack 1 during the blowout 290 .
- the BOP umbilical 151 b may have a first conduit connected to the hydraulic line 157 via the BOP junction plate 150 b , a second conduit connected to the choke/kill line 154 via the BOP junction plate 150 b , a third conduit in communication with the injection line 152 via the BOP junction plate 150 b , and a control conduit/cable in communication with the controller 105 via the BOP junction plate 150 b .
- the junction plate 50 may connect the first BOP umbilical conduit to the hydraulic tie-in 57 , the second BOP umbilical conduit to the choke/kill tie-in 54 , the third BOP umbilical conduit to the injection line 52 , and the BOP umbilical control conduit/cable to the actuator of valve 56 .
- Each of the shutoff valves 56 , 156 s , and 158 and choke valve 156 c may be fail-closed and may include an ROV operable override.
- the choke valve 156 c may also include a visual position indicator for viewing by the ROV 205 .
- each conduit/cable of the umbilicals 151 b,v may be run as separate lines or only some of the lines may be grouped together in an umbilical.
- the choke valve 156 c may be arranged in a bypass spool of choke/kill line 154 (having shutoff valves straddling the choke valve 156 c ) or the ECS 100 may further include separate choke and kill lines (corresponding to separate choke and kill lines of the BOP stack 1 ).
- FIG. 3A-3F are operational diagrams illustrating installation and use of the ECS 100 .
- the vessel 200 may be deployed during an early stage of a drilling operation, such as after the MODU 250 has cemented the conductor pipe and connected the BOP stack 1 to the wellhead 2 .
- the vessel 200 may include a dynamic positioning system to maintain position of the vessel 200 on the waterline 201 w and a heave compensator to account for vessel heave due to wave action of the sea 201 .
- the vessel 200 may further include a tower 211 having an injector 212 for deployment cable 209 .
- the injector 212 may wind or unwind the deployment cable 209 from drum 213 .
- the ROV 205 may be deployed into the sea 201 from the vessel 200 .
- the ROV 205 may be an unmanned, self-propelled submarine that includes a video camera, an articulating arm, a thruster, and other instruments for performing a variety of tasks.
- the ROV 205 may further include a chassis made from a light metal or alloy, such as aluminum, and a float made from a buoyant material, such as syntactic foam, located at a top of the chassis.
- the ROV 205 may be controlled and supplied with electricity from the vessel 200 .
- the ROV 205 may be connected to the support vessel 200 by a tether 206 .
- the tether 206 may provide electrical, hydraulic, and/or data communication between the ROV 206 and the vessel 200 .
- An operator on the vessel 200 may control the movement and operations of ROV 205 .
- the tether 206 may be wound or unwound from drum 207 .
- the injector 212 and deployment line 209 may then be used to lower the ECS 100 to the seafloor 201 f through the moonpool of the vessel 200 .
- the ROV 205 may guide landing of the ECS 100 .
- the ROV 205 may then operate the skid frame legs until the mud mat has engaged the seafloor 201 f .
- the ROV 205 may then deploy the umbilical 151 b and connect the umbilical to the junction plates 150 b , 50 .
- the umbilical 151 b may connect to the junction plates 150 b , 50 using hot stabs or hydraulic connectors.
- the vessel 200 may leave and drilling operations may continue.
- the drilling operation may or may not be halted during installation of the ECS 100 .
- the ECS 100 may be deployed by the MODU 250 or any other vessel having an ROV and a hoist.
- the vessel 200 may be re-deployed to the ECS site.
- An acoustic signal 240 may be transmitted from the vessel 200 to the ECS 100 instructing the ECS to open the valve 158 .
- the ECS controller 105 may receive the signal via the receiver 110 and operate the actuator of the valve 158 .
- the accumulator 116 may then inject hydraulic fluid through the hydraulic line 157 , junction plate 150 b , the respective conduit of the umbilical 151 b , junction plate 50 , hydraulic tie-in 57 , and check valve 58 to the blind-shear preventer extension port 15 .
- the fluid path of the hydraulic fluid may bypass the control pods 24 p,r , thereby operating the preventer actuator notwithstanding malfunction of the control pods 24 p,r .
- the vessel 200 may be deployed and the blind-shear preventer closed before the MODU sinks, thereby reducing the chance sinking debris may obstruct closure of the blind-shear preventer 10 b .
- the blind-shear preventer 10 b is successfully closed and damage to the MODU 250 is minimal, then the BOP stack 1 and the MODU 250 may be repaired or replaced and drilling operations may resume or the wellbore may be plugged and abandoned through the BOP stack.
- damage to the MODU 250 is extensive (i.e., sunk to the seafloor), then the vessel 200 may remain in place while a relief well is drilled using a new MODU (not shown).
- the ROV 205 may be used to deploy and connect the vessel umbilical 151 v to the vessel junction plate 150 v .
- the vessel 200 may instruct the ECS controller 105 via the electrical cable of the vessel umbilical 151 v to open the choke 156 c and shutoff 156 s valves and the shutoff valve 56 .
- the vessel 200 may then pump heavy mud (aka kill fluid) through the respective conduit of vessel umbilical 151 v , vessel junction plate 150 v , the choke/kill line 154 , BOP junction plate 150 b , respective conduit of BOP umbilical 151 b , stack junction plate 50 , and choke/kill tie in 54 to the pipe preventer port 11 p in an attempt to bullhead the wellbore.
- heavy mud aka kill fluid
- dispersant may be injected through the respective conduit of vessel umbilical 151 v , junction plate 150 v , the injection line 152 , junction plate 150 b , respective conduit of BOP umbilical 151 b , and injection line 52 to the blind-shear preventer port while a new MODU drills a relief well.
- the production fluid from the blowing wellbore may be allowed to flow to production facilities (not shown) located on board the vessel 200 via the choke/kill line 154 .
- the choke valve 156 c may be controlled to maintain a positive pressure differential in the BOP stack 1 (relative to ambient pressure at the seafloor 201 f ), such as greater than or equal to one psig.
- Production fluid may flow to the vessel through the umbilical and to the production facilities where the production fluid may be separated into crude oil, natural gas, and (produced) water.
- the crude oil may be stored onboard the vessel or transferred to a tanker or supertanker (not shown).
- the gas may be flared.
- the water may be stored for later treatment or treated and pumped into the sea.
- the BOP stack 1 and/or the ECS 100 may further include a pressure sensor (not shown) in fluid communication with the respective choke/kill line/tie-in 54 , 154 and in data communication with the ECS controller 105 .
- the pressure may be monitored to ensure that the pressure differential is maintained.
- a hydrates inhibitor, such as methanol, ethylene glycol, or propylene glycol, or dispersant may be injected into the blind-shear preventer port 11 b via the injection lines 52 , 152 .
- the ROV 205 may visually monitor the BOP stack 1 for leakage to ensure that the pressure differential is being maintained.
- the choke 156 c may be kept fully open and the excess production fluid may leak into the sea 201 and, as discussed above, dispersant may be injected into the blind-shear preventer port via the injection lines 52 , 152 .
- the ECS 100 may be operated by the MODU 250 , the new MODU, or any other vessel having acoustic transmission capability, an ROV, and/or fluid handling capability.
- the acoustic signal 240 may be sent by any vehicle having acoustic transmission capability, such as a helicopter dropping an acoustic transmission buoy.
- the ECS 100 may not be deployed until after the blowout occurs.
- the step of sending the acoustic signal may be omitted as the ECS 100 may be lowered with the vessel umbilical 151 v already connected and the ROV may connect the BOP umbilical 151 b or the ROV may connect both umbilicals 151 b,v.
Abstract
Description
- This application claims benefit of U.S. Provisional App. No. 61/411,666 (Atty. Dock. No. WWCl/0017USL), filed Nov. 9, 2010, which is hereby incorporated by reference in its entirety.
- 1. Field of the Invention
- Embodiments of the present invention generally relate to an emergency control system for a subsea blowout preventer.
- 2. Description of the Related Art
- Bringing an underwater well blowout under control is difficult since it is usually accompanied by hydrocarbons and/or fire at the surface and damage to the subsea equipment connector. This uncontrolled flow of oil and gas is not only a waste of energy but also can be a source of water and beach pollution. Control of the well flow from a blowout and collection of oil spills therefrom have been handled separately. Control of well flow is attempted by drilling separate wells to feed heavy mud into the flowing well to kill the flow.
- Embodiments of the present invention generally relate to an emergency control system for a subsea blowout preventer. In one embodiment, an emergency control system (ECS) for a subsea blowout preventer (BOP) includes a frame having a mud mat for engaging a seafloor; an ECS accumulator connected to the frame; a BOP interface connected to the frame and operable to connect to a stack interface of a BOP stack; a valve connected to the frame and operable to supply hydraulic fluid from the ECS accumulator to the interface; an acoustic receiver; and a controller operable to receive an instruction signal from the acoustic receiver and open the valve.
- In another embodiment, a method of safeguarding a subsea drilling operation includes: lowering an emergency control system (ECS) to a seafloor, the ECS comprising: an ECS accumulator, a BOP interface, a hydraulic line extending from the ECS accumulator to the BOP interface, and a valve disposed in the hydraulic line; and operating a remotely operated vehicle (ROV) to connect the BOP interface to a stack interface of a subsea blowout preventer (BOP) stack, wherein the ECS is located at a substantial distance from the BOP stack.
- So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
-
FIG. 1 illustrates a subsea blowout preventer (BOP) stack, according to one embodiment of the present invention. -
FIG. 2 is a flow diagram of an emergency control system (ECS) connected to the BOP stack. -
FIG. 3A-3F are operational diagrams illustrating installation and use of the ECS. -
FIG. 1 illustrates a subsea blowout preventer (BOP)stack 1, according to one embodiment of the present invention.FIG. 2 is a flow diagram of an emergency control system (ECS) 100 connected to theBOP stack 1. TheBOP Stack 1 may be employed to control the well during drilling operations in the event of erratic formation pressure causing loss of pressure control, i.e., a kick, which may otherwise lead to a blowout 290 (FIG. 3D ). TheBOP stack 1 may also be used to secure and disconnect a marine riser 255 (seeFIG. 3A ) from awellhead 2 in the event of a mobile offshore drilling unit (MODU) 250 losing position due to automatic station keeping failure, weather, sea state, or mooring failure. - The
BOP Stack 1 may be arranged in two sections, including an upper section (aka Lower Marine Riser Package (LMRP)) 5 u which may interface with theriser 255 via ariser adapter 22 located at a top thereof. The LMRP 5 u may further include aflex joint 23 which may accommodate angular movement to compensate for MODU offset. Theflex joint 23 may interface with an upper single or dual element hydraulically operated upperannular BOP 12 u for the stripping of drill pipe or tubulars which are run in and out of a wellbore (not shown). The LMRP 5 u may further include a hydraulically operatedconnector 26 for connection to a mandrel at a top of the BOP stacklower section 5 b. - The BOP stack
lower section 5 b may include one or more hydraulically operatedram preventers 10 b,p, such as a blind-shear preventer 10 b and apipe preventer 10 p, connected together via bolted flanges. Eachram preventer 10 b,p may include two opposed rams disposed within a body. The body may have a bore that is aligned with the wellbore. Opposed cavities may intersect the bore and support the rams as they move radially into and out of the bore. A bonnet may be connected to the body on the outer end of each cavity and may support an actuator that provides the force required to move the rams into and out of the bore. Each actuator may include a hydraulic piston to radially move each ram and a mechanical lock to maintain the position of the ram in case of hydraulic pressure loss. The lock may include a threaded rod, a motor (not shown) for rotationally driving the rod, and a threaded sleeve. Once each ram is hydraulically extended into the bore, the motor may be operated to push the sleeve into engagement with the piston. Each actuator may include single or dual pistons (dual piston shown inFIG. 1 , single piston shown inFIG. 2 ). - Each of the rams may be equipped with seals that engage and prohibit flow through the bore when the rams are closed. The
pipe preventer 10 p may include pipe rams operable to engage and seal against an outer surface of drill pipe, thereby closing the annulus. The blind-shear preventer 10 p may include blind-shear rams operable to cut through drill pipe and seal the well. The upper portion of the severed drill string may be freed from the ram while the lower drill string portion may remain in the wellbore. Alternatively, the BOP stack may include a separate blind preventer and a separate shear preventer which may act together to perform the function of the blind-shear preventer. Additionally, thelower section 5 b may include additional pipe preventers (not shown) for engaging and sealing against an outer surface of other tubulars, such as casing (not shown), and/or a redundant drill pipe preventer. - The BOP stack
lower section 5 b may further include a lowerannular BOP 12 b. The BOP stacklower section 5 b may further include a hydraulically latchedwellhead connector 8 connected to a bottom ram preventer via a flange. Thewellhead connector 8 may connect to thewellhead 2. Thewellhead 2 may lead to the wellbore. - The LMRP 5 u may further include one or more control pods, such as a
primary pod 24 p and a backup pod 24 r. Eachpod 24 p,r may be in electrical or hydraulic communication with the MODU via acontrol line 30. Eachpod 24 p,r may include one or more control valves 24 a-d and acontroller 24 m. Each valve 24 a-d may be in electric or hydraulic communication with thecontroller 24 m via an electric or hydraulic control line (unnumbered dashed lines). The BOP stacklower section 5 b may further include one ormore accumulators 16 for storing pressurized hydraulic fluid. The BOP stacklower section 5 b may further include aframe 28 for supporting theaccumulators 16. Theaccumulators 16 may be in fluid communication with one or more of the control valves 24 a-d for operating the various functions of theBOP stack 1, such as the annular 12 u,b andram preventers 10 b,p (only blind-shear preventer 10 b shown connected to the pod 24). A hydraulic fluid charge line (not shown) may extend from theaccumulators 16 to the MODU 250 for charging the accumulators. Although shown as shutoff valves, the control valves 24 a-d may alternatively be directional control valves, thereby combining functionality of two valves into one valve. Thecontroller 24 m may receive instruction signals form theMODU 250 via thecontrol line 30 and operate the appropriate valves 24 a-d in response to the instruction signals. Eachcontrol pod 24 p,r may also include a dead-man's switch (not shown) for closing thepreventers 10 b,p,12 u,b in response to a loss of communication with theMODU 250. Eachpod 24 p,r may be hydraulically latched to theBOP stack 1 to facilitate maintenance of the pods. - A choke and/or kill
line 13 may also extend between theMODU 250 and aport 11 p formed through a body of thepipe preventer 10 p. The choke/kill line 13 line may connect to the stacklower section 5 b atconnector 20. Ashutoff valve 14 may be disposed at thepreventer port 11 p. Theshutoff valve 14 may be operated by thepods 24 p,r via an electric or hydraulic control line. Although oneline 13 is shown, a separate choke line and a separate kill line may extend between theMODU 250 andrespective ports 11 p formed through the pipe preventer body. Alternatively, the choke/kill line 13 may connect to a separate spool (not shown) of the stacklower section 5 b. As discussed above, theLMRP 5 u may further include additional pipe ram preventers (not shown) and each pipe ram preventer may have port(s) to receive the choke/kill line to allow circulation through the BOP Stack column depending on which individual preventer is closed. The choke/kill line 13 may be used to bypass theriser 255 during a well control event, such as a kick. A choke valve (not shown) on theMODU 250 may then be operated to exert backpressure on the annulus while circulating mud through the drill string. Alternatively, the choke/kill line 13 may be used to bullhead the wellbore. - To facilitate connection of the
ECS 100, thelower stack section 5 b may further include an interface, such as ajunction plate 50. A choke/kill tie-inline 54 may extend from thestack junction plate 50 to the choke/kill line 13 at a lower section of the choke/kill line 13 between thevalve 14 and theport 11 p. Ashutoff valve 56 may be disposed in the choke/kill tie-in 54. Theshutoff valve 56 may have an electric or hydraulic actuator in communication with thestack junction plate 50 so that thevalve 56 may be operated from theECS 100. Alternatively or additionally, thevalve 56 may be operated manually by a remotely operated vehicle (ROV) 205 (FIG. 3A ) at thestack junction plate 50. Aninjection line 52 may extend from thestack junction plate 50 to aport 11 b formed through a body of the blind-shear preventer 10 b. Acheck valve 55 may be disposed in theinjection line 52 and operable to allow flow from thejunction plate 50 to thepreventer port 11 b and prevent reverse flow therethrough. A hydraulic tie-in line 57 (shown inFIG. 2 only) may extend from thestack junction plate 50 to anextension actuation port 15 of the blind-shear actuator. Acheck valve 58 may be disposed in theinjection line 52 and operable to allow flow from thestack junction plate 50 to theactuator port 15 and prevent reverse flow therethrough. - The
ECS 100 may include askid frame 128, acontroller 105, abattery 106, areceiver 110, anaccumulator 116, one or more interfaces, such asjunction plates 150 b,v, aninjection line 152, ahydraulic line 157, and a choke/kill line 154. Each of the ECS components may be connected to theskid frame 128 and the skid frame may include retractable legs and a mud mat for supporting and stabilizing theECS 100 from afloor 201 f of the sea 201 (FIG. 3A ). TheECS accumulator 116 may store sufficient fluid energy to extend the blind-shear preventer 10 b one or more times, such as twice. Thehydraulic line 157 may provide fluid communication between theaccumulator 116 and theBOP junction plate 150 b. Ashutoff valve 158 may be disposed in thehydraulic line 157 and have an actuator in hydraulic or electrical communication with thecontroller 105 via a control line. - A support vessel, such as a light or medium intervention vessel 200 (
FIG. 3A ), may connect to thevessel junction plate 150 v via a vessel umbilical 151 v. The vessel umbilical 151 v may include one or more fluid conduits and an electrical cable. Thejunction plate 150 v may connect the electrical cable to thecontroller 105 for providing electricity from thevessel 200 to the controller and providing data communication between the vessel and the controller. One of the vessel umbilical conduits may connect to the choke/kill line 154 via thevessel junction plate 150 v. The choke/kill line 154 may provide fluid communication between thevessel junction plate 150 v and theBOP junction plate 150 b. Ashutoff valve 156 s and chokevalve 156 c may be disposed in thehydraulic line 157 and each have an actuator in hydraulic or electrical communication with thecontroller 105 via a control line. Leads (not shown) may connect thebattery 106 and thereceiver 110 to thecontroller 105. Thebattery 106 may provide electricity to theECS controller 105 before connection of the vessel umbilical 151 v and thereceiver 110 may allow an instruction signal to be sent wirelessly from thevessel 200 before connection of the vessel umbilical 151 v. A second of the vessel umbilical conduits may connect to theinjection line 152 via thevessel junction plate 150 v. Theinjection line 152 may provide fluid communication between thevessel junction plate 150 v and theBOP junction plate 150 b. Acheck valve 155 may be disposed in theinjection line 152 and allow fluid flow from thevessel junction plate 150 v to theBOP junction plate 150 b and prevent reverse flow therethrough. - A BOP umbilical 151 b may connect the
junction plates vessel 200 may connect to theECS 100 while being clear from theBOP stack 1 during theblowout 290. The BOP umbilical 151 b may have a first conduit connected to thehydraulic line 157 via theBOP junction plate 150 b, a second conduit connected to the choke/kill line 154 via theBOP junction plate 150 b, a third conduit in communication with theinjection line 152 via theBOP junction plate 150 b, and a control conduit/cable in communication with thecontroller 105 via theBOP junction plate 150 b. Thejunction plate 50 may connect the first BOP umbilical conduit to the hydraulic tie-in 57, the second BOP umbilical conduit to the choke/kill tie-in 54, the third BOP umbilical conduit to theinjection line 52, and the BOP umbilical control conduit/cable to the actuator ofvalve 56. - Each of the
shutoff valves valve 156 c may be fail-closed and may include an ROV operable override. Thechoke valve 156 c may also include a visual position indicator for viewing by theROV 205. Alternatively, each conduit/cable of theumbilicals 151 b,v may be run as separate lines or only some of the lines may be grouped together in an umbilical. Alternatively, thechoke valve 156 c may be arranged in a bypass spool of choke/kill line 154 (having shutoff valves straddling thechoke valve 156 c) or theECS 100 may further include separate choke and kill lines (corresponding to separate choke and kill lines of the BOP stack 1). -
FIG. 3A-3F are operational diagrams illustrating installation and use of theECS 100. - The
vessel 200 may be deployed during an early stage of a drilling operation, such as after theMODU 250 has cemented the conductor pipe and connected theBOP stack 1 to thewellhead 2. Thevessel 200 may include a dynamic positioning system to maintain position of thevessel 200 on thewaterline 201 w and a heave compensator to account for vessel heave due to wave action of thesea 201. Thevessel 200 may further include atower 211 having aninjector 212 fordeployment cable 209. Theinjector 212 may wind or unwind thedeployment cable 209 fromdrum 213. - The
ROV 205 may be deployed into thesea 201 from thevessel 200. TheROV 205 may be an unmanned, self-propelled submarine that includes a video camera, an articulating arm, a thruster, and other instruments for performing a variety of tasks. TheROV 205 may further include a chassis made from a light metal or alloy, such as aluminum, and a float made from a buoyant material, such as syntactic foam, located at a top of the chassis. TheROV 205 may be controlled and supplied with electricity from thevessel 200. TheROV 205 may be connected to thesupport vessel 200 by atether 206. Thetether 206 may provide electrical, hydraulic, and/or data communication between theROV 206 and thevessel 200. An operator on thevessel 200 may control the movement and operations ofROV 205. Thetether 206 may be wound or unwound fromdrum 207. - The
injector 212 anddeployment line 209 may then be used to lower theECS 100 to theseafloor 201 f through the moonpool of thevessel 200. TheROV 205 may guide landing of theECS 100. TheROV 205 may then operate the skid frame legs until the mud mat has engaged theseafloor 201 f. Once theECS 100 has landed on theseafloor 201 f, theROV 205 may then deploy the umbilical 151 b and connect the umbilical to thejunction plates junction plates junction plates vessel 200 may leave and drilling operations may continue. The drilling operation may or may not be halted during installation of theECS 100. Alternatively, theECS 100 may be deployed by theMODU 250 or any other vessel having an ROV and a hoist. - In the event of the blowout 290 (failure of the BOP stack 1), the
vessel 200 may be re-deployed to the ECS site. Anacoustic signal 240 may be transmitted from thevessel 200 to theECS 100 instructing the ECS to open thevalve 158. TheECS controller 105 may receive the signal via thereceiver 110 and operate the actuator of thevalve 158. Theaccumulator 116 may then inject hydraulic fluid through thehydraulic line 157,junction plate 150 b, the respective conduit of the umbilical 151 b,junction plate 50, hydraulic tie-in 57, andcheck valve 58 to the blind-shearpreventer extension port 15. The fluid path of the hydraulic fluid may bypass thecontrol pods 24 p,r, thereby operating the preventer actuator notwithstanding malfunction of thecontrol pods 24 p,r. Assuming theMODU 250 is burning, thevessel 200 may be deployed and the blind-shear preventer closed before the MODU sinks, thereby reducing the chance sinking debris may obstruct closure of the blind-shear preventer 10 b. If the blind-shear preventer 10 b is successfully closed and damage to theMODU 250 is minimal, then theBOP stack 1 and theMODU 250 may be repaired or replaced and drilling operations may resume or the wellbore may be plugged and abandoned through the BOP stack. If damage to theMODU 250 is extensive (i.e., sunk to the seafloor), then thevessel 200 may remain in place while a relief well is drilled using a new MODU (not shown). - If closure of the blind-
shear preventer 10 b fails or is only partially successful, then theROV 205 may be used to deploy and connect the vessel umbilical 151 v to the vessel junction plate 150 v. Once connected, thevessel 200 may instruct theECS controller 105 via the electrical cable of the vessel umbilical 151 v to open thechoke 156 c andshutoff 156 s valves and theshutoff valve 56. Thevessel 200 may then pump heavy mud (aka kill fluid) through the respective conduit of vessel umbilical 151 v,vessel junction plate 150 v, the choke/kill line 154,BOP junction plate 150 b, respective conduit of BOP umbilical 151 b, stackjunction plate 50, and choke/kill tie in 54 to thepipe preventer port 11 p in an attempt to bullhead the wellbore. If the bullhead operation fails, then dispersant may be injected through the respective conduit of vessel umbilical 151 v,junction plate 150 v, theinjection line 152,junction plate 150 b, respective conduit of BOP umbilical 151 b, andinjection line 52 to the blind-shear preventer port while a new MODU drills a relief well. - Alternatively or in response to failure of the bullhead operation, the production fluid from the blowing wellbore may be allowed to flow to production facilities (not shown) located on board the
vessel 200 via the choke/kill line 154. If capacity of the production facilities is greater than or equal to the production (blowout) rate of the wellbore, thechoke valve 156 c may be controlled to maintain a positive pressure differential in the BOP stack 1 (relative to ambient pressure at theseafloor 201 f), such as greater than or equal to one psig. Production fluid may flow to the vessel through the umbilical and to the production facilities where the production fluid may be separated into crude oil, natural gas, and (produced) water. The crude oil may be stored onboard the vessel or transferred to a tanker or supertanker (not shown). The gas may be flared. The water may be stored for later treatment or treated and pumped into the sea. TheBOP stack 1 and/or theECS 100 may further include a pressure sensor (not shown) in fluid communication with the respective choke/kill line/tie-in ECS controller 105. As the wellbore is produced, the pressure may be monitored to ensure that the pressure differential is maintained. A hydrates inhibitor, such as methanol, ethylene glycol, or propylene glycol, or dispersant may be injected into the blind-shear preventer port 11 b via the injection lines 52, 152. Alternatively, theROV 205 may visually monitor theBOP stack 1 for leakage to ensure that the pressure differential is being maintained. - If production capacity is less than the production rate of the wellbore, then the
choke 156 c may be kept fully open and the excess production fluid may leak into thesea 201 and, as discussed above, dispersant may be injected into the blind-shear preventer port via the injection lines 52, 152. - Alternatively, the
ECS 100 may be operated by theMODU 250, the new MODU, or any other vessel having acoustic transmission capability, an ROV, and/or fluid handling capability. Alternatively, theacoustic signal 240 may be sent by any vehicle having acoustic transmission capability, such as a helicopter dropping an acoustic transmission buoy. - Alternatively, the
ECS 100 may not be deployed until after the blowout occurs. The step of sending the acoustic signal may be omitted as theECS 100 may be lowered with the vessel umbilical 151 v already connected and the ROV may connect the BOP umbilical 151 b or the ROV may connect bothumbilicals 151 b,v. - While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
Claims (15)
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US13/292,280 US20120111572A1 (en) | 2010-11-09 | 2011-11-09 | Emergency control system for subsea blowout preventer |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US41166610P | 2010-11-09 | 2010-11-09 | |
US13/292,280 US20120111572A1 (en) | 2010-11-09 | 2011-11-09 | Emergency control system for subsea blowout preventer |
Publications (1)
Publication Number | Publication Date |
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US20120111572A1 true US20120111572A1 (en) | 2012-05-10 |
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US13/292,280 Abandoned US20120111572A1 (en) | 2010-11-09 | 2011-11-09 | Emergency control system for subsea blowout preventer |
Country Status (2)
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US (1) | US20120111572A1 (en) |
WO (1) | WO2012064812A2 (en) |
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WO2012064812A3 (en) | 2012-07-05 |
WO2012064812A2 (en) | 2012-05-18 |
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